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<SEC-DOCUMENT>0000004904-02-000106.txt : 20020415
<SEC-HEADER>0000004904-02-000106.hdr.sgml : 20020415
ACCESSION NUMBER:		0000004904-02-000106
CONFORMED SUBMISSION TYPE:	10-K
PUBLIC DOCUMENT COUNT:		14
CONFORMED PERIOD OF REPORT:	20011231
FILED AS OF DATE:		20020329

FILER:

	COMPANY DATA:	
		COMPANY CONFORMED NAME:			AMERICAN ELECTRIC POWER CO INC
		CENTRAL INDEX KEY:			0000004904
		STANDARD INDUSTRIAL CLASSIFICATION:	ELECTRIC SERVICES [4911]
		IRS NUMBER:				134922640
		STATE OF INCORPORATION:			NY
		FISCAL YEAR END:			1231

	FILING VALUES:
		FORM TYPE:		10-K
		SEC ACT:		1934 Act
		SEC FILE NUMBER:	001-03525
		FILM NUMBER:		02592763

	BUSINESS ADDRESS:	
		STREET 1:		1 RIVERSIDE PLZ
		CITY:			COLUMBUS
		STATE:			OH
		ZIP:			43215
		BUSINESS PHONE:		6142231000

	FORMER COMPANY:	
		FORMER CONFORMED NAME:	KINGSPORT UTILITIES INC
		DATE OF NAME CHANGE:	19660906
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>module.txt
<DESCRIPTION>AEP AND REPORTING SUBSIDIARIES
<TEXT>
<PAGE>
<PAGE>

- --------------------------------------------------------------------------------
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D. C. 20549
                                -----------------
                                    FORM 10-K
                                -----------------
(Mark One)

|X|  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
     ACT OF 1934
     For the fiscal year ended December 31, 2001

|_|  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934
     For the transition period from _____________ to ______________


<TABLE>
<CAPTION>

COMMISSION       REGISTRANTS; STATES OF INCORPORATION;                               I.R.S.  EMPLOYER
FILE NUMBER      ADDRESS AND TELEPHONE NUMBER                                        IDENTIFICATION NOS.
- -----------      ----------------------------                                       -------------------
<S>             <C>                                                                      <C>
1-3525           AMERICAN ELECTRIC POWER COMPANY, INC.  (A New York Corporation)         13-4922640
0-18135          AEP GENERATING COMPANY (An Ohio Corporation)                            31-1033833
1-3457           APPALACHIAN POWER COMPANY (A Virginia Corporation)                      54-0124790
0-346            CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation)                   74-0550600
1-2680           COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation)                   31-4154203
1-3570           INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)                 35-0410455
1-6858           KENTUCKY POWER COMPANY (A Kentucky Corporation)                         61-0247775
1-6543           OHIO POWER COMPANY (An Ohio Corporation)                                31-4271000
0-343            PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)            73-0410895
1-3146           SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)            72-0323455
0-340            WEST TEXAS UTILITIES COMPANY (A Texas Corporation)                      75-0646790
                 1 Riverside Plaza, Columbus, Ohio 43215
                 Telephone (614) 223-1000

</TABLE>

     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 X. No.
                                                  ---

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

     AEP Generating Company, Columbus Southern Power Company, Kentucky Power
Company, Public Service Company of Oklahoma and West Texas Utilities Company
meet the conditions set forth in General Instruction I(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 I(2) to such Form 10-K.


<PAGE>






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

<TABLE>
<CAPTION>

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

<S>                             <C>                                              <C>
AEP Generating Company      None

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

Appalachian Power           8-1/4% Junior Subordinated Deferrable
  Company                        Interest Debentures, Series A, Due  2026.......  New York Stock Exchange
                            8% Junior Subordinated Deferrable
                                 Interest Debentures, Series B, Due  2027.......  New York Stock Exchange
                            7.20% Senior Notes, Series A, Due 2038..............  New York Stock Exchange
                            7.30% Senior Notes, Series B, Due 2038................New York Stock Exchange

Columbus Southern           8-3/8% Junior Subordinated Deferrable
  Power Company                  Interest Debentures, Series A, Due 2025........  New York Stock Exchange
                            7.92% Junior Subordinated Deferrable
                                 Interest Debentures, Series B, Due 2027........  New York Stock Exchange

CPL Capital I               8.00% Cumulative Quarterly Income
                                 Preferred Securities,  Series A, Liquidation
                                 Preference $25 per Preferred Security............New York Stock Exchange

Indiana Michigan            8% Junior Subordinated Deferrable
  Power Company                  Interest Debentures, Series A, Due 2026........  New York Stock Exchange
                            7.60% Junior Subordinated Deferrable
                                 Interest Debentures, Series B, Due 2038..........New York Stock Exchange

Kentucky Power              8.72% Junior Subordinated Deferrable
  Company                        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
                            7.92% Junior Subordinated Deferrable
                                 Interest Debentures  Series B, Due 2027..........New York Stock Exchange
                            7-3/8% Senior Notes, Series A, Due 2038.............  New York Stock Exchange

PSO Capital I               8.00% Trust Originated Preferred
                                 Securities, Series A, Liquidation
                                 Preference $25 per Preferred Security..........  New York Stock Exchange

SWEPCo Capital I            7.875% Trust Preferred Securities,
                                 Series A,  Liquidation amount $25
                                 per Preferred Security.........................  New York Stock Exchange

</TABLE>


<PAGE>


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

<TABLE>
<CAPTION>

         REGISTRANT                                TITLE OF EACH CLASS
         ----------                                -------------------
<S>                                               <C>
AEP Generating Company                             None
American Electric Power Company, Inc.              None
Appalachian Power Company                          None
Central Power and Light Company                    4.00% Cumulative Preferred Stock, Non-Voting, $100 par value
                                                   4.20% Cumulative Preferred Stock, Non-Voting, $100 par value
Columbus Southern Power Company                    None
Indiana Michigan Power Company                     4.125% Cumulative Preferred Stock, Non-Voting, $100 par value
Kentucky Power Company                             None
Ohio Power Company                                 4.50% Cumulative Preferred Stock, Voting, $100 par value
Public Service Company of Oklahoma                 None
Southwestern Electric Power Company                4.28% Cumulative Preferred Stock, Non-Voting, $100 par value
                                                   4.65% Cumulative Preferred Stock, Non-Voting, $100 par value
                                                   5.00% Cumulative Preferred Stock, Non-Voting, $100 par value
West Texas Utilities Company                       None

</TABLE>


<TABLE>
<CAPTION>
                                                 AGGREGATE MARKET VALUE
                                                OF VOTING AND NON-VOTING         NUMBER OF SHARES
                                                   COMMON EQUITY HELD             OF COMMON STOCK
                                                  BY NON-AFFILIATES OF            OUTSTANDING OF
                                                   THE REGISTRANTS AT           THE REGISTRANTS AT
                                                       FEBRUARY 1, 2002          FEBRUARY 1, 2002
                                                ------------------------        ------------------

<S>                                                <C>                         <C>
AEP Generating Company                                    None                         1,000
                                                                                ($1,000 par value)
American Electric Power Company, Inc.               $13,478,213,062                 322,368,167
                                                                                 ($6.50 par value)
Appalachian Power Company                                 None                      13,499,500
                                                                                  (no par value)
Central Power and Light Company                           None                       6,755,535
                                                                                  ($25 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                                        None                      27,952,473
                                                                                  (no par value)
Public Service Company of Oklahoma                        None                       9,013,000
                                                                                  ($15 par value)
Southwestern Electric Power Company                       None                       7,536,640
                                                                                  ($18 par value)
West Texas Utilities Company                              None                       5,488,560
                                                                                  ($25 par value)

</TABLE>


     NOTE ON MARKET VALUE OF COMMON EQUITY HELD BY NON-AFFILIATES

     American Electric Power Company, Inc. owns, directly or indirectly, all of
the common stock of AEP Generating Company, Appalachian Power Company, Central
Power and Light Company, Columbus Southern Power Company, Indiana Michigan Power
Company, Kentucky Power Company, Ohio Power Company, Public Service Company of
Oklahoma, Southwestern Electric Power Company and West Texas Utilities Company
(see Item 12 herein).


<PAGE>




                       DOCUMENTS INCORPORATED BY REFERENCE

<TABLE>
<CAPTION>

                                                                                 PART OF FORM 10-K
                                                                                INTO WHICH DOCUMENT
DESCRIPTION                                                                       IS INCORPORATED
- -----------                                                                     -------------------
<S>                                                                                <C>
Portions of Annual Reports of the following companies for the fiscal year            Part II
ended December 31, 2001:

          AEP Generating Company
          American Electric Power Company, Inc.
          Appalachian Power Company
          Central Power and Light Company
          Columbus Southern Power Company
          Indiana Michigan Power Company
          Kentucky Power Company
          Ohio Power Company
          Public Service Company of Oklahoma
          Southwestern Electric Power Company
          West Texas Utilities Company

Portions of Proxy Statement of American Electric Power Company, Inc. for             Part III
2002 Annual Meeting of Shareholders, to be filed within 120 days after
December 31, 2001

Portions of Information Statements of the following companies for 2002               Part III
Annual Meeting of Shareholders, to be filed within 120 days after December
31, 2001:

          Appalachian Power Company
          Ohio Power Company

</TABLE>

                         ------------------------------

     THIS COMBINED FORM 10-K IS SEPARATELY FILED BY AEP GENERATING COMPANY,
AMERICAN ELECTRIC POWER COMPANY, INC., APPALACHIAN POWER COMPANY, CENTRAL POWER
AND LIGHT COMPANY, COLUMBUS SOUTHERN POWER COMPANY, INDIANA MICHIGAN POWER
COMPANY, KENTUCKY POWER COMPANY, OHIO POWER COMPANY, PUBLIC SERVICE COMPANY OF
OKLAHOMA, SOUTHWESTERN ELECTRIC POWER COMPANY AND WEST TEXAS UTILITIES 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

<TABLE>
<CAPTION>

                                                                                           PAGE
                                                                                          NUMBER
                                                                                         --------
<S>                                                                                         <C>

Glossary of Terms......................................................................       i

Forward-Looking Information............................................................       1

PART I
      Item      1.  Business.............................................................     2
      Item      2.  Properties...........................................................    35
      Item      3.  Legal Proceedings....................................................    39
      Item      4.  Submission of Matters to a Vote of Security Holders..................    40
      Executive Officers of the Registrants..............................................    40

PART II
      Item      5.  Market for Registrant's Common Equity and Related
                         Stockholder Matters...........................................      42
      Item      6.  Selected Financial Data............................................      42
      Item      7.  Management's Discussion and Analysis of Results of
                        Operations and Financial Condition.............................      42
      Item     7A.  Quantitative and Qualitative Disclosures About Market Risk ...Risk       43
      Item      8.  Financial Statements and Supplementary Data........................      43
      Item      9.  Changes in and Disagreements with Accountants
                        on Accounting and Financial Disclosure.........................      43

PART III
      Item     10.  Directors and Executive Officers of the Registrants................      43
      Item     11.  Executive Compensation.............................................      44
      Item     12.  Security Ownership of Certain Beneficial Owners
                         and Management................................................      45
      Item     13.  Certain Relationships and Related Transactions.....................      46

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

Signatures.............................................................................      49

Index to Financial Statement Schedules.................................................     S-1

Independent Auditors' Report...........................................................     S-2

Exhibit Index..........................................................................     E-1

</TABLE>



<PAGE>



                                GLOSSARY OF TERMS

     The following abbreviations or acronyms used in this Form 10-K are defined
below:

<TABLE>
<CAPTION>

   ABBREVIATION OR ACRONYM                              DEFINITION
   -----------------------                              ----------
<S>                                     <C>
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.
Btu..................................... British thermal unit.
Buckeye................................. Buckeye Power, Inc., an unaffiliated corporation.
C3...................................... C3 Communications, Inc.
CAA..................................... Clean Air Act.
CAAA.................................... Clean Air Act Amendments of 1990.
CCD Group............................... CSPCo, CG&E and DP&L.
CERCLA.................................. Comprehensive Environmental Response, Compensation and Liability Act of 1980.
CG&E.................................... The Cincinnati Gas & Electric Company, an unaffiliated utility company.
CO2..................................... Carbon dioxide.
Cook Plant.............................. The Donald C. Cook Nuclear Plant, owned by I&M, located near Bridgman, Michigan.
CPL..................................... Central Power and Light Company, an electric utility subsidiary of AEP.
CSPCo................................... Columbus Southern Power Company, an electric utility subsidiary of AEP.
CSW....................................  Central and South West Corporation.
DOE..................................... United States Department of Energy.
DP&L.................................... The Dayton Power and Light Company, an unaffiliated utility company.
East Zone Companies of AEP.............. APCo, CSPCo, I&M, KEPCo and OPCo.
ERCOT................................... Electric Reliability Council of Texas.
EWG..................................... Exempt wholesale generator.
Federal EPA............................. United States Environmental Protection Agency.
FERC.................................... Federal Energy Regulatory Commission (an independent commission within the DOE).
FUCO.................................... Foreign utility company as defined by PUHCA.
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.
MTM..................................... Mark-to-market.
NOx..................................... Nitrogen oxide.
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.
PCBs.................................... Polychlorinated biphenyls.

</TABLE>



                                       i

<PAGE>
<TABLE>
<CAPTION>

   ABBREVIATION OR ACRONYM                              DEFINITION
   -----------------------                              ----------
<S>                                     <C>
PSO..................................... Public Service Company of Oklahoma, an electric utility subsidiary of AEP.
PUCO.................................... The Public Utilities Commission of Ohio.
PUHCA................................... Public Utility Holding Company Act of 1935, as amended.
QF...................................... Qualifying facility as defined in the Public Utility Regulatory Policies Act of 1978.
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.
SEEBOARD................................ SEEBOARD Group plc, Crawley, West Sussex, United Kingdom.
Service Corporation..................... American Electric Power Service Corporation, a service subsidiary of AEP.
SO2..................................... Sulfur dioxide.
SO2 Allowance........................... An allowance to emit one ton of sulfur dioxide granted under the Clean Air  Act
                                            Amendments of 1990.
SPP..................................... Southwest Power Pool.
STPNOC.................................. STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on
                                            behalf of its joint owners including CPL.
SWEPCo.................................. Southwestern Electric Power Company, an electric utility subsidiary of AEP.
TVA .................................... Tennessee Valley Authority.
Vale.................................... Empresa De Electricidade Vale Paranapanema SA, a Brazilian Electric Distribution
                                            Company.
VEPCo................................... Virginia Electric and Power Company, an unaffiliated utility company.
Virginia SCC............................ Virginia State Corporation Commission.
West Virginia PSC....................... Public Service Commission of West Virginia.
West Zone Companies of AEP.............. CPL, PSO, SWEPCo and WTU.
WTU..................................... West Texas Utilities Company, an electric utility subsidiary of AEP.
Zimmer or Zimmer Plant.................. Wm. H. Zimmer Generating Station, a 1,300,000-kilowatt coal-fired generating unit
                                            commonly owned by CSPCo (25.4%), CG&E (46.5%) and DP&L (28.1%), and operated by
                                            CG&E.

</TABLE>

                                       ii

<PAGE>




FORWARD-LOOKING INFORMATION
- --------------------------------------------------------------------------------

     This report made by AEP and certain of its subsidiaries includes
forward-looking statements within the meaning of Section 21E of the Securities
Exchange Act of 1934. These forward-looking statements reflect assumptions and
involve a number of risks and uncertainties. Among the factors that could cause
actual results to differ materially from forward-looking statements are:

     -    Electric load and customer growth.

     -    Abnormal weather conditions.

     -    Available sources of and prices for coal and gas.

     -    Availability of generating capacity.

     -    Litigation concerning AEP's merger with CSW.

     -    The timing of the implementation of AEP's restructuring plan.

     -    Risks related to energy trading and construction under contract.

     -    The speed and degree to which competition is introduced to our power
          generation business.

     -    The ability to recover net regulatory assets, other stranded costs and
          implementation costs in connection with deregulation of generation in
          certain states.

     -    New legislation and government regulations.

     -    The structure and timing of a competitive market for electricity and
          its impact on prices.

     -    The ability of AEP to successfully control its costs.

     -    The success of new business ventures.

     -    International developments affecting AEP's foreign investments.

     -    The effects of fluctuations in foreign currency exchange rates.

     -    The economic climate and growth in AEP's service and trading
          territories, both domestic and foreign.

     -    The ability of AEP to comply with or to challenge successfully new
          environmental regulations and to litigate successfully claims that AEP
          violated the CAA.

     -    Inflationary trends.

     -    Changes in electricity and gas market prices and interest rates.

     -    Other risks and unforeseen events.




                                       1
<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 domestic electric
utility subsidiaries and varying percentages of other subsidiaries.
Substantially all of the operating revenues of AEP and its subsidiaries are
derived from the marketing and trading of power and gas and the furnishing of
electric service.

     The service area of AEP's domestic electric utility subsidiaries covers
portions of the states of Arkansas, Indiana, Kentucky, Louisiana, Michigan,
Ohio, Oklahoma, Tennessee, Texas, 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,
which do business as "American Electric Power," have traditionally provided
electric service, consisting of generation, transmission and distribution, on an
integrated basis to their retail customers.

     At December 31, 2001, the subsidiaries of AEP had a total of 27,726
employees. AEP, as such, has no employees. The operating subsidiaries of AEP
are:

          APCo (organized in Virginia in 1926) is engaged in the generation,
     sale, purchase, transmission and distribution of electric power to
     approximately 917,000 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, 2001, APCo and its wholly owned
     subsidiaries had 2,629 employees. Among the principal industries served by
     APCo are coal mining, primary metals, chemicals and textile mill products.
     In addition to its AEP System interconnections, APCo also is interconnected
     with the following unaffiliated utility companies: Carolina Power & Light
     Company, Duke Energy Corporation 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.

          CPL (organized in Texas in 1945) is engaged in the generation, sale,
     purchase, transmission and distribution of electric power to approximately
     689,000 customers in southern Texas, and in supplying electric power at
     wholesale to other utilities, municipalities and rural electric
     cooperatives. At December 31, 2001, CPL had 1,374 employees. Among the
     principal industries served by CPL are oil and gas extraction, food
     processing, apparel, metal refining, chemical and petroleum refining,
     plastics, and machinery equipment.

          CSPCo (organized in Ohio in 1937, the earliest direct predecessor
     company having been organized in 1883) is engaged in the generation, sale,
     purchase, transmission and distribution of electric power to approximately
     678,000 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, 2001, CSPCo had 1,222 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. 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.




                                       2
<PAGE>

          I&M (organized in Indiana in 1925) is engaged in the generation, sale,
     purchase, transmission and distribution of electric power to approximately
     567,000 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, 2001, I&M had 2,851 employees. Among the principal industries
     served are primary metals, transportation equipment, electrical and
     electronic machinery, fabricated metal products, 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 Energy 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,
     sale, purchase, transmission and distribution of electric power to
     approximately 173,000 customers in an area in eastern Kentucky, and in
     supplying electric power at wholesale to other utilities and municipalities
     in Kentucky. At December 31, 2001, KEPCo had 427 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 45,000 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, 2001, Kingsport
     Power Company had 58 employees.

          OPCo (organized in Ohio in 1907 and re-incorporated in 1924) is
     engaged in the generation, sale, purchase, transmission and distribution of
     electric power to approximately 698,000 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, 2001, OPCo and its wholly owned subsidiaries had 2,297
     employees. Among the principal industries served by OPCo are primary
     metals, rubber and plastic products, stone, clay, glass and concrete
     products, petroleum refining and chemicals. 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.

          PSO (organized in Oklahoma in 1913) is engaged in the generation,
     sale, purchase, transmission and distribution of electric power to
     approximately 502,000 customers in eastern and southwestern Oklahoma, and
     in supplying electric power at wholesale to other utilities, municipalities
     and rural electric cooperatives. At December 31, 2001, PSO had 989
     employees. Among the principal industries served by PSO are natural gas and
     oil production, oil refining, steel processing, aircraft maintenance, paper
     manufacturing and timber products, glass, chemicals, cement, plastics,
     aerospace manufacturing, telecommunications, and rubber goods.

          SWEPCo (organized in Delaware in 1912) is engaged in the generation,
     sale, purchase, transmission and distribution of electric power to
     approximately 431,000 customers in northeastern Texas, northwestern
     Louisiana, and western Arkansas, and in supplying electric power at
     wholesale to other utilities, municipalities and rural electric
     cooperatives. At December 31, 2001, SWEPCo had 1,375 employees. Among the
     principal industries served by SWEPCo are natural gas and oil production,
     petroleum




                                       3
<PAGE>

     refining, manufacturing of pulp and paper, chemicals, food processing, and
     metal refining. The territory served by SWEPCo also includes several
     military installations, colleges, and universities.

          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, 2001, Wheeling Power Company
     had 64 employees.

          WTU (organized in Texas in 1927) is engaged in the generation, sale,
     purchase, transmission and distribution of electric power to approximately
     189,000 customers in west and central Texas, and in supplying electric
     power at wholesale to other utilities, municipalities and rural electric
     cooperatives. At December 31, 2001, WTU had 689 employees. The principal
     industry served by WTU is agriculture. The territory served by WTU also
     includes several military installations and correctional facilities.

     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 and KEPCo. 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.

     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.

AEP-CSW MERGER

     On June 15, 2000, CSW merged with and into a wholly owned merger subsidiary
of AEP with CSW being the surviving corporation. The merger was pursuant to an
Agreement and Plan of Merger, dated as of December 21, 1997, that AEP and CSW
had entered into. As a result of the merger, each outstanding share of common
stock, par value $3.50 per share, of CSW (other than shares owned by AEP or CSW)
was converted into 0.6 of a share of common stock, par value $6.50 per share, of
AEP. CSW's four wholly-owned domestic electric utility subsidiaries are CPL,
PSO, SWEPCo and WTU.

     AEP is complying or intends to comply with the following conditions imposed
by the FERC as part of the FERC's order approving the merger:

     -    Transfer operational control of AEP's east and west transmission
          systems to fully-functioning, FERC-approved regional transmission
          organizations. See Transmission Services for Non-Affiliates.

     -    Two interim transmission-related mitigation measures consisting of
          market monitoring and independent calculation and posting of available
          transmission capacity to monitor the operation of AEP's east
          transmission system. AEP implemented these measures upon the
          consummation of the merger.

     -    Divestiture of 550 MW of generating capacity comprised of 300 MW of
          capacity in SPP and 250 MW of capacity in ERCOT. AEP must complete
          divestiture of the SPP capacity by July 1, 2002. AEP has completed
          divestiture of the ERCOT capacity.

     The FERC found that certain energy sales of SPP and ERCOT capacity would be
reasonable and effective interim mitigation measures until completion of the
required SPP and ERCOT divestitures. As required by the FERC, the proposed
interim energy sales were in effect when the merger was consummated.




                                       4
<PAGE>

     Litigation: On January 18, 2002, the U.S. Court of Appeals for the District
of Columbia ruled that the SEC failed to prove that the merger met the
requirements of PUHCA and remanded the case to the SEC for further review. The
court held that the SEC must explain its conclusion that the merger met PUHCA
requirements that utilities be "physically interconnected" and justify its
finding that the merger will result in a combined entity that is confined to a
"single area or region."

     In its June 2000 approval of the merger, the SEC agreed with AEP that AEP's
and CSW's systems are interconnected because they have transmission access
rights to a single high-voltage line through Missouri and also meet the PUHCA's
single region requirement because it is now technically possible to centrally
control the output of power plants across many states. In its ruling, the court
held that the SEC failed to explain its conclusions that the transmission
integration and single region requirements are satisfied.

     Management believes that the merger meets the requirements of PUHCA and
expects the matter to be resolved favorably.

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 and CPL are subject to regulation by the NRC under the Atomic
Energy Act of 1954, as amended, with respect to the operation of the Cook Plant
and STP, respectively.

   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. Following the report, legislation
was introduced in Congress to repeal PUHCA and transfer certain federal
authority to the FERC as recommended in the SEC report. Since 1997, such PUHCA
repeal language has been reintroduced in each session of Congress both as a
separate bill and as part of broader legislation regarding changes in the
electric industry. Legislative hearings were held but neither the House of
Representatives nor the Senate passed any PUHCA repeal legislation. A number of
bills contemplating PUHCA repeal separately and with the restructuring of the
electric utility industry have been introduced in the current Congress. See
Competition and Business Change. 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.




                                       5
<PAGE>


   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.

   Rates

     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. Under current rate regulation, 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,
except for the states of Ohio, Texas and Virginia as noted below. Certain states
served by the AEP System allow alternative forms of rate regulation in addition
to the traditional cost-of-service approach. However, the rates of AEP's
operating subsidiaries in those states continue to be cost-based. 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.

     AEP is exposed to risk from changes in the market prices of coal and
natural gas used to generate electricity where generation is no longer regulated
or where existing fuel clauses are suspended or frozen. The protection afforded
by fuel clause recovery mechanisms has either been eliminated by the
implementation of customer choice in Ohio (effective January 1, 2001) and in the
ERCOT power grid area of Texas (effective January 1, 2002) or frozen by
settlement agreements in Indiana, Michigan, and West Virginia. To the extent the
fuel supply of the generating units in these states is not under fixed price
long-term contracts, AEP is subject to market price risk. AEP continues to be
protected against market price changes by active fuel clauses in Oklahoma,
Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.

     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. In addition, current rate regulation
may, and in the case of Ohio, Texas and Virginia has been, subject to
significant revision. See Competition and Business Change and the footnote to
the financial statements entitled Customer Choice and Industry Restructuring.





                                       6
<PAGE>



CLASSES OF SERVICE

     The principal classes of service from which the domestic electric utility
subsidiaries of AEP derive revenues and the amount of such revenues during the
year ended December 31, 2001 are as follows:


<TABLE>
<CAPTION>

                                                    AEP
                                                  SYSTEM(a)         AEGCo           APCo             CPL           CSPCo
                                                  ---------         -----           ----             ---           -----
                                                                              (IN THOUSANDS)

<S>                                              <C>                  <C>         <C>             <C>             <C>
Wholesale Business:
   Residential...............................    $ 3,553,216          $    0      $ 587,062       $ 660,884       $ 477,341
   Commercial................................      2,328,383               0        267,312         473,337         426,444
   Industrial................................      2,388,354               0        353,070         345,071         141,583
   Other Retail Customers....................        419,232               0         77,258          49,007          46,948
   Energy Delivery...........................    (3,356,000)                      (575,036)       (473,182)        (483,219)
                                               -------------  --------------  -------------       ---------       ---------
      Total Retail...........................      5,333,185               0        709,666       1,055,117         609,097
   Marketing and Trading-Electricity.........     35,339,641         227,338      5,571,750       1,671,686       3,117,136
   Marketing and Trading-Gas.................     14,368,857               0              0               0               0
   Unrealized MTM Income:....................
       Electric..............................        209,660               0         29,334          19,930          16,730
       Gas...................................         46,990               0              0               0               0
   Other.....................................        631,016             210        113,644         101,812          73,681
                                               -------------  --------------  -------------       ---------       ---------

         Total Wholesale Business............     55,929,349         227,548      6,424,394       2,848,545       3,816,644
                                               -------------  --------------  -------------       ---------       ---------

Energy Delivery Business:....................
   Transmission..............................      1,029,000               0        180,244         162,734         109,824
   Distribution..............................      2,327,000               0        394,792         310,448         373,395
                                               -------------  --------------  -------------       ---------       ---------
         Total Energy Delivery...............      3,356,000               0        575,036         473,182         483,219
                                               -------------  --------------  -------------       ---------       ---------

Other Investments:...........................
   SEEBOARD..................................      1,451,233               0              0               0               0
   CitiPower.................................        349,773               0              0               0               0
   Other.....................................        170,645               0              0               0               0
                                               -------------  --------------  -------------       ---------       ---------
         Total Other Investments.............      1,971,651               0              0               0               0
                                               -------------  --------------  -------------       ---------       ---------
               Total Revenues................   $ 61,257,000       $ 227,548    $ 6,999,430     $ 3,321,727     $ 4,299,863
                                               =============  ==============  =============       =========       =========

</TABLE>


<TABLE>
<CAPTION>


                                                     I&M        KEPCo         OPCo         PSO        SWEPCo        WTU
                                                     ---        -----         ----         ---        ------        ----
                                                                              (IN THOUSANDS)
<S>                                              <C>         <C>           <C>          <C>          <C>          <C>
Wholesale Business:
   Residential...............................    $ 350,600   $ 109,882     $ 444,418    $ 381,515    $ 321,022    $ 160,520
   Commercial................................      218,818      47,369       235,220      305,525      226,946       98,153
   Industrial................................      323,157      92,215       526,431      215,038      273,096       60,032
   Other Retail Customers....................       59,983      16,058        68,968       12,746       33,271       44,318
   Energy Delivery...........................     (314,410)   (134,619)     (552,713)    (261,877)    (333,004)    (169,036)
                                                 ---------   ---------     ---------    ---------     --------      -------
      Total Retail...........................      638,148     130,905       722,324      652,947      521,331      193,987
   Marketing and Trading-Electricity.........    3,783,302   1,364,877     4,848,386    1,258,861    1,653,208      648,527
   Marketing and Trading-Gas.................            0           0             0            0            0            0
   Unrealized MTM Income:....................
        Electric.............................            0           0        23,139            0       10,830        4,390
        Gas..................................            0           0             0            0            0            0
   Other.....................................       67,765      28,994       115,840       27,564       56,075       48,331
                                                 ---------   ---------     ---------    ---------     --------      -------
         Total Wholesale Business............    4,489,215   1,524,776     5,709,689    1,939,372    2,241,444      895,235
                                                 ---------   ---------     ---------    ---------     --------      -------
Energy Delivery Business:....................
   Transmission..............................      122,345      53,697       167,399       63,045       81,324       75,443
   Distribution..............................      192,065      80,922       385,314      198,832      251,680       93,593
                                                 ---------   ---------     ---------    ---------     --------      -------
         Total Energy Delivery...............      314,410     134,619       552,713      261,877      333,004      169,036
                                                 ---------   ---------     ---------    ---------     --------      -------
Other Investments:
   SEEBOARD..................................            0           0             0            0            0            0
   CitiPower.................................            0           0             0            0            0            0
   Other                                                 0           0             0            0            0            0
                                                 ---------   ---------     ---------    ---------     --------      -------
         Total Other Investments.............            0           0             0            0            0            0
                                                 ---------   ---------     ---------    ---------     --------      -------
               Total Revenues................  $ 4,803,625  $1,659,395   $ 6,262,402  $ 2,201,249  $ 2,574,448  $ 1,064,271
                                                 =========   =========   ===========  ===========  ===========  ===========

</TABLE>

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






                                       7
<PAGE>


SALE OF POWER

     AEP's electric utility subsidiaries own or lease generating stations with
total generating capacity of approximately 38,300 megawatts. See Item 2.
Properties, for more information regarding the generating stations. They operate
their generating plants as a single interconnected and coordinated electric
utility system and, in the east zone, share the costs and benefits in the AEP
System Power Pool. As discussed below under AEP System Power Pool, after
corporate separation, the public utility subsidiaries that are no longer
regulated at the state level will participate in a separate power pool. Most of
the electric power generated at AEP's generating stations is sold, in
combination with transmission and distribution services, to retail customers of
AEP's utility subsidiaries in their service territories. See Regulation--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 their 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 SO2 Allowances associated with
transactions under the Interconnection Agreement. As part of AEP's restructuring
settlement agreement filed with the FERC, CSPCo and OPCo would no longer be
parties to the Interconnection Agreement and certain other modifications to its
terms would also be made. See Competition and Business Change--AEP Restructuring
Plan.

     Power marketing and trading transactions (trading activities) are conducted
by the AEP Power Pool and shared among the parties under the Interconnection
Agreement. Trading activities involve the purchase and sale of electricity under
physical forward contracts at fixed and variable prices and the trading of
electricity contracts including exchange traded futures and options and
over-the-counter options and swaps. The majority of these transactions represent
physical forward contracts in the AEP System's traditional marketing area and
are typically settled by entering into offsetting contracts. The regulated
physical forward contracts are recorded on a gross basis in the month when the
contract settles.

     In addition, the AEP Power Pool enters into transactions for the purchase
and sale of electricity options, futures and swaps, and for the forward purchase
and sale of electricity outside of the AEP System's traditional marketing area.

     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, 1999, 2000 and 2001:

                         1999(a)       2000(a)       2001(a)
                         ----          ----          ----
                                (IN THOUSANDS)

APCo..............    $ (89,100)    $(274,000)    $(256,700)
CSPCo.............     (184,500)     (250,400)     (251,200)
I&M...............      (61,700)       93,900       166,200
KEPCo.............       23,700       (21,500)      (27,600)
OPCo..............      311,600       452,000       369,300

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

     CPL, PSO, SWEPCo, WTU, and AEP Service Corporation are parties to a
Restated and Amended Operating Agreement originally dated as of January 1, 1997
(CSW Operating Agreement). The CSW Operating Agreement requires the operating
companies of the west zone to maintain specified annual planning reserve margins
and requires the subsidiaries that have capacity in excess of the required
margins to make such capacity available for sale to other AEP subsidiaries as
capacity commitments. The CSW Operating Agreement also delegates to AEP Service
Corporation the authority to coordinate the acquisition, disposition, planning,
design and construction of generating units and to supervise the operation and
maintenance of a central control center. As part of AEP's restructuring
settlement agreement filed with the FERC, CPL and WTU would no longer be parties
to the CSW Operating Agreement and certain other




                                       8
<PAGE>

modifications to its terms would also be made. See Competition and Business
Change--AEP Restructuring Plan.

   Wholesale Sales of Power to Non-Affiliates

     AEP's electric utility subsidiaries also sell electric power on a wholesale
basis to non-affiliated electric utilities and power marketers. Such sales are
either made (i) by individual companies pursuant to various long-term power
agreements or (ii) under the Interconnection Agreement (AEP Power Pool) or the
CSW Operating Agreement. Sales made under the Interconnection Agreement are
allocated among the East Zone subsidiaries based on member-load ratios. Sales
made under the CSW Operating Agreement are allocated among the West Zone
subsidiaries based on participation ratios.

     Reference is made to the footnote to the financial statements entitled
Commitments and Contingencies that is incorporated by reference in Item 8 for
information with respect to AEP's long-term agreements to sell power.

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 are
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 Regulation--Rates. As discussed below, 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, 1999,
2000 and 2001:

                     1999            2000            2001
                     ----            ----            ----
                                (IN THOUSANDS)

APCo.........      $ (8,300)      $ (3,400)       $ (3,100)
CSPCo........        39,000         38,300          40,200
I&M..........       (43,900)       (43,800)        (41,300)
KEPCo........        (4,300)        (6,000)         (4,600)
OPCo.........        17,500         14,900           8,800


     CPL, PSO, SWEPCo, WTU, and AEP Service Corporation are parties to a
Transmission Coordination Agreement originally dated as of January 1, 1997
(TCA). The TCA establishes a coordinating committee, which is charged with the
responsibility of overseeing the coordinated planning of the transmission
facilities of the west zone operating subsidiaries, including the performance of
transmission planning studies, the interaction of such subsidiaries with
independent system operators (ISO) and other regional bodies interested in
transmission planning and compliance with the terms of the Open Access
Transmission Tariff (OATT) filed with the FERC and the rules of the FERC
relating to such tariff.

     Under the TCA, the west zone operating subsidiaries have delegated to AEP
Service Corporation the responsibility of monitoring the reliability of their
transmission systems and administering the OATT on their behalf. The TCA also
provides for the allocation among the west zone operating subsidiaries of
revenues collected for transmission and ancillary services provided under the
OATT.

   Transmission Services for Non-Affiliates

     AEP's electric utility subsidiaries and other System companies also provide
transmission services for non-affiliated companies.



                                       9
<PAGE>

     On April 24, 1996, the FERC issued orders 888 and 889. These orders require
each public utility that owns or controls interstate transmission facilities to
file an open access network and point-to-point transmission tariff that offers
services comparable to the utility's own uses of its transmission system. The
orders also require utilities to functionally unbundle their services, by
requiring them to use their own tariffs in making off-system and third-party
sales. As part of the orders, the FERC issued a pro-forma tariff which reflects
the Commission's views on the minimum non-price terms and conditions for
non-discriminatory transmission service. In addition, the orders require all
transmitting utilities to establish an Open Access Same-time Information System
(OASIS) which electronically posts transmission information such as available
capacity and prices, and require utilities to comply with Standards of Conduct
which prohibit utilities' system operators from providing non-public
transmission information to the utility's merchant employees. The orders also
allow a utility to seek recovery of certain prudently-incurred stranded costs
that result from unbundled transmission service.

     In December 1999, FERC issued Order 2000, which provides for the voluntary
formation of regional transmission organizations (RTOs), entities created to
operate, plan and control utility transmission assets. Order 2000 also
prescribes certain characteristics and functions of acceptable RTO proposals.

     On July 9, 1996, the AEP System companies filed a tariff conforming with
the FERC's pro-forma transmission tariff.

     Since 1998 AEP has engaged in discussions with a group of Midwestern
utilities regarding the development of the Alliance RTO which may take the form
of an ISO or an independent transmission company (Transco), depending upon the
occurrence of certain conditions. The Transco, if formed, would operate
transmission assets that it would own, and also would operate other owners'
transmission assets on a contractual basis.

     In 2001 the Alliance companies filed with the FERC a proposed business plan
for the Alliance RTO. In December 2001, the FERC issued an order approving the
proposal of the Midwest ISO (an independent operator of transmission assets in
the Midwest) for an RTO and rejecting the Alliance RTO's business plan and
finding that the Alliance RTO lacks sufficient scope and regional configuration
to exist as a stand-alone RTO. The FERC directed the Alliance companies to
negotiate with the Midwest ISO and others to explore possible combinations.
Following such discussions, on March 5, 2002, the Alliance RTO filed with the
FERC a request for a declaratory order seeking resolution of these issues.

COORDINATION OF EAST AND WEST ZONE OPERATING SUBSIDIARIES

     AEP's System Integration Agreement provides for the integration and
coordination of AEP's east and west zone operating subsidiaries, joint dispatch
of generation within the AEP System, and the distribution, between the two
operating zones, of costs and benefits associated with the System's generating
plants. It is designed to function as an umbrella agreement in addition to the
AEP Interconnection Agreement and the CSW Operating Agreement, each of which
will continue to control the distribution of costs and benefits within each zone
for all regulated subsidiaries.

     AEP's System Transmission Integration Agreement provides for the
integration and coordination of the planning, operation and maintenance of the
transmission facilities of AEP's east and west zone operating subsidiaries. Like
the System Integration Agreement, the System Transmission Integration Agreement
functions as an umbrella agreement in addition to the AEP Transmission Agreement
and the Transmission Coordination Agreement. The System Transmission Integration
Agreement contains two service schedules that govern:

     -    The allocation of transmission costs and revenues.

     -    The allocation of third-party transmission costs and revenues and
          System dispatch costs.

The Transmission Integration Agreement anticipates that additional service
schedules may be added as circumstances warrant.




                                       10
<PAGE>




CERTAIN POWER AGREEMENTS

   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 aggregate power participation ratio of APCo,
CSPCo, I&M and OPCo is 42.1%. The proceeds from the sale of power by OVEC are
designed to be sufficient for OVEC to meet its operating expenses and fixed
costs and to provide a return on its equity capital. On September 29, 2000, DOE
issued a notice of cancellation of the DOE/OVEC power agreement, such
cancellation to be effective no later than April 30, 2003. In conjunction with
this notice, DOE released all future rights to OVEC's generating capacity,
effective September 1, 2001. DOE was therefore not entitled to any OVEC capacity
beyond August 31, 2001, and the sponsoring companies became entitled to receive
and pay for all OVEC capacity (approximately 2,200MW) in proportion to their
power participation ratios at that time.

   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 25 of the rural electric cooperatives which
operate in the State of Ohio at 337 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 August 8, 2001, was
recorded at 1,344,315 kilowatts.

     Reference is made to Wholesale Business Operations -- Structured
Arrangements Involving Capacity, Energy, and Ancillary Services for a discussion
of an agreement with an affiliate of Buckeye to construct and operate a
gas-fired electric generating peaking facility.

   Century Aluminum

     Century Aluminum of West Virginia, Inc. (formerly Ravenswood Aluminum
Corporation), operates a major aluminum reduction plant in the Ohio River Valley
at Ravenswood, West Virginia. The power requirement of such plant presently is
approximately 357,000 kilowatts. OPCo is providing electric service pursuant to
a contract approved by the PUCO for the period July 1, 1996 through July 31,
2003.

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 and KEPCo 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




                                       11
<PAGE>

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, 2004. As part of AEP's restructuring settlement agreement
pending with the FERC, the KEPCo unit power agreement would be extended to
December 31, 2009 for Unit 1 and December 7, 2022 for Unit 2. See Competition
and Business Change--AEP Restructuring Plan.

   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.

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 many 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. Proposals are being made and/or legislation has been enacted in
Arkansas, Michigan, Ohio, Oklahoma, Texas, Virginia and West Virginia that would
also require electric utilities to sell distribution services separately. These
measures generally allow competition in the generation and sale of electric
power, but not in its transmission and distribution. However, movement toward
retail deregulation in certain of these states is slowing as a consequence of,
among other things, adverse developments related to deregulation of the electric
industry in California.

     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




                                       12
<PAGE>

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 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 any
stranded investment losses.

     Reference is made to Management's Discussion and Analysis of Results of
Operations and Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters and the footnote to the financial statements
entitled Customer Choice and Industry Restructuring incorporated by reference in
Items 7 and 8, respectively, for further information with respect to competition
and business change.

   AEP Position on Competition

     AEP favors 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. AEP's working model for industry
restructuring envisions a progressive transition to full customer choice.
Implementation of these measures would require legislative changes and
regulatory approvals.

     The legislatures and/or the regulatory commissions in many states,
including some in AEP's service territory, are considering or have adopted
"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. As competition
develops in retail power generation, the public utility subsidiaries of AEP
believe that they should have a favorable competitive position because of their
relatively low costs.

   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.

     FERC orders 888 and 889, issued in April 1996, provide that utilities must
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 public utility subsidiaries of AEP have functionally separated
their wholesale power sales from their transmission functions, as required by
orders 888 and 889.



                                       13
<PAGE>

   Retail

     The public utility subsidiaries of AEP have the exclusive right to sell
electric power at retail within their service areas in the states of Arkansas,
Indiana, Kentucky, Louisiana, Oklahoma, Tennessee and West Virginia.
Furthermore, while customer choice commenced in Michigan on January 1, 2002, I&M
does not have any competing suppliers active in its Michigan service territory
at this time. However, AEP's public utility subsidiaries 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 benefited by
attracting new industrial customers to their service territories.

   AEP Restructuring Plan

     As a result of deregulating legislation that has been enacted or is being
considered in several of the states in which the AEP public utility subsidiaries
provide service, AEP has reassessed the corporate ownership of its public
utility subsidiaries' assets. Deregulating legislation in some of the states
requires the separation of generation assets from transmission and distribution
assets. On November 1, 2000, AEP filed with the SEC under PUHCA for approval of
a restructuring plan in part to meet the requirements of this legislation. This
application is pending.

     On July 24, 2001, AEP filed with the FERC for approval of the restructuring
plan and on December 21, 2001, a settlement agreement with six state regulatory
commissions and other major parties was filed with the FERC. The settlement
agreement is pending approval. FERC approval is necessary before the SEC will
issue its order.

     AEP's restructuring plan is designed to align its legal structure and
business activities with the requirements of deregulation. AEP's plan
contemplates the formation of two first tier subsidiaries that would hold the
following public utility assets:

     -    A subsidiary would hold the assets of public utility subsidiaries that
          remain subject to regulation as to rates by at least one state utility
          commission. AEP intends for this subsidiary ultimately to hold all
          transmission and distribution assets.

     -    A subsidiary would hold (i) public utility and non-utility
          subsidiaries that derive their revenues from competitive activity and
          (ii) foreign utility subsidiaries and other investments. AEP intends
          for this subsidiary to ultimately hold all generation assets not
          subject to regulation.

WHOLESALE BUSINESS OPERATIONS

     AEP's wholesale business operations focus on value-driven asset
optimization at each link of the energy chain through the following activities:

     -    A diversified portfolio of owned assets and structured third party
          arrangements, including:



                                       14
<PAGE>

          -    Power generation facilities and renewable energy sources.

          -    Natural gas pipeline, storage and processing facilities.

          -    Coal mines and related facilities.

          -    Barge, rail and other fuel transportation related assets.

     -    Trade and market energy commodities, including electric power, natural
          gas, natural gas liquids, oil, coal, and SO2 allowances in North
          America and Europe.

     -    Price-risk management services and liquidity through a variety of
          energy-related financial instruments, including exchange-traded
          futures and over-the-counter forward, option, and swap agreements.

     -    Long-term transactions to buy or sell capacity, energy, and ancillary
          services of electric generating facilities, either existing or to be
          constructed, at various locations in North America and Europe.

   Power Generation Facilities and Renewable Energy Sources

     In addition to approximately 38,300 MW listed under Item 2. Properties, AEP
has ownership interests in the generating facilities listed under AEP-Other
Generation of approximately 1,900 MW domestically and 6,700 MW internationally,
of which approximately 1,100 MW is from renewable energy sources.

   Natural Gas Pipeline, Storage and Processing Facilities

     In June 2001, AEP acquired Houston Pipe Line Company (HPL) and Lodisco LLC
for $727 million from Enron Corp. The acquired assets include: (i) a 4,200-mile
intrastate gas pipeline in Texas with capacity of approximately 2.4 billion
cubic feet per day; (ii) the exclusive right (for 30 years with an additional
20-year extension) to the underground Bammel Storage Facility (one of the
largest natural gas storage facilities in North America) with 118 billion cubic
feet of storage capacity and appurtenant pipelines including the Bammel Loop,
Houston City Loop and the Texas City Loop; and (iii) certain gas marketing
contracts.

     AEP acquired Louisiana Intrastate Gas Company, LLC ("LIG") in 1998. LIG's
midstream gas assets include: (i) a 2,000-mile intrastate gas pipeline in
Louisiana with capacity of approximately 800 million cubic feet per day; (ii)
five natural gas processing plants that straddle the pipeline; and (iii) a ten
billion cubic foot underground natural gas storage facility directly connected
to the Henry Hub, one of the most active gas trading areas in North America.

   Coal Mines and Related Facilities

     In October 2001, to enhance its coal trading and marketing activities, AEP
acquired substantially all the assets of Quaker Coal Company as part of a
bankruptcy proceeding restructuring. AEP paid $101 million to Quaker's creditors
and assumed additional liabilities of approximately $58 million. The acquisition
included property, coal reserves, mining operations and royalty interests in
Colorado, Kentucky, Ohio, Pennsylvania and West Virginia. AEP will continue to
operate the mines and facilities which have approximately 800 employees.

   Barge, Rail and Other Fuel Transportation Related Assets

     In November 2001, AEP acquired MEMCO Barge Line Inc. for $270 million as
part of its overall asset optimization program. MEMCO is engaged in the
transportation of coal and dry bulk commodities, primarily on the Ohio,
Illinois, and Lower Mississippi rivers. MEMCO owns or leases 1,200 hopper barges
and 30 towboats. The addition of MEMCO's barge assets to AEP's existing fleet
places AEP among the leading barge operators in the country. See Fuel
Supply--Coal and Lignite for other barges and towboats leased by I&M and OPCo.

   Trading and Marketing of Energy Commodities

     Sales: Based upon volumetric sales in the U.S., Power Markets Weekly ranked
AEP's wholesale trading business No. 2 in electric sales for the first, second
and third quarters of 2001. Platts Gas Daily ranked AEP Nos. 14, 10 and 2 in gas
sales for the




                                       15
<PAGE>
first, second and third quarters, respectively, of 2001.

     ICEX: To gain access to additional liquidity trading points, AEP acquired
an interest in the internet-based electronic trading system, Intercontinental
Exchange, L.L.C. (ICEX), in 2000 that enables participants to initiate,
negotiate, and execute trades in the crude oil, natural gas, and spot and
forward energy markets. Other investors include global energy companies and
leading investment banking firms.

   Structured Arrangements Involving Capacity, Energy, and Ancillary Services

     AEP has entered into an agreement with The Dow Chemical Company to
construct a 900 MW cogeneration facility at Dow's chemical facility in
Plaquemine, Louisiana. Commercial operation is expected in 2003. AEP is entitled
to 100% of the facility's capacity and energy and has contracted to sell the
power from this facility to an unaffiliated party.

     In January 2000, OPCo and National Power Cooperative, Inc. (NPC), an
affiliate of Buckeye, entered into an agreement relating to construction and
operation of a 510 MW gas-fired electric generating peaking facility to be owned
by NPC. From the commercial operation date (expected in 2002) until the end of
2005, OPCo will be entitled to 100% of the power generated by the facility, and
responsible for the fuel and other costs of the facility. After 2005, NPC and
OPCo will be entitled to 80% and 20%, respectively, of the power of the
facility, and both parties will generally be responsible for the fuel and other
costs of the facility. OPCo will also provide certain back-up power to NPC.

INTERNATIONAL ELECTRIC

     Other international holdings of AEP include the following.

     Australia: CitiPower Pty. is an electric distribution and retail sales
company in Victoria, Australia. CitiPower serves approximately 240,000 customers
in the city of Melbourne. With about 3,100 miles of distribution lines in a
service area that covers approximately 100 square miles, CitiPower distributes
about 4,800 gigawatt-hours annually. AEP acquired CitiPower in 1998 for U.S.$1.1
billion.

     UK: SEEBOARD, headquartered in Crawley, West Sussex and acquired as part of
AEP's merger with CSW, is one of the 12 regional electricity companies formed as
a result of the restructuring and subsequent privatization of the United Kingdom
electricity industry in 1990. CSW acquired indirect control of SEEBOARD in April
1996. SEEBOARD's principal businesses are the distribution and supply of
electricity. In addition, SEEBOARD is engaged in other businesses, including gas
supply, electricity generation, and electrical contracting. SEEBOARD has
approximately 2,000,000 customers and its service area covers approximately
3,000 square miles in Southeast England with the majority of its customers in
Kent, Sussex and parts of Surrey.

     Possible Divestitures: On February 3, 2002, AEP announced the appointment
of investment banks to advise AEP on the prospects for divestment of CitiPower
and/or SEEBOARD. Because of pooling of interests accounting restrictions,
imposed as part of AEP's merger with CSW and which expire in June 2002, any
possible divestment of CitiPower and/or SEEBOARD is not anticipated until after
these restrictions lapse.

PRO SERV

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

AEP COMMUNICATIONS

     AEP Communications markets wholesale, high capacity, fiber optic services,
colocation, and wireless tower infrastructure services under the C3 brand with
operations in Arkansas, Kansas, Louisiana, Oklahoma and Texas.

     AEP Communications joined with several other energy and telecommunications
companies to form AFN Communications, LLC. (AFN). AFN is a




                                       16
<PAGE>

super regional telecommunications company that provides long haul fiber optic
capacity to competitive local exchange carriers, wireless carriers and long
distance companies. AFN does business in New York, Pennsylvania, Virginia, West
Virginia, Ohio, Indiana, Michigan, Illinois, and Kentucky and has approximately
10,000 route miles of fiber optic network.

     C3, an entity that was acquired through the merger with CSW, is engaged in
providing fiber optic and collocation services in Texas, Louisiana, Oklahoma,
Arkansas, and Kansas. C3 does business as C3 Networks and has approximately
5,300 route miles of fiber optic network.

     Management is evaluating certain of AEP's telecommunications investments
for possible disposal.

CONSTRUCTION PROGRAM

   General

     The AEP System is continuously involved in assessing the adequacy of its
generation, transmission, distribution and other facilities to plan and provide
for the reliable supply of electric power and energy to its customers. In this
assessment process, assumptions are continually being reviewed as new
information becomes available, and assessments and plans are modified, as
appropriate. Thus, System reinforcement plans are subject to change,
particularly with the restructuring of the electric utility industry and the
move to increasing competition in the marketplace. See Competition and Business
Change.

   Generation

     Committed or anticipated capability changes to the AEP System's generation
resources includes the expiration of the Rockport Unit 2 sale of 250 megawatts
to Carolina Power & Light Company, an unaffiliated company, on December 31,
2009. See AEP-CSW Merger for a discussion of the divestiture of generating
capacity as part of the merger.

     Apart from these changes and temporary power purchases that can be
arranged, there are no specific commitments for additions of new generation
resources on the AEP System. Given the restructuring taking place in the
industry, the extent of the need of AEP's operating companies for any additional
generation resources in the foreseeable future is highly uncertain.

   Proposed Transmission Facilities

     On September 30, 1997, APCo refiled applications in Virginia and West
Virginia for certificates to build a Wyoming-Cloverdale 765,000-volt Project.
The preferred route for this line was approximately 132 miles in length,
connecting APCo's Wyoming Station in southern West Virginia to APCo's Cloverdale
Station near Roanoke, Virginia.

     APCo originally announced this project in 1990. Since then it has been in
the process of trying to obtain federal permits and state certificates. At the
federal level, the U.S. Forest Service (Forest Service) is directing the
preparation of an Environmental Impact Statement (EIS), which is required prior
to granting permits for crossing lands under federal jurisdiction. Permits are
needed from the (i) Forest Service to cross federal forests, (ii) Army Corps of
Engineers to cross the New River and a watershed near the Wyoming Station, and
(iii) National Park Service or Forest Service to cross the Appalachian National
Scenic Trail.

     In June 1996, the Forest Service released a Draft EIS and preliminarily
identified a "No Action Alternative" as its preferred alternative for the
original Wyoming-Cloverdale Project. If this alternative were incorporated into
a Final EIS, APCo would not be authorized to cross federal forests administered
by the Forest Service. The Forest Service stated that it would not prepare the
Final EIS until after Virginia and West Virginia determined need and routing
issues on non-federal lands.

     West Virginia: On May 27, 1998, the West Virginia PSC issued an order
granting APCo's application for a certificate to construct the
Wyoming-Cloverdale 765,000-volt Project. On March 13, 2002, the West Virginia
PSC issued an order granting APCo's request to construct the line with a
terminus at Jacksons Ferry substation in Virginia instead of the Cloverdale
substation as discussed below under Virginia.



                                       17

<PAGE>
     Virginia: Following several procedural delays and Hearing Examiner's
rulings, APCo filed a study in May 1999 identifying the Wyoming-Jacksons Ferry
Project as an alternative project to the Wyoming-Cloverdale Project. The
Jacksons Ferry Project proposes a line from Wyoming Station in West Virginia to
APCo's existing 765,000-volt Jacksons Ferry Station in Virginia. APCo estimates
that the Wyoming-Jacksons Ferry line would be 90 miles in length, including 32
miles in West Virginia previously certified. In May 2000, the Virginia SCC held
an evidentiary hearing to consider both projects. On October 2, 2000, the
Hearing Examiner's report to the Virginia SCC recommended approval of the
Wyoming-Jacksons Ferry Alternative Project. On May 31, 2001, the Virginia SCC
issued an order granting APCo's application for a certificate to construct the
Wyoming-Jacksons Ferry 765,000-volt Project.

     Proposed Completion Schedule and Estimated Cost: Subsequent to Virginia and
West Virginia granting certificates to construct the Project, the Forest Service
restarted the EIS process and is scheduled to complete and release a supplement
to the Draft EIS in April 2002. The Final EIS process should continue for the
balance of 2002, with a decision on the federal permits anticipated in Spring
2003. APCo has also begun required consultation with the U.S. Fish and Wildlife
Service under the Endangered Species Act, which should be completed concurrently
with the EIS process.

     Given the status of the Project permitting process, and assuming that the
projected schedule of the EIS process will be met, management estimates that the
Wyoming-Jacksons Ferry 765,000-volt Project cannot be completed before Summer
2006.

     Depending upon the outcome of the EIS permitting process by the Forest
Service, APCo's estimated cost for the Wyoming-Jacksons Ferry Project ranges
from $250 to $280 million, assuming a Summer 2006 in-service date.

   Construction Expenditures

     The following table shows construction expenditures during 1999, 2000 and
2001 and current estimates of 2002 construction expenditures, in each case
including AFUDC but excluding assets acquired under leases.

<TABLE>
<CAPTION>
                      1999         2000          2001       2002
                     ACTUAL       ACTUAL        ACTUAL    ESTIMATE
                     ------       ------        ------    --------
                                     (IN THOUSANDS)
<S>               <C>           <C>         <C>         <C>
AEP System (a)..  $1,679,600    $1,773,400  $1,832,000  $1,820,400
   AEGCo........       8,300         5,200       6,900      45,600
   APCo.........     211,400       199,300     306,000     258,200
   CPL..........     255,800       199,500     194,100     172,300
   CSPCo........     115,300       128,000     132,500     145,400
   I&M..........     165,300       171,100      91,100     205,400
   KEPCo........      44,300        36,200      37,200     128,800
   OPCo.........     193,900       254,000     344,600     349,700
   PSO..........     104,500       176,900     124,900      80,600
   SWEPCo.......     112,900       120,200     112,100     111,900
   WTU..........      52,600        64,500      39,800      51,800
</TABLE>
- -----------------------
(a)  Includes expenditures of other subsidiaries not shown.

     Reference is made to the footnote 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 estimated 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 1999, 2000 and 2001 and the current estimate for 2002 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





                                       18
<PAGE>

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.

                     1999      2000        2001       2002
                    ACTUAL    ACTUAL      ACTUAL    ESTIMATE
                    ------    ------      ------    --------
                                 (IN THOUSANDS)

AEGCo.............  $      8     $  70    $ 3,500     27,700
APCo..............    24,500     2,100     99,200     86,500
CPL...............     (a)       (a)        2,500        200
CSPCo.............    10,600     6,600     22,500     25,500
I&M...............     4,500     1,900        700     28,500
KEPCo.............     1,900       400     11,200     60,200
OPCo..............    37,400    91,200    125,300    103,900
PSO...............     (a)       (a)          400        400
SWEPCo............     (a)       (a)        9,200      9,600
WTU...............     (a)       (a)          800      3,000
                     -------    ------    -------    -------
   AEP System (a).. $ 78,908  $102,270   $275,300   $345,500
                    ========  ========   ========   ========

- -----------------------
(a)  Amounts not available for west zone companies of AEP prior to AEP-CSW
     merger.

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 cash capital contributions by AEP.
If one or more of the 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 curtailment of construction and other outlays or the use of
alternative financing arrangements, if available, which may be more costly.

     AEP's subsidiaries have also utilized, and expect to continue to utilize,
additional financing arrangements, such as unsecured debt and leasing
arrangements, including the leasing of utility assets and coal mining and
transportation equipment and facilities. 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.

     New projects undertaken by AEP's unregulated subsidiaries are generally
financed through equity funds provided by AEP, non-recourse debt incurred on a
project-specific basis, debt issued by such subsidiaries or through a
combination thereof. See Wholesale Business Operations and Item 7 for additional
information concerning AEP's unregulated subsidiaries.

     AEP's revolving credit agreements include covenants and events of default
typical for this type of facility, including a maximum debt/capital test and a
$50 million cross-acceleration provision. At December 31, 2001, AEP was in
compliance with its debt covenants. With the exception of a voluntary bankruptcy
or insolvency, any event of default has either or both a cure period or notice
requirement before termination of the agreements. A voluntary bankruptcy or
insolvency would be considered an immediate termination event.

     Reference is made to Management's Discussion and Analysis of Results of
Operations and Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters incorporated by reference in Item 7 for
information with respect to AEP's plans to restructure its debt to implement
corporate separation. See Competition and Business Change--AEP Restructuring
Plan herein.

FUEL SUPPLY

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

                          1997   1998   1999    2000   2001
                          ----   ----   ----    ----   ----
Coal....................    76%    79%    79%     78%    74%
Gas.....................    12%    14%    15%     13%    12%
Nuclear.................     8%     3%     3%      5%    11%
Hydroelectric and other.     4%     4%     3%      4%     3%


     Variations in the generation of nuclear power are primarily related to
refueling outages and, in 1997 through 2000, the shutdown of the Cook Plant to
respond to issues raised by the NRC.




                                       19
<PAGE>



   Natural Gas

     AEP consumed over 240 billion cubic feet of natural gas during 2001 for the
system operating companies. A majority of the gas fired electric generation
plants are connected to at least two natural gas pipelines, which provides
greater access to competitive supplies and improves reliability. Natural gas
requirements for each plant are supplied by a portfolio of long-term and
short-term purchase and transportation agreements that are acquired on a
competitive basis and based on market prices.

   Coal and Lignite

     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 began 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 -- Air Pollution Control --
Title IV Acid Rain Program 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 by
entering into additional supply agreements, either on a long-term or spot basis,
at prices and upon terms which cannot now be predicted.

     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.

     Western coal purchased by System companies is transported to AEP generating
stations by rail and via an affiliated river terminal for subsequent
transloading to barges for final delivery. CPL, PSO and SWEPCo own (in the
aggregate) 2,982 coal hopper cars and APCo, I&M and OPCo lease (in the
aggregate) an additional 4,066 coal hopper cars to be used in unit train
movements. I&M and OPCo lease (in the aggregate) 15 towboats, 454 jumbo barges
and 143 standard barges. Certain subsidiaries of AEP also own or lease coal
transfer facilities at various other locations.

     See Wholesale Business Operations--Barge, Rail and Other Fuel
Transportation Related Assets herein for information with respect to the
acquisition of MEMCO Barge Line Inc. in 2001.

     The System generating companies procure coal through purchases pursuant to
long-term contracts or spot purchases from affiliated and 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





                                       20
<PAGE>

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>



                                                           1997(a)     1998(a)     1999(a)       2000        2001
                                                           ----        ----        ----          ----        ----
<S>                                                    <C>           <C>         <C>         <C>         <C>
Total coal delivered to
   AEP operated plants   (thousands of tons)...........  54,292       54,004      54,306      73,259      73,889
Sources (percentage):
   Subsidiaries........................................      14%         14%         12%          9%          4%
   Long-term contracts.................................      66%         66%         64%         67%         68%
   Spot or short-term purchases........................      20%         20%         24%         24%         28%
Average price per ton of spot-purchased coal...........  $24.38       $25.05      $27.18      $24.03      $27.30
</TABLE>

- --------------------
(a)  Includes east zone companies only.


     The average cost of coal consumed during the past five years by all AEP
System companies is shown below. AEP System companies' data for 1997 includes
only AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo.


<TABLE>
<CAPTION>

                                                                   1997        1998         1999        2000        2001
                                                                   ----        ----         ----        ----        ----
                                                                                      DOLLARS PER TON
<S>                                                                <C>          <C>         <C>          <C>        <C>
AEP System Companies.............................................  $ 29.68      $ 29.87     $ 30.01      $ 31.39    $ 28.55
   AEGCo.........................................................    19.30        19.37       20.79        20.65      21.01
   APCo..........................................................    36.09        34.81       33.29        32.84      32.41
   CPL...........................................................    26.93        26.93       26.49        25.95      26.78
   CSPCo.........................................................    31.69        31.63       29.94        28.50      30.63
   I&M...........................................................    23.68        22.61       24.54        23.44      23.57
   KEPCo.........................................................    26.76        27.42       26.76        25.35      25.02
   OPCo..........................................................    36.00        38.94       40.56        46.52      35.06
   PSO...........................................................    21.11        20.37       20.94        21.21      20.45
   SWEPCo........................................................    23.16        23.02       21.34        22.59      24.22
   WTU...........................................................    18.19        21.37       21.72        22.26      23.81

</TABLE>

<TABLE>
<CAPTION>

                                                                   1997        1998         1999        2000        2001
                                                                   ----        ----         ----        ----        ----
                                                                                  CENTS PER MILLION BTU'S
<S>                                                                <C>          <C>         <C>          <C>        <C>
AEP System Companies.............................................   140.13       142.17      141.95       149.12     136.85
   AEGCo.........................................................   115.21       112.63      116.90       116.23     118.89
   APCo..........................................................   146.54       141.76      135.40       134.86     135.88
   CPL...........................................................   136.40       137.00      135.78       137.86     140.22
   CSPCo.........................................................   134.44       134.15      127.42       120.83     131.64
   I&M...........................................................   123.36       118.02      121.90       117.99     121.27
   KEPCo.........................................................   110.37       112.15      109.91       104.88     104.97
   OPCo..........................................................   151.66       164.44      169.23       194.77     146.87
   PSO...........................................................   120.91       116.73      119.54       121.83     116.33
   SWEPCo........................................................   152.79       150.62      143.34       144.96     153.88
   WTU...........................................................   109.13       126.22      129.13       131.56     143.21

</TABLE>




                                       21
<PAGE>

     The coal supplies at AEP System 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, 2001, the
System's coal inventory was approximately 41 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 2001 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 2001 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>
<CAPTION>

                                                                                                  AVERAGE SULFUR CONTENT
                                                                       ESTIMATED REQUIRE-           OF DELIVERED COAL
                                              TOTAL CONSUMPTION       MENTS FOR REMAINDER     ----------------------------
                                                 DURING 2001            OF USEFUL LIVES                     POUNDS OF SO2
                                           (IN THOUSANDS OF TONS)    (IN MILLIONS OF TONS)    BY WEIGHT   PER MILLION BTU'S
                                            --------------------      -------------------     ---------   -----------------

<S>                                                  <C>                       <C>               <C>             <C>
AEGCo (a)...............................             4,829                     215               0.3%            0.7
APCo....................................            10,529                     375               0.7%            1.2
CPL.....................................             2,470                      36               0.3%            0.7
CSPCo...................................             5,637                     213(b)            2.4%            4.1
I&M (c).................................             7,026                     244               0.6%            1.2
KEPCo...................................             2,981                      80               0.9%            1.5
OPCo....................................            19,392                     546(d)            2.1%            3.5
PSO.....................................             4,049                      41               0.4%            0.9
SWEPCo..................................            12,254                     117               0.6%            1.6
WTU.....................................             1,370                      32               0.4%            0.8

</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.
(d)  Total does not include OPCo's portion of Sporn 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 0.7% during 2001, 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.

     CPL: CPL has coal supply agreements of one year or less duration with two
coal suppliers and various coal trading firms for the delivery of approximately
2,400,000 tons of coal for the year 2002. Approximately one half of the coal
delivered to Coleto Creek is from Wyoming with the other half from Colorado.
Both sources supply low sulfur coal with a limit of 1.2 lbs/MMBtu.

     CSPCo: CSPCo has coal supply agreements with unaffiliated suppliers for the
delivery of approximately 3,780,000 tons in 2002. 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




                                       22
<PAGE>

units, each operating company is contractually responsible for obtaining the
needed fuel.

     I&M: I&M has historically received coal under two coal supply agreements
with unaffiliated Wyoming suppliers for low sulfur coal from surface mines
principally for consumption at the Rockport Plant. As a result of litigation
involving future deliveries from one of these suppliers, there will not be any
coal delivered under this contract in 2002. Under the other agreement, the
supplier 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. This
contract, which expires on December 31, 2004, has remaining deliveries of
approximately 22,800,000 tons.

     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 648,000 tons of coal in 2002.
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 has historically been
supplied from both affiliated and unaffiliated suppliers. As a result of the
2001 sale of AEP's coal mines in Ohio and West Virginia and an agreement to
purchase approximately 34,000,000 tons of coal through 2008 from the purchaser
of the mines, coal consumed at OPCo's plants in 2002 will be supplied from
unaffiliated suppliers under long-term contracts and/or on a spot purchase
basis.

     PSO: PSO takes all its coal from one coal supplier under a contract that
provides for the entire plant requirements with at least 16,830,000 tons
remaining to be delivered between 2002 and 2007. The coal is supplied from
Wyoming and has a maximum sulfur content of 1.2 lbs. SO2 per MMBtu.

     SWEPCo: SWEPCo receives coal at its plants under a combination of
agreements, including one long-term coal contract with a Wyoming producer, one
affiliate mine-mouth lignite operation and agreements with various producers and
coal trading firms. SWEPCo's long-term coal supply contract provides
approximately half of the requirements for both coal plants. SWEPCo must take
delivery of 25,625,000 tons of coal through 2006, with the remainder of its coal
requirements met through short-term spot agreements for low sulfur (less than
1.2 lbs. SO2 per MMBtu) coal with various Wyoming coal suppliers and trading
companies.

     WTU: WTU has one long-term coal supply contract that provides approximately
two-thirds of the coal requirements for the Oklaunion Power Station. This
contract has approximately 9,180,000 tons of coal remaining to be delivered
between 2002 and mid-2006. The remaining coal requirements for Oklaunion are
being purchased under short-term agreements with various Wyoming coal suppliers
and coal trading firms, with such coal being low sulfur (less than 1.2 lbs. SO2
per MMBtu).

   Nuclear

     I&M and STPNOC have made commitments to meet certain of the nuclear fuel
requirements of the Cook Plant and STP, respectively. The nuclear fuel cycle
consists of:

     -    Mining and milling of uranium ore to uranium concentrates.

     -    Conversion of uranium concentrates to uranium hexafluoride.

     -    Enrichment of uranium hexafluoride.

     -    Fabrication of fuel assemblies.

     -    Utilization of nuclear fuel in the reactor.

     -    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. I&M has made and will make




                                       23
<PAGE>

purchases of uranium in various forms in the spot, short-term, and mid-term
markets until it decides that deliveries under long-term supply contracts are
warranted.

     CPL and the other STP participants have entered into contracts with
suppliers for 100% of the uranium concentrate sufficient for the operation of
both STP units through Spring 2006 and with an additional 50% of the uranium
concentrate needed for STP through Spring 2007. In addition, CPL and the other
STP participants have entered into contracts with suppliers for 100% of the
nuclear fuel conversion service sufficient for the operation of both STP units
through Spring 2003, with additional flexible contracts to provide at least 50%
of the conversion service needed for STP through 2008. CPL and the other STP
participants have entered into flexible contracts to provide for 100% of
enrichment through Fall 2004, with additional flexible contracts to provide at
least 50% of enrichment services through Fall 2008. Also, fuel fabrication
services have been contracted for operation through 2028 for Unit 1 and 2029 for
Unit 2.

     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. AEP anticipates that the Cook Plant has storage capacity to permit
normal operations through 2012.

     STP has on-site storage facilities with the capability to store the spent
nuclear fuel generated by the STP units over their licensed lives.

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

   Nuclear Waste and Decommissioning

     Reference is made to Management's Discussion and Analysis of Results of
Operations and Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters in the financial statements and Commitments and
Contingencies in the footnotes to these statements that are incorporated by
reference in Items 7 and 8, respectively, for information with respect to
nuclear waste and decommissioning and related litigation.

     The ultimate cost of retiring the Cook Plant and STP may be materially
different from estimates and funding targets as a result of the:

     -    Type of decommissioning plan selected.

     -    Escalation of various cost elements (including, but not limited to,
          general inflation).

     -    Further development of regulatory requirements governing
          decommissioning.

     -    Limited availability to date of significant experience in
          decommissioning such facilities.

     -    Technology available at the time of decommissioning differing
          significantly from that assumed in these studies.

     -    Availability of nuclear waste disposal facilities.

Accordingly, management is unable to provide assurance that the ultimate cost of
decommissioning the Cook Plant and STP will not be significantly greater than
current projections.

     Low-Level Waste: 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
refuse 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. Michigan, the state where the Cook
Plant is located, was a member of the Midwest Compact, but its membership was
revoked in 1991. As a result, Michigan is responsible for developing a disposal
site for the low-level waste generated in Michigan.

     Although Michigan amended its law regarding low-level waste site
development in 1994 to allow a




                                       24
<PAGE>

volunteer to host a facility, little progress has been made to date. A bill was
introduced in 1996 to further address the issue but no action was taken.
Development of required legislation and progress with the site selection process
has been inhibited by many factors, and management is unable to predict when a
new disposal site for Michigan low-level waste will be available.

     Texas is a member of the Texas Compact, which includes the states of Maine
and Vermont. Texas had identified a disposal site in Hudspeth County for
construction of a low-level waste disposal facility. During the licensing
process for the Hudspeth site, that site was found to be unsuitable. No
additional site has been considered. Management is unable to predict when a
disposal site for Texas 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 and Texas. This was the
first opportunity for the Cook Plant to dispose of low-level waste since 1990.
To the extent practicable, the waste formerly placed in storage and the waste
presently generated by the Cook Plant and STP are now being sent to the disposal
site.

     Under state law, the amounts of low-level radioactive waste being disposed
of at the South Carolina facility from non-regional generators, such as the Cook
Plant and STP, are limited and being reduced. Non-regional access to the South
Carolina facility is currently allowed through the end of fiscal year 2008.

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. In
addition to imposing continuing compliance obligations, these laws and
regulations authorize the imposition of substantial penalties for noncompliance,
including fines, injunctive relief and other sanctions.

     It is expected that:

     -    Costs related to environmental requirements will eventually be
          reflected in the rates of AEP's electric utility subsidiaries, or
          where states are deregulating generation, unbundled transition period
          generation rates, stranded cost wires charges and future market prices
          for electricity.

     -    AEP's electric utility subsidiaries will be able to provide for
          required environmental controls.

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. Moreover, legislation adopted by certain states and proposed at the
state and federal level governing restructuring of the electric utility industry
may also affect the recovery of certain costs. See Competition and Business
Change.

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

     AEP's international operations are subject to regulation with respect to
air, waste and water quality standards and other environmental matters by
various authorities within the host countries. Under certain circumstances,
these authorities may require modifications to these facilities and operations
or impose fines and other costs for violations of applicable statutes and
regulations. From time to time, these operations are made aware of various
environmental issues or are named as parties to various legal claims, actions,
complaints or other proceedings related to environmental matters. Management
does not expect disposition of any such pending environmental proceedings to
have a material adverse effect on AEP's consolidated results of operations or
financial condition.

     Reference is made to Management's Discussion and Analysis of Results of
Operations and Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters and the footnote to the financial statements
entitled




                                       25
<PAGE>

Commitments and Contingencies incorporated by reference in Items 7 and 8,
respectively, for further information with respect to environmental matters,
including discussion of legislative proposals under consideration by the
Administration and Congress focused on reductions in emissions of CO2, NOx, SO2,
mercury and other constituents.

   Air Pollution Control

     For the AEP System operating companies, compliance with the CAA is
requiring substantial expenditures that generally are being recovered through
the rates of AEP's operating subsidiaries. Certain matters discussed below may
require significant additional operating and capital expenditures. However,
there can be no assurance that all such costs will be recovered. See
Construction Program -- Construction Expenditures.

     Title I National Ambient Air Quality Standards Attainment: In July 1997,
Federal EPA revised the ozone and particulate matter National Ambient Air
Quality Standards (NAAQS), creating a new eight-hour ozone standard and
establishing a new standard for particulate matter less than 2.5 microns in
diameter (PM2.5). In addition to the potential financial consequences discussed
above, both of these new standards have the potential to affect adversely the
operation of AEP System generating units. In May 1999, the U.S. Court of Appeals
for the District of Columbia Circuit remanded the ozone and PM2.5 NAAQS to
Federal EPA. In February 2001, the U.S. Supreme Court issued an opinion
reversing in part and affirming in part the Court of Appeals decision. The
Supreme Court remanded the case to the Court of Appeals for further proceedings,
including a review of whether adoption of the standards was arbitrary and
capricious and directed Federal EPA to develop a policy for implementing the
revised ozone standard in conformity with the CAA. The Court of Appeals held
oral argument on the remanded issues in December 2001.

     NOx SIP Call: In October 1998, Federal EPA issued a final rule (NOx
transport SIP call or NOx SIP Call) establishing state-by-state NOx emission
budgets for the five-month ozone season to be met beginning May 1, 2003. The NOx
budgets originally applied to 22 eastern states and the District of Columbia and
are premised mainly on the assumption of controlling power plant NOx emissions
projected for the year 2007 to 0.15 lb. per million Btu (approximately 85% below
1990 levels), although the reductions could be substantially greater for certain
State Implementation Plans. The SIP call was accompanied by a proposed Federal
Implementation Plan, which could be implemented in any state that fails to
submit an approvable SIP. The NOx reductions called for by Federal EPA are
targeted at coal-fired electric utilities and may adversely impact the ability
of electric utilities to construct new facilities or to operate affected
facilities without making significant capital expenditures.

     In October 1998, the AEP System operating companies joined with certain
other parties seeking a review of the final NOx SIP Call rule in the U.S. Court
of Appeals for the District of Columbia Circuit. In March 2000, the court issued
a decision upholding the major provisions of the rule. The court subsequently
extended the date for submission of SIP revisions until October 30, 2000, and
the compliance deadline until May 31, 2004. In March 2001, the U.S. Supreme
Court denied petitions filed by industry petitioners, including AEP System
operating companies, seeking review of the Court of Appeals decision.

     In May 1999 and March 2000, Federal EPA finalized the NOx budget
allocations to be implemented through the NOx SIP Call. AEP and other parties
filed petitions for review in the U.S. Court of Appeals for the District of
Columbia Circuit and in June 2000 the court issued an opinion remanding the
budget determinations for further consideration of certain growth factor
assumptions made by Federal EPA. In December 2000, Federal EPA issued a
determination that eleven states, including certain states in which AEP System
operating companies have sources covered by the NOx SIP Call rule, had failed to
submit complying SIP revisions. AEP System operating companies and unaffiliated
utilities appealed this determination to the U.S. Court of Appeals for the
District of Columbia Circuit and the court has stayed the proceeding pending
Federal EPA action on the remand of growth factor issues.




                                       26
<PAGE>

     In April 2000, the Texas Natural Resource Conservation Commission adopted
rules requiring significant reductions in NOx emissions from utility sources,
including those of CPL and SWEPCo. The rule compliance date is May 2003 for CPL
and May 2005 for SWEPCo.

     Management's estimates indicate that compliance with the revised NOx SIP
Call rule, and SIP revisions already adopted, could result in required capital
expenditures for the AEP System of approximately $1.6 billion, of which
approximately $450 million has been expended through December 31, 2001.
Reference is made to the footnote to the financial statements entitled
Commitments and Contingencies incorporated by reference in Item 8 for
information with respect to AEP registrant subsidiaries' compliance cost
estimates and amounts expended.

     In May 2001, OPCo completed a $175 million installation of selective
catalytic reduction (SCR) technology to reduce NOx emissions on its two-unit
2,600 MW Gavin Plant and, during the 2001 ozone season (May through September),
operated the SCR units. Construction of selective catalytic reduction technology
on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and on APCo's
Mountaineer Plant, began in 2001. The Amos and Mountaineer projects (expected to
be completed in 2002) are estimated to cost a total of $230 million. Management
has undertaken the Gavin, Amos and Mountaineer projects to meet applicable NOx
emission reduction requirements. Additional expenditures of approximately $7
million are planned or undertaken to address certain operational issues arising
during initial operation of the Gavin SCR units.

     Since compliance costs cannot be estimated with certainty, the actual costs
to comply could be significantly different from management's estimates depending
upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless capital and operating costs of any additional pollution
control equipment necessary for compliance are recovered from customers through
regulated rates and market prices for electricity, they could have a material
adverse effect on future results of operations, cash flows and possibly
financial condition of AEP and its affected subsidiaries.

     Section 126 Petitions: In January 2000, Federal EPA adopted a revised rule
granting petitions filed by certain northeastern states under Section 126 of the
CAA. The petitions sought significant reductions in nitrogen oxide emissions
from utility and industrial sources. The rule imposed emission reduction
requirements comparable to the NOx SIP Call rule beginning May 1, 2003, for most
of AEP's coal-fired generating units. Certain AEP System operating companies and
other utilities filed petitions for review in the U.S. Court of Appeals for the
District of Columbia Circuit. In May 2001, the court issued an opinion which
upheld substantially the entire rule. The court did not agree that Federal EPA
had properly supported the growth factors for the NOx allowance budgets. In
August 2001, the court issued an order tolling the May 1, 2003, compliance date
pending resolution of the remand of the growth factor issues. In January 2002,
Federal EPA advised that it intends to establish May 31, 2004, as the final
compliance date for the rule. Cost estimates for compliance with Section 126 are
projected to be somewhat less than those set forth above for the NOx SIP Call
rule reflecting the fact that Section 126 does not apply to AEGCo's and I&M's
Rockport Plant.

     West Virginia SO2 Limits: West Virginia promulgated SO2 limitations, which
Federal EPA approved in February 1978. The emission limitations for OPCo's
Mitchell Plant have been approved by Federal EPA for primary ambient air quality
(health-related) standards only. West Virginia is obligated to reanalyze SO2
emission limits for the Mitchell Plant with respect to secondary ambient air
quality (welfare-related) standards. Because the CAA 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.

     In August 1994, Federal EPA issued a Notice of Violation to OPCo alleging
that Kammer Plant was operating in violation of the applicable federally
enforceable SO2 emission limit. In May 1996, the Notice of Violation and an
enforcement action subsequently filed by Federal EPA were resolved through the
entry of a consent decree in the




                                       27
<PAGE>

U.S. District Court for the Northern District of West Virginia. Kammer Plant has
achieved and maintained compliance with the applicable SO2 emission limit for a
period in excess of one year, pursuant to the provisions of the consent decree.
In May 2001, the court terminated the consent decree.

     Short Term SO2 Limits: In January 1997, Federal EPA proposed a new
intervention level program under the authority of Section 303 of the CAA to
address five-minute peak SO2 concentrations believed to pose a health risk to
certain segments of the population. The proposal establishes a "concern" level
and an "endangerment" level. States must investigate exceedances of the concern
level and decide whether to take corrective action. If the endangerment level is
exceeded, the state must take action to reduce SO2 levels. In January 2001,
Federal EPA published a Federal Register notice inviting comment with respect to
its decision not to promulgate a five-minute SO2 NAAQS and intent to take final
action on the intervention level program by the summer of 2001. The effect of
this proposed intervention program on AEP operations or financial performance
cannot be predicted at this time.

     Hazardous Air Pollutants: Hazardous air pollutant (HAP) emissions from
utility boilers are potentially subject to control requirements under Title III
of the CAAA which specifically directed Federal EPA to study potential public
health impacts of HAPs emitted from electric utility steam generating units. In
December 2000, Federal EPA announced its intent to regulate emissions of mercury
from coal and oil-fired power plants, concluding that these emissions pose
significant hazards to public health. A decision on whether to regulate other
HAPs emissions from these sources was deferred.

     Federal EPA added coal and oil-fired electric utility steam generating
units to the list of "major sources" of HAPs under Section 112 (c) of the CAA,
which compels the development of "Maximum Achievable Control Technology" (MACT)
standards for these units. Listing under Section 112 (c) also compels a
preconstruction permitting obligation to establish case-by-case MACT standards
for each new or reconstructed source in the category. MACT standards for utility
mercury emissions are scheduled to be proposed by December 2003 and finalized by
December 2004. The Utility Air Regulatory Group (which includes AEP System
operating companies as members) filed a petition with Federal EPA seeking
reconsideration of the decision to regulate mercury emissions from power plants
under Section 112(c) of the CAA.

     In addition, Federal EPA is required to study the deposition of hazardous
pollutants in 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. In 1998, Federal EPA determined that the CAA
is adequate to address any adverse public health or environmental effects
associated with the atmospheric deposition of hazardous air pollutants in the
Great Lakes. The potential impact of adverse developments in these programs on
AEP operations or financial performance cannot be predicted at this time.

     Title IV Acid Rain Program: The Acid Rain Program (Title IV) of the CAAA
created an emission allowance program pursuant to which utilities are authorized
to emit a designated quantity of SO2, measured in tons per year.

     Phase II of the Acid Rain Program, which affects all fossil fuel-fired
steam generating units with capacity greater than 25 megawatts imposed more
stringent SO2 emission control requirements beginning January 1, 2000. If a unit
emitted SO2 in 1985 at a rate in excess of 1.2 pounds per million Btu heat
input, the Phase II allowance allocation is premised upon an emission rate of
1.2 pounds at 1985 utilization levels. Future SO2 requirements will be met
through accumulation or acquisition of allowances, the use of controls or fuels,
or a combination thereof. See Fuel Supply--Coal and Lignite.

     Title IV of the CAAA also regulates emissions of NOx. Federal EPA has
promulgated NOx emission limitations for all boiler types in the AEP System at
levels significantly below original design, which were to be achieved by January
1, 2000 on a unit-by-unit or System-wide average basis. AEP sources subject to
Title IV of the CAAA are in





                                       28
<PAGE>

compliance with the provisions thereof.

     Regional Haze: In July 1999, Federal EPA finalized rules to regulate
regional haze attributable to anthropogenic emissions. The primary goal of the
new regional haze program is to address visibility impairment in and around
"Class I" protected areas, such as national parks and wilderness areas. Because
regional haze precursor emissions are believed by Federal EPA to travel long
distances, the rules address the potential regulation of such precursor
emissions in every state. Under the rule, each state must develop a regional
haze control program that imposes controls necessary to steadily reduce
visibility impairment in Class I areas on the worst days and that ensures that
visibility remains good on the best days. In addition, Federal EPA intends to
require Best Available Retrofit Technology (BART) for power plants and other
large emission sources constructed between 1962 and 1977.

     In January 2001, Federal EPA proposed guidelines for states to use in
setting BART emission limits for power plants and other large emission sources
and in determining which sources are subject to those limits. The proposed rule
calls for technologies which Federal EPA estimates are capable of reducing SO2
emissions by 90 to 95 percent. The proposed rule also contemplates that other
visibility-impairing emissions must be reduced. Emission trading programs could
be used in lieu of unit-by-unit BART requirements under the proposal, provided
they yield greater visibility improvement and emission reductions.

     The AEP System is a significant emitter of fine particulate matter and
other precursors of regional haze and a number of AEP's generating units could
be subject to BART controls. Federal EPA's regional haze rule may have an
adverse financial impact on AEP as it may trigger the requirement to install
costly new pollution control devices to control emissions of fine particulate
matter and its precursors (including SO2 and NOx). The actual impact of the
regional haze regulations cannot be determined at this time. AEP System
operating companies and other utilities filed a petition seeking a review of the
regional haze rule in the U.S. Court of Appeals for the District of Columbia
Circuit in August 1999.

     Permitting and Enforcement: The CAAA expanded the enforcement authority of
the federal government by:

     -    Increasing the range of civil and criminal penalties for violations of
          the CAA and enhancing administrative civil provisions.

     -    Imposing a national operating permit system, emission fee program and
          enhanced monitoring, recordkeeping and reporting requirements.

     Section 103 of CERCLA and Section 304 of the Emergency Planning and
Community Right-to-Know Act require notification to state and federal
authorities of releases of reportable quantities (RQs) of hazardous and
extremely hazardous substances. A number of these substances are emitted by
AEP's power plants and other sources. Until recently, emissions of these
substances, whether expressly limited in a permit or otherwise subject to
federal review or waiver (e.g., mercury), were deemed "federally permitted
releases" which did not require emergency notification. In December 1999,
Federal EPA published interim guidance in the Federal Register, which provided
that any hazardous substance or extremely hazardous substance not expressly and
individually limited in a permit must be reported if they are emitted at levels
above an RQ. Specifically, constituents of regulated pollutants (e.g., metals
contained in particulate matter) were not deemed to be federally permitted. AEP
System operating companies have provided supplemental information regarding air
releases from their facilities and are submitting follow-up reports. Federal EPA
suspended its December 1999 guidance as it considers certain revisions to the
guidance. Settlement discussions regarding the guidance are underway.

     Global Climate Change: In December 1997, delegates from 167 nations,
including the U.S., agreed to a treaty, known as the "Kyoto Protocol,"
establishing legally-binding emission reductions for gases suspected of causing
climate change. The Protocol requires ratification by at least 55 nations that
account for at least 55% of developed countries' 1990 emissions of CO2 to enter
into force.

     Although the U.S. signed the treaty on November 12, 1998, it was not sent
to the Senate for



                                       29
<PAGE>

its advice and consent to ratification. In a letter dated March 13, 2001 from
President Bush to four U. S. senators, he indicated his opposition to the Kyoto
Protocol and said he does not believe that the government should impose
mandatory emissions reductions for CO2 on the electric utility sector.

     Despite U.S. opposition to the treaty, at the Seventh Conference of the
Parties to the United Nations Framework Convention on Climate Change, held in
Marrakech, Morocco in November 2001, the parties finalized the rules, procedures
and guidelines required to facilitate ratification of the treaty by most
nations, and entry into force is expected by 2003.

     Since the AEP System is a significant emitter of carbon dioxide, its
results of operations, cash flows and financial condition could be materially
adversely affected by the imposition of limitations on CO2 emissions if
compliance costs cannot be fully recovered from customers. In addition, any
program to reduce CO2 emissions could impose substantial costs on industry and
society and erode the economic base that AEP's operations serve. However, it is
management's belief that the Kyoto Protocol is highly unlikely to be ratified or
implemented in the U.S. in its current form. AEP's 4,000 MW of coal-fired
generation in the United Kingdom acquired in 2001 may be exposed to potential
carbon dioxide emission control obligations since the U.K. is expected to be a
party to the Kyoto Protocol. AEP is developing an emissions mitigation plan for
these plants to ensure compliance as necessary.

     On February 14, 2002, President Bush announced new climate change
initiatives for the U.S. Among the policies to be pursued is a voluntary
commitment to reduce the "greenhouse gas intensity" of the economy by 18% within
the next ten years. It is anticipated that the Administration will seek to
partner with various industrial sectors, including the electric utility
industry, to reach this goal. AEP is unable to predict at this time the effect
that this program will have upon its operations or financial performance in the
future.

     New Source Review: In July 1992, Federal EPA published final regulations
governing application of new source rules to generating plant repairs and
pollution control projects undertaken to comply with the CAA. Generally, the
rule provides that plants undertaking pollution control projects will not
trigger New Source Review (NSR) requirements. The Natural Resources Defense
Council and a group of utilities, including five AEP System operating companies,
filed petitions in the U.S. Court of Appeals for the District of Columbia
Circuit seeking a review of the regulations. In July 1998, Federal EPA requested
comment on proposed revisions to the New Source Review rules, which would change
New Source Review applicability criteria by eliminating exclusions contained in
the current regulation. The Administration and Congress are considering
initiatives to reform the NSR requirements, but no regulatory revisions have
been proposed to date.

     New Source Review Litigation: On November 3, 1999, following issuance by
Federal EPA of substantial information requests to AEP System operating
companies, the Department of Justice (DOJ), on Federal EPA's behalf, filed a
complaint in the U.S. District Court for the Southern District of Ohio that
alleges AEP made modifications to generating units at certain of its coal-fired
generating plants over the course of the past 20 years that extend unit
operating lives or restore or increase unit generating capacity without a
preconstruction permit in violation of the CAA. The complaint named OPCo's
Cardinal Unit 1, Mitchell, Muskingum River, and Sporn plants and I&M's Tanners
Creek plant. Federal EPA also issued Notices of Violation to AEP alleging
similar violations at certain other AEP plants.

     In March 2000, DOJ filed an amended complaint that added allegations for
certain of the AEP plants previously named in the complaint as well as counts
for APCo's Amos, Clinch River, and Kanawha River plants, CSPCo's Conesville
Plant, and OPCo's Kammer Plant. In addition to the allegations regarding New
Source Review and New Source Performance Standard violations, DOJ included
allegations regarding visible particulate emission violations for Cardinal and
Muskingum River plants.

     A number of northeastern and eastern states have been allowed to intervene
in the litigation, and




                                       30
<PAGE>

a number of special interest groups filed a separate complaint based on
substantially similar allegations, which has been consolidated with the DOJ
complaint. In addition to the plants named by the government and special
interest groups, the intervenor states have included allegations concerning
OPCo's Gavin Plant.

     In May 2000, AEP filed a motion to dismiss with the District Court, which,
if granted, would dispose of most of the claims of the government and
intervenors.

     In February 2001, the plaintiffs filed a motion for partial summary
judgment seeking a determination that four projects undertaken on units at
Sporn, Cardinal, and Clinch River Plants do not constitute "routine maintenance,
repair and replacement" as used in the NSR programs. In August 2001, the court
issued an order denying the plaintiffs' motion as premature. Management believes
its maintenance, repair and replacement activities were in conformity with the
CAA and intends to vigorously pursue its defense.

     A number of unaffiliated utilities have also received notices of violation,
complaints, or administrative orders relating to NSR. A notice of violation was
issued in June 2000 to DP&L with respect to its ownership interest in Stuart
Station, in which CSPCo also owns a 26 percent interest. W.C. Beckjord Unit 6,
operated by CG&E, in which CSPCo owns a 12.5 percent interest, is also the
subject of an enforcement action. Cinergy Corp., the parent company of CG&E, has
entered into an agreement in principle with the DOJ in an attempt to resolve the
litigation relating to W.C. Beckjord Unit 6 and other plants owned or operated
by Cinergy and its subsidiaries. This agreement in principle also covers the
Zimmer Plant which has not been the subject of an enforcement action. VEPCo has
also entered into a similar agreement in principle. Neither CG&E nor VEPCo have
reached final agreements with the DOJ. Two other unaffiliated utilities, Tampa
Electric Company and PSEG Fossil, LLC, have reached settlements with the Federal
government.

     In November 2000, several environmental groups filed a petition with Ohio
EPA seeking to have the draft Title V operating permits for OPCo's Cardinal and
Muskingum River plants as well as the Beckjord Plant and a plant owned by an
unaffiliated utility, modified to incorporate requirements and timetables for
compliance with New Source Review requirements. In December 2000, a petition was
filed by these groups with the Administrator of Federal EPA seeking a similar
modification of the final Title V permit for CSPCo's Conesville Plant. Ohio EPA
has refused to consider these petitions outside the regular Title V permit
processing procedures or to interfere with the resolution of these issues by the
District Court.

     The CAA authorizes civil penalties of up to $27,500 per day per violation
at each generating unit ($25,000 per day prior to January 30, 1997). In March
2001, the District Court issued orders holding that claims for civil penalties
based on alleged activities that occurred more than five years prior to the
filing of the complaint are barred. Although the plaintiffs' claims for
injunctive relief are not barred, the court noted that the nature of the relief
ordered may be impacted by the plaintiffs' delay in filing the complaints.

     Management is unable to estimate the loss or range of loss related to the
contingent liability for civil penalties under the CAA proceedings and unable to
predict the timing of resolution of these matters due to the number of alleged
violations and issues to be determined by the court. In the event the AEP System
companies do not prevail, any capital and operating costs of additional
pollution control equipment that may be required as well as any penalties
imposed could materially adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates and market prices for electricity.

   Water Pollution Control

     The Clean Water Act prohibits the discharge of pollutants to waters of the
United States from point sources except pursuant to an NPDES permit issued by
Federal EPA or a state under a federally authorized state program.

     Under the Clean Water Act, effluent limitations requiring application of
the best available technology economically achievable are to be




                                       31
<PAGE>

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 AEP System generating plants are required to have NPDES permits and
have received them. NPDES permit conditions and effluent limitations are
reviewed during the permit renewal process. Under Federal 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 that expire in 2002.

     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 CSPCo's Conesville and OPCo's 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, the thermal limits
for both Conesville and Muskingum River plants were raised in the renewed
permits issued in 1996. Consequently, the potential for load curtailment and
adverse cost impacts was further reduced. In early 2002, AEP submitted a
petition to Ohio EPA requesting additional less stringent thermal loading
limitations for these plants.

     Section 316(b) of the Clean Water Act requires that cooling water intake
structures reflect the best technology available (BTA) for minimizing adverse
environmental impact. Federal EPA issued final regulations defining BTA for new
sources that were published in the Federal Register on December 18, 2001. New
sources are those commencing construction after January 17, 2002. On February
28, 2002, Federal EPA issued a proposed rule addressing BTA for intake
structures at existing plants. This proposal is expected to be published in the
Federal Register for comment in April 2002. Under a previous court-established
schedule, Federal EPA is required to issue final regulations for existing plants
by August 2003. Federal EPA's rulemaking could result in a definition of BTA
that could ultimately require retrofitting of certain existing plant intake
structures. Such changes would involve costs for AEP System operating companies,
but the significance of these costs cannot be determined at this time.

     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.

     Section 303 of the Federal Clean Water Act 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 it is
shown that water quality standards are not being met. In order to bring these
waters back into compliance, total maximum daily load (TMDL) allocations of
these pollutants will be made, and subsequently translated into discharge limits
in NPDES permits. Federal EPA has also directed that states take action to adopt
enhanced anti-degradation of water quality requirements. In October 2001,
Federal EPA issued a rule delaying until April 30, 2003, the effective date of
its TMDL rule issued in July 2000, the effective date of which had been
previously delayed by Congress. Implementation of these provisions could result
in significant costs to the AEP System if biological monitoring requirements and
water quality-based effluent limits and requirements are placed in NPDES
permits.

     In March 1995, Federal EPA finalized a set of rules that 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




                                       32
<PAGE>

related to I&M's Cook Plant. Based on Federal EPA's current policy on intake
credits and site specific variables and Michigan's implementation strategy,
management does not presently expect the GLWQI will have a significant adverse
impact on Cook Plant operations. If Indiana and Ohio eventually adopt the GLWQI
criteria for statewide application, AEP System plants located in those states
could be adversely affected, although the significance depends on the
implementation strategy of those states.

     Oil Pollution Act: The Oil Pollution Act of 1990 (OPA) defines certain
facilities that, due to oil storage volume, and location, could reasonably be
expected to cause significant and substantial harm to the environment by
discharging oil. Such facilities must operate under approved spill response
plans and implement spill response training and drill programs. OPA imposes
substantial penalties for failure to comply. AEP System operating companies with
oil handling and storage facilities meeting the OPA criteria have in place
required response plans, training and drill programs.

   Solid and Hazardous Waste

     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. CERCLA expanded the reporting requirement 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 PCBs contained in certain capacitors and transformers, but the
occurrence and ramifications of a spill or release of such substances cannot be
predicted.

     CERCLA, RCRA and similar state laws provide governmental agencies with the
authority to require cleanup of hazardous waste sites and releases of hazardous
substances into the environment and to seek compensation for damages to natural
resources. Since liability under CERCLA is strict, joint and several, and can be
applied retroactively, AEP System operating 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 operating companies are identified as Potentially Responsible
Parties (PRPs) for five federal sites where remediation has not been completed,
including APCo at one site, CSPCo at one site, I&M at two sites, and OPCo at one
site. AEP has also been named a PRP at two sites under state law. Management's
present estimates do not anticipate material clean-up costs for identified sites
for which AEP subsidiaries have been declared PRPs. In addition, AEP subsidiary
companies are engaged in certain remedial projects at various locations, the
costs of which are not expected to be material. However, if significant costs
are incurred for cleanup, future results of operations and possibly financial
condition could be adversely affected unless the costs can be recovered through
rates and/or future market prices for electricity where generation is
deregulated.

     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 of in surface impoundments or landfills
in accordance with state permits or authorization or are beneficially utilized.
As required by RCRA, Federal 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, Federal EPA issued a regulatory
determination that such high volume coal combustion wastes should not be
regulated as hazardous waste. Federal EPA chose to address separately the issue
of low volume wastes (such as metal and boiler cleaning wastes) associated with
burning coal and other fossil fuels. In May 2000, Federal EPA issued a
regulatory determination that such low volume wastes are also




                                       33
<PAGE>

excluded from regulation under the RCRA hazardous waste provisions when mixed
and co-managed with high volume fossil fuel combustion wastes.

     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 that 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 and
STP and regulated under the Atomic Energy Act is excluded from regulation under
RCRA.

     Underground Storage Tanks: Federal EPA's technical requirements for
underground storage tanks containing petroleum required retrofitting or
replacement of an appreciable number of tanks. Compliance costs for tank
replacement were not significant. Some limited site remediation associated with
tank removal is ongoing, but these costs are not expected to be significant.

   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, electrical equipment, 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 Energy Policy Act of 1992 established a coordinated Federal EMF
research program which ended in 1998. In 1999, the National Institute of
Environmental Health Sciences (NIEHS), as required by the Act, provided a report
to Congress summarizing the results of this program. The report concluded that
"the probability that ...EMF is truly a health hazard is currently small" and
that the evidence that exists for health effects is "insufficient to warrant
aggressive regulatory actions." Nevertheless, the NIEHS identified several areas
where further research might be warranted. AEP has supported EMF research
through the years and continues to fund the Electric Power Research Institute's
EMF research program, contributing over $400,000 to this program in 2001, and
intending to contribute a similar amount in 2002. See Research and Development.

     AEP's participation in these programs is a continuation of its efforts to
monitor and support further research and to communicate with its customers and
employees about this issue. Residential customers of AEP are provided
information and field measurements on request, although there is no scientific
basis for interpreting such measurements.

     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.

     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 over 100 research projects that
focus on:

     -    Exploring new methods of generating electricity, such as through
          renewable sources (e.g., wind, solar).

     -    Enhancing energy trading infrastructure.

     -    Developing more efficient methods of operating generating plants.



                                       34
<PAGE>



     -    Optimizing and efficiently managing generation and other
          energy-related assets.

     -    Reducing emissions resulting from the burning of fossil fuels (coal
          and natural gas).

     -    Improving the efficiency, utilization and reliability of the
          transmission and distribution systems.

     -    Exploring the application of new technologies.

     AEP System operating companies are members of the Electric Power Research
Institute (EPRI), an organization founded in 1973 that manages science and
technology initiatives on behalf of its members. EPRI's members include investor
owned and public utilities, independent power producers, international
organizations and others.

     AEP participates in EPRI programs that meet its research and development
objectives. Total AEP dues to EPRI were $9,000,000 for 2001, $17,000,000 for
2000 and $22,000,000 for 1999. Of these amounts, the former CSW System paid
approximately $7,000,000 in 2000 and $8,000,000 in 1999 for EPRI programs.

     Total research and development expenditures by AEP and its subsidiaries,
including EPRI dues, were approximately $15,000,000 for 2001, $20,000,000 for
2000 and $25,000,000 for 1999.


Item 2.  PROPERTIES
- --------------------------------------------------------------------------------

     At December 31, 2001, the AEP System owned (or leased where indicated)
generating plants with net power capabilities (east zone subsidiaries-winter
rating; west zone subsidiaries-summer rating) shown in the following table:


<TABLE>
<CAPTION>

                              Coal      Natural Gas       Hydro       Nuclear     Lignite        Other          Total
   Company      Stations       MW           MW              MW           MW          MW             MW            MW
- -------------------------------------------------------------------------------------------------------------------------

<S>            <C>            <C>             <C>            <C>       <C>              <C>            <C>       <C>
AEGCo          1(a)            1,300                                                                              1,300
APCo           17(b)           5,081                         777                                                  5,858
CPL            12(c)(d)          686          3,175            6         630                                      4,497
CSPCo          6(e)            2,595                                                                              2,595
I&M            10(a)           2,295                          11       2,110                                      4,416
KEPCo          1               1,060                                                                              1,060
OPCo           8(b)(f)         8,464                          48                                                  8,512
PSO            8(c)            1,043          3,169                                                   25(g)       4,237
SWEPCo         9               1,848          1,797                                     842                       4,487
WTU            12(c)             377            999                                                   16(g)       1,392
- -------------------------------------------------------------------------------------------------------------------------
Totals:        84             24,749          9,140          842       2,740            842            41        38,354
- -------------------------------------------------------------------------------------------------------------------------

</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)  CPL, PSO, and WTU jointly own the Oklaunion power station. Their respective
     ownership interests are reflected in this table.
(d)  Reflects CPL's interest in STP.
(e)  CSPCo owns generating units in common with CG&E and DP&L. Its ownership
     interest of 1,330 MW is reflected in this table.
(f)  The scrubber facilities at the General James M. Gavin Plant are leased. The
     lease terminates in 2010 unless extended.
(g)  PSO and WTU have 25 MW and 10 MW respectively of facilities designed
     primarily to burn oil.  WTU has one 6 MW wind farm facility.




                                       35
<PAGE>

     AEP-Other Generation: In addition to the generating facilities described
above, AEP has ownership interests in other electrical generating facilities,
both foreign and domestic. Information concerning these facilities at December
31, 2001 is listed below (except for Bajio which went into commercial operation
in March 2002).


<TABLE>
<CAPTION>

                                                                             CAPACITY        OWNERSHIP
FACILITY                             FUEL                 LOCATION           TOTAL MW         INTEREST         STATUS
- ---------------------------------------------------------------------------------------------------------------------
<S>                              <C>                 <C>                      <C>             <C>              <C>
Brush II                          Natural gas             Colorado                68            47.75%           QF
Eastex                            Natural gas              Texas                 440               50%           QF
Indian Mesa                          Wind                  Texas                 161              100%           EWG
Mulberry                          Natural gas             Florida                120            46.25%           QF
Newgulf                           Natural gas              Texas                  85              100%           EWG
Orange Cogen                      Natural gas             Florida                103               50%           QF
Sweeny                            Natural gas              Texas                 480               50%           QF
Thermo Cogeneration               Natural gas             Colorado               272               50%           QF
Trent Wind Farm                      Wind                  Texas                 150              100%           EWG
- ---------------------------------------------------------------------------------------------------------------------
Total U.S.                                                                     1,879
- ---------------------------------------------------------------------------------------------------------------------
Bajio                             Natural gas             Mexico                 605               50%          FUCO
Bakun                                Hydro              Philippines               70               10%          FUCO
Codrington                           Wind                Australia                18               20%          FUCO
Ferrybridge                          Coal              United Kingdom          2,000              100%          FUCO
Fiddler's Ferry                      Coal              United Kingdom          2,000              100%          FUCO
Medway                            Natural gas          United Kingdom            675             37.5%          FUCO
Nanyang                              Coal                  China                 250               70%          FUCO
Ord Hydro                            Hydro               Australia                30               20%          FUCO
Southcoast                        Natural gas          United Kingdom            380               50%          FUCO
Vale                             Hydro/Thermal             Brazil                665               (a)          FUCO
Victoria                             Hydro               Australia                10               20%          FUCO
- ---------------------------------------------------------------------------------------------------------------------
Total International                                                            6,703
- ---------------------------------------------------------------------------------------------------------------------

</TABLE>

(a)  AEP has varying minority interests which aggregate to 168 MW.


     See Item 1 under Fuel Supply for information concerning coal reserves owned
or controlled by subsidiaries of AEP and under Wholesale Business Operations for
information concerning AEP's natural gas pipeline, storage and processing
facilities.

     The following table sets forth the total overhead circuit miles of
transmission and distribution lines of the AEP System and its operating
companies and that portion of the total representing 765,000-volt lines:

                            TOTAL OVERHEAD
                           CIRCUIT MILES OF
                           TRANSMISSION AND    CIRCUIT MILES OF
                          DISTRIBUTION LINES   765,00-VOLT LINES
                          ------------------   -----------------

AEP System (a)..............   211,300(b)         2,023
   APCo.....................    51,295              642
   CPL......................    31,210             ---
   CSPCo (a)................    13,703             ---
   I&M......................    20,672              614
   KEPCo....................    10,443              258
   OPCo ....................    29,347              509
   PSO......................    18,713             ---
   SWEPCo...................    19,873             ---
   WTU......................    12,605             ---

- ----------------------
(a)  Includes 766 miles of 345,000-volt jointly owned lines.
(b)  Includes 73 miles of transmission lines not identified with an operating
     company.






                                       36
<PAGE>


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 fixed physical properties and franchises of the AEP
System operating companies, except for limited conditions and limitations, 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 Arkansas, Indiana, Kentucky, Michigan, Ohio,
Texas, 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 east zone system is interconnected through 121 high-voltage
transmission interconnections with 25 neighboring electric utility systems. The
all-time and 2001 one-hour peak system demands were 25,940,000 and 25,433,000
kilowatts, respectively (which included 7,314,000 and 5,469,000 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 July 24, 2001, respectively. The net dependable
capacity to serve the system load on such date, including power available under
contractual obligations, was 23,457,000 and 23,974,000 kilowatts, respectively.
The all-time and 2001 one-hour internal peak demand was 20,218,000 kilowatts,
and occurred on August 8, 2001. The net dependable capacity to serve the system
load on such date, including power dedicated under contractual arrangements, was
23,935,000 kilowatts. The all-time one-hour integrated and internal net system
peak demands and 2001 peak demands for the east zone generating subsidiaries are
shown in the following tabulation:

ALL-TIME ONE-HOUR INTEGRATED       2001 ONE-HOUR INTEGRATED
   NET SYSTEM PEAK DEMAND           NET SYSTEM PEAK DEMAND
- ------------------------------     --------------------------
                        (IN THOUSANDS)
          NUMBER OF                  NUMBER OF
          KILOWATTS       DATE       KILOWATTS       DATE
          -----------     ------     -----------    -------
APCo......  8,303   January 17, 1997  7,750    January 10, 2001
CSPCo.....  4,833   July 23, 2001     4,833    July 23, 2001
I&M.......  5,403   June 23, 2001     5,403    July 23, 2001
KEPCo.....  1,860   January 10, 2001  1,860    January 10, 2001
OPCo......  7,291   June 17, 1994     6,668    July 24, 2001


ALL-TIME ONE-HOUR INTEGRATED       2001 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  6,402     January 3, 2001
CSPCo......  3,927     August 8, 2001    3,927     August 8, 2001
I&M........  4,232     August 8, 2001    4,232     August 8, 2001
KEPCo.....   1,579     January 3, 2001   1,579     January 3, 2001
OPCo.......  5,705     June 11, 1999     5,341     July 24, 2001


     The all-time and 2001 one-hour internal peak demand for the west zone
system was 15,048,000 and 14,648,000 kilowatts, respectively, and occurred on
August 31, 2000 and July 23, 2001, respectively. The all-time one-hour internal
net system peak demands and 2001 peak demands for the west zone generating
subsidiaries are shown in the following tabulation:




                                       37
<PAGE>

 ALL-TIME ONE-HOUR INTEGRATED          2001 ONE-HOUR INTEGRATED
   NET INTERNAL PEAK DEMAND           NET INTERNAL PEAK DEMAND
- -------------------------------      -------------------------
                       (IN THOUSANDS)
           NUMBER OF                   NUMBER OF
           KILOWATTS       DATE        KILOWATTS       DATE
           -----------     -----       -----------    -------

CPL .......  4,623   September 5, 2000   4,323   June 12, 2001
PSO........  3,823   August 30, 2000     3,785   August 9, 2001
SWEPCo.....  4,625   August 31, 2000     4,344   July 18, 2001
WTU.......   1,537   September 5, 2000   1,472   July 19, 2001


HYDROELECTRIC PLANTS

     AEP has 18 hydro facilities, of which 16 are licensed through FERC. The
license for the Elkhart hydroelectric plant in Indiana was issued in January
2001 and extends for a period of thirty years. The license for the Mottville
hydroelectric plant in Michigan expires in 2003 and the application for a new
license was filed with FERC in September 2001.

COOK NUCLEAR PLANT AND STP

     The following table provides operating information relating to the Cook
Plant and STP.

                       COOK PLANT                STP(a)
                   -------------------     ------------------
                    UNIT 1     UNIT 2     UNIT 1     UNIT 2
                    ------     ------     ------     ------
Year Placed in
Operation            1975       1978       1988       1989
Year of
Expiration of
Nrc License (b)      2014       2017       2027       2028
Nominal Net
Electrical
Rating in          1,020,000  1,090,000  1,250,600  1,250,600
Kilowatts

Net Capacity  Factors
      2001 (c)       87.3%      83.4%      94.4%      87.1%
      2000 (d)        1.4%      50.0%      78.2%      96.1%

- ---------------------
(a)  Reflects total plant.
(b)  For economic or other reasons, operation of the Cook Plant and STP for the
     full term of their operating licenses cannot be assured.
(c)  The capacity factor for both units of the Cook Plant was significantly
     reduced in 2001 due to an unplanned dual maintenance outage in September
     2001 to implement design changes that improved the performance of the
     essential service water system.
(d)  The Cook Plant was shut down in September 1997 to respond to issues raised
     regarding the operability of certain safety systems. The restart of both
     units of the Cook Plant was completed with Unit 2 reaching 100% power on
     July 5, 2000 and Unit 1 achieving 100% power on January 3, 2001.

     Costs associated with the operation (excluding fuel), maintenance and
retirement of nuclear plants continue to be of greater significance and less
predictable than costs associated with other sources of generation, in large
part due to changing regulatory requirements and safety standards, availability
of nuclear waste disposal facilities and experience gained in the construction
and operation of nuclear facilities. I&M and CPL may also incur costs and
experience reduced output at Cook Plant and STP, respectively, because of the
design criteria prevailing at the time of construction and the age of the
plant's systems and equipment. Nuclear industry-wide and Cook Plant and STP
initiatives have contributed to slowing the growth of operating and maintenance
costs at these plants. However, the ability of I&M and CPL to obtain adequate
and timely recovery of costs associated with the Cook Plant and STP,
respectively, including replacement power, any unamortized investment at the end
of the useful life of the Cook Plant and STP (whether scheduled or premature),
the carrying costs of that investment and retirement costs, is not assured. See
Competition and Business Change.

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 or STP
and costs of replacement power in the event of a nuclear incident at the Cook
Plant or STP. 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, CPL, I&M and
other AEP System companies.

     Reference is made to the footnote to the financial statements entitled
Commitments and Contingencies that is incorporated by reference in Item 8 for
information with respect to nuclear incident liability insurance.



                                       38
<PAGE>



Item 3.  LEGAL PROCEEDINGS
- --------------------------------------------------------------------------------

     Federal EPA Notice of Violation to OPCo: On August 31, 2000, Region V,
Federal EPA, issued a Notice of Violation (NOV) to OPCo's Gavin Plant that
alleges violations of the Federal EPA-approved Ohio mass particulate emission
limit, opacity, and air pollution nuisance rules. AEP has submitted information
in response to the allegations and requested a conference to discuss the NOV
with Region V representatives.

     Ohio EPA Notices of Violation to OPCo: On August 17, 2001, Ohio EPA issued
proposed findings and orders to OPCo's Gavin Plant based on the alleged failure
of a mass particulate emissions test on May 17, 2000. OPCo requested a
conference to discuss the proposed findings and orders and submitted the results
of its investigation of the test procedures, which confirmed that the May 17
test was invalid due to the corrosion and disintegration of the test probe.

     On December 27, 2001, Ohio EPA issued two NOVs to OPCo's Gavin Plant,
alleging that OPCo failed to notify Ohio EPA of a malfunction of the flyash
handling system at the plant, and that OPCo failed to conduct a required mass
particulate emissions test. OPCo has submitted additional control plans for the
flyash handling system and information regarding the particulate testing
completed at the Gavin Plant in response to the NOVs.

     COLI Litigation: On February 20, 2001, the U.S. District Court for the
Southern District of Ohio ruled against AEP in its suit against the United
States over deductibility of interest claimed by AEP in its consolidated federal
income tax return related to its COLI program. AEP had filed suit to resolve the
IRS' assertion that interest deductions for AEP's COLI program should not be
allowed. In 1998 and 1999 AEP paid the disputed taxes and interest attributable
to COLI interest deductions for taxable years 1991-98 to avoid the potential
assessment by the IRS of additional interest on the contested tax. The payments
were included in other assets pending the resolution of this matter. As a result
of the U.S. District Court's decision to deny the COLI interest deductions, net
income was reduced in 2000 as follows:

                                             (IN MILLIONS)

AEP System operating companies......             $ 319
   APCo.............................                82
   CSPCo............................                41
   I&M..............................                66
   KEPCo............................                 8
   OPCo.............................               118


     The Company has filed an appeal of the U.S. District Court's decision with
the U.S. Court of Appeals for the Sixth Circuit.

                             ----------------------

     See Item 1 for a discussion of certain environmental matters.

                             ----------------------

     Reference is made to the footnote to the financial statements entitled
Commitments and Contingencies incorporated by reference in Item 8 for further
information with respect to other legal proceedings.



                                       39
<PAGE>




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

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

AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(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 1, 2002.

<TABLE>
<CAPTION>

NAME                              AGE                                        OFFICE (a)
- ----                              ---                                        ---------

<S>                               <C>   <C>
E. Linn Draper, Jr.............    60    Chairman of the Board, President and Chief Executive Officer of AEP and of the
                                         Service Corporation

Thomas V. Shockley, III........    56    Vice Chairman and Chief Operating Officer of the Service Corporation
Henry W. Fayne.................    55    Executive Vice President of the Service Corporation
Robert P. Powers...............    48    Executive Vice President-Nuclear  Generation and Technical Services of the Service
                                         Corporation

Susan Tomasky..................    48    Executive Vice President-Policy, Finance and Strategic Planning of the Service
                                         Corporation
J. H. Vipperman................    61    Executive Vice President-Shared Services of the Service Corporation

</TABLE>

- -------------------------
(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 for Messrs.
     Powers and Shockley and Ms. Tomasky. Prior to joining the Service
     Corporation in July 1998 as Senior Vice President-Generation, Mr. Powers
     was Vice President of Pacific Gas & Electric and plant manager of its
     Diablo Canyon Nuclear Generating Station (1996-1998). Prior to joining the
     Service Corporation in July 1998 as Senior Vice President, Ms. Tomasky was
     a partner with the law firm of Hogan & Hartson (August 1997-July 1998) and
     General Counsel of the Federal Energy Regulatory Commission (May
     1993-August 1997). Mr. Powers and Ms. Tomasky became executive officers of
     AEP effective with their promotions to Executive Vice President on October
     24, 2001 and January 26, 2000, respectively. Prior to joining the Service
     Corporation in his current position upon the merger with CSW, Mr. Shockley
     was President and Chief Operating Officer of CSW (1997-2000) and Executive
     Vice President of CSW (1990-1997). 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, CPL, I&M, OPCO AND SWEPCO. The names of the executive officers of
APCo, CPL, I&M, OPCo and SWEPCo, the positions they hold with these companies,
their ages as of March 1, 2002, and a brief account of their business experience
during the past five years appear below. The directors and executive officers of
APCo, CPL, I&M, OPCo and SWEPCo are elected annually to serve a one-year term.

<TABLE>
<CAPTION>

NAME                             AGE                             POSITION (a)(b)                               PERIOD
- ----                             ---                             ---------------                               ------

<S>                              <C>   <C>                                                                <C>
E. Linn Draper, Jr............    60    Director of CPL and SWEPCo                                         2000-Present
                                        Chairman of the Board and Chief Executive Officer of CPL and
                                            SWEPCo                                                         2000-Present
                                        Director of APCo, I&M and OPCo                                     1992-Present
                                        Chairman of the Board and Chief Executive Officer of APCo, I&M
                                            and OPCo                                                       1993-Present
                                        Chairman of the Board, President and Chief Executive Officer of
                                            AEP and the Service Corporation                                1993-Present

</TABLE>



                                       40
<PAGE>



<TABLE>
<CAPTION>

NAME                             AGE                             POSITION (a)(b)                               PERIOD
- ----                             ---                             ---------------                               ------

<S>                              <C>   <C>                                                                <C>

Thomas V. Shockley, III.......    56    Director and Vice President of APCo, CPL, I&M, OPCo and SWEPCo     2000-Present
                                        Chief Operating Officer of the Service Corporation                 2001-Present
                                        Vice Chairman of AEP and the Service Corporation                   2000-Present
                                        President and Chief Operating Officer of CSW                       1997-2000
                                        Executive Vice President of CSW                                    1990-1997

Henry W. Fayne................    55    President of APCo, CPL, I&M, OPCo and SWEPCo                       2001-Present
                                        Director of CPL and SWEPCO                                         2000-Present
                                        Director of APCo                                                   1995-Present
                                        Director of OPCo                                                   1993-Present
                                        Director of I&M                                                    1998-Present
                                        Vice President of CPL and SWEPCo                                   2000-2001
                                        Vice President of APCo, I&M and OPCo                               1998-2001
                                        Vice President of AEP                                              1998-Present
                                        Chief Financial Officer of AEP                                     1998-2001
                                        Executive Vice President of the Service Corporation                2001-Present
                                        Executive Vice President-Finance and Analysis of the Service
                                            Corporation                                                    2000-2001
                                        Executive Vice President-Financial Services of the Service
                                            Corporation                                                    1998-2000
                                        Senior Vice President-Corporate Planning & Budgeting of the
                                            Service Corporation                                            1995-1998

Robert P. Powers..............    48    Director and Vice President of APCo, CPL, OPCo and SWEPCo          2001-Present
                                        Director of I&M                                                    2001-Present
                                        Vice President of I&M                                              1998-Present
                                        Executive Vice President-Nuclear Generation and Technical
                                            Services of the Service Corporation                            2001-Present
                                        Senior Vice President-Nuclear Operations of the Service
                                        Corporation                                                        2000-2001
                                        Senior Vice President-Nuclear Generation of the Service
                                            Corporation                                                    1998-2000
                                        Vice President of Pacific Gas & Electric and Plant Manager of
                                            its Diablo Canyon Nuclear Generating Station                   1996-1998

Susan Tomasky.................    48    Director and Vice President of APCo, CPL, I&M, OPCo and SWEPCo     2000-Present
                                        Executive Vice President-Policy, Finance and Strategic Planning
                                            of the Service Corporation                                     2001-Present
                                        Executive Vice President-Legal, Policy and Corporate
                                            Communications and General Counsel of the Service Corporation  2000-2001
                                        Senior Vice President and General Counsel of the Service
                                            Corporation                                                    1998-2000
                                        Hogan & Hartson (law firm)                                         1997-1998
                                        General Counsel of the FERC                                        1993-1997

</TABLE>


                                       41
<PAGE>


<TABLE>
<CAPTION>

NAME                             AGE                             POSITION (a)(b)                               PERIOD
- ----                             ---                             ---------------                               ------

<S>                              <C>   <C>                                                                <C>

J. H. Vipperman...............    61    Director and Vice President of CPL and SWEPCo                      2000-Present
                                        Director of APCo                                                   1985-Present
                                        Director of I&M and OPCo                                           1996-Present
                                        Vice President of APCo, I&M and OPCo                               1996-Present
                                        Executive Vice President-Shared Services of the Service
                                            Corporation                                                    2000-Present
                                        Executive Vice President-Corporate Services of the
                                             Service Corporation                                           1998-2000
                                        Executive Vice President-Energy Delivery of the
                                             Service Corporation                                           1996-1997

</TABLE>

- -----------------
(a)  Dr. Draper is a director of BCP Management, Inc., which is the general
     partner of Borden Chemicals and Plastics L.P.
(b)  Dr. Draper, Messrs. Fayne, Powers, Shockley and Vipperman and Ms. Tomasky
     are directors of AEGCo, CSPCo, KEPCo, PSO and WTU. Dr. Draper and Mr.
     Shockley are also directors of AEP.



PART II ------------------------------------------------------------------------

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

     AEP. The information required by this item is incorporated herein by
reference to the material under Common Stock and Dividend Information in the
2001 Annual Report.

     AEGCO, APCO, CPL, CSPCO, I&M, KEPCO, OPCO, PSO, SWEPCO AND WTU. The common
stock of these companies is held solely by AEP. The amounts of cash dividends on
common stock paid by these companies to AEP during 2001 and 2000 are
incorporated by reference to the material under Statement of Retained Earnings
in the 2001 Annual Reports.


Item 6.  SELECTED FINANCIAL DATA
- --------------------------------------------------------------------------------

     AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(a).

     AEP, APCO, CPL, I&M, OPCO AND SWEPCO. The information required by this item
is incorporated herein by reference to the material under Selected Consolidated
Financial Data in the 2001 Annual Reports.

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

     AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(a).
Management's narrative analysis of the results of operations and other
information required by Instruction I(2)(a) is incorporated herein by reference
to the material under Management's Narrative Analysis of Results of Operations
in the 2001 Annual Reports.

     AEP, APCO, CPL, I&M, OPCO AND SWEPCO. 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 Management's Discussion and
Analysis of Financial Condition, Contingencies and Other Matters in the 2001
Annual Reports.





                                       42
<PAGE>

Item 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
- --------------------------------------------------------------------------------

     AEGCO, AEP, APCO, CPL, CSPCO, I&M, KEPCO, OPCO, PSO, SWEPCO AND WTU. The
information required by this item is incorporated herein by reference to the
material under Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters in the 2001 Annual Reports.

Item 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
- --------------------------------------------------------------------------------

     AEGCO, AEP, APCO, CPL, CSPCO, I&M, KEPCO, OPCO, PSO, SWEPCO AND WTU. 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.

     CPL, PSO, SWEPCO AND WTU. The information required by this item is
incorporated herein by reference to each company's Current Report on Form 8-K
dated July 5, 2000.


PART III -----------------------------------------------------------------------

Item 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
- --------------------------------------------------------------------------------
     AEGCo, CSPCo, KEPCo, PSO and WTU. Omitted pursuant to Instruction I(2)(c).

     AEP. The information required by this item is incorporated herein by
reference to the material under Nominees for Director and Section 16(a)
Beneficial Ownership Reporting Compliance of the definitive proxy statement of
AEP for the 2002 annual meeting of shareholders, to be filed within 120 days
after December 31, 2001. Reference also is made to the information under the
caption Executive Officers of the Registrants in Part I of this report.

     APCO AND OPCO. The information required by this item is incorporated herein
by reference to the material under Election of Directors of the definitive
information statement of each company for the 2002 annual meeting of
stockholders, to be filed within 120 days after December 31, 2001. Reference
also is made to the information under the caption Executive Officers of the
Registrants in Part I of this report.

     CPL AND SWEPCO. 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 2002 annual meeting of
stockholders, to be filed within 120 days after December 31, 2001. Reference
also is made to the information under the caption Executive Officers of the
Registrants in Part I of this report.

     I&M. The names of the directors and executive officers of I&M, the
positions they hold




                                       43
<PAGE>

with I&M, their ages as of March 12, 2002, and a brief account of their business
experience during the past five years appear below and under the caption
Executive Officers of the Registrants in Part I of this report.

<TABLE>
<CAPTION>

NAME                             AGE                              POSITION (a)                                 PERIOD
- ----                             ---                              ------------                                 ------

<S>                                <C>  <C>                                                               <C>
K. G. Boyd.....................    50    Director                                                         1997-Present
                                         Vice President - Fort Wayne Region Distribution Operations       2000-Present
                                         Indiana Region Manager                                           1997-2000
                                         Fort Wayne District Manager                                      1994-1997

John E. Ehler..................    45    Director                                                         2001-Present
                                         Manager of Distribution Systems-Fort Wayne District              2000-Present
                                         Region Operations Manager                                        1997-2000

David L. Lahrman...............    50    Director and Manager, Region Support                             2001-Present
                                         Fort Wayne District Manager                                      1997-2001
                                         Region Operations Manager                                        1994-1997

Marc E. Lewis..................    47    Director                                                         2001-Present
                                         Assistant General Counsel of the Service Corporation             2001-Present
                                         Senior Counsel of the Service Corporation                        2000-2001
                                         Senior Attorney of the Service Corporation                       1994-2000

Susanne M. Moorman............     52    Director and General Manager, Community Services                 2000-Present
                                         Manager, Customer Services Operations                            1997-2000
                                         Director, Customer Services                                      1994-1997

John R. Sampson................    49    Director and Vice President                                      1999-Present
                                         Indiana State President                                          2000-Present
                                         Indiana & Michigan State President                               1999-2000
                                         Site Vice President, Cook Nuclear Plant                          1998-1999
                                         Plant Manager, Cook Nuclear Plant                                1996-1998

D. B. Synowiec.................    58    Director                                                         1995-Present
                                         Plant Manager, Rockport Plant                                    1990-Present


</TABLE>

- -----------------
(a)  Positions are with I&M unless otherwise indicated.


Item 11.  EXECUTIVE COMPENSATION
- --------------------------------------------------------------------------------

     AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(c).

     AEP. The information required by this item is incorporated herein by
reference to the material under Directors Compensation and Stock Ownership
Guidelines, Executive Compensation and the performance graph of the definitive
proxy statement of AEP for the 2002 annual meeting of shareholders to be filed
within 120 days after December 31, 2001.

     APCO AND OPCO. The information required by this item is incorporated herein
by reference to the material under Executive Compensation of the definitive
information statement of each company for the 2002 annual meeting of
stockholders, to be filed within 120 days after December 31, 2001.

     CPL, I&M AND SWEPCO. The information required by this item is incorporated
herein by reference to the material under Executive Compensation of the
definitive information




                                       44
<PAGE>

statement of APCo for the 2002 annual meeting of stockholders, to be filed
within 120 days after December 31, 2001.



Item 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
- --------------------------------------------------------------------------------

     AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(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 for the 2002 annual meeting of
shareholders to be filed within 120 days after December 31, 2001.

     APCO AND 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 each company for the 2002
annual meeting of stockholders, to be filed within 120 days after December 31,
2001.

     CPL AND SWEPCO. 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 2002
annual meeting of stockholders, to be filed within 120 days after December 31,
2001.

     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, 2002, 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 (a)        UNITS (b)        TOTAL
- ----                                                                             ---------         --------         -----
<S>                                                                                 <C>                   <C>       <C>
Karl G. Boyd...........................................................           6,964                 88        7,052
E. Linn Draper, Jr.....................................................         238,274(c)         119,218      357,492
John E. Ehler..........................................................               7                 --            7
Henry W. Fayne.........................................................          72,685(d)          13,735       86,420
David L. Lahrman.......................................................             360                 --          360
Marc E. Lewis..........................................................           1,117                 --        1,117
Susanne M. Moorman.....................................................             841                 --          841
Robert P. Powers.......................................................          21,269              1,209       22,478
John R. Sampson........................................................           5,525                109        5,634
Thomas V. Shockley, III................................................         138,822(d)(e)           --      138,822
David B. Synowiec......................................................           2,361                129        2,490
Susan Tomasky..........................................................          67,322              4,329       71,651
Joseph H. Vipperman....................................................          78,043(c)(d)        7,201       85,244
All Directors and Executive Officers...................................         633,590(d)(f)      146,018      779,608

</TABLE>




                                       45
<PAGE>



- -------------------------
(a)    Includes share equivalents held in the AEP Retirement Savings Plan (and
       for Mr. Shockley, the CSW Retirement Savings Plan) in the amounts listed
       below:


<TABLE>
<CAPTION>

                                AEP RETIREMENT SAVINGS                                          AEP RETIREMENT SAVINGS
         NAME                 PLAN (SHARE EQUIVALENTS)           NAME                         PLAN (SHARE EQUIVALENTS)
         ----                 ------------------------           ----                         ------------------------
<S>                                            <C>            <C>                                            <C>
       Mr. Boyd.............................     1,964           Mr. Powers.................................       436
       Dr. Draper...........................     4,280           Mr. Sampson................................       525
       Mr. Ehler............................         7           Mr. Shockley...............................     6,579
       Mr. Fayne............................     5,412           Mr. Synowiec...............................       695
       Mr. Lahrman..........................       360           Ms. Tomasky................................       656
       Mr. Lewis............................     1,117           Mr. Vipperman..............................    10,498
       Ms. Moorman.........................`       841      All Directors and Executive Officers............    33,370

</TABLE>

       With respect to the share equivalents held in the AEP Retirement
       Savings Plan, such persons have sole voting power, but the
       investment/disposition power is subject to the terms of the Plan.
       Also, includes the following numbers of shares attributable to options
       exercisable within 60 days: Mr. Boyd, 5,000; Dr. Draper, 233,333; Mr.
       Powers, 20,833; Mr. Sampson, 5,000; Mr. Shockley, 94,450; Mr.
       Synowiec, 1,666; and Messrs. Fayne and Vipperman and Ms. Tomasky,
       66,666.

(b)  This column includes amounts deferred in stock units and held under AEP's
     officer benefit plans.

(c)  Includes the following numbers of shares held in joint tenancy with a
     family member: Dr. Draper, 661; and Mr. Vipperman, 80.

(d)  Does not include, for Messrs. Fayne, Shockley and Vipperman, 85,231 shares
     in the American Electric Power System Educational Trust Fund over which
     Messrs. Fayne, Shockley and Vipperman 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 by family members over which
     beneficial ownership is disclaimed: Mr. Shockley, 496.

(f)  Represents less than 1% of the total number of shares outstanding

Item 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
- --------------------------------------------------------------------------------


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

     AEGCO, CSPCO, KEPCO, PSO AND WTU. Omitted pursuant to Instruction I(2)(c).


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.

<TABLE>
<CAPTION>
<S>                                                                                  <C>
                                                                                       PAGE
                                                                                       ----
       AEGCo:
          Independent Auditors' Report; Statements of Income for the years ended
          December 31, 2001, 2000, and 1999; Statements of Retained Earnings for
          the years ended December 31, 2001, 2000 and 1999; Statements of Cash
          Flows for the years ended December 31, 2001, 2000, and 1999; Balance
          Sheets as of December 31, 2001 and 2000; Statements of Capitalization
          as of December 31, 2001 and 2000; Combined Notes to Financial
          Statements.

       AEP and its subsidiaries consolidated:
          Consolidated Statements of Income for the years ended December 31,
          2001, 2000, and 1999; Consolidated Balance Sheets as of December 31,
          2001 and 2000; Consolidated

</TABLE>



                                       46
<PAGE>
                                                                            PAGE
                                                                            ----

          Statements of Cash Flows for the years ended December 31, 2001, 2000,
          and 1999; Consolidated Statements of Common Shareholders' Equity and
          Comprehensive Income for the years ended December 31, 2001, 2000, and
          1999; Combined Notes to Financial Statements; Schedule of Consolidated
          Cumulative Preferred Stocks of Subsidiaries at December 31, 2001 and
          2000; Schedule of Consolidated Long-term Debt of Subsidiaries at
          December 31, 2001 and 2000; Independent Auditors' Reports.

       APCo, I&M, and OPCo:
          Independent Auditors' Report; Consolidated Statements of Income for
          the years ended December 31, 2001, 2000, and 1999; Consolidated
          Statements of Comprehensive Income for the years ended December 31,
          2001, 2000 and 1999; Consolidated Balance Sheets as of December 31,
          2001 and 2000; Consolidated Statements of Cash Flows for the years
          ended December 31, 2001, 2000, and 1999; Consolidated Statements of
          Retained Earnings for the years ended December 31, 2001, 2000, and
          1999; Consolidated Statements of Capitalization as of December 31,
          2001 and 2000; Schedule of Consolidated Long-term Debt as of December
          31, 2001 and 2000; Combined Notes to Financial Statements.

       CPL, CSPCo, PSO, and SWEPCo:
          Independent Auditors' Report(s); Consolidated Statements of Income for
          the years ended December 31, 2001, 2000, and 1999; Consolidated
          Balance Sheets as of December 31, 2001 and 2000; Consolidated
          Statements of Cash Flows for the years ended December 31, 2001, 2000,
          and 1999; Consolidated Statements of Retained Earnings for the years
          ended December 31, 2001, 2000, and 1999; Consolidated Statements of
          Capitalization as of December 31, 2001 and 2000; Schedule of
          Consolidated Long-term Debt as of December 31, 2001 and 2000; Combined
          Notes to Financial Statements.

        KEPCo:
          Independent Auditors' Report; Statements of Income for the years ended
          December 31, 2001, 2000, and 1999; Statements of Retained Earnings for
          the years ended December 31, 2001, 2000, and 1999; Statements of Cash
          Flows for the years ended December 31, 2001, 2000, and 1999;
          Statements of Comprehensive Income for the years ended December 31,
          2001, 2000 and 1999; Balance Sheets as of December 31, 2001 and 2000;
          Statements of Capitalization as of December 31, 2001 and 2000;
          Schedule of Long-term Debt as of December 31, 2001 and 2000; Combined
          Notes to Financial Statements.

        WTU:
          Independent Auditors' Reports; Statements of Income for the years
          ended December 31, 2001, 2000, and 1999; Statements of Retained
          Earnings for the years ended December 31, 2001, 2000, and 1999;
          Statements of Cash Flows for the years ended December 31, 2001, 2000,
          and 1999; Balance Sheets as of December 31, 2001 and 2000; Statements
          of Capitalization as of December 31, 2001 and 2000; Schedule of
          Long-term Debt as of December 31, 2001 and 2000; Combined Notes to
          Financial Statements.




                                       47
<PAGE>
                                                                            PAGE
                                                                            ----



<TABLE>
<CAPTION>

<S>                                                                                  <C>
2.   FINANCIAL STATEMENT SCHEDULES:

                                                                                     Page
                                                                                     ----

     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, CPL, CSPCo, I&M, KEPCo, OPCo, PSO, SWEPCo
     and WTU 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,
2001.

</TABLE>



                                       48
<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/  SUSAN TOMASKY
                                     -------------------------------------------
                                       (SUSAN TOMASKY, VICE PRESIDENT,
                                       SECRETARY AND CHIEF FINANCIAL OFFICER)

Date:  March 18, 2002

     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/ SUSAN TOMASKY                                   Vice President, Secretary and           March 18, 2002
- --------------------------------------------                     Chief Financial Officer
              (SUSAN TOMASKY)

(iii) PRINCIPAL ACCOUNTING OFFICER:

          /s/ JOSEPH M. BUONAIUTO                                    Controller and                   March 18, 2002
- -------------------------------------------                    Chief Accounting Officer
             (JOSEPH M. BUONAIUTO)

(iv)  A MAJORITY OF THE DIRECTORS:

                *E. R. BROOKS
              *DONALD M. CARLTON
              *JOHN P. DESBARRES
                *ROBERT W. FRI
              *WILLIAM R. HOWELL
            *LESTER A. HUDSON, JR.
              *LEONARD J. KUJAWA
               *JAMES L. POWELL
              *RICHARD L. SANDOR
           *THOMAS V. SHOCKLEY, III
               *DONALD G. SMITH
           *LINDA GILLESPIE STUNTZ
             *KATHRYN D. SULLIVAN
                                                                                                      March 18, 2002
*By:       /s/ SUSAN TOMASKY
    ---------------------------------
    (SUSAN TOMASKY, ATTORNEY-IN-FACT)
</TABLE>



                                       49
<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
                                       APPALACHIAN POWER COMPANY
                                       CENTRAL POWER AND LIGHT COMPANY
                                       COLUMBUS SOUTHERN POWER COMPANY
                                       KENTUCKY POWER COMPANY
                                       OHIO POWER COMPANY
                                       PUBLIC SERVICE COMPANY OF OKLAHOMA
                                       SOUTHWESTERN ELECTRIC POWER COMPANY
                                       WEST TEXAS UTILITIES COMPANY

                                           BY:        /s/  SUSAN TOMASKY
                                              ---------------------------------
                                              (SUSAN TOMASKY, VICE PRESIDENT)


Date:  March 18, 2002

     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/ SUSAN TOMASKY                                         Vice President                   March 18, 2002
      -------------------------------------------                     And Director
              (SUSAN TOMASKY)

(iii) PRINCIPAL ACCOUNTING OFFICER:

          /s/ JOSEPH M. BUONAIUTO                                     Controller and                  March 18, 2002
      -------------------------------------------                  Chief Accounting Officer
             (JOSEPH M. BUONAIUTO)

(iv)  A MAJORITY OF THE DIRECTORS:

              *HENRY W. FAYNE
                *A. A. PENA
             *ROBERT P. POWERS
          *THOMAS V. SHOCKLEY, III
              *J. H. VIPPERMAN
                                                                                                      March 18, 2002
*By:    /s/ SUSAN TOMASKY
    -------------------------------------------
           (SUSAN TOMASKY, ATTORNEY-IN-FACT)
</TABLE>



                                       50

<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/  SUSAN TOMASKY
                                        ----------------------------------------
                                          (SUSAN TOMASKY, VICE PRESIDENT)

Date:  March 18, 2002

     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/ SUSAN TOMASKY                                          Vice President                   March 18, 2002
      ------------------------------------------------                 And Director
               (SUSAN TOMASKY)

(iii) PRINCIPAL ACCOUNTING OFFICER:

          /s/ JOSEPH M. BUONAIUTO                                       Controller and                 March 18, 2002
      ------------------------------------------------            Chief Accounting Officer
            (JOSEPH M. BUONAIUTO)

(iv)  A MAJORITY OF THE DIRECTORS
:
                *K. G. BOYD
              *JOHN E. EHLER
              *HENRY W. FAYNE
             *DAVID L. LAHRMAN
              *MARC E. LEWIS
            *SUSANNE M. MOORMAN
             *ROBERT P. POWERS
             *JOHN R. SAMPSON
         *THOMAS V. SHOCKLEY, III
              *D. B. SYNOWIEC
             *J. H. VIPPERMAN

*By:     /s/ SUSAN TOMASKY
    --------------------------------------------------
    (SUSAN TOMASKY, ATTORNEY-IN-FACT)                                                                  March 18, 2002
</TABLE>




                                       51

<PAGE>



                     INDEX TO FINANCIAL STATEMENT SCHEDULES

<TABLE>

                                                                                                                     Page
<S>                                                                                                                  <C>
INDEPENDENT AUDITORS' REPORT ...............................................................................          S-2

The following financial statement schedules 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

CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
        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-4

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-5

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
        Schedule II-- Valuation and Qualifying Accounts and Reserves.......................................           S-5

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
        Schedule II-- Valuation and Qualifying Accounts and Reserves.......................................           S-5

WEST TEXAS UTILITIES COMPANY
        Schedule II-- Valuation and Qualifying Accounts and Reserves.......................................           S-6
</TABLE>


                                      S-1

<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, 2001 and 2000,
and for each of the three years in the period ended December 31, 2001, and have
issued our reports thereon dated February 22, 2002; such financial statements
and reports are included in the 2001 Annual Reports 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, except for the financial statement schedules of
Central Power and Light Company and subsidiary, Public Service Company of
Oklahoma and its subsidiaries, Southwestern Electric Power Company and
subsidiaries, and West Texas Utilities Company for the year ended December 31,
1999 and the financial information of Central and South West Corporation and its
subsidiaries that is included in the financial statement schedule for American
Electric Power Company, Inc. and its subsidiaries for the year ended December
31, 1999. 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 22, 2002



                                      S-2
<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
- ---------------------------------------------------------------------------------------------------------------------------
                                                                            (IN THOUSANDS)
<S>                                            <C>             <C>            <C>            <C>              <C>
DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
        Year Ended December 31, 2001.......     $71,722         $124,542       $19,766(a)     $106,589(b)      $109,441
                                                =======         ========       =======        ========         ========
        Year Ended December 31, 2000.......     $63,207         $ 70,670       $ 8,358(a)     $ 70,513(b)      $ 71,722
                                                =======         ========       =======        ========         ========
        Year Ended December 31, 1999.......     $52,543         $ 38,347       $15,802(a)     $ 43,485(b)      $ 63,207
                                                =======         ========       =======        ========         ========
- ---------------------
(a)   Recoveries on accounts previously written off.
(b)   Uncollectible accounts written off.
===========================================================================================================================
</TABLE>

<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
- ---------------------------------------------------------------------------------------------------------------------------
                                                                            (IN THOUSANDS)
<S>                                            <C>             <C>            <C>            <C>              <C>
DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
        Year Ended December 31, 2001.......      $2,588          $2,644        $1,017(a)        $4,372(b)       $1,877
                                                 ======          ======        ======           ======          ======
        Year Ended December 31, 2000.......      $2,609          $6,592        $1,526(a)        $8,139(b)       $2,588
                                                 ======          ======        ======           ======          ======
        Year Ended December 31, 1999.......      $2,234          $5,492        $1,995(a)        $7,112(b)       $2,609
                                                 ======          ======        ======           ======          ======
- ---------------------
(a)   Recoveries on accounts previously written off.
(b)   Uncollectible accounts written off.
===========================================================================================================================
</TABLE>

<TABLE>
<CAPTION>

===========================================================================================================================

                                          CENTRAL POWER AND LIGHT AND SUBSIDIARY
                               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
- ---------------------------------------------------------------------------------------------------------------------------
                                                                            (IN THOUSANDS)
<S>                                            <C>             <C>            <C>            <C>              <C>

DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
        Year Ended December 31, 2001.......      $1,675          $  186        $ --_ (a)        $1,675(b)        $  186
                                                 ======          ======        ======           ======           ======
        Year Ended December 31, 2000.......      $--             $1,675        $ --  (a)        $ --  (b)        $1,675
                                                 ======          ======        ======           ======           ======
        Year Ended December 31, 1999.......      $--             $--           $ --  (a)        $ --  (b)        $--
                                                 ======          ======        ======           ======           ======
- ---------------------
(a)   Recoveries on accounts previously written off.
(b)   Uncollectible accounts written off.
===========================================================================================================================
</TABLE>



                                      S-3
<PAGE>


<TABLE>
<CAPTION>

                                     COLUMBUS SOUTHERN 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
- ---------------------------------------------------------------------------------------------------------------------------
                                                                            (IN THOUSANDS)
<S>                                            <C>             <C>            <C>            <C>              <C>
DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
        Year Ended December 31, 2001.......      $  659          $  331        $    --(a)      $   245(b)       $   745
                                                 ======          ======        =======         =======          =======
        Year Ended December 31, 2000.......      $3,045          $2,082        $ 1,405(a)      $ 5,873(b)       $   659
                                                 ======          ======        =======         =======          =======
        Year Ended December 31, 1999.......      $2,598          $3,334        $10,782(a)      $13,669(b)       $ 3,045
                                                 ======          ======        =======         =======          =======
- ---------------------
(a)   Recoveries on accounts previously written off.
(b)   Uncollectible accounts written off.
===========================================================================================================================
</TABLE>

<TABLE>
<CAPTION>

===========================================================================================================================

                                     INDIANA MICHIGAN 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
- ---------------------------------------------------------------------------------------------------------------------------
                                                                            (IN THOUSANDS)
<S>                                            <C>             <C>            <C>            <C>              <C>
DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
        Year Ended December 31, 2001.......      $  759          $   65      $    3(a)       $   86(b)      $  741
                                                 ======          ======      ======          ======         ======
        Year Ended December 31, 2000.......      $1,848          $ (235)     $  907(a)       $1,761(b)      $  759
                                                 ======          ======      ======          ======         ======
        Year Ended December 31, 1999.......      $2,027          $3,966      $1,367(a)       $5,512(b)      $1,848
                                                 ======          ======      ======          ======         ======
- ---------------------
(a)   Recoveries on accounts previously written off.
(b)   Uncollectible accounts written off.
===========================================================================================================================
</TABLE>

<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
- ---------------------------------------------------------------------------------------------------------------------------
                                                                            (IN THOUSANDS)
<S>                                            <C>             <C>            <C>            <C>              <C>
DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
        Year Ended December 31, 2001.......       $282          $   --      $(24)(a)         $  (6)(b)         $264
                                                  ====          ======      =====            =======           ====
        Year Ended December 31, 2000.......       $637          $  187      $  9 (a)         $  551(b)         $282
                                                  ====          ======      =====            ======            ====
        Year Ended December 31, 1999.......       $848          $1,032      $ 467(a)         $1,710(b)         $637
                                                  ====          ======      =====            ======            ====
- ---------------------
(a)   Recoveries on accounts previously written off.
(b)   Uncollectible accounts written off.
===========================================================================================================================
</TABLE>



                                      S-4
<PAGE>


<TABLE>
<CAPTION>

===========================================================================================================================

                                           OHIO 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
- ---------------------------------------------------------------------------------------------------------------------------
                                                                            (IN THOUSANDS)
<S>                                            <C>             <C>            <C>            <C>              <C>
DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
        Year Ended December 31, 2001.......      $1,054           $  554       $ --  (a)      $  229(b)         $1,379
                                                 ======           ======       ======         ======            ======
        Year Ended December 31, 2000.......      $2,223           $  472       $  778(a)      $2,419(b)         $1,054
                                                 ======           ======       ======         ======            ======
        Year Ended December 31, 1999.......      $1,678           $4,730       $1,273(a)      $5,458(b)         $2,223
                                                 ======           ======       ======         ======            ======
- ---------------------
(a)   Recoveries on accounts previously written off.
(b)   Uncollectible accounts written off.
===========================================================================================================================
</TABLE>

<TABLE>
<CAPTION>

===========================================================================================================================

                                   PUBLIC SERVICE COMPANY OF OKLAHOMA 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
- ---------------------------------------------------------------------------------------------------------------------------
                                                                            (IN THOUSANDS)
<S>                                            <C>             <C>            <C>            <C>              <C>
DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
        Year Ended December 31, 2001.......      $  467         $    44         $ --  (a)     $   467(b)        $   44
                                                 ======         =======         ======        =======           ======
        Year Ended December 31, 2000.......      $--            $   467         $ --  (a)     $ --   (b)        $  467
                                                 ======         =======         ======        =======           ======
        Year Ended December 31, 1999.......      $--            $ --            $ --  (a)     $ --   (b)        $ --
                                                 ======         =======         ======        =======           ======
- ---------------------
(a)   Recoveries on accounts previously written off.
(b)   Uncollectible accounts written off.
===========================================================================================================================
</TABLE>

<TABLE>
<CAPTION>

===========================================================================================================================

                                   SOUTHWESTERN ELECTRIC 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
- ---------------------------------------------------------------------------------------------------------------------------
                                                                            (IN THOUSANDS)
<S>                                            <C>             <C>            <C>            <C>              <C>
DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
        Year Ended December 31, 2001.......      $  911         $   89        $   --  (a)      $  911(b)        $   89
                                                 ======         ======        =======          ======           ======
        Year Ended December 31, 2000.......      $4,428         $  911        $(4,428)(a)      $  -- (b)        $  911
                                                 ======         ======        =======          ======           ======
        Year Ended December 31, 1999.......      $3,269         $5,415        $   --  (a)      $4,256(b)        $4,428
                                                 ======         ======        =======          ======           ======
- ---------------------
(a)   Recoveries on accounts previously written off.
(b)   Uncollectible accounts written off.
===========================================================================================================================
</TABLE>


                                      S-5

<PAGE>


<TABLE>
<CAPTION>

===========================================================================================================================

                                               WEST TEXAS UTILITIES 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
- ---------------------------------------------------------------------------------------------------------------------------
                                                                            (IN THOUSANDS)
<S>                                            <C>             <C>            <C>            <C>              <C>
DEDUCTED FROM ASSETS:
   Accumulated Provision for
     Uncollectible Accounts:
        Year Ended December 31, 2001.......       $288           $   13         $35(a)        $  140(b)          $196
                                                  ====           ======         ===           ======             ====
        Year Ended December 31, 2000.......       $186           $1,499         $46(a)        $1,443(b)          $288
                                                  ====           ======         ===           ======             ====
        Year Ended December 31, 1999.......       $497           $  (66)        $43(a)        $  288(b)          $186
                                                  ====            =====         ===           ======             ====

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


                                      S-6

<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. 229.10(d) and 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
(+), 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.

<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
   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 (amended as of June 15, 2000) [Annual
                           Report on Form 10-K of AEGCo for the fiscal year ended December 31, 2000,
                           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 2001 Annual Report (for the fiscal year ended December 31,
                           2001) which are incorporated by reference in this filing.
 *24               --      Power of Attorney.

  AEP++
   3(a)            --      Copy of Restated Certificate of Incorporation of AEP, dated October 29, 1997
                           [Quarterly Report on Form 10-Q of AEP for the quarter ended September 30, 1997,
                           File No. 1-3525, Exhibit 3(a)].
   3(b)            --      Copy of Certificate of Amendment of the Restated Certificate of Incorporation of AEP,
                           dated January 13, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended
                           December 31, 1998, File No. 1-3525, Exhibit 3(b)].
   3(c)            --      Composite copy of the Restated Certificate of Incorporation of AEP, as amended
                           [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998,
                           File No. 1-3525, Exhibit 3(c)].
   3(d)            --      Copy of By-Laws of AEP, as amended through January 28, 1998 [Annual Report on Form 10-K
                           of AEP for the fiscal year ended December 31, 1997, File No. 1-3525, Exhibit 3(b)].
  *4(a)            --      Indenture (for unsecured debt securities), dated as of May 1, 2001, between AEP and The Bank
                           of New York, as Trustee.
</TABLE>


                                      E-1

<PAGE>

<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
  *4(b)            --      First Supplemental Indenture, dated as of May 1, 2001, between AEP and The Bank of New York,
                           as Trustee, for 6.125% Senior Notes, Series A, due May 15, 2006.
  *4(c)            --      Second Supplemental Indenture, dated as of May 1, 2001, between AEP and The Bank of New York, as
                           Trustee, for 5.50% Putable Callable Notes, Series B, Putable Callable May 15, 2003.
  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)].
  10(c)            --      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(d)            --      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)].
  10(e)            --      Modification No. 1 to the 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 AEP
                           for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
  10(f)(1)         --      Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
                           Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
                           [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
                           1-3525, Exhibit 10(f)].
  10(f)(2)         --      Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
                           Report on Form 8-K of AEP dated December 15, 1999, File No. 1-3525, Exhibit 10].
 +10(g)(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)].
 +10(g)(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)].
 +10(h)            --      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)].
</TABLE>


                                      E-2

<PAGE>

<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
+10(i)(1)          --      AEP Deferred Compensation and Stock Plan for Non-Employee Directors, as amended June 1, 2000
                           [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525,
                           Exhibit 10(i)(1)].
*+10(i)(2)         --      AEP Stock Unit Accumulation Plan for Non-Employee Directors, as amended January 1, 2002.
+10(j)(1)(A)       --      AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001 [Annual Report on
                           Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525,
                           Exhibit 10(j)(1)(A)].
+10(j)(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)].
+10(j)(2)          --      AEP System Supplemental Retirement Savings Plan, Amended and Restated as of June 1, 2001
                           (Non-Qualified) [Registration Statement No. 333-66048, Exhibit 4].
+10(j)(3)          --      Service Corporation Umbrella Trust 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)].
+10(k)             --      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)].
+10(l)             --      AEP System Senior Officer Annual Incentive Compensation Plan[Annual Report on Form 10-K of AEP
                           for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
+10(m)             --      AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of
                           AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].
+10(n)             --      AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective
                           March 1, 1999 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No.
                           1-3525, Exhibit 10(o)].
*+10(o)            --      AEP Change In Control Agreement.
+10(p)             --      AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000].
+10(q)             --      Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3,
                           2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000,
                           File No. 1-3525, Exhibit 10(s)].
+10(r)(1)          --      Central and South West System Special Executive Retirement Plan as amended and restated effective
                           July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998,
                           File No. 1-1443, Exhibit 18].
*+10(r)(2)         --      Certified CSW Board Resolution of April 18, 1991.
+10(r)(3)          --      CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992].
*12                --      Statement re: Computation of Ratios.
*13                --      Copy of those portions of the AEP 2001 Annual Report (for the fiscal year ended December 31,
                           2001) which are incorporated by reference in this filing.
*21                --      List of subsidiaries of AEP.
*23(a)             --      Consent of Deloitte & Touche LLP.
*23(b)             --      Consent of Arthur Andersen LLP.
*23(c)             --      Consent of KPMG Audit plc.
*24                --      Power of Attorney.
</TABLE>


                                      E-3
<PAGE>


<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
    APCO++
    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)           --      Copy of Articles of Amendment to the Restated Articles of Incorporation of APCo, dated
                           March 6, 1997 [Annual Report on Form 10-K of APCo for the fiscal year ended December 31,
                           1996, File No. 1-3457, Exhibit 3(c)].
    3(d)           --      Composite copy of the Restated Articles of Incorporation of APCo (amended as
                           of March 7, 1997) [Annual Report on Form 10-K of APCo for the fiscal
                           year ended December 31, 1996, File No. 1-3457, Exhibit 3(d)].
   *3(e)           --      Copy of By-Laws of APCo (amended as of October 24, 2001).
    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);
                           Registration Statement No. 333-20305, Exhibits 4(b) and 4(c); Annual
                           Report on Form 10-K of APCo for the fiscal year ended December 31,
                           1996, File No. 1-3457, Exhibit 4(b); Annual Report on Form 10-K of
                           APCo for the fiscal year ended December 31, 1998, File No. 1-3457,
                           Exhibit 4(b)].
    4(b)           --      Indenture (for unsecured debt securities), dated as of January 1, 1998, between APCo and The
                           Bank of New York, As Trustee [Registration Statement No. 333-45927, Exhibit 4(a);
                           Registration Statement No. 333-49071, Exhibit 4(b); Registration Statement No. 333-84061,
                           Exhibits 4(b) and 4(c); Annual Report on Form 10-K of APCo for the fiscal year ended December
                           31, 1999, File No. 1-3457, Exhibit 4(c); Registration Statement No. 333-81402, Exhibits 4(b),
                           4(c) and 4(d)].
</TABLE>


                                      E-4
<PAGE>


<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
  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 Modification No. 1 to the 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 AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
  10(e)(1)         --      Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
                           Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
                           [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
                           1-3525, Exhibit 10(f)].
  10(e)(2)         --      Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
                           Report on Form 8-K of APCo dated December 15, 1999, File No. 1-3457, Exhibit 10].

 +10(f)(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)].

 +10(f)(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)].

 +10(g)            --      AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP
                           for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
</TABLE>



                                      E-5
<PAGE>

<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
 +10(h)(1)        --      AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001 [Annual Report on Form
                          10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(1)(A)].
+10(h)(2)         --      AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2001
                          (Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000,
                          File No. 1-3525, Exhibit 10(j)(2)].
+10(h)(3)         --      Umbrella Trust 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)].
+10(i)            --      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)].
+10(j)            --      AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of
                          AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].
+10(k)            --      AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective
                          March 1, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998,
                          File No. 1-3525, Exhibit 10(o)].
+10(l)            --      AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended
                          December 31, 2001, File No. 1-3525, Exhibit 10(o)].
+10(m)            --      AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000].
+10(n)            --      Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3,
                          2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000,
                          File No. 1-3525, Exhibit 10(s)].
+10(o)(1)         --      Central and South West System Special Executive Retirement Plan as amended and restated effective
                          July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998,
                          File No. 1-1443, Exhibit 18].
+10(o)(2)         --      Certified CSW Board Resolution of April 18, 1991 [Annual Report on Form 10-K of AEP for the fiscal
                          year ended December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
+10(o)(3)         --      CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992].
*12               --      Statement re: Computation of Ratios.
*13               --      Copy of those portions of the APCo 2001 Annual Report (for the fiscal year ended December 31,
                          2001) 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, 2001, File No. 1-3525, Exhibit 21].
*24               --      Power of Attorney.

CPL++
  3(a)            --      Restated Articles of Incorporation Without Amendment, Articles of Correction to Restated
                          Articles of Incorporation Without Amendment, Articles of Amendment to Restated Articles of
                          Incorporation, Statements of Registered Office and/or Agent, and Articles of Amendment to the
                          Articles of Incorporation [Quarterly Report on Form 10-Q of CPL for the quarter ended March
                          31, 1997, File No. 0-346, Exhibit 3.1].
  3(b)            --      By-Laws of CPL (amended as of April 19, 2000) [Annual Report on Form 10-K of CPL for the fiscal
                          year ended December 31, 2000, File No. 0-346, Exhibit 3(b)].
</TABLE>


                                      E-6
<PAGE>

<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>              <C>      <C>
  4(a)           --        Indenture of Mortgage or Deed of Trust, dated November 1, 1943, between CPL and The First
                           National Bank of Chicago and R. D. Manella, as Trustees, as amended and supplemented
                           [Registration Statement No. 2-60712, Exhibit 5.01;  Registration Statement No. 2-62271,
                           Exhibit 2.02; Form U-1 No. 70-7003, Exhibit 17; Registration Statement No. 2-98944, Exhibit 4
                           (b); Form U-1 No. 70-7236, Exhibit 4; Form U-1 No. 70-7249, Exhibit 4; Form U-1 No. 70-7520,
                           Exhibit 2; Form U-1 No. 70-7721, Exhibit 3; Form U-1 No. 70-7725, Exhibit 10; Form U-1 No.
                           70-8053, Exhibit 10 (a); Form U-1 No. 70-8053, Exhibit 10 (b);  Form U-1 No. 70-8053, Exhibit
                           10 (c); Form U-1 No. 70-8053, Exhibit 10 (d); Form U-1 No. 70-8053, Exhibit 10 (e); Form U-1
                           No. 70-8053, Exhibit 10 (f)].
  4(b)           --        CPL-obligated,  mandatorily redeemable preferred securities of subsidiary trust holding solely
                           Junior Subordinated Debentures of CPL:
                           (1)  Indenture, dated as of May 1, 1997, between CPL and the Bank of New York, as Trustee
                                [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibits 4.1 and
                                4.2].
                           (2)  Amended and Restated Trust Agreement of CPL Capital I, dated as of May 1, 1997, among CPL,
                                as Depositor, the Bank of New York, as Property Trustee, The Bank of New York (Delaware), as
                                Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of CPL dated
                                March 31, 1997, File No. 0-346, Exhibit 4.3].
                           (3)  Guarantee Agreement, dated as of May 1, 1997, delivered by CPL for the benefit of the holders
                                of CPL Capital I's Preferred Securities [Quarterly Report on Form 10-Q of CPL dated
                                March 31, 1997, File No. 0-346, Exhibit 4.4].
                           (4)  Agreement as to Expenses and Liabilities dated as of May 1, 1997, between CPL and CPL Capital I
                                [Quarterly Report on Form 10-Q of CPL dated March 31, 1997, File No. 0-346, Exhibit 4.5].
  4(c)           --        Indenture (for unsecured debt securities), dated as of November 15, 1999, between CPL and The Bank of
                           New York, as Trustee, as amended and supplemented [Annual Report on Form 10-K of CPL for the fiscal
                           year ended December 31, 2000, File No. 0-346, Exhibits 4(c), 4(d) and 4(e)].
*12              --        Statement re: Computation of Ratios.
*13              --        Copy of those portions of the CPL 2001 Annual Report (for the fiscal year ended December 31, 2001)
                           which are incorporated by reference in this filing.
*23(a)           --        Consent of Deloitte & Touche LLP.
*23(b)           --        Consent of Arthur Andersen LLP.
*24              --        Power of Attorney.

CSPCO++
  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)].
</TABLE>


                                      E-7
<PAGE>

<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
  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)].
  4(b)           --        Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between CSPCo
                           and Bankers Trust Company, as Trustee [Registration Statement No. 333-54025, Exhibits 4(a), 4(b),
                           4(c) and 4(d); Annual Report on Form 10-K of CSPCo for the fiscal year ended December 31, 1998,
                           File No. 1-2680, Exhibits 4(c) and 4(d)].
 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)].
 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 Modification No. 1 to the 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 AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
</TABLE>


                                      E-8
<PAGE>


<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
 10(e)(1)        --        Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
                           Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
                           [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
                           1-3525, Exhibit 10(f)].
 10(e)(2)        --        Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
                           Report on Form 8-K of CSPCo dated December 15, 1999, File No. 1-2680, Exhibit 10].
*12              --        Statement re: Computation of Ratios.
*13              --        Copy of those portions of the CSPCo 2001 Annual Report (for the fiscal year ended December 31,
                           2001) which are incorporated by reference in this filing.
*23              --        Consent of Deloitte & Touche LLP.
*24              --        Power of Attorney.

I&M++
  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)           --        Copy of Articles of Amendment to the Amended Articles of Acceptance of I&M, dated March 6,
                           1997 [Annual Report on Form 10-K of I&M for fiscal year ended December 31, 1996,
                           File No. 1-3570, Exhibit 3(b)].
  3(c)           --        Composite Copy of the Amended Articles of Acceptance of I&M (amended as of March 7, 1997)
                           [Annual Report on Form 10-K of I&M for the fiscal year ended December 31, 1996, File No. 1-3570,
                           Exhibit 3(c)].
 *3(d)           --        Copy of the By-Laws of I&M (amended as of November 28, 2001).
  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 the fiscal year ended December
                           31, 1993, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of I&M for the  fiscal
                           year ended December 31, 1994, File No. 1-3570, Exhibit 4(b); Annual Report on Form 10-K of
                           I&M for the fiscal year ended December 31, 1996, File No. 1-3570, Exhibit 4(b)].
  4(b)           --        Copy of Indenture (for unsecured debt securities), dated as of October 1, 1998, between
                           I&M and The Bank of New York, as Trustee [Registration Statement No. 333-88523,
                           Exhibits 4(a), 4(b) and 4(c); Registration Statement No. 58656, Exhibits 4(b) and 4(c)].
 *4(c)           --        Copy of Company Order and Officers' Certificate, dated December 12, 2001, establishing
                           certain terms of the 6.125% Notes, Series C, due 2006.
</TABLE>


                                      E-9
<PAGE>


<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
 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)].
 10(a)(4)        --        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)(5)        --        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, 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 Modification No. 1 to the 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 AEP for the fiscal year ended December 1, 1996, File No. 1-3525, Exhibit 10(l)].
 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)].
</TABLE>


                                      E-10
<PAGE>


<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
 10(g)(1)         --       Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
                           Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
                           [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
                           1-3525, Exhibit 10(f)].
 10(g)(2)         --       Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
                           Report on Form 8-K of I&M dated December 15, 1999, File No. 1-3570, Exhibit 10].
*12               --       Statement re: Computation of Ratios.
*13               --       Copy of those portions of the I&M 2001 Annual Report (for the fiscal year ended December 31,
                           2001) 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, 2001, File No. 1-3525, Exhibit 21].
*23               --       Consent of Deloitte & Touche LLP.
*24               --       Power of Attorney.

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 June 15, 2000) [Annual Report on Form 10-K of KEPCo for the
                           fiscal year ended December 31, 2000, File No. 1-6858, Exhibit 3(b)].
  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)].
  4(b)           --        Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between
                           KEPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-75785, Exhibits
                           4(a), 4(b), 4(c) and 4(d); Annual Report on Form 10-K of KEPCo for the fiscal year ended
                           December 31, 1999, File No. 1-6858, Exhibit 4(c); Annual Report on Form 10-K of KEPCo for the
                           fiscal year ended December 31, 2000, File No. 1-6858, Exhibit 4(c)].
 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 Modification No. 1 to the 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 AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
</TABLE>


                                      E-11
<PAGE>


<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
 10(d)(1)         --       Agreement and Plan of Merger, dated as of December 21, 1997, By and Among American Electric
                           Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
                           [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
                           1-3525, Exhibit 10(f)].
 10(d)(2)         --       Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
                           Report on Form 8-K of KEPCo dated December 15, 1999, File No. 1-6858, Exhibit 10].
*12               --       Statement re: Computation of Ratios.
*13               --       Copy of those portions of the KEPCo 2001 Annual Report (for the fiscal year ended December 31,
                           2001) which are incorporated by reference in this filing.
*24               --       Power of Attorney.

OPCO++
  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)            --       Copy of Certificate of Amendment to Amended Articles of Incorporation of OPCo, dated March 6,
                           1997 [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File
                           No. 1-6543, Exhibit 3(c)].
  3(d)            --       Composite copy of the Amended Articles of Incorporation of OPCo (amended as of March 7, 1997)
                           [Annual Report on Form 10-K of OPCo for the fiscal year ended December 31, 1996, File No. 1-6543,
                           Exhibit 3(d)].
  3(e)            --       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)(iv); 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)].
  4(b)            --       Copy of Indenture (for unsecured debt securities), dated as of September 1, 1997, between
                           OPCo and Bankers Trust Company, as Trustee [Registration Statement No. 333-49595, Exhibits
                           4(a), 4(b) and 4(c); Annual Report on Form 10-K of OPCo for the fiscal year ended December
                           31, 1998, File No. 1-6543, Exhibits 4(c) and 4(d); Annual Report on Form 10-K of OPCo for the
                           fiscal year ended December 31, 1999, File No. 1-6543, Exhibits 4(c) and 4(d); Annual Report
                           on Form 10-K of OPCo for the fiscal year ended December 31, 2000, File No. 1-6543, Exhibit
                           4(c)].
</TABLE>


                                      E-12
<PAGE>


<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
 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, 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); 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 Modification No. 1 to the 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 AEP for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(l)].
 10(e)             --      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 on
                           Form 10-K of OPCo for the fiscal year ended December 31, 1993, File No. 1-6543, Exhibit
                           10(f)].
 10(f)             --      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)].
 10(g)(1)          --      Agreement and Plan of Merger, dated as of December 21, 1997, by and among American Electric
                           Power Company, Inc., Augusta Acquisition Corporation and Central and South West Corporation
                           [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1997, File No.
                           1-3525, Exhibit 10(f)].
 10(g)(2)          --      Amendment No. 1, dated as of December 31, 1999, to the Agreement and Plan of Merger [Current
                           Report on Form 8-K of OPCo dated December 15, 1999, File No. 1-6543, Exhibit 10].
</TABLE>


                                      E-13
<PAGE>

<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
+10(h)(1)          --      AEP Deferred Compensation Agreement for certain executive officers [Annual Report on Form 10-K of
                           OPCo for the fiscal year ended December 31, 1985, File No. 1-3525, Exhibit 10(e)].
+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)].
+10(i)             --      AEP System Senior Officer Annual Incentive Compensation Plan [Annual Report on Form 10-K of AEP
                           for the fiscal year ended December 31, 1996, File No. 1-3525, Exhibit 10(i)(1)].
+10(j)(1)          --      AEP System Excess Benefit Plan, Amended and Restated as of January 1, 2001 [Annual Report on Form
                           10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525, Exhibit 10(j)(1)(A)].
+10(j)(2)          --      AEP System Supplemental Retirement Savings Plan, Amended and Restated as of January 1, 2001
                           (Non-Qualified) [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No.
                           1-3525, Exhibit 10(j)(2)].
+10(j)(3)          --      Umbrella Trust 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)].
+10(k)             --      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)].
+10(l)             --      AEP System Survivor Benefit Plan, effective January 27, 1998 [Quarterly Report on Form 10-Q of
                           AEP for the quarter ended September 30, 1998, File No. 1-3525, Exhibit 10].
+10(m)             --      AEP Senior Executive Severance Plan for Merger with Central and South West Corporation, effective
                           March 1, 1999[Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 1998, File No.
                           1-3525, Exhibit 10(o)].
+10(n)             --      AEP Change In Control Agreement [Annual Report on Form 10-K of AEP for the fiscal year ended December
                           31, 2001, File No. 1-3525, Exhibit 10(o)].
+10(o)             --      AEP System 2000 Long-Term Incentive Plan [Proxy Statement of AEP, March 10, 2000].
+10(p)             --      Memorandum of agreement between Susan Tomasky and the Service Corporation dated January 3,
                           2001 [Annual Report on Form 10-K of AEP for the fiscal year ended December 31, 2000, File No. 1-3525,
                           Exhibit 10(s)].
+10(q)(1)          --      Central and South West System Special Executive Retirement Plan as amended and restated effective
                           July 1, 1997 [Annual Report on Form 10-K of CSW for the fiscal year ended December 31, 1998, File No.
                           1-1443, Exhibit 18].
+10(q)(2)          --      Certified CSW Board Resolution of April 18, 1991 [Annual Report on Form 10-K of AEP for the fiscal
                           year ended December 31, 2001, File No. 1-3525, Exhibit 10(r)(2)].
+10(q)(3)          --      CSW 1992 Long-Term Incentive Plan [Proxy Statement of CSW, March 13, 1992].
*12                --      Statement re: Computation of Ratios.
*13                --      Copy of those portions of the OPCo 2001 Annual Report (for the fiscal year ended December 31,
                           2001) 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, 2001, File No. 1-3525, Exhibit 21].
*23                --      Consent of Deloitte & Touche LLP.
*24                --      Power of Attorney.
</TABLE>


                                      E-14

<PAGE>


<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
PSO++
  3(a)             --      Restated Certificate of Incorporation of PSO [Annual Report on Form U5S of Central and South West
                           Corporation for the fiscal year ended December 31, 1996, File No. 1-1443, Exhibit B-3.1].
  3(b)             --      By-Laws of PSO (amended as of June 28, 2000) [Annual Report on Form 10-K of PSO for the fiscal
                           year ended December 31, 2000, File No. 0-343, Exhibit 3(b)].
  4(a)             --      Indenture, dated July 1, 1945, between PSO and Liberty Bank and Trust Company of Tulsa,
                           National Association, as Trustee, as amended and supplemented [Registration Statement No.
                           2-60712, Exhibit 5.03; Registration Statement No. 2-64432, Exhibit 2.02; Registration
                           Statement No. 2-65871, Exhibit 2.02; Form U-1 No. 70-6822, Exhibit 2; Form U-1 No. 70-7234,
                           Exhibit 3; Registration Statement No. 33-48650, Exhibit 4(b); Registration Statement No.
                           33-49143, Exhibit 4(c); Registration Statement No. 33-49575, Exhibit 4(b); Annual Report on
                           Form 10-K of PSO for the fiscal year ended December 31, 1993, File No. 0-343, Exhibit 4(b);
                           Current Report on Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.01; Current
                           Report on Form 8-K of PSO dated  March 4, 1996, No. 0-343, Exhibit 4.02; Current Report on
                           Form 8-K of PSO dated March 4, 1996, No. 0-343, Exhibit 4.03].
  4(b)            --      PSO-obligated,  mandatorily redeemable preferred securities of subsidiary trust holding solely
                           Junior Subordinated Debentures of PSO:
                           (1)  Indenture, dated as of May 1, 1997, between PSO and The Bank of New York, as Trustee
                                [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.6
                                and 4.7].
                           (2)  Amended and Restated Trust Agreement of PSO Capital I, dated as of May 1, 1997, among PSO,
                                as Depositor, The Bank of New York, as Property Trustee, The Bank of New York (Delaware), as
                                Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form 10-Q of PSO dated
                                March 31, 1997, File No. 0-343, Exhibit 4.8].
                           (3)  Guarantee Agreement, dated as of May 1, 1997, delivered by PSO for the benefit of the holders
                                of PSO Capital I's Preferred Securities [Quarterly Report on Form 10-Q of PSO dated
                                March 31, 1997, File No. 0-343, Exhibits 4.9].
                           (4)  Agreement as to Expenses and Liabilities, dated as of May 1, 1997, between PSO and PSO Capital I
                                [Quarterly Report on Form 10-Q of PSO dated March 31, 1997, File No. 0-343, Exhibits 4.10].
  4(c)             --      Indenture (for unsecured debt securities), dated as of November 1, 2000, between PSO and The Bank of
                           New York, as Trustee [Annual Report on Form 10-K of PSO for the fiscal year ended December 31, 2000, File
                           No. 0-343, Exhibits 4(c) and 4(d)]
*12                --      Statement re: Computation of Ratios.
*13                --      Copy of those portions of the PSO 2001 Annual Report (for the fiscal year ended December 31, 2001)
                           which are incorporated by reference in this filing.
*23(a)             --      Consent of Deloitte & Touche LLP.
*23(b)             --      Consent of Arthur Andersen LLP.
*24                --      Power of Attorney.

SWEPCO++
  3(a)             --      Restated Certificate of Incorporation, as amended through May 6, 1997, including Certificate of
                           Amendment of Restated Certificate of Incorporation [Quarterly Report on Form 10-Q of SWEPCo for the
                           quarter ended March 31, 1997, File No. 1-3146, Exhibit 3.4].
</TABLE>


                                      E-15
<PAGE>


<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
   3(b)            --      By-Laws of SWEPCo (amended as of April 27, 2000) [Quarterly Report on Form 10-Q of SWEPCo for
                           the quarter ended March 31, 2000, File No. 1-3146, Exhibit 3.3].
   4(a)            --      Indenture, dated February 1, 1940, between SWEPCo and Continental Bank, National Association
                           and M. J. Kruger, as Trustees, as amended and supplemented [Registration Statement No.
                           2-60712, Exhibit 5.04; Registration Statement No. 2-61943, Exhibit 2.02;  Registration
                           Statement No. 2-66033, Exhibit 2.02; Registration Statement No. 2-71126, Exhibit 2.02;
                           Registration Statement No. 2-77165, Exhibit 2.02; Form U-1 No. 70-7121, Exhibit 4; Form U-1
                           No. 70-7233, Exhibit 3; Form U-1 No. 70-7676, Exhibit 3; Form U-1 No. 70-7934, Exhibit 10;
                           Form U-1 No. 72-8041, Exhibit 10(b); Form U-1 No. 70-8041, Exhibit 10(c); Form U-1 No.
                           70-8239, Exhibit 10(a)].
   4(b)            --      SWEPCO-obligated, mandatorily redeemable preferred securities of subsidiary trust holding
                           solely Junior Subordinated Debentures of SWEPCo:
                           (1)  Indenture, dated as of May 1, 1997, between SWEPCo and the Bank of New York, as Trustee
                                [Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibits 4.11
                                and 4.12].
                           (2)  Amended and Restated Trust Agreement of SWEPCo Capital I, dated as of May 1, 1997, among
                                SWEPCo, as Depositor, the Bank of New York, as Property Trustee, The Bank of New York
                                (Delaware), as Delaware Trustee, and the Administrative Trustee [Quarterly Report on Form
                                10-Q of SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit 4.13].
                           (3)  Guarantee Agreement, dated as of May 1, 1997, delivered by SWEPCo for the benefit of the
                                holders of SWEPCo Capital I's Preferred Securities [Quarterly Report on Form 10-Q of
                                SWEPCo dated March 31, 1997, File No. 1-3146, Exhibit 4.14].
                           (4)  Agreement as to Expenses and Liabilities, dated as of May 1, 1997 between SWEPCo and SWEPCo
                                Capital I [Quarterly Report on Form 10-Q of SWEPCo dated March 31, 1997, File No. 1-3146,
                                Exhibits 4.15].
   4(c)            --      Indenture (for unsecured debt securities), dated as of February 4, 2000, between SWEPCo and The Bank
                           of New York, as Trustee [Annual Report on Form 10-K of SWEPCo for the fiscal year ended December 31,
                           2000, File No. 1-3146, Exhibits 4(c) and 4(d)].
 *12               --      Statement re: Computation of Ratios.
 *13               --      Copy of those portions of the SWEPCo 2001 Annual
                           Report (for the fiscal year ended December 31, 2001)
                           which are incorporated by reference in this filing.
 *23(a)            --      Consent of Deloitte & Touche LLP.
 *23(b)            --      Consent of Arthur Andersen LLP.
 *24               --      Power of Attorney.

WTU++
   3(a)            --      Restated Articles of Incorporation, as amended, and Articles of Amendment to the Articles of
                           Incorporation [Annual Report on Form 10-K of WTU for the fiscal year ended December 31, 1996,
                           File No. 0-340, Exhibit 3.5].
   3(b)            --      By-Laws of WTU  (amended  as of May 1,  2000)  [Quarterly  Report on Form 10-Q of WTU for the
                           quarter ended March 31, 2000, File No. 0-340, Exhibit 3.4].
</TABLE>


                                      E-16
<PAGE>


<TABLE>
<CAPTION>

EXHIBIT NUMBER                              DESCRIPTION
- --------------                              -----------
<S>               <C>      <C>
   4(a)            --      Indenture, dated August 1, 1943, between WTU and Harris Trust and Savings Bank and J.
                           Bartolini, as Trustees, as amended and supplemented [Registration Statement No. 2-60712,
                           Exhibit 5.05; Registration Statement No. 2-63931, Exhibit 2.02; Registration Statement No.
                           2-74408, Exhibit 4.02; Form U-1 No. 70-6820, Exhibit 12; Form U-1 No. 70-6925, Exhibit 13;
                           Registration Statement No. 2-98843, Exhibit 4(b); Form U-1 No. 70-7237, Exhibit 4; Form U-1
                           No. 70-7719, Exhibit 3; Form U-1 No. 70-7936, Exhibit 10; Form U-1 No. 70-8057, Exhibit 10;
                           Form U-1 No. 70-8265, Exhibit 10; Form U-1 No. 70-8057, Exhibit 10(b); Form U-1 No. 70-8057,
                           Exhibit 10(c)].
 *12               --      Statement re: Computation of Ratios.
 *13               --      Copy of those portions of the WTU 2001 Annual
                           Report (for the fiscal year ended December 31, 2001) which are incorporated by reference in
                           this filing.
 *24               --      Power of Attorney.
</TABLE>

                                       -------------------------------------


++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.



                                      E-17



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4
<SEQUENCE>4
<FILENAME>x4a.txt
<DESCRIPTION>(A) INDENTURE DATED AS OF MAY 1, 2001
<TEXT>

<PAGE>

                                                                    Exhibit 4(a)




                      AMERICAN ELECTRIC POWER COMPANY, INC.


                                       AND


                              THE BANK OF NEW YORK,


                                   AS TRUSTEE


                              --------------------


                                    INDENTURE


                             Dated as of May 1, 2001


                              --------------------


                              CROSS-REFERENCE TABLE


    Section of
Trust Indenture Act                                      Section of
of 1939, as amended                                       Indenture

310(a)........................................................ 7.09
310(b)........................................................ 7.08
      ........................................................ 7.10
310(c)........................................................ Inapplicable
311(a)........................................................ 7.13
311(b)........................................................ 7.13
311(c)........................................................ Inapplicable
312(a)........................................................ 5.01
      ........................................................ 5.02(a)
312(b)........................................................ 5.02(c)
      ........................................................ 5.02(d)
312(c)........................................................ 5.02(e)
313(a)........................................................ 5.04(a)
313(b)........................................................ 5.04(b)
313(c)........................................................ 5.04(a)
      ........................................................ 5.04(b)
313(d)........................................................ 5.04(c)
314(a)........................................................ 5.03
314(b)........................................................ Inapplicable
314(c)........................................................ 13.06(a)
314(d)........................................................ Inapplicable
314(e)........................................................ 13.06(b)
314(f)........................................................ Inapplicable
315(a)........................................................ 7.01(a)
      ........................................................ 7.02
315(b)........................................................ 6.07
315(c)........................................................ 7.01(a)
315(d)........................................................ 7.01(b)
315(e)........................................................ 6.08
316(a)........................................................ 6.06
      ........................................................ 8.04
316(b)........................................................ 6.04
316(c)........................................................ 8.01
317(a)........................................................ 6.02
317(b)........................................................ 4.03
318(a)........................................................ 13.08

                                TABLE OF CONTENTS

This Table of Contents does not constitute  part of the Indenture and should not
have any bearing upon the interpretation of any of its terms or provisions

                                    RECITALS:

    Purpose of Indenture....................................................1
    Compliance with legal requirements......................................1
    Purpose of and consideration for Indenture..............................1

ARTICLE ONE - DEFINITIONS

     Section 1.01

          Certain terms defined,  other terms defined in the Trust Indenture Act
          of 1939, as amended,  or by reference therein in the Securities Act of
          1933, as amended, to have the meanings assigned therein

          Affiliate.........................................................2
          Authenticating Agent..............................................2
          Authorized Officer................................................2
          Board of Directors................................................3
          Board Resolution..................................................3
          Business Day......................................................3
          Certificate.......................................................3
          Commission........................................................3
          Company...........................................................3
          Company Order.....................................................3
          Corporate Trust Office............................................4
          Default...........................................................4
          Depository........................................................4
          Discount Security.................................................4
          Dollar............................................................4
          Eligible Obligations..............................................4
          Event of Default..................................................4
          Global Security...................................................5
          Eligible Obligations..............................................5
          Governmental Authority............................................5
          Indenture.........................................................5
          Instructions......................................................6
          Interest .........................................................6
          Interest Payment Date.............................................6
          Officers' Certificate.............................................6
          Opinion of Counsel................................................6
          Outstanding.......................................................6
          Periodic Offering.................................................7
          Person............................................................7
          Place of Payment..................................................7
          Predecessor Security..............................................7
          Responsible Officer...............................................7
          Security..........................................................8
          Securityholder....................................................8
          Series............................................................8
          Tranche...........................................................8
          Trustee...........................................................8
          Trust Indenture Act...............................................8
          United States.....................................................9

ARTICLE TWO - ISSUE, DESCRIPTION, TERMS, EXECUTION, REGISTRATION AND EXCHANGE OF
              SECURITIES

     Section 2.01
          Designation,  terms,  amount,  authentication  and delivery of
          Securities........................................................9

     Section 2.02
          Form of Security and Trustee's certificate.......................10

     Section 2.03
          Date and denominations of Securities, and provisions for
          payment of principal, premium and interest.......................11

     Section 2.04
          Execution of Securities..........................................13

     Section 2.05
          Exchange of Securities...........................................15
          (a) Registration and transfer of Securities......................15
          (b) Security Register; Securities to be accompanied
              by proper instruments of transfer............................15
          (c) Charges upon exchange, transfer or
              registration of Securities...................................15
          (d) Restrictions on transfer or
              exchange at time of redemption...............................16

     Section 2.06
          Temporary Securities.............................................16

     Section 2.07
          Mutilated, destroyed, lost or stolen Securities..................16

     Section 2.08
          Cancellation of surrendered Securities...........................17

     Section 2.09
          Provisions of Indenture and Securities
          for sole benefit of parties and Securityholders..................18

     Section 2.10
          Appointment of Authenticating Agent..............................18

     Section 2.11
          Global Security..................................................19
          (a) Authentication and Delivery; Legend..........................19
          (b) Transfer of Global Security..................................19
          (c) Issuance of Securities in Definitive Form....................19

     Section 2.12
          Payment in Proper Currency.......................................20

     Section 2.13
          Identification of Securities.....................................20

ARTICLE THREE - REDEMPTION OF SECURITIES AND SINKING FUND PROVISIONS

     Section 3.01
          Redemption of Securities.........................................20

     Section 3.02
          (a) Notice of redemption.........................................21
          (b) Selection of Securities in case
              redeemed.....................................................22

     Section 3.03
          (a) When Securities called for
              redemption become due and payable............................22
          (b) Receipt of new Security upon
              partial payment..............................................23

     Section 3.04
          Sinking Fund for Securities......................................23

     Section 3.05
          Satisfaction of Sinking Fund
          Payments with Securities.........................................23

     Section 3.06
          Redemption of Securities for
          Sinking Fund.....................................................23

ARTICLE FOUR - PARTICULAR COVENANTS OF THE COMPANY

     Section 4.01
          Payment of principal (and premium
          if any) and interest on Securities...............................24

     Section 4.02
          Maintenance of office or agency for payment of Securities,
          designation of office or agency for payment, registration,
          transfer and exchange
          of Securities....................................................24

     Section 4.03
          (a) Duties of paying agent.......................................25
          (b) Company as paying agent......................................25
          (c) Holding sums in trust........................................26

     Section 4.04
          Appointment to fill vacancy in
          office of Trustee................................................26

     Section 4.05
          Restriction on consolidation,
          merger or sale...................................................26

ARTICLE FIVE - SECURITYHOLDERS' LISTS AND REPORTS
               BY THE COMPANY AND THE TRUSTEE

     Section 5.01
          Company to furnish Trustee information
          as to names and addresses of
          Securityholders..................................................26

     Section 5.02
          (a) Trustee to preserve information
              as to names and addresses of
              Securityholders received by it
              in capacity of paying agent..................................26
          (b) Trustee may destroy list of
              Securityholders on certain
              conditions...................................................27
          (c) Trustee to make information as to
              names and addresses of Securityholders
              available to "applicants" to mail
              communications to Securityholders in
              certain circumstances........................................27
          (d) Procedure if Trustee elects not to
              make information available to
              applicants...................................................27
          (e) Company and Trustee not accountable
              for disclosure of information................................28

     Section 5.03
          (a) Annual and other reports to be filed
              by Company with Trustee......................................28
          (b) Additional information and reports
              to be filed with Trustee and
              Securities and Exchange Commission...........................28
          (c) Summaries of information and reports
              to be transmitted by Company to
              Securityholders..............................................29
          (d) Annual Certificate to be furnished
              to Trustee...................................................29
          (e) Effect of Delivery to Trustee................................29

     Section 5.04
          (a) Trustee to transmit annual report
              to Securityholders...........................................29
          (b) Trustee to transmit certain further
              reports to Securityholders...................................30

          (c) Copies of reports to be filed with
              stock exchanges and Securities and
              Exchange Commission..........................................31

ARTICLE SIX - REMEDIES OF THE TRUSTEE AND
              SECURITYHOLDERS ON EVENT OF DEFAULT

     Section 6.01
          (a) Events of default defined....................................31
          (b) Acceleration of maturity
              upon Event of Default........................................32
          (c) Waiver of default and rescission
              of declaration of maturity...................................32
          (d) Restoration of former position
              and rights upon curing default...............................33

     Section 6.02
          (a) Covenant of Company to pay to
              Trustee whole amount due on
              Securities on default in payment
              of interest or principal (and
              premium, if any).............................................33
          (b) Trustee may recover judgment for
              whole amount due on Securities on
              failure of Company to pay....................................33
          (c) Billing of proof of claim by Trustee
              in bankruptcy, reorganization or
              receivership proceeding......................................34
          (d) Rights of action and of asserting
              claims may be enforced by Trustee
              without possession of Securities.............................34

     Section 6.03
          Application of monies collected by Trustee.......................35

     Section 6.04
          Limitation on suits by holders of Securities.....................35

     Section 6.05
          (a) Remedies Cumulative..........................................36
          (b) Delay or omission in exercise
              of rights not waiver of default..............................36

     Section 6.06
          Rights of holders of majority in
          principal amount of Securities to
          direct trustee and to waive defaults.............................36

     Section 6.07
          Trustees to give notice of defaults
          known to it, but may withhold in
          certain circumstances............................................37

     Section 6.08
          Requirements of an undertaking to pay
          costs in certain suits under Indenture
          or against Trustee...............................................38

ARTICLE SEVEN - CONCERNING THE TRUSTEE

     Section 7.01
          (a) Upon Event of Default occurring and
              continuing, Trustee shall exercise powers
              vested in it, and use same degree of
              care and skill in their exercise, as
              prudent individual will use..................................38
          (b) Trustee not relieved from liability
              for negligence or willful misconduct
              except as provided in this section...........................39
              (1) Prior to Event of Default and
                  after the curing of all Events of
                  Default which may have occurred
                  (i) Trustee not liable except for
                      performance of duties specifically
                      set forth
                 (ii) In absence of bad faith, Trustee
                      may conclusively rely on
                      certificates or opinions furnished
                      it hereunder,subject to duty to
                      examine the same if specifically
                      required to be furnished to it
              (2) Trustee not liable for error of judgment made
                  in good faith by Responsible Officer unless
                  Trustee negligent
              (3) Trustee not liable for action or non-action
                  in accordance with direction of holders
                  of majority in principal amount of
                  Securities
              (4) Trustee need not expend own funds without
                  adequate indemnity

     Section 7.02
          Subject to provisions of Section 7.01:
          (a) Trustee may rely on documents believed
              genuine and properly signed or presented.....................40
          (b) Sufficient evidence by certain
              instruments provided for.....................................40
          (c) Trustee may consult with counsel and act
              on advice or Opinion of Counsel..............................40
          (d) Trustee may require indemnity from
              Securityholders..............................................40
          (e) Trustee not liable for actions in good
              faith believed to be authorized..............................41
          (f) Trustee not bound to investigate facts or
              matters stated in certificates, etc. unless
              requested in writing by Securityholders......................41
          (g) Trustee may perform duties directly or
              through agents or attorneys..................................41
          (h) Permissive rights of Trustee.................................41

     Section 7.03
          (a) Trustee not liable for recitals in
              Indenture or in Securities...................................41
          (b) No representations by Trustee as to
              validity or Indenture or of Securities.......................41
          (c) Trustee not accountable for use of
              Securities or proceeds.......................................41

     Section 7.04
          Trustee, paying agent or Security
          Registrar may own Security.......................................42

     Section 7.05
          Monies received by Trustee to be held
          in Trust without interest........................................42

     Section 7.06
          (a) Trustee entitled to compensation,
              reimbursement and indemnity..................................42
          (b) Obligations to Trustee to be
              secured by lien prior to
              Securities...................................................42
          (c) Nature of Expenses...........................................43
          (d) Survival of Obligations......................................43

     Section 7.07
          Right of Trustee to rely on certificate
          of officers of Company where no other
          evidence specifically prescribed.................................43

     Section 7.08
          Trustee acquiring conflicting interest
          to eliminate conflict or resign..................................43

     Section 7.09
          Requirements for eligibility of
          trustee..........................................................43

     Section 7.10
          (a) Resignation of Trustee and
              appointment of successor.....................................44
          (b) Removal of Trustee by Company
              or by court on Securityholders'
              application..................................................45
          (c) Removal of Trustee by holders
              of majority in principal amount
              of Securities................................................45
          (d) Time when resignation or removal
              of Trustee effective.........................................45
          (e) One Trustee for each series..................................45

     Section 7.11
          (a) Acceptance by successor Trustee..............................45
          (b) Trustee with respect to less than
              all series...................................................45
          (c) Company to confirm Trustee's rights..........................46
          (d) Successor Trustee to be qualified............................46
          (e) Notice of succession.........................................46

     Section 7.12
          Successor to Trustee by merger, consolidation
          of succession to business........................................47

     Section 7.13
          Limitations on rights of Trustee as a
          creditor to obtain payment of certain
          claims...........................................................47

ARTICLE EIGHT - CONCERNING THE SECURITYHOLDERS

     Section 8.01
          Evidence of action by Securityholders............................47

     Section 8.02
          Proof of execution of instruments and of
          holding of Securities............................................48

     Section 8.03
          Who may be deemed owners of Securities...........................48

     Section 8.04
          Securities owned by Company or controlled
          or controlling companies disregarded for
          certain purposes.................................................48

     Section 8.05
          Instruments executed by Securityholders
          bind future holders..............................................49

ARTICLE NINE - SUPPLEMENTAL INDENTURES

     Section 9.01
          Purposes for which supplemental indenture
          may be entered into without consent of
          Securityholders..................................................49

     Section 9.02
          Modification of Indenture with consent
          of Securityholders...............................................52

     Section 9.03
          Effect of supplemental indentures................................53

     Section 9.04
          Securities may bear notation of changes
          by supplemental indentures.......................................54

     Section 9.05
          Opinion of Counsel...............................................54

ARTICLE TEN - CONSOLIDATION, MERGER AND SALE

     Section 10.01
          Consolidations or mergers of Company
          and sales or conveyances of property
          of Company permitted.............................................54

     Section 10.02
          (a) Rights and duties of successor company.......................55
          (b) Appropriate changes may be made in
              phraseology and form of Securities...........................55
          (c) Company may consolidate or merge into
              itself or acquire properties of other
              corporations.................................................55

     Section 10.03
          Opinion of Counsel...............................................56

ARTICLE ELEVEN - DEFEASANCE AND CONDITIONS TO DEFEASANCE;
                 UNCLAIMED MONIES

     Section 11.01
          Defeasance and conditions to defeasance..........................56

     Section 11.02
          Application by Trustee of funds deposited
          for payment of Securities........................................57

     Section 11.03
          Repayment of monies held by paying agent.........................57

     Section 11.04
          Repayment of monies held by Trustee..............................58

     Section 11.05
          Delivery of Officer's Certificate
          and Opinion of Counsel...........................................58

ARTICLE TWELVE - IMMUNITY OF INCORPORATORS, STOCKHOLDERS,
                  OFFICERS AND DIRECTORS

     Section 12.01
          Incorporators, Stockholders, officers and
          directors of Company exempt from individual
          liability........................................................58

ARTICLE THIRTEEN - MISCELLANEOUS PROVISIONS

     Section 13.01
          Successors and assigns of Company
          bound by Indenture...............................................59

     Section 13.02
          Acts of board, committee or officer
          of successor company valid.......................................59

     Section 13.03
          Surrender of powers by Company...................................59

     Section 13.04
          Required notices or demands may by
          served by mail...................................................59

     Section 13.05
          Indenture and Securities to be construed
          in accordance with laws of the State
          of New York......................................................59

     Section 13.06
          (a) Officers' Certificate and Opinion of
              Counsel to be furnished upon applications
              or demands by company........................................60
          (b)  Statements to be included in each
              certificate or opinion with respect
              to compliance with condition or covenant.....................60

     Section 13.07
          Payments due on non-Business Days................................60

     Section 13.08
          Provisions required by Trust Indenture
          Act of 1939 to control...........................................60

     Section 13.09
          Indenture may be executed in counterparts........................60

     Section 13.10
          Separability of Indenture provisions.............................60

     Section 13.11
          Assignment by Company to subsidiary..............................61

     Section 13.12
          Headings.........................................................61

     Section 13.13
          Securities in Foreign Currencies.................................61


ACCEPTANCE OF TRUST BY TRUSTEE.............................................62

TESTIMONIUM................................................................62

SIGNATURES AND SEALS.......................................................62

ACKNOWLEDGEMENTS...........................................................63



     THIS  INDENTURE,  dated as of the 1st day of May,  2001,  between  AMERICAN
ELECTRIC  POWER COMPANY,  INC., a corporation  duly organized and existing under
the laws of the  State of New York  (hereinafter  sometimes  referred  to as the
"Company"),  and THE BANK OF NEW YORK, a banking corporation of the State of New
York, as trustee (hereinafter sometimes referred to as the "Trustee"):

     WHEREAS, for its lawful corporate purposes, the Company has duly authorized
the  execution  and  delivery of this  Indenture  to provide for the issuance of
unsecured  promissory  notes or other  evidences  of  indebtedness  (hereinafter
referred to as the "Securities"),  in an unlimited aggregate principal amount to
be issued from time to time in one or more series as in this Indenture provided,
as registered  Securities without coupons,  to be manually  authenticated by the
certificate  of the  Trustee,  and which  will rank  pari  passu  with all other
unsecured and unsubordinated debt of the Company;

     WHEREAS,  to provide the terms and conditions upon which the Securities are
to be authenticated,  issued and delivered,  the Company has duly authorized the
execution of this Indenture;

     WHEREAS,  the Securities and the certificate of  authentication to be borne
by the Securities (the "Certificate of Authentication")  are to be substantially
in such forms as may be approved by a Company Order (as defined  below),  or set
forth in this Indenture or in any indenture supplemental to this Indenture;

     AND WHEREAS,  all acts and things  necessary to make the Securities  issued
pursuant hereto, when executed by the Company and authenticated and delivered by
the  Trustee  as in this  Indenture  provided,  the  valid,  binding  and  legal
obligations of the Company,  and to constitute  these presents a valid indenture
and  agreement  according to its terms,  have been done and performed or will be
done and performed prior to the issuance of such  Securities,  and the execution
of this Indenture has been and the issuance hereunder of the Securities has been
or will be prior to issuance in all respects duly  authorized,  and the Company,
in the  exercise  of the  legal  right  and power in it  vested,  executes  this
Indenture and proposes to make, execute, issue and deliver the Securities;

     NOW, THEREFORE, THIS INDENTURE WITNESSETH:

     That in order to declare the terms and conditions upon which the Securities
are and are to be authenticated,  issued and delivered,  and in consideration of
the premises,  of the purchase and  acceptance of the  Securities by the holders
thereof  and of the sum of one dollar  ($1.00) to it duly paid by the Trustee at
the execution of these presents, the receipt whereof is hereby acknowledged, the
Company  covenants and agrees with the Trustee,  for the equal and proportionate
benefit (subject to the provisions of this Indenture) of the respective  holders
from time to time of the Securities,  without any discrimination,  preference or
priority of any one Security over any other by reason of priority in the time of
issue, sale or negotiation thereof, or otherwise,  except as provided herein, as
follows:


                                   ARTICLE ONE
                                   DEFINITIONS

     SECTION  1.01.....The  terms  defined  in this  Section  (except as in this
Indenture otherwise expressly provided or unless the context otherwise requires)
for all purposes of this Indenture, any Company Order, any Board Resolution, and
any indenture  supplemental  hereto shall have the respective meanings specified
in this Section. All other terms used in this Indenture which are defined in the
Trust  Indenture Act of 1939, as amended,  or which are by reference in such Act
defined in the  Securities Act of 1933, as amended  (except as herein  otherwise
expressly  provided or unless the context  otherwise  requires),  shall have the
meanings  assigned  to  such  terms  in  said  Trust  Indenture  Act and in said
Securities Act as in force at the date of the execution of this instrument.

Affiliate:

The term  "Affiliate"  of the Company shall mean any company at least a majority
of whose outstanding voting stock shall at the time be owned by the Company,  or
by one or more direct or indirect  subsidiaries  of or by the Company and one or
more direct or indirect  subsidiaries  of the Company.  For the purposes only of
this definition of the term "Affiliate",  the term "voting stock", as applied to
the  stock of any  company,  shall  mean  stock of any class or  classes  having
ordinary  voting power for the  election of a majority of the  directors of such
company,  other than stock having such power only by reason of the occurrence of
a contingency.

Authenticating Agent:

The term "Authenticating  Agent" shall mean an authenticating agent with respect
to all or any of the series of  Securities,  as the case may be,  appointed with
respect  to all or any  series  of the  Securities,  as the case may be,  by the
Trustee pursuant to Section 2.10.

Authorized Officer:

The  term  "Authorized  Officer"  shall  mean the  Chairman  of the  Board,  the
President,  any Vice President,  the Treasurer,  any Assistant  Treasurer or any
other officer or agent of the Company duly  authorized by the Board of Directors
to act in respect of matters relating to this Indenture.

Board of Directors or Board:

The term "Board of  Directors"  or "Board"  shall mean the Board of Directors of
the Company, or any duly authorized committee of such Board.

Board Resolution:

The term "Board  Resolution" shall mean a copy of a resolution  certified by the
Secretary or an Assistant  Secretary of the Company to have been duly adopted by
the Board of  Directors  and to be in full  force and effect on the date of such
certification.

Business Day:

The term "Business Day",  with respect to any Security,  shall mean any day that
(a) in the Place of Payment  (or in any of the Places of  Payment,  if more than
one) in which  amounts are payable as specified in the form of such Security and
(b) in the city in which the Trustee  administers  its corporate trust business,
is not a day on which banking  institutions are authorized or required by law or
regulation to close.

Certificate:

The term "Certificate" shall mean a certificate signed by an Authorized Officer.
The Certificate need not comply with the provisions of Section 13.06.

Commission:

The term "Commission" shall mean the Securities and Exchange Commission, as from
time to time constituted,  created under the Securities Exchange Act of 1934, as
amended  (the  "Exchange  Act") or if at any time  after the  execution  of this
instrument  such  Commission  is not  existing  and  performing  the  duties now
assigned to it under the Trust Indenture Act, then the body, if any,  performing
such duties on such date.

Company:

The  term  "Company"  shall  mean  American  Electric  Power  Company,  Inc.,  a
corporation duly organized and existing under the laws of New York, and, subject
to the provisions of Article Ten, shall also include its successors and assigns.

Company Order:

The term  "Company  Order" shall mean a written  order signed in the name of the
Company by an Authorized Officer and the Secretary or an Assistant  Secretary of
the Company, pursuant to a Board Resolution establishing a series of Securities.

Corporate Trust Office:

The term "Corporate  Trust Office" shall mean the office of the Trustee at which
at any  particular  time its  corporate  trust  business  shall  be  principally
administered,  which office at the date of the  execution  of this  Indenture is
located at 101 Barclay Street, Floor 21W, New York, New York 10286.

Default:

The term "Default"  shall mean any event,  act or condition which with notice or
lapse of time, or both, would constitute an Event of Default.

Depository:

The term "Depository"  shall mean, with respect to Securities of any series, for
which the  Company  shall  determine  that such  Securities  will be issued as a
Global  Security,  The  Depository  Trust Company,  New York, New York,  another
clearing  agency,  or any successor  registered  as a clearing  agency under the
Exchange Act or other  applicable  statute or regulation,  which,  in each case,
shall be designated by the Company pursuant to either Section 2.01 or 2.11.

Discount Security:

The term  "Discount  Security"  means any Security  which provides for an amount
less than the principal  amount thereof to be due and payable upon a declaration
of acceleration of the maturity thereof pursuant to Section 6.01(b).

Dollar:

The term "Dollar" or "$" means a dollar or other equivalent unit in such coin or
currency  of the  United  States as at the time  shall be legal  tender  for the
payment of public and private debts.

Eligible Obligations:

The term "Eligible Obligations" means (a) with respect to Securities denominated
in Dollars, Eligible Obligations;  or (b) with respect to Securities denominated
in a  currency  other  than  Dollars  or in a  composite  currency,  such  other
obligations   or  instruments  as  shall  be  specified  with  respect  to  such
Securities, as contemplated by Section 2.01.

Event of Default:

The term "Event of Default" with respect to  Securities  of a particular  series
shall mean any event  specified  in Section  6.01,  continued  for the period of
time, if any, therein designated.

Global Security:

The term "Global Security" shall mean, with respect to any series of Securities,
a Security  executed by the  Company  and  authenticated  and  delivered  by the
Trustee to the Depository or pursuant to the  Depository's  instruction,  all in
accordance  with the  Indenture,  which shall be  registered  in the name of the
Depository or its nominee.

Governmental Authority:

The term  "Governmental  Authority" means the government of the United States or
of any State or  Territory  thereof or of the  District  of  Columbia  or of any
county,  municipality or other political subdivision of any of the foregoing, or
any  department,  agency,  authority  or  other  instrumentality  of  any of the
foregoing.

Eligible Obligations:

The term  "Eligible  Obligations"  shall  mean  securities  that are (i)  direct
obligations  of the United  States of America  for the payment of which its full
faith and  credit is  pledged  or (ii)  obligations  of a person  controlled  or
supervised by and acting as an agency or  instrumentality  of the United States,
the payment of which is  unconditionally  guaranteed  as a full faith and credit
obligation  by the United  States,  which,  in either case,  are not callable or
redeemable  at the  option  of the  issuer  thereof,  and shall  also  include a
depository  receipt  issued by a bank (as  defined  in  Section  3(a)(2)  of the
Securities  Act of 1933,  as  amended)  as  custodian  with  respect to any such
Governmental Obligation or a specific payment of principal of or interest on any
such  Governmental  Obligation  held by such  custodian  for the  account of the
holder of such  depository  receipt;  provided  that (except as required by law)
such  custodian is not  authorized to make any deduction from the amount payable
to the  holder of such  depository  receipt  from any  amount  received  by such
custodian in respect of the  Governmental  Obligation or the specific payment of
principal  of or  interest  on the  Governmental  Obligation  evidenced  by such
depository receipt.

Indenture:

The term "Indenture" shall mean this instrument as originally  executed,  or, if
amended or supplemented as herein provided,  as so amended or supplemented,  and
shall  include the terms of a particular  series of  Securities  established  as
contemplated by Section 2.01.

Instructions:

The term "Instructions" shall mean instructions acceptable to the Trustee issued
pursuant to a Company Order in connection with a Periodic Offering and signed by
an  Authorized  Officer.  Instructions  need not comply with the  provisions  of
Section 13.06.

Interest:

The term "interest" when used with respect to  non-interest  bearing  Securities
shall mean interest  payable after maturity  (whether at stated  maturity,  upon
acceleration or redemption or otherwise) or after the date, if any, on which the
Company  becomes  obligated  to  acquire a  Security,  whether  by  purchase  or
otherwise.

Interest Payment Date:

The term  "Interest  Payment Date" when used with respect to any  installment of
interest on a Security of a particular  series shall mean the date  specified in
such  Security  or  in  a  Board  Resolution,  Company  Order  or  an  indenture
supplemental  hereto  with  respect to such series as the fixed date on which an
installment  of interest  with respect to  Securities  of that series is due and
payable.

Officers' Certificate:

The  term  "Officers'  Certificate"  shall  mean  a  certificate  signed  by  an
Authorized  Officer and by the Secretary or Assistant  Secretary of the Company.
Each such  certificate  shall  include the  statements  provided  for in Section
13.06, if and to the extent required by the provisions thereof.

Opinion of Counsel:

The term "Opinion of Counsel"  shall mean an opinion in writing  signed by legal
counsel, who may be an employee of or counsel for the Company. Each such opinion
shall include the statements provided for in Section 13.06, if and to the extent
required by the provisions thereof.

Outstanding:

The term  "outstanding",  when used with  reference to Securities of any series,
shall,  subject to the  provisions of Section 8.04,  mean, as of any  particular
time, all Securities of that series  theretofore  authenticated and delivered by
the Trustee under this Indenture,  except (a) Securities theretofore canceled by
the Trustee or any paying agent, or delivered to the Trustee or any paying agent
for  cancellation  or which have  previously  been  canceled;  (b) Securities or
portions  thereof  for the  payment or  redemption  of which  monies or Eligible
Obligations in the necessary  amount shall have been deposited in trust with the
Trustee or with any paying agent (other than the Company) or shall have been set
aside and  segregated  in trust by the Company (if the Company  shall act as its
own paying agent);  provided,  however,  that if such  Securities or portions of
such Securities are to be redeemed prior to the maturity thereof, notice of such
redemption  shall have been given as in Article  Three  provided,  or  provision
satisfactory to the Trustee shall have been made for giving such notice; and (c)
Securities in lieu of or in substitution  for which other  Securities shall have
been  authenticated  and delivered  pursuant to the terms of Section  2.07.  The
principal  amount of a Discount  Security that shall be deemed to be Outstanding
for purposes of this Indenture shall be the amount of the principal thereof that
would be due and payable as of the date of such determination upon a declaration
of acceleration of the maturity thereof.

Periodic Offering:

The term  "Periodic  Offering"  means an offering of Securities of a series from
time to time,  during which any or all of the specific terms of the  Securities,
including without limitation the rate or rates of interest, if any, thereon, the
maturity or  maturities  thereof and the  redemption  provisions,  if any,  with
respect  thereto,  are to be  determined  by the  Company or its agents upon the
issuance of such Securities.

Person:

The term  "person"  means  any  individual,  corporation,  partnership,  limited
liability company,  joint venture,  trust or unincorporated  organization or any
Governmental Authority.

Place of Payment:

The term "Place of Payment"  shall mean the place or places where the  principal
of and  interest,  if any,  on the  Securities  of any  series  are  payable  as
specified in accordance with Section 2.01.

Predecessor Security:

The term  "Predecessor  Security" of any  particular  Security  shall mean every
previous Security evidencing all or a portion of the same debt as that evidenced
by such  particular  Security;  and,  for the purposes of this  definition,  any
Security  authenticated  and  delivered  under  Section  2.07 in lieu of a lost,
destroyed  or stolen  Security  shall be deemed to evidence the same debt as the
lost, destroyed or stolen Security.

Responsible Officer:

The term "Responsible  Officer" when used with respect to the Trustee shall mean
the chairman of the board of directors,  the president,  any vice president, the
secretary,  the treasurer, any trust officer, any corporate trust officer or any
other  officer  or  assistant  officer  of the  Trustee  customarily  performing
functions  similar to those  performed  by the  persons who at the time shall be
such officers,  respectively,  or to whom any corporate trust matter is referred
because of his or her knowledge of and familiarity with the particular subject.

Security or Securities:

The term  "Security" or "Securities"  shall mean any Security or Securities,  as
the case may be, authenticated and delivered under this Indenture.

Securityholder:

The term  "Securityholder",  "holder of Securities" or "registered holder" shall
mean the person or persons in whose name or names a particular Security shall be
registered on the books of the Company kept for that purpose in accordance  with
the terms of this Indenture.

Series:

The term  "series"  means a series of  Securities  established  pursuant to this
Indenture and includes, if the context so requires, each Tranche thereof.

Tranche:

The term  "Tranche"  means  Securities  which (a) are of the same series and (b)
have identical terms except as to principal amount and/or date of issuance.

Trustee:

The term  "Trustee"  shall  mean  The  Bank of New  York,  and,  subject  to the
provisions of Article Seven, shall also include its successors and assigns, and,
if at any time there is more than one person acting in such capacity  hereunder,
"Trustee"  shall mean each such person.  The term "Trustee" as used with respect
to a particular  series of the Securities shall mean the trustee with respect to
that series.

Trust Indenture Act:

The term "Trust  Indenture  Act",  subject to the  provisions of Sections  9.01,
9.02, and 10.01,  shall mean the Trust  Indenture Act of 1939, as amended and in
effect at the date of execution of this Indenture.

United States:

The term "United  States" means the United States of America,  its  Territories,
its possessions and other areas subject to its political jurisdiction.


                                   ARTICLE TWO
                      ISSUE, DESCRIPTION, TERMS, EXECUTION,
                     REGISTRATION AND EXCHANGE OF SECURITIES

     SECTION 2.01.....The  aggregate principal amount of Securities which may be
authenticated and delivered under this Indenture is unlimited.

     The Securities may be issued from time to time in one or more series and in
one or more Tranches thereof. Each series shall be authorized by a Company Order
or Orders or one or more  indentures  supplemental  hereto,  which shall specify
whether the  Securities of such series shall be subject to a Periodic  Offering.
The  Company  Order or Orders or  supplemental  indenture  and, in the case of a
Periodic  Offering,  Instructions or other procedures  acceptable to the Trustee
specified  in such Company  Order or Orders,  shall  establish  the terms of the
series,  which may include the following:  (i) any  limitations on the aggregate
principal amount of the Securities to be authenticated  and delivered under this
Indenture  as part of such  series  (except  for  Securities  authenticated  and
delivered upon  registration of transfer of, in exchange for or in lieu of other
Securities  of that  series);  (ii) the stated  maturity or  maturities  of such
series;  (iii) the date or dates from which interest shall accrue,  the Interest
Payment  Dates  on  which  such  interest  will  be  payable  or the  manner  of
determination  of such  Interest  Payment  Dates  and the  record  date  for the
determination  of holders  to whom  interest  is  payable  on any such  Interest
Payment Date;  (iv) the interest rate or rates (which may be fixed or variable),
or method of calculation of such rate or rates, for such series;  (v) the terms,
if any, regarding the redemption,  purchase or repayment of such series (whether
at the option of the  Company or a holder of the  Securities  of such series and
whether pursuant to a sinking fund or analogous  provisions,  including payments
made in cash in  anticipation  of future  sinking fund  obligations),  including
redemption,  purchase or repayment date or dates of such series, if any, and the
price or prices and other terms and  conditions  applicable to such  redemption,
purchase  or  repayment  (including  any  premium);  (vi)  whether  or  not  the
Securities  of such series  shall be issued in whole or in part in the form of a
Global  Security  and, if so, the  Depositary  for such Global  Security and the
related  procedures  with  respect  to  transfer  and  exchange  of such  Global
Security;  (vii)  the  designation  of  such  series;  (viii)  the  form  of the
Securities of such series; (ix) the maximum annual interest rate, if any, of the
Securities  permitted for such series; (x) whether the Securities of such series
shall be  subject  to  Periodic  Offering;  (xi)  the  currency  or  currencies,
including  composite  currencies,  in which  payment  of the  principal  of (and
premium, if any) and interest on the Securities of such series shall be payable,
if other than  Dollars;  (xii) any other  information  necessary to complete the
Securities  of such  series;  (xiii) the  establishment  of any office or agency
pursuant  to  Section  4.02  hereof  and any  other  place or  places  which the
principal  of and  interest,  if any,  on  Securities  of that  series  shall be
payable;  (xiv) if other than  denominations of $1,000 or any integral  multiple
thereof,  the  denominations  in which the  Securities  of the  series  shall be
issuable; (xv) the obligations or instruments, if any, which shall be considered
to be  Eligible  Obligations  in  respect  of  the  Securities  of  such  series
denominated in a currency other than Dollars or in a composite  currency;  (xvi)
whether  or not the  Securities  of such  series  shall be  issued  as  Discount
Securities and the terms thereof,  including the portion of the principal amount
thereof which shall be payable upon  declaration of acceleration of the maturity
thereof pursuant to Section 6.01(b);  (xvii) if the principal,  premium, if any,
or interest,  if any, on such  Securities are to be payable,  at the election of
the Company or the holder  thereof,  in coin or  currency,  including  composite
currencies,  other than that in which the  Securities  are stated to be payable,
the period or periods  within which,  and the terms and  conditions  upon which,
such  election  shall be made;  (xviii) if the amount of payment of principal of
and premium,  if any, or interest,  if any, on such Securities may be determined
with  reference  to an index,  formula  or other  method,  or based on a coin or
currency other than that in which the  Securities are stated to be payable,  the
manner in which such amount  shall be  determined;  and (xix) any other terms of
such series not inconsistent with this Indenture.

     All Securities of any one series shall be substantially identical except as
to  denomination  and except as may  otherwise be provided in or pursuant to any
such Company Order or in any indentures supplemental hereto.

     If any of the terms of the series are  established by action taken pursuant
to a Company  Order, a copy of an  appropriate  record of the  applicable  Board
Resolution shall be certified by the Secretary or an Assistant  Secretary of the
Company and  delivered to the Trustee at or prior to the delivery of the Company
Order setting forth the terms of that series.

     SECTION 2.02.....The Securities of any series shall be substantially of the
tenor and purport (i) as set forth in one or more indentures supplemental hereto
or as  provided  in a Company  Order,  or (ii) with  respect  to any  Tranche of
Securities of a series subject to Periodic Offering,  to the extent permitted by
any of the documents  referred to in clause (i) above,  in  Instructions,  or by
other  procedures  acceptable to the Trustee  specified in such Company Order or
Orders, in each case with such appropriate insertions, omissions,  substitutions
and other  variations  as are required or permitted by this  Indenture,  and may
have such letters,  numbers or other marks of  identification or designation and
such legends or endorsements  printed,  lithographed or engraved  thereon as the
Company may deem appropriate and as are not inconsistent  with the provisions of
this Indenture, or as may be required to comply with any law or with any rule or
regulation  made  pursuant  thereto or with any rule or  regulation of any stock
exchange on which  Securities of that series may be listed or of the Depository,
or to conform to usage.

     The Trustee's  Certificate of Authentication  shall be in substantially the
following form:

     "This is one of the Securities of the series designated in accordance with,
     and referred to in, the within-mentioned Indenture.

     Dated:

     THE BANK OF NEW YORK, as Trustee

     By:___________________________
        Authorized Signatory"


     SECTION 2.03.....The  Securities shall be issuable as registered Securities
and in the denominations of $1,000 or any integral multiple thereof,  subject to
Sections  2.01(xi) and (xiv).  The Securities of a particular  series shall bear
interest payable on the dates and at the rate or rates specified with respect to
that series.  Except as otherwise specified as contemplated by Section 2.01, the
principal of and the interest on the  Securities  of any series,  as well as any
premium  thereon  in case of  redemption  thereof  prior to  maturity,  shall be
payable in Dollars at the office or agency of the  Company  maintained  for that
purpose. Each Security shall be dated the date of its authentication.

     The  interest  installment  on  any  Security  which  is  payable,  and  is
punctually  paid  or  duly  provided  for,  on any  Interest  Payment  Date  for
Securities  of that  series  shall  be paid to the  person  in whose  name  said
Security (or one or more  Predecessor  Securities) is registered at the close of
business on the regular record date for such interest  installment,  except that
interest  payable on redemption or maturity shall be payable as set forth in the
Company Order or indenture  supplemental  hereto  establishing the terms of such
series of Securities.  Except as otherwise  specified as contemplated by Section
2.01,  interest on Securities will be computed on the basis of a 360-day year of
twelve 30-day months.

     Any interest on any Security which is payable,  but is not punctually  paid
or duly  provided for, on any Interest  Payment Date for  Securities of the same
series (herein called "Defaulted  Interest") shall forthwith cease to be payable
to the registered holder on the relevant regular record date by virtue of having
been such holder; and such Defaulted  Interest shall be paid by the Company,  at
its election, as provided in clause (1) or clause (2) below:

          (1)  The  Company  may  make  payment  of any  Defaulted  Interest  on
     Securities  to the  persons  in  whose  names  such  Securities  (or  their
     respective Predecessor  Securities) are registered at the close of business
     on a special record date for the payment of such Defaulted Interest,  which
     shall be fixed in the  following  manner:  the  Company  shall  notify  the
     Trustee in writing of the amount of Defaulted  Interest proposed to be paid
     on each such Security and the date of the proposed payment, and at the same
     time the Company shall deposit with the Trustee an amount of money equal to
     the  aggregate  amount  proposed  to be paid in respect  of such  Defaulted
     Interest or shall make  arrangements  satisfactory  to the Trustee for such
     deposit  prior  to the  date  of the  proposed  payment,  such  money  when
     deposited  to be held in trust for the benefit of the  persons  entitled to
     such Defaulted  Interest as in this clause provided.  Thereupon the Trustee
     shall fix a special record date for the payment of such Defaulted  Interest
     which  shall not be more than 15 nor less than 10 days prior to the date of
     the  proposed  payment  and not less than 10 days after the  receipt by the
     Trustee of the notice of the proposed  payment.  The Trustee shall promptly
     notify the Company of such special  record date and, in the name and at the
     expense of the Company,  shall cause notice of the proposed payment of such
     Defaulted Interest and the special record date therefor to be mailed, first
     class postage prepaid,  to each  Securityholder at his or her address as it
     appears in the Security Register (as hereinafter defined), not less than 10
     days prior to such special record date.  Notice of the proposed  payment of
     such Defaulted  Interest and the special  record date therefor  having been
     mailed as aforesaid,  such Defaulted  Interest shall be paid to the persons
     in whose names such Securities (or their respective Predecessor Securities)
     are  registered on such special  record date and shall be no longer payable
     pursuant to the following clause (2).

          (2) The  Company  may make  payment of any  Defaulted  Interest on any
     Securities   in  any  other  lawful  manner  not   inconsistent   with  the
     requirements  of any  securities  exchange on which such  Securities may be
     listed, and upon such notice as may be required by such exchange, if, after
     notice given by the Company to the Trustee of the proposed payment pursuant
     to this clause,  such manner of payment shall be deemed  practicable by the
     Trustee.

     Unless  otherwise  set forth in a Company  Order or one or more  indentures
supplemental  hereto establishing the terms of any series of Securities pursuant
to Section 2.01 hereof,  the term "regular  record date" as used in this Section
with respect to a series of Securities with respect to any Interest Payment Date
for such series  shall mean either the  fifteenth  day of the month  immediately
preceding  the month in which an  Interest  Payment  Date  established  for such
series  pursuant to Section 2.01 hereof shall occur,  if such  Interest  Payment
Date is the  first  day of a month,  or the last  day of the  month  immediately
preceding  the month in which an  Interest  Payment  Date  established  for such
series  pursuant to Section 2.01 hereof shall occur,  if such  Interest  Payment
Date is the  fifteenth  day of a month,  whether  or not such date is a Business
Day.  Subject to the foregoing  provisions  of this Section,  each Security of a
series  delivered under this Indenture upon transfer of or in exchange for or in
lieu of any other  Security  of such  series  shall carry the rights to interest
accrued and unpaid, and to accrue, which were carried by such other Security.

     SECTION 2.04.....The Securities shall, subject to the provisions of Section
2.06, be printed on steel engraved  borders or fully or partially  engraved,  or
legibly typed, as the proper officer of the Company may determine,  and shall be
signed on behalf of the Company by an Authorized Officer.  The signature of such
Authorized  Officer  upon  the  Securities  may be in the  form  of a  facsimile
signature of a present or any future Authorized  Officer and may be imprinted or
otherwise  reproduced on the Securities and for that purpose the Company may use
the facsimile signature of any person who shall have been an Authorized Officer,
notwithstanding  the fact that at the time the Securities shall be authenticated
and  delivered or disposed of such person shall have ceased to be an  Authorized
Officer.

     Only such Securities as shall bear thereon a Certificate of  Authentication
substantially in the form established for such Securities,  executed manually by
an  authorized  signatory of the Trustee,  or by any  Authenticating  Agent with
respect to such Securities,  shall be entitled to the benefits of this Indenture
or be valid or  obligatory  for any purpose.  Such  certificate  executed by the
Trustee, or by any Authenticating Agent appointed by the Trustee with respect to
such Securities,  upon any Security  executed by the Company shall be conclusive
evidence  that the Security so  authenticated  has been duly  authenticated  and
delivered  hereunder and that the  registered  holder thereof is entitled to the
benefits of this Indenture.

     At any time and from time to time after the  execution and delivery of this
Indenture,  the  Company may deliver  Securities  of any series  executed by the
Company to the Trustee for authentication, together with a Company Order for the
authentication  and delivery of such  Securities and the Trustee,  in accordance
with such  Company  Order,  shall  authenticate  and  deliver  such  Securities;
provided,  however,  that  in the  case  of  Securities  offered  in a  Periodic
Offering,  the Trustee shall  authenticate and deliver such Securities from time
to time in accordance with  Instructions or such other procedures  acceptable to
the Trustee as may be  specified by or pursuant to a  supplemental  indenture or
Company  Order  delivered  to the  Trustee  prior  to  the  time  of  the  first
authentication of Securities of such series.

     In   authenticating   such   Securities   and  accepting   the   additional
responsibilities  under this  Indenture  in  relation  to such  Securities,  the
Trustee shall receive and (subject to Section 7.01) shall be fully  protected in
relying upon, (i) an Opinion of Counsel and (ii) an Officers' Certificate,  each
stating that the form and terms thereof have been established in conformity with
the  provisions of this  Indenture;  provided,  however,  that,  with respect to
Securities  of a series  subject to a Periodic  Offering,  the Trustee  shall be
entitled to receive such Opinion of Counsel and Officers'  Certificate only once
at or prior to the time of the first authentication of Securities of such series
and that, in such opinion or certificate,  the opinion or certificate  described
above may state that when the terms of such Securities, or each Tranche thereof,
shall have been established pursuant to a Company Order or Orders or pursuant to
such  procedures  acceptable  to the  Trustee,  as may be specified by a Company
Order,  such terms will have been  established in conformity with the provisions
of this Indenture.  Each Opinion of Counsel and Officers'  Certificate delivered
pursuant to this Section 2.04 shall include all statements prescribed in Section
13.06(b).  Such  Opinion of Counsel  shall also be to the effect  that when such
Securities have been executed by the Company and authenticated by the Trustee in
accordance  with the provisions of this Indenture and delivered to and duly paid
for  by  the  purchasers  thereof,  they  will  be  valid  and  legally  binding
obligations of the Company,  enforceable in accordance with their terms (subject
to customary exceptions) and will be entitled to the benefits of this Indenture.

     With respect to Securities of a series subject to a Periodic Offering,  the
Trustee may conclusively  rely, as to the authorization by the Company of any of
such Securities, the forms and terms thereof and the legality, validity, binding
effect and enforceability  thereof,  upon the Company Order, Opinion of Counsel,
Officers'  Certificate and other documents delivered pursuant to this Section at
or prior to the time of the first  authentication  of  Securities of such series
unless and until such Company Order, Opinion of Counsel,  Officers'  Certificate
or other documents have been superseded or revoked or expire by their terms.

     The Trustee shall not be required to  authenticate  such  Securities if the
issue of such  Securities  pursuant to this  Indenture will affect the Trustee's
own rights,  duties or immunities  under the  Securities  and this  Indenture or
otherwise in a manner which is not reasonably acceptable to the Trustee.

     SECTION  2.05.....(a)...Securities  of any  series  may be  exchanged  upon
presentation  thereof at the office or agency of the Company designated for such
purpose,  for other Securities of such series of authorized  denominations,  and
for a like aggregate principal amount, upon payment of a sum sufficient to cover
any tax or other  governmental  charge in relation  thereto,  all as provided in
this Section.  In respect of any  Securities so  surrendered  for exchange,  the
Company shall execute,  the Trustee shall authenticate and such office or agency
shall deliver in exchange therefor the Security or Securities of the same series
which the  Securityholder  making the  exchange  shall be  entitled  to receive,
bearing numbers not contemporaneously outstanding.

     (b) The Company  shall keep,  or cause to be kept,  at its office or agency
designated  for such purpose in the Borough of Manhattan,  the City and State of
New York,  or such  other  location  designated  by the  Company a  register  or
registers (herein referred to as the "Security  Register") in which,  subject to
such reasonable regulations as it may prescribe,  the Company shall register the
Securities and the transfers of Securities as in this Article provided and which
at all  reasonable  times  shall  be open for  inspection  by the  Trustee.  The
registrar for the purpose of  registering  Securities and transfer of Securities
as herein  provided  shall be appointed as  authorized by Board  Resolution,  an
indenture supplement hereto or Company Order (the "Security Registrar").

     Upon  surrender for transfer of any Security at the office or agency of the
Company  designated  for such purpose in the Borough of Manhattan,  the City and
State of New York, or other  location as aforesaid,  the Company shall  execute,
the Trustee  shall  authenticate  and such office or agency shall deliver in the
name of the  transferee or  transferees a new Security or Securities of the same
series as the Security presented for a like aggregate principal amount.

     All Securities  presented or surrendered  for exchange or  registration  of
transfer,  as provided in this Section,  shall be accompanied (if so required by
the Company or the Security Registrar) by a written instrument or instruments of
transfer,  in form satisfactory to the Company or the Security  Registrar,  duly
executed by the registered holder or by his duly authorized attorney in writing.

     (c) Except as provided in the first  paragraph of Section  2.07, no service
charge shall be made for any exchange or registration of transfer of Securities,
or issue of new Securities in case of partial  redemption of any series, but the
Company  may  require  payment  of a sum  sufficient  to cover  any tax or other
governmental  charge in  relation  thereto,  other than  exchanges  pursuant  to
Section 2.06, Section 3.03(b) and Section 9.04 not involving any transfer.

     (d) The  Company  shall  neither  be  required  (i) to issue,  exchange  or
register the transfer of any Securities during a period beginning at the opening
of business 15 days before the day of the mailing of a notice of  redemption  of
less than all the  outstanding  Securities  of the same series and ending at the
close of business on the day of such mailing,  nor (ii) to register the transfer
of or  exchange  any  Securities  of any series or portions  thereof  called for
redemption or as to which the holder thereof has exercised its right, if any, to
require the Company to repurchase such Security in whole or in part, except that
portion of such Security not required to be repurchased.  The provisions of this
Section 2.05 are, with respect to any Global  Security,  subject to Section 2.11
hereof.

     SECTION  2.06.....Pending  the preparation of definitive  Securities of any
series, the Company may execute, and the Trustee shall authenticate and deliver,
temporary  Securities  (printed,  lithographed or typewritten) of any authorized
denomination, and substantially in the form of the definitive Securities in lieu
of which they are issued, but with such omissions,  insertions and variations as
may be  appropriate  for temporary  Securities,  all as may be determined by the
Company. Every temporary Security of any series shall be executed by the Company
and  be   authenticated   by  the  Trustee  upon  the  same  conditions  and  in
substantially  the  same  manner,  and  with  like  effect,  as  the  definitive
Securities of such series in accordance with Section 2.04.  Without  unnecessary
delay the Company will execute and will furnish  definitive  Securities  of such
series and  thereupon  any or all  temporary  Securities  of such  series may be
surrendered in exchange therefor (without charge to the holders thereof), at the
office or agency of the  Company  designated  for the  purpose,  and the Trustee
shall  authenticate and such office or agency shall deliver in exchange for such
temporary   Securities  an  equal  aggregate   principal  amount  of  definitive
Securities of such series,  unless the Company advises the Trustee to the effect
that  definitive  Securities  need not be executed and  furnished  until further
notice from the Company.  Until so exchanged,  the temporary  Securities of such
series shall be entitled to the same benefits under this Indenture as definitive
Securities of such series authenticated and delivered hereunder.


     SECTION  2.07.....In case any temporary or definitive Security shall become
mutilated  or be  destroyed,  lost or stolen,  the Company  (subject to the next
succeeding sentence) shall execute, and upon its request the Trustee (subject as
aforesaid)  shall  authenticate  and deliver,  a new Security of the same series
bearing a number not contemporaneously outstanding, in exchange and substitution
for the mutilated  Security,  or in lieu of and in substitution for the Security
so  destroyed,  lost or stolen.  In every case the  applicant  for a substituted
Security  shall  furnish to the  Company  and to the  Trustee  such  security or
indemnity  as may be  required  by them to save each of them  harmless,  and, in
every case of  destruction,  loss or theft,  the applicant shall also furnish to
the  Company  and  to  the  Trustee  evidence  to  their   satisfaction  of  the
destruction,  loss or theft of the  applicant's  Security  and of the  ownership
thereof.  The Trustee may authenticate any such substituted Security and deliver
the same  upon the  written  request  or  authorization  of any  officer  of the
Company. Upon the issuance of any substituted Security,  the Company may require
the payment of a sum  sufficient to cover any tax or other  governmental  charge
that may be imposed in relation  thereto and any other  expenses  (including the
fees and  expenses of the  Trustee)  connected  therewith.  In case any Security
which has matured or is about to mature shall become  mutilated or be destroyed,
lost or stolen, the Company may, instead of issuing a substitute  Security,  pay
or authorize the payment of the same (without  surrender  thereof  except in the
case of a mutilated Security) if the applicant for such payment shall furnish to
the Company and to the Trustee such security or indemnity as they may require to
save them harmless, and, in case of destruction,  loss or theft, evidence to the
satisfaction of the Company and the Trustee of the destruction, loss or theft of
such Security and of the ownership thereof.

     Every  Security  issued  pursuant  to the  provisions  of this  Section  in
substitution  for any Security  which is  mutilated,  destroyed,  lost or stolen
shall constitute an additional contractual obligation of the Company, whether or
not the  mutilated,  destroyed,  lost or stolen  Security  shall be found at any
time, or be enforceable by anyone,  and shall be entitled to all the benefits of
this Indenture equally and proportionately  with any and all other Securities of
the same series duly issued  hereunder.  All Securities  shall be held and owned
upon the express  condition  that the foregoing  provisions  are exclusive  with
respect to the  replacement or payment of mutilated,  destroyed,  lost or stolen
Securities,  and shall  preclude (to the extent lawful) any and all other rights
or remedies, notwithstanding any law or statute existing or hereafter enacted to
the  contrary  with  respect  to  the   replacement  or  payment  of  negotiable
instruments or other securities without their surrender.

     SECTION  2.08.....All  Securities  surrendered  for the purpose of payment,
redemption,  exchange  or  registration  of  transfer,  or for credit  against a
sinking fund,  shall,  if  surrendered  to the Company or any paying  agent,  be
delivered to the Trustee for  cancellation,  or, if  surrendered to the Trustee,
shall be  canceled  by it,  and no  Securities  shall be issued in lieu  thereof
except as  expressly  required or  permitted  by any of the  provisions  of this
Indenture.  On request of the Company,  the Trustee shall deliver to the Company
canceled  Securities  held by the  Trustee.  In the absence of such  request the
Trustee may dispose of  canceled  Securities  in  accordance  with its  standard
procedures.  If the  Company  shall  otherwise  acquire  any of the  Securities,
however,  such acquisition  shall not operate as a redemption or satisfaction of
the  indebtedness  represented by such Securities  unless and until the same are
delivered to the Trustee for cancellation.

     SECTION 2.09.....Nothing in this Indenture or in the Securities, express or
implied,  shall give or be construed to give to any person, firm or corporation,
other than the parties  hereto and the holders of the  Securities,  any legal or
equitable right, remedy or claim under or in respect of this Indenture, or under
any  covenant,  condition or provision  herein  contained;  all such  covenants,
conditions and  provisions  being for the sole benefit of the parties hereto and
of the holders of the Securities.

     SECTION  2.10.....So  long as any of the  Securities  of any series  remain
outstanding there may be an  Authenticating  Agent for any or all such series of
Securities   which  the  Trustee   shall  have  the  right  to   appoint.   Said
Authenticating  Agent  shall be  authorized  to act on behalf of the  Trustee to
authenticate Securities of such series issued upon exchange, transfer or partial
redemption  thereof,  and Securities so  authenticated  shall be entitled to the
benefits of this Indenture and shall be valid and obligatory for all purposes as
if authenticated by the Trustee  hereunder.  All references in this Indenture to
the  authentication  of  Securities  by the  Trustee  shall be deemed to include
authentication   by  an   Authenticating   Agent  for  such  series  except  for
authentication  upon original issuance or pursuant to Section 2.07 hereof.  Each
Authenticating  Agent  shall  be  acceptable  to  the  Company  and  shall  be a
corporation which has a combined capital and surplus,  as most recently reported
or determined by it,  sufficient under the laws of any jurisdiction  under which
it is  organized or in which it is doing  business to conduct a trust  business,
and which is otherwise  authorized  under such laws to conduct such business and
is subject to supervision or examination by Federal or State authorities.  If at
any time any Authenticating  Agent shall cease to be eligible in accordance with
these provisions it shall resign immediately.

     Any Authenticating Agent may at any time resign by giving written notice of
resignation to the Trustee and to the Company.  The Trustee may at any time (and
upon request by the Company  shall)  terminate the agency of any  Authenticating
Agent by giving written notice of termination to such  Authenticating  Agent and
to the Company. Upon resignation, termination or cessation of eligibility of any
Authenticating   Agent,   the  Trustee   may   appoint  an  eligible   successor
Authenticating  Agent  acceptable to the Company.  Any successor  Authenticating
Agent,  upon acceptance of its appointment  hereunder,  shall become vested with
all the rights,  powers and duties of its predecessor hereunder as if originally
named as an Authenticating  Agent pursuant hereto.  The Company agrees to pay to
each  Authenticating  Agent from time to time  reasonable  compensation  for its
services under this Section.

     SECTION  2.11.....(a)....If the Company shall establish pursuant to Section
2.01 that the  Securities  of a  particular  series are to be issued as a Global
Security,  then the Company shall execute and the Trustee  shall,  in accordance
with Section 2.04,  authenticate and deliver,  a Global Security which (i) shall
represent,  and  shall  be  denominated  in an  amount  equal  to the  aggregate
principal  amount of, all of the  Outstanding  Securities  of such series,  (ii)
shall be registered in the name of the Depository or its nominee, (iii) shall be
authenticated  and delivered by the Trustee to the Depository or pursuant to the
Depository's  instruction  and (iv)  shall  bear a legend  substantially  to the
following  effect:  "Except  as  otherwise  provided  in  Section  2.11  of  the
Indenture,  this Security may be transferred,  in whole but not in part, only to
another  nominee of the Depository or to a successor  Depository or to a nominee
of such successor Depository."

     (b)  Notwithstanding the provisions of Section 2.05, the Global Security of
a series may be transferred, in whole but not in part and in the manner provided
in Section 2.05, only to another  nominee of the Depository for such series,  or
to a successor Depository for such series selected or approved by the Company or
to a nominee of such successor Depository.

     (c) If at any time the Depository  for a series of Securities  notifies the
Company that it is unwilling or unable to continue as Depository for such series
or if at any time the  Depository  for such series shall no longer be registered
or in good  standing  under the  Exchange  Act, or other  applicable  statute or
regulation  and a successor  Depository  for such series is not appointed by the
Company  within 90 days after the Company  receives such notice or becomes aware
of such  condition,  as the case may be,  this  Section  2.11 shall no longer be
applicable to the  Securities  of such series and the Company will execute,  and
subject to Section 2.05, the Trustee will authenticate and deliver Securities of
such  series in  definitive  registered  form  without  coupons,  in  authorized
denominations,  and in an  aggregate  principal  amount  equal to the  principal
amount of the  Global  Security  of such  series  in  exchange  for such  Global
Security. In addition, the Company may at any time determine that the Securities
of any series shall no longer be represented  by a Global  Security and that the
provisions of this Section 2.11 shall no longer apply to the  Securities of such
series. In such event the Company will execute, and subject to Section 2.05, the
Trustee, upon receipt of an Officers' Certificate  evidencing such determination
by the  Company,  will  authenticate  and deliver  Securities  of such series in
definitive registered form without coupons, in authorized denominations,  and in
an  aggregate  principal  amount  equal to the  principal  amount of the  Global
Security of such series in exchange for such Global Security.  Upon the exchange
of the Global Security for such Securities in definitive registered form without
coupons, in authorized  denominations,  the Global Security shall be canceled by
the Trustee.  Such  Securities in definitive  registered form issued in exchange
for the Global Security  pursuant to this Section 2.11(c) shall be registered in
such names and in such authorized  denominations as the Depository,  pursuant to
instructions  from its  direct or  indirect  participants  or  otherwise,  shall
instruct the Security  Registrar.  The Trustee shall deliver such  Securities to
the Depository for delivery to the persons in whose names such Securities are so
registered.

     SECTION 2.12.....In the case of the Securities of any series denominated in
any  currency  other than  Dollars or in a  composite  currency  (the  "Required
Currency"),  except as otherwise  specified  with respect to such  Securities as
contemplated  by Section 2.01, the obligation of the Company to make any payment
of the  principal  thereof,  or the  premium or interest  thereon,  shall not be
discharged  or  satisfied  by any  tender by the  Company,  or  recovery  by the
Trustee, in any currency other than the Required Currency,  except to the extent
that such tender or recovery shall result in the Trustee timely holding the full
amount of the  Required  Currency  then due and  payable.  If any such tender or
recovery is in a currency other than the Required Currency, the Trustee may take
such  actions as it  considers  appropriate  to exchange  such  currency for the
Required Currency. The costs and risks of any such exchange,  including, without
limitation, the risks of delay and exchange rate fluctuation,  shall be borne by
the  Company,  the  Company  shall  remain  fully  liable for any  shortfall  or
delinquency in the full amount of Required Currency then due and payable, and in
no circumstances  shall the Trustee be liable therefor except in the case of its
negligence or willful misconduct.

     SECTION  2.13.....The Company in issuing Securities may use "CUSIP" numbers
(if then  generally  in use) and,  if so used,  the  Trustee  shall use  "CUSIP"
numbers in notices of  redemption  as a  convenience  to holders of  Securities;
provided that any such notice may state that no representation is made as to the
correctness  of such numbers either as printed on the Securities or contained in
any  notice of  redemption  and that  reliance  may be placed  only on the other
identification numbers printed on the Securities,  and any such redemption shall
not be affected by any defect in or omission of such numbers.  The Company shall
promptly notify the Trustee of any change in the CUSIP numbers.


                                  ARTICLE THREE
              REDEMPTION OF SECURITIES AND SINKING FUND PROVISIONS

     SECTION 3.01.....The Company may redeem the Securities of any series issued
hereunder on and after the dates and in  accordance  with the terms  established
for such series pursuant to Section 2.01 hereof.

     SECTION  3.02.....(a)....In  case the Company shall desire to exercise such
right to redeem all or, as the case may be, a portion of the  Securities  of any
series in accordance  with the right  reserved so to do, it shall give notice of
such  redemption  to holders of the  Securities of such series to be redeemed by
mailing,  first class postage prepaid, a notice of such redemption not less than
30 days and not more than 60 days before the date fixed for  redemption  of that
series to such  holders at their last  addresses  as they shall  appear upon the
Security  Register.  Any notice  which is mailed in the manner  herein  provided
shall be  conclusively  presumed  to have been duly  given,  whether  or not the
registered  holder receives the notice.  In any case,  failure duly to give such
notice to the holder of any Security of any series  designated for redemption in
whole or in part, or any defect in the notice,  shall not affect the validity of
the proceedings for the redemption of any other Securities of such series or any
other  series.  In the  case  of  any  redemption  of  Securities  prior  to the
expiration of any  restriction on such  redemption or subject to compliance with
certain conditions provided in the terms of such Securities or elsewhere in this
Indenture,  the Company shall furnish the Trustee with an Officers'  Certificate
evidencing compliance with any such restriction or condition.

     Unless otherwise so provided as to a particular series of Securities, if at
the time of mailing  of any  notice of  redemption  the  Company  shall not have
deposited  with the paying agent an amount in cash  sufficient  to redeem all of
the Securities  called for redemption,  including  accrued  interest to the date
fixed for redemption,  such notice shall state that it is subject to the receipt
of  redemption  moneys  by the  paying  agent on or  before  the date  fixed for
redemption  (unless such redemption is mandatory) and such notice shall be of no
effect unless such moneys are so received on or before such date.

     Each such notice of redemption shall identify the Securities to be redeemed
(including CUSIP numbers, if any), specify the date fixed for redemption and the
redemption  price at which  Securities  of that series are to be  redeemed,  and
shall  state  that  payment of the  redemption  price of such  Securities  to be
redeemed will be made at the office or agency of the Company,  upon presentation
and surrender of such  Securities,  that interest  accrued to the date fixed for
redemption  will be paid as specified  in said notice,  that from and after said
date  interest  will  cease to accrue and that the  redemption  is for a sinking
fund, if such is the case. If less than all the Securities of a series are to be
redeemed,  the notice to the holders of Securities of that series to be redeemed
in whole or in part shall specify the  particular  Securities to be so redeemed.
In case any Security is to be redeemed in part only, the notice which relates to
such  Security  shall state the portion of the  principal  amount  thereof to be
redeemed,  and shall state that on and after the redemption date, upon surrender
of such  Security,  a new  Security or  Securities  of such series in  principal
amount equal to the unredeemed portion thereof will be issued.

     (b) If less than all the  Securities  of a series are to be  redeemed,  the
Company  shall give the Trustee at least 45 days'  notice in advance of the date
fixed for redemption  (unless the Trustee shall agree to a shorter period) as to
the aggregate  principal amount of Securities of the series to be redeemed,  and
thereupon the Trustee  shall select,  by lot or in such other manner as it shall
deem  appropriate  and fair in its  discretion  and  which may  provide  for the
selection  of a portion or portions  (equal to $1,000 or any  integral  multiple
thereof, subject to Sections 2.01(xi) and (xiv)) of the principal amount of such
Securities of a  denomination  larger than $1,000  (subject as  aforesaid),  the
Securities to be redeemed and shall  thereafter  promptly  notify the Company in
writing of the numbers of the Securities to be redeemed, in whole or in part.

     The  Company  may,  if and  whenever  it shall so  elect,  by  delivery  of
instructions signed on its behalf by an Authorized Officer, instruct the Trustee
or any paying  agent to call all or any part of the  Securities  of a particular
series for  redemption  and to give notice of redemption in the manner set forth
in this Section, such notice to be in the name of the Company or its own name as
the Trustee or such paying agent may deem advisable. In any case in which notice
of  redemption  is to be given by the  Trustee  or any such  paying  agent,  the
Company shall deliver or cause to be delivered to, or permit to remain with, the
Trustee  or such  paying  agent,  as the case may be,  such  Security  Register,
transfer  books or other  records,  or suitable  copies or  extracts  therefrom,
sufficient to enable the Trustee or such paying agent to give any notice by mail
that may be required under the provisions of this Section.

     SECTION  3.03.....(a)....If  the giving of notice of redemption  shall have
been  completed as above  provided,  the Securities or portions of Securities of
the series to be redeemed  specified in such notice shall become due and payable
on the date and at the place stated in such notice at the applicable  redemption
price,  together with,  subject to the Company Order or  supplemental  indenture
hereto establishing the terms of such series of Securities,  interest accrued to
the date fixed for  redemption  and interest on such  Securities  or portions of
Securities  shall  cease to accrue on and after the date  fixed for  redemption,
unless the Company  shall  default in the payment of such  redemption  price and
accrued  interest  with  respect to any such  Security  or portion  thereof.  On
presentation  and  surrender of such  Securities  on or after the date fixed for
redemption  at the place of payment  specified  in the notice,  said  Securities
shall be paid and redeemed at the applicable  redemption  price for such series,
together with,  subject to the Company Order or  supplemental  indenture  hereto
establishing the terms of such series of Securities, interest accrued thereon to
the date fixed for redemption.

     (b)  Upon  presentation  of any  Security  of such  series  which  is to be
redeemed  in  part  only,  the  Company  shall  execute  and the  Trustee  shall
authenticate  and the office or agency  where the  Security is  presented  shall
deliver to the holder thereof,  at the expense of the Company, a new Security or
Securities of the same series,  of authorized  denominations in principal amount
equal to the unredeemed portion of the Security so presented.

     SECTION 3.04.....The  provisions of this Section 3.04 and Sections 3.05 and
3.06 shall be applicable to any sinking fund for the retirement of Securities of
a series,  except as  otherwise  specified as  contemplated  by Section 2.01 for
Securities of such series.

     The minimum amount of any sinking fund payment provided for by the terms of
Securities  of any series is herein  referred to as a  "mandatory  sinking  fund
payment",  and any payment in excess of such minimum amount  provided for by the
terms of Securities of any series is herein referred to as an "optional  sinking
fund  payment".  If provided for by the terms of Securities  of any series,  the
cash amount of any sinking  fund payment may be subject to reduction as provided
in Section 3.05. Each sinking fund payment shall be applied to the redemption of
Securities  of such series as provided  for by the terms of  Securities  of such
series.

     SECTION  3.05.....The  Company (i) may deliver Outstanding  Securities of a
series (other than any previously called for redemption) and (ii) may apply as a
credit Securities of a series which have been redeemed either at the election of
the Company  pursuant to the terms of such Securities or through the application
of  permitted  optional  sinking  fund  payments  pursuant  to the terms of such
Securities,  in each case in  satisfaction  of all or any part of any  mandatory
sinking fund payment;  provided that such Securities have not been previously so
credited. Such Securities shall be received and credited for such purpose by the
Trustee at the  redemption  price  specified in such  Securities  for redemption
through operation of the mandatory sinking fund and the amount of such mandatory
sinking fund payment shall be reduced accordingly.

     SECTION  3.06.....Not  less than 45 days prior to each sinking fund payment
date for any series of  Securities,  the Company  will deliver to the Trustee an
Officers'  Certificate  specifying  the amount of the next ensuing  sinking fund
payment  for that  series  pursuant  to the terms of that  series,  the  portion
thereof, if any, which is to be satisfied by delivering and crediting Securities
of that series  pursuant to Section 3.05 and the basis for such credit and will,
together with such Officers' Certificate,  deliver to the Trustee any Securities
to be so delivered.  Not less than 30 days before each such sinking fund payment
date the Trustee  shall select the  Securities  to be redeemed upon such sinking
fund  payment  date in the manner  specified in Section 3.02 and cause notice of
the  redemption  thereof  to be given in the name of and at the  expense  of the
Company  in the  manner  provided  in Section  3.02,  except  that the notice of
redemption  shall  also  state  that the  Securities  of such  series  are being
redeemed by operation  of the sinking  fund and the sinking  fund payment  date.
Such notice having been duly given,  the redemption of such Securities  shall be
made upon the terms and in the manner stated in Section 3.03.


                                  ARTICLE FOUR
                       PARTICULAR COVENANTS OF THE COMPANY

     The  Company  covenants  and agrees for each  series of the  Securities  as
follows:

     SECTION  4.01.....The  Company will duly and punctually pay or cause to be
paid the  principal of (and premium,  if any) and interest on the  Securities of
that  series  at the  time and  place  and in the  manner  provided  herein  and
established with respect to such Securities.

     SECTION   4.02.....So   long  as  any  series  of  the  Securities   remain
outstanding,  the Company agrees to maintain an office or agency with respect to
each such series, which shall be in the Borough of Manhattan, the City and State
of New York or at such other  location  or  locations  as may be  designated  as
provided  in this  Section  4.02,  where (i)  Securities  of that  series may be
presented  for  payment,  (ii)  Securities  of that series may be  presented  as
hereinabove  authorized  for  registration  of transfer and exchange,  and (iii)
notices and demands to or upon the Company in respect of the  Securities of that
series and this Indenture may be given or served,  such  designation to continue
with respect to such office or agency until the Company shall, by written notice
signed by an  Authorized  Officer and delivered to the Trustee,  designate  some
other  office or agency  for such  purposes  or any of them.  If at any time the
Company shall fail to maintain any such required  office or agency or shall fail
to furnish the Trustee with the address thereof, such presentations, notices and
demands may be made or served at the Corporate Trust Office of the Trustee,  and
the  Company  hereby  appoints  the  Trustee  as its agent to  receive  all such
presentations,  notices and demands.  The Trustee will  initially  act as paying
agent for the Securities.

     The  Company  may also from time to time,  by written  notice  signed by an
Authorized  Officer and  delivered to the Trustee,  designate  one or more other
offices or agencies for the foregoing  purposes within or outside the Borough of
Manhattan,   City  of  New  York,  and  may  from  time  to  time  rescind  such
designations; provided, however, that no such designation or rescission shall in
any manner  relieve  the  Company of its  obligations  to  maintain an office or
agency in the Borough of Manhattan, City of New York for the foregoing purposes.
The Company will give prompt  written notice to the Trustee of any change in the
location of any such other office or agency.

     SECTION  4.03.....(a)....If  the Company  shall  appoint one or more paying
agents for all or any series of the  Securities,  other  than the  Trustee,  the
Company  will cause each such paying agent to execute and deliver to the Trustee
an instrument  in which such agent shall agree with the Trustee,  subject to the
provisions of this Section:

          (1)  that it will  hold  all  sums  held by it as such  agent  for the
     payment  of the  principal  of (and  premium,  if any) or  interest  on the
     Securities  of that series  (whether  such sums have been paid to it by the
     Company  or by any  other  obligor  of such  Securities)  in trust  for the
     benefit of the persons entitled thereto;

          (2) that it will give the Trustee  prompt notice of any failure by the
     Company (or by any other obligor of such Securities) to make any payment of
     the  principal of (and  premium,  if any) or interest on the  Securities of
     that series when the same shall be due and payable;

          (3) that it will,  at any time during the  continuance  of any failure
     referred  to in the  preceding  paragraph  (a)(2)  above,  upon the written
     request of the  Trustee,  forthwith  pay to the Trustee all sums so held in
     trust by such paying agent; and

          (4) that it will perform all other duties of paying agent as set forth
     in this Indenture.

     (b) If the Company  shall act as its own paying  agent with  respect to any
series of the Securities, it will on or before each due date of the principal of
(and  premium,  if any) or interest on  Securities  of that  series,  set aside,
segregate  and hold in trust for the benefit of the persons  entitled  thereto a
sum  sufficient  to pay such  principal  (and  premium,  if any) or  interest so
becoming due on  Securities of that series until such sums shall be paid to such
persons or otherwise disposed of as herein provided and will promptly notify the
Trustee  of such  action,  or any  failure  (by it or any other  obligor on such
Securities)  to take such action.  Whenever  the Company  shall have one or more
paying agents for any series of Securities,  it will,  prior to each due date of
the  principal of (and  premium,  if any) or interest on any  Securities of that
series, deposit with the paying agent a sum sufficient to pay the principal (and
premium,  if any) or interest so becoming  due, such sum to be held in trust for
the benefit of the persons entitled to such principal,  premium or interest, and
(unless such paying agent is the Trustee) the Company will  promptly  notify the
Trustee of its action or failure so to act.

     (c)  Anything  in this  Section to the  contrary  notwithstanding,  (i) the
agreement  to hold sums in trust as provided  in this  Section is subject to the
provisions  of Section  11.04,  and (ii) the  Company  may at any time,  for the
purpose of obtaining the satisfaction and discharge of this Indenture or for any
other  purpose,  pay, or direct any paying agent to pay, to the Trustee all sums
held in trust by the Company or such paying  agent,  such sums to be held by the
Trustee  upon the same terms and  conditions  as those upon which such sums were
held by the Company or such paying  agent;  and, upon such payment by any paying
agent to the  Trustee,  such paying  agent  shall be  released  from all further
liability with respect to such money.

     SECTION  4.04.....The  Company,  whenever  necessary  to  avoid  or fill a
vacancy in the office of  Trustee,  will  appoint,  in the  manner  provided  in
Section  7.10,  a  Trustee,  so that  there  shall  at all  times  be a  Trustee
hereunder.

     SECTION  4.05.....The  Company will not, while any of the Securities remain
outstanding,  consolidate  with, or merge into, or merge into itself, or sell or
convey all or  substantially  all of its property to any other Person unless the
provisions of Article Ten hereof are complied with.

     SECTION  4.06.....In the event that the Company issues a Discount Security,
the  Company  shall  file  with  the  Trustee  at or  prior  to the  time of the
authentication  of such  Discount  Security  a written  notice,  in such form as
mutually  agreed upon by the Company and the Trustee,  specifying  the amount of
original issue  discount that will be accrued on such Discount  Security in each
calendar year from the date of issuance to the maturity thereof.


                                  ARTICLE FIVE
                SECURITYHOLDERS' LISTS AND REPORTS BY THE COMPANY
                                 AND THE TRUSTEE

     SECTION  5.01.....The  Company will furnish or cause to be furnished to the
Trustee (a) on each  regular  record  date (as defined in Section  2.03) for the
Securities  of each Tranche of a series a list,  in such form as the Trustee may
reasonably require, of the names and addresses of the holders of such Tranche of
Securities as of such regular record date, provided,  that the Company shall not
be obligated to furnish or cause to be furnished  such list at any time that the
list shall not differ in any respect from the most recent list  furnished to the
Trustee by the Company and (b) at such other times as the Trustee may request in
writing  within 30 days after the receipt by the Company of any such request,  a
list of similar form and content as of a date not more than 15 days prior to the
time such list is furnished;  provided,  however, no such list need be furnished
for any series for which the Trustee shall be the Security Registrar.

     SECTION 5.02.....(a)....The Trustee shall preserve, in as current a form as
is reasonably practicable,  all information as to the names and addresses of the
holders of  Securities  contained  in the most  recent list  furnished  to it as
provided  in  Section  5.01 and as to the  names and  addresses  of  holders  of
Securities  received by the Trustee in its  capacity as Security  Registrar  (if
acting in such capacity).

     (b) The Trustee may destroy any list furnished to it as provided in Section
5.01 upon receipt of a new list so furnished.

     (c) In case three or more holders of  Securities  of a series  (hereinafter
referred to as "applicants") apply in writing to the Trustee, and furnish to the
Trustee  reasonable  proof that each such  applicant  has owned a Security for a
period of at least six months preceding the date of such  application,  and such
application  states that the applicants desire to communicate with other holders
of Securities of such series or holders of all Securities  with respect to their
rights under this  Indenture or under such  Securities,  and is accompanied by a
copy of the form of proxy or other  communication  which such applicants propose
to transmit, then the Trustee shall, within five Business Days after the receipt
of such application, at its election, either:

          (1) afford to such applicants  access to the information  preserved at
     the time by the Trustee in accordance with the provisions of subsection (a)
     of this Section 5.02; or

          (2) inform such applicants as to the approximate  number of holders of
     Securities of such series or of all  Securities,  as the case may be, whose
     names and addresses appear in the information  preserved at the time by the
     Trustee,  in  accordance  with the  provisions  of  subsection  (a) of this
     Section  5.02,  and  as  to  the  approximate   cost  of  mailing  to  such
     Securityholders the form of proxy or other communication, if any, specified
     in such application.

     (d) If the Trustee shall elect not to afford such applicants access to such
information,  the Trustee shall,  upon the written  request of such  applicants,
mail to each  holder of such  series or of all  Securities,  as the case may be,
whose name and address appears in the  information  preserved at the time by the
Trustee in accordance  with the  provisions  of  subsection  (a) of this Section
5.02, a copy of the form of proxy or other  communication  which is specified in
such request,  with reasonable  promptness  after a tender to the Trustee of the
material to be mailed and of  payment,  or  provision  for the  payment,  of the
reasonable  expenses of mailing,  unless within five days after such tender, the
Trustee shall mail to such  applicants  and file with the  Commission,  together
with a copy of the  material  to be mailed,  a written  statement  to the effect
that, in the opinion of the Trustee,  such mailing would be contrary to the best
interests of the holders of Securities of such series or of all  Securities,  as
the case may be,  or would be in  violation  of  applicable  law.  Such  written
statement  shall specify the basis of such  opinion.  If the  Commission,  after
opportunity for a hearing upon the objections specified in the written statement
so filed, shall enter an order refusing to sustain any of such objections or if,
after  the  entry of an order  sustaining  one or more of such  objections,  the
Commission  shall find,  after notice and opportunity for hearing,  that all the
objections so sustained have been met and shall enter an order so declaring, the
Trustee  shall mail  copies of such  material to all such  Securityholders  with
reasonable  promptness  after the entry of such  order and the  renewal  of such
tender;  otherwise,  the Trustee shall be relieved of any  obligation or duty to
such applicants respecting their application.

     (e) Each and every holder of the  Securities,  by receiving and holding the
same,  agrees with the Company and the Trustee  that neither the Company nor the
Trustee  nor  any  paying  agent  nor  any  Security  Registrar  shall  be  held
accountable by reason of the disclosure of any such  information as to the names
and addresses of the holders of Securities in accordance  with the provisions of
subsection  (c) of this  Section,  regardless  of the  source  from  which  such
information was derived,  and that the Trustee shall not be held  accountable by
reason of mailing any material  pursuant to a request made under said subsection
(c).

     SECTION  5.03.....(a)....The  Company covenants and agrees to file with the
Trustee,  within 30 days after the Company is required to file the same with the
Commission,  a copy of the annual reports and of the information,  documents and
other  reports  (or a copy  of  such  portions  of any of the  foregoing  as the
Commission may from time to time by rules and regulations  prescribe)  which the
Company may be required  to file with the  Commission  pursuant to Section 13 or
Section  15(d) of the  Exchange  Act; or, if the Company is not required to file
information,  documents or reports pursuant to either of such sections,  then to
file  with the  Trustee  and,  unless  the  Commission  shall  not  accept  such
information,  documents or reports, the Commission, in accordance with the rules
and  regulations  prescribed  from time to time by the  Commission,  such of the
supplementary  and  periodic  information,  documents  and reports  which may be
required  pursuant to Section 13 of the  Exchange  Act, in respect of a security
listed and  registered  on a national  securities  exchange as may be prescribed
from time to time in such rules and regulations.

     (b) The  Company  covenants  and  agrees to file with the  Trustee  and the
Commission, in accordance with the rules and regulations prescribed from time to
time by the Commission, such additional information,  documents and reports with
respect to compliance by the Company with the conditions and covenants  provided
for in this  Indenture  as may be  required  from time to time by such rules and
regulations.

     (c) The  Company  covenants  and agrees to  transmit  by mail,  first class
postage  prepaid,  or reputable  over-night  delivery service which provides for
evidence of receipt, to the Securityholders, as their names and addresses appear
upon the  Security  Register,  within 30 days after the filing  thereof with the
Trustee, such summaries of any information, documents and reports required to be
filed by the Company  pursuant to subsections (a) and (b) of this Section as may
be  required  by  rules  and  regulations  prescribed  from  time to time by the
Commission.

     (d) The  Company  covenants  and agrees to furnish  to the  Trustee,  on or
before  May 15 in  each  calendar  year  in  which  any of  the  Securities  are
outstanding, or on or before such other day in each calendar year as the Company
and the  Trustee  may from  time to time  agree  upon,  a  certificate  from the
principal executive officer, principal financial officer or principal accounting
officer,  as to his or her  knowledge,  of the  Company's  compliance  with  all
conditions and covenants under this  Indenture.  For purposes of this subsection
(d), such compliance  shall be determined  without regard to any period of grace
or requirement of notice provided under this Indenture.

     (e)  Delivery  of such  information,  documents  or reports to the  Trustee
pursuant to Section  5.03(a) or 5.03(b) is for  informational  purposes only and
the Trustee's  receipt thereof shall not constitute  constructive  notice of any
information   contained  therein  or  determinable  from  information  contained
therein,  including,  in the case of Section 5.03(b),  the Company's  compliance
with any of the covenants hereunder.

     SECTION  5.04.....(a)....On  or before July 15 in each year in which any of
the Securities are outstanding,  the Trustee shall transmit by mail, first class
postage  prepaid,  to the  Securityholders,  as their names and addresses appear
upon the Security  Register,  a brief report dated as of the  preceding  May 15,
with respect to any of the following  events which may have occurred  within the
previous  twelve months (but if no such event has occurred within such period no
report need be transmitted):

          (1)  any  change  to its  eligibility  under  Section  7.09,  and  its
     qualifications under Section 310 of the Trust Indenture Act;

          (2) the creation of or any material change to a relationship specified
     in  paragraphs  (1) through (10) of Section  310(b) of the Trust  Indenture
     Act;

          (3) the  character  and  amount of any  advances  (and if the  Trustee
     elects so to state, the circumstances  surrounding the making thereof) made
     by the Trustee (as such) which  remain  unpaid on the date of such  report,
     and for the reimbursement of which it claims or may claim a lien or charge,
     prior to that of the Securities, on any property or funds held or collected
     by it as trustee if such advances so remaining  unpaid  aggregate more than
     1/2 of 1% of the principal amount of the Securities outstanding on the date
     of such report;

          (4) any change to the amount,  interest rate, and maturity date of all
     other  indebtedness  owing by the Company,  or by any other  obligor on the
     Securities,  to the Trustee in its individual capacity, on the date of such
     report,  with a  brief  description  of any  property  held  as  collateral
     security   therefor,   except  any  indebtedness   based  upon  a  creditor
     relationship arising in any manner described in paragraphs (2), (3), (4) or
     (6) of Section 311(b) of the Trust Indenture Act;

          (5) any change to the property and funds,  if any,  physically  in the
     possession of the Trustee as such on the date of such report;

          (6) any release,  or release and substitution,  of property subject to
     the lien, if any, of this Indenture  (and the  consideration  therefor,  if
     any) which it has not previously reported;

          (7) any  additional  issue of  Securities  which the  Trustee  has not
     previously reported; and

          (8) any action taken by the Trustee in the  performance  of its duties
     under this Indenture which it has not previously  reported and which in its
     opinion  materially affects the Securities or the Securities of any series,
     except any  action in respect of a default,  notice of which has been or is
     to be withheld by it in accordance with the provisions of Section 6.07.

     (b) The Trustee shall transmit by mail, first class postage prepaid, to the
Securityholders, as their names and addresses appear upon the Security Register,
a brief report with respect to the  character and amount of any advances (and if
the  Trustee  elects so to  state,  the  circumstances  surrounding  the  making
thereof)  made by the  Trustee  as  such  since  the  date  of the  last  report
transmitted  pursuant to the provisions of subsection (a) of this Section (or if
no such report has yet been so transmitted,  since the date of execution of this
Indenture),  for the  reimbursement  of which it  claims  or may claim a lien or
charge prior to that of the  Securities  of any series on property or funds held
or collected by it as Trustee, and which it has not previously reported pursuant
to this subsection if such advances  remaining unpaid at any time aggregate more
than 10% of the principal  amount of Securities  of such series  outstanding  at
such time, such report to be transmitted within 90 days after such time.

     (c) A copy of each such report shall,  at the time of such  transmission to
Securityholders,  be filed by the  Trustee  with the  Company,  with each  stock
exchange upon which any  Securities  are listed (if so listed) and also with the
Commission.  The Company agrees to notify the Trustee when any Securities become
listed on any stock exchange.


                                   ARTICLE SIX
                   REMEDIES OF THE TRUSTEE AND SECURITYHOLDERS
                               ON EVENT OF DEFAULT

     SECTION  6.01.....(a)....Whenever used herein with respect to Securities of
a particular  series,  "Event of Default" means any one or more of the following
events which has occurred and is continuing:

          (1) default in the payment of any  installment of interest upon any of
     the  Securities  of that series,  as and when the same shall become due and
     payable, and continuance of such default for a period of 30 days;

          (2) default in the payment of the  principal of (or  premium,  if any,
     on) any of the  Securities of that series as and when the same shall become
     due and  payable  whether at  maturity,  upon  redemption,  pursuant to any
     sinking fund  obligation,  by declaration or otherwise,  and continuance of
     such default for a period of 3 Business Days;

          (3) failure on the part of the Company  duly to observe or perform any
     other  of the  covenants  or  agreements  on the part of the  Company  with
     respect  to  that  series   contained  in  such   Securities  or  otherwise
     established  with respect to that series of Securities  pursuant to Section
     2.01  hereof or  contained  in this  Indenture  (other  than a covenant  or
     agreement  which has been expressly  included in this Indenture  solely for
     the benefit of one or more series of Securities other than such series) for
     a period of 90 days after the date on which written notice of such failure,
     requiring the same to be remedied and stating that such notice is a "Notice
     of Default" hereunder, shall have been given to the Company by the Trustee,
     by registered  or certified  mail, or to the Company and the Trustee by the
     holders  of at least  33% in  principal  amount of the  Securities  of that
     series at the time outstanding;

          (4) a decree or order by a court having  jurisdiction  in the premises
     shall have been entered adjudging the Company as bankrupt or insolvent,  or
     approving   as   properly   filed  a  petition   seeking   liquidation   or
     reorganization  of the  Company  under the Federal  Bankruptcy  Code or any
     other  similar  applicable  Federal or State law,  and such decree or order
     shall have continued  unvacated and unstayed for a period of 90 consecutive
     days; or an involuntary  case shall be commenced under such Code in respect
     of  the  Company  and  shall  continue  undismissed  for  a  period  of  90
     consecutive  days or an order  for  relief  in such  case  shall  have been
     entered;  or a  decree  or  order  of a court  having  jurisdiction  in the
     premises  shall  have been  entered  for the  appointment  on the ground of
     insolvency  or  bankruptcy  of a receiver or  custodian  or  liquidator  or
     trustee or assignee in  bankruptcy  or  insolvency of the Company or of its
     property,  or for the winding up or  liquidation  of its affairs,  and such
     decree or order shall have  remained in force  unvacated and unstayed for a
     period of 90 consecutive days;

          (5) the  Company  shall  institute  proceedings  to be  adjudicated  a
     voluntary  bankrupt,  or  shall  consent  to  the  filing  of a  bankruptcy
     proceeding  against  it, or shall  file a  petition  or  answer or  consent
     seeking liquidation or reorganization  under the Federal Bankruptcy Code or
     any other similar  applicable Federal or State law, or shall consent to the
     filing of any such  petition,  or shall consent to the  appointment  on the
     ground of insolvency or bankruptcy of a receiver or custodian or liquidator
     or  trustee  or  assignee  in  bankruptcy  or  insolvency  of it or of  its
     property, or shall make an assignment for the benefit of creditors; or

          (6) the  occurrence  of any other  Event of  Default  with  respect to
     Securities of such series, as contemplated by Section 2.01 hereof.

     (b)  The  Company  shall  file  with  the  Trustee  written  notice  of the
occurrence  of any Event of Default  within five  Business Days of the Company's
becoming aware of any such Event of Default. In each and every such case, unless
the principal of all the Securities of that series shall have already become due
and payable, either the Trustee or the holders of not less than 33% in aggregate
principal amount of the Securities of that series then outstanding hereunder, by
notice  in  writing  to the  Company  (and  to the  Trustee  if  given  by  such
Securityholders),  may declare the principal (or, if any of such  Securities are
Discount  Securities,  such portion of the  principal  amount  thereof as may be
specified by their terms as  contemplated by Section 2.01) of all the Securities
of that series to be due and payable immediately,  and upon any such declaration
the same  shall  become  and  shall be  immediately  due and  payable,  anything
contained in this  Indenture or in the  Securities of that series or established
with  respect to that  series  pursuant to Section  2.01 hereof to the  contrary
notwithstanding.

     (c) Section 6.01(b),  however,  is subject to the condition that if, at any
time after the  principal  of the  Securities  of that series shall have been so
declared due and  payable,  and before any judgment or decree for the payment of
the monies due shall have been obtained or entered as hereinafter provided,  the
Company shall pay or shall deposit with the Trustee a sum  sufficient to pay all
matured  installments of interest upon all the Securities of that series and the
principal of (and  premium,  if any, on) any and all  Securities  of that series
which shall have become due otherwise than by  acceleration  (with interest upon
such  principal  and  premium,  if any,  and, to the extent that such payment is
enforceable under applicable law, upon overdue installments of interest,  at the
rate per annum  expressed in the  Securities  of that series to the date of such
payment or deposit) and the amount  payable to the Trustee  under  Section 7.06,
and any and all  defaults  under the  Indenture,  other than the  nonpayment  of
principal on  Securities of that series which shall not have become due by their
terms,  shall have been remedied or waived as provided in Section 6.06, then and
in every such case the holders of a majority in  aggregate  principal  amount of
the Securities of that series then outstanding, by written notice to the Company
and to the Trustee,  may rescind and annul such declaration and its consequences
with respect to that series of Securities;  but no such rescission and annulment
shall  extend to or shall  affect any  subsequent  default,  or shall impair any
right consequent thereon.

     (d) In case the  Trustee  shall have  proceeded  to enforce  any right with
respect to Securities of that series under this  Indenture and such  proceedings
shall  have  been  discontinued  or  abandoned  because  of such  rescission  or
annulment or for any other reason or shall have been determined adversely to the
Trustee,  then and in every  such  case the  Company  and the  Trustee  shall be
restored  respectively to their former positions and rights  hereunder,  and all
rights,  remedies  and powers of the Company and the Trustee  shall  continue as
though no such proceedings had been taken.

     SECTION  6.02.....(a)....The  Company  covenants  that in case an  Event of
Default described in subsection  6.01(a)(1) or (a)(2) shall have occurred and be
continuing, upon demand of the Trustee, the Company will pay to the Trustee, for
the benefit of the holders of the  Securities  of that series,  the whole amount
that then shall have become due and payable on all such Securities for principal
(and  premium,  if any) or interest,  or both, as the case may be, with interest
upon the overdue principal (and premium, if any) and (to the extent that payment
of such interest is enforceable under applicable law and without  duplication of
any  other  amounts  paid  by the  Company  in  respect  thereof)  upon  overdue
installments  of interest at the rate per annum  expressed in the  Securities of
that  series;  and,  in  addition  thereto,  such  further  amount  as  shall be
sufficient to cover the costs and expenses of collection, and the amount payable
to the Trustee under Section 7.06.

     (b) In case the Company shall fail  forthwith to pay such amounts upon such
demand,  the Trustee,  in its own name and as trustee of an express trust, shall
be entitled and  empowered to institute any action or  proceedings  at law or in
equity for the  collection of the sums so due and unpaid,  and may prosecute any
such action or proceeding to judgment or final decree,  and may enforce any such
judgment  or  final  decree  against  the  Company  or  other  obligor  upon the
Securities  of that series and collect in the manner  provided by law out of the
property  of the Company or other  obligor  upon the  Securities  of that series
wherever situated the monies adjudged or decreed to be payable.

     (c) In  case  of any  receivership,  insolvency,  liquidation,  bankruptcy,
reorganization,   readjustment,   arrangement,  composition  or  other  judicial
proceedings affecting the Company, any other obligor on such Securities,  or the
creditors  or property of either,  the Trustee  shall have power to intervene in
such  proceedings and take any action therein that may be permitted by the court
and shall (except as may be otherwise  provided by law) be entitled to file such
proofs of claim and other papers and  documents as may be necessary or advisable
in order to have the claims of the Trustee and of the holders of  Securities  of
such series allowed for the entire amount due and payable by the Company or such
other  obligor  under  this  Indenture  at  the  date  of  institution  of  such
proceedings  and for any  additional  amount which may become due and payable by
the Company or such other  obligor  after such date,  and to collect and receive
any monies or other property  payable or  deliverable on any such claim,  and to
distribute  the same after the  deduction  of the amount  payable to the Trustee
under  Section  7.06;  and any  receiver,  assignee or trustee in  bankruptcy or
reorganization is hereby authorized by each of the holders of Securities of such
series to make such payments to the Trustee,  and, in the event that the Trustee
shall consent to the making of such payments  directly to such  Securityholders,
to pay to the Trustee any amount due it under Section 7.06.

     (d) All rights of action and of asserting  claims under this Indenture,  or
under any of the terms  established  with respect to  Securities of that series,
may be enforced by the Trustee without the possession of any of such Securities,
or the production thereof at any trial or other proceeding relative thereto, and
any such suit or  proceeding  instituted  by the Trustee shall be brought in its
own name as trustee of an express  trust,  and any  recovery of judgment  shall,
after  provision  for payment to the  Trustee of any  amounts due under  Section
7.06,  be for the  ratable  benefit  of the  holders of the  Securities  of such
series.

     In case of an Event of Default hereunder, the Trustee may in its discretion
proceed to protect and enforce the rights vested in it by this Indenture by such
appropriate  judicial  proceedings  as the Trustee shall deem most  effectual to
protect  and  enforce  any of such  rights,  either  at law or in  equity  or in
bankruptcy or otherwise, whether for the specific enforcement of any covenant or
agreement  contained  in the  Indenture  or in aid of the  exercise of any power
granted in this  Indenture,  or to enforce  any other legal or  equitable  right
vested in the Trustee by this Indenture or by law.

     Nothing  herein  contained  shall be deemed to  authorize  the  Trustee  to
authorize or consent to or accept or adopt on behalf of any  Securityholder  any
plan of  reorganization,  arrangement,  adjustment or composition  affecting the
Securities  of that series or the rights of any holder  thereof or to  authorize
the  Trustee to vote in respect of the claim of any  Securityholder  in any such
proceeding.

     SECTION  6.03.....Any  monies  collected by the Trustee pursuant to Section
6.02 with respect to a particular  series of Securities  shall be applied in the
order  following,  at the date or dates fixed by the Trustee and, in case of the
distribution  of such monies on account of  principal  (or  premium,  if any) or
interest,  upon  presentation  of the several  Securities  of that  series,  and
stamping thereon the payment, if only partially paid, and upon surrender thereof
if fully paid:

          FIRST:  To the payment of costs and expenses of collection  and of all
     amounts payable to the Trustee under Section 7.06;

          SECOND:  To the  payment  of the  amounts  then  due and  unpaid  upon
     Securities of such series for principal (and premium, if any) and interest,
     in  respect  of  which or for the  benefit  of which  such  money  has been
     collected,  ratably,  without preference or priority of any kind, according
     to the  amounts  due and  payable on such  Securities  for  principal  (and
     premium, if any) and interest, respectively; and

          THIRD: To the Company.

     SECTION  6.04.....No  holder of any  Security of any series  shall have any
right by virtue or by availing of any  provision of this  Indenture to institute
any suit, action or proceeding in equity or at law upon or under or with respect
to this Indenture or for the  appointment  of a receiver or trustee,  or for any
other remedy  hereunder,  unless such holder  previously shall have given to the
Trustee  written  notice of an Event of Default and of the  continuance  thereof
with respect to Securities of such series  specifying such Event of Default,  as
hereinbefore  provided,  and  unless  also the  holders  of not less than 33% in
aggregate  principal  amount of the  Securities of such series then  outstanding
shall have made written request upon the Trustee to institute such action,  suit
or proceeding in its own name as trustee hereunder and shall have offered to the
Trustee such reasonable indemnity as it may require against the costs,  expenses
and liabilities to be incurred  therein or thereby,  and the Trustee for 60 days
after its receipt of such  notice,  request and offer of  indemnity,  shall have
failed to institute any such action, suit or proceeding; it being understood and
intended,  and being  expressly  covenanted  by the  taker  and  holder of every
Security of such series with every other such taker and holder and the  Trustee,
that no one or more holders of Securities of such series shall have any right in
any  manner  whatsoever  by  virtue  or by  availing  of any  provision  of this
Indenture to affect, disturb or prejudice the rights of the holders of any other
of such  Securities,  or to obtain or seek to obtain priority over or preference
to any other such holder,  or to enforce any right under this Indenture,  except
in the manner herein  provided and for the equal,  ratable and common benefit of
all holders of Securities of such series.  For the protection and enforcement of
the provisions of this Section,  each and every  Securityholder  and the Trustee
shall be entitled to such relief as can be given either at law or in equity.

     Notwithstanding any other provisions of this Indenture,  however, the right
of any holder of any  Security  to  receive  payment  of the  principal  of (and
premium, if any) and interest on such Security, as therein provided, on or after
the  respective  due  dates  expressed  in  such  Security  (or in the  case  of
redemption, on the redemption date), or to institute suit for the enforcement of
any such payment on or after such respective dates or redemption date, shall not
be impaired or affected without the consent of such holder.

     SECTION  6.05.....(a)....All  powers and remedies  given by this Article to
the Trustee or to the Securityholders  shall, to the extent permitted by law, be
deemed cumulative and not exclusive of any others thereof or of any other powers
and  remedies  available  to the  Trustee or the holders of the  Securities,  by
judicial  proceedings or otherwise,  to enforce the performance or observance of
the  covenants  and   agreements   contained  in  this  Indenture  or  otherwise
established with respect to such Securities.

     (b) No delay or  omission  of the  Trustee  or of any  holder of any of the
Securities  to exercise  any right or power  accruing  upon any Event of Default
occurring and continuing as aforesaid  shall impair any such right or power,  or
shall  be  construed  to be a  waiver  of any such  default  or an  acquiescence
therein;  and, subject to the provisions of Section 6.04, every power and remedy
given by this Article or by law to the Trustee or to the  Securityholders may be
exercised from time to time, and as often as shall be deemed  expedient,  by the
Trustee or by the Securityholders.

     SECTION 6.06.....The holders of a majority in aggregate principal amount of
the Securities of any series at the time  outstanding,  determined in accordance
with Section 8.04, shall have the right to direct the time,  method and place of
conducting any proceeding for any remedy available to the Trustee, or exercising
any  trust or power  conferred  on the  Trustee  with  respect  to such  series;
provided, however, that such direction shall not be in conflict with any rule of
law or with this  Indenture  or unduly  prejudicial  to the rights of holders of
Securities of any other series at the time outstanding  determined in accordance
with  Section 8.04 not parties  thereto.  Subject to the  provisions  of Section
7.01,  the Trustee shall have the right to decline to follow any such  direction
if the Trustee in good faith shall, by a Responsible  Officer or Officers of the
Trustee,  determine that the proceeding so directed might involve the Trustee in
personal  liability.  The holders of a majority in aggregate principal amount of
the  Securities  of  any  series  at  the  time  outstanding  affected  thereby,
determined in accordance  with Section 8.04, may on behalf of the holders of all
of the  Securities of such series waive any past default in the  performance  of
any of the covenants  contained  herein or established  pursuant to Section 2.01
with  respect  to such  series  and its  consequences,  except a default  in the
payment of the  principal  of, or premium,  if any,  or interest  on, any of the
Securities  of that series as and when the same shall become due by the terms of
such  Securities  otherwise than by  acceleration  (unless such default has been
cured and a sum  sufficient  to pay all matured  installments  of  interest  and
principal otherwise than by acceleration and any premium has been deposited with
the Trustee (in  accordance  with Section  6.01(c))) or a call for redemption of
Securities of that series.  Upon any such waiver,  the default  covered  thereby
shall be deemed to be cured for all purposes of this  Indenture and the Company,
the Trustee and the holders of the  Securities  of such series shall be restored
to their former positions and rights hereunder, respectively; but no such waiver
shall extend to any  subsequent or other default or impair any right  consequent
thereon.

     SECTION  6.07.....The Trustee shall, within 90 days after the occurrence of
a default  with respect to a particular  series,  transmit by mail,  first class
postage prepaid, to the holders of Securities of that series, as their names and
addresses appear upon the Security Register, notice of all defaults with respect
to that series known to the Trustee,  unless such defaults shall have been cured
or waived before the giving of such notice (the term "defaults" for the purposes
of this Section being hereby  defined to be the events  specified in subsections
(1),  (2),  (3),  (4),  (5), (6) and (7) of Section  6.01(a),  not including any
periods of grace provided for therein and  irrespective  of the giving of notice
provided for by subsection (4) of Section  6.01(a));  provided,  that, except in
the case of default in the payment of the  principal of (or premium,  if any) or
interest  on any of the  Securities  of that  series  or in the  payment  of any
sinking or analogous fund  installment  established with respect to that series,
the Trustee shall be protected in withholding  such notice if and so long as the
board of directors,  the executive committee,  or a trust committee of directors
and/or  Responsible  Officers,  of the Trustee in good faith  determine that the
withholding  of such notice is in the  interests of the holders of Securities of
that series;  provided further, that in the case of any default of the character
specified in Section  6.01(a)(4)  with respect to  Securities  of such series no
such notice to the holders of the Securities of that series shall be given until
at least 30 days after the occurrence thereof.

     The Trustee  shall not be deemed to have  knowledge of any default,  except
(i) a default under subsection (a)(1),  (a)(2) or (a)(3) of Section 6.01 as long
as the Trustee is acting as paying agent for such series of  Securities  or (ii)
any  default as to which the Trustee  shall have  received  written  notice or a
Responsible Officer charged with the administration of this Indenture shall have
obtained written notice.

     SECTION  6.08.....All  parties to this Indenture  agree, and each holder of
any Securities by his or her acceptance  thereof shall be deemed to have agreed,
that any court may in its discretion require, in any suit for the enforcement of
any right or remedy under this Indenture, or in any suit against the Trustee for
any action taken or omitted by it as Trustee,  the filing by any party  litigant
in such  suit of an  undertaking  to pay the costs of such  suit,  and that such
court  may in its  discretion  assess  reasonable  costs,  including  reasonable
attorneys' fees,  against any party litigant in such suit,  having due regard to
the merits and good faith of the claims or defenses made by such party litigant;
but the provisions of this Section shall not apply to any suit instituted by the
Trustee,   to  any  suit   instituted  by  any   Securityholder,   or  group  of
Securityholders,  holding  more than 10% in  aggregate  principal  amount of the
outstanding  Securities  of  any  series,  or to  any  suit  instituted  by  any
Securityholder  for the  enforcement  of the  payment  of the  principal  of (or
premium,  if any) or interest on any  Security of such  series,  on or after the
respective due dates expressed in such Security or established  pursuant to this
Indenture.


                                  ARTICLE SEVEN
                             CONCERNING THE TRUSTEE

     SECTION 7.01.....(a)....The Trustee, prior to the occurrence of an Event of
Default  with  respect  to  Securities  of a series  and after the curing of all
Events of Default  with  respect to  Securities  of that  series  which may have
occurred,  shall  undertake to perform with respect to Securities of such series
such  duties  and  only  such  duties  as are  specifically  set  forth  in this
Indenture,  and no  implied  covenants  or  obligations  shall be read into this
Indenture  against  the  Trustee.  In case an Event of Default  with  respect to
Securities  of a series has occurred  (which has not been cured or waived),  the
Trustee  shall  exercise  with respect to  Securities of that series such of the
rights and powers  vested in it by this  Indenture,  and use the same  degree of
care and skill in their  exercise,  as a prudent man would exercise or use under
the circumstances in the conduct of his own affairs.

     (b) No  provision  of this  Indenture  shall be  construed  to relieve  the
Trustee from liability for its own negligent  action,  its own negligent failure
to act, or its own willful misconduct, except that:

          (1) prior to the  occurrence  of an Event of Default  with  respect to
     Securities  of a series and after the curing or waiving of all such  Events
     of Default with respect to that series which may have occurred:

               (i) the duties and  obligations of the Trustee shall with respect
          to  Securities  of such  series be  determined  solely by the  express
          provisions of this Indenture, and the Trustee shall not be liable with
          respect to  Securities of such series  except for the  performance  of
          such  duties and  obligations  as are  specifically  set forth in this
          Indenture,  and no implied covenants or obligations shall be read into
          this Indenture against the Trustee; and

               (ii) in the absence of bad faith on the part of the Trustee,  the
          Trustee may with  respect to  Securities  of such series  conclusively
          rely, as to the truth of the  statements  and the  correctness  of the
          opinions  expressed   therein,   upon  any  certificates  or  opinions
          furnished to the Trustee and  conforming to the  requirements  of this
          Indenture;  but in the case of any such certificates or opinions which
          by any provision hereof are  specifically  required to be furnished to
          the Trustee,  the Trustee shall be under a duty to examine the same to
          determine  whether  or not they  conform to the  requirements  of this
          Indenture  (but  need not  confirm  or  investigate  the  accuracy  of
          mathematical calculations or other facts stated therein);

          (2) the Trustee  shall not be liable for any error of judgment made in
     good faith by a Responsible Officer or Responsible Officers of the Trustee,
     unless it shall be proved that the Trustee was  negligent  in  ascertaining
     the pertinent facts;

          (3) the Trustee  shall not be liable with  respect to any action taken
     or omitted to be taken by it in good faith in  accordance  with the written
     direction of the holders of not less than a majority in principal amount of
     the Securities of any series at the time outstanding  relating to the time,
     method and place of conducting any  proceeding for any remedy  available to
     the Trustee,  or exercising  any trust or power  conferred upon the Trustee
     under this Indenture with respect to the Securities of that series; and

          (4) none of the provisions  contained in this Indenture  shall require
     the  Trustee  to expend or risk its own  funds or  otherwise  incur or risk
     personal financial  liability in the performance of any of its duties or in
     the  exercise  of any of its rights or powers,  if the  Trustee  reasonably
     believes  that the  repayment of such funds or liability is not  reasonably
     assured  to it under  the terms of this  Indenture  or  adequate  indemnity
     against such risk is not reasonably assured to it.

     (c) Whether or not therein  expressly so provided,  every provision of this
Indenture  relating to the conduct or  affecting  the  liability of or affording
protection  to the Trustee  shall be subject to the  provisions  of this Section
7.01.

     SECTION 7.02. Except as otherwise provided in Section 7.01:

     (a) The  Trustee  may  conclusively  rely and shall be fully  protected  in
acting or refraining  from acting upon any resolution,  certificate,  statement,
instrument, opinion, report, notice, request, direction, consent, order, demand,
approval,  bond,  security or other  paper or document  believed by it (i) to be
genuine  and (ii) to have  been  signed  or  presented  by the  proper  party or
parties;

     (b) Any request, direction, order or demand of the Company mentioned herein
shall  be  sufficiently   evidenced  by  a  Board  Resolution  or  an  Officers'
Certificate (unless other evidence in respect thereof is specifically prescribed
herein);

     (c) The Trustee may consult with counsel of its selection and the advice of
such counsel or any Opinion of Counsel shall be full and complete  authorization
and  protection in respect of any action taken or suffered or omitted  hereunder
in good faith and in reliance thereon;

     (d) The Trustee  shall be under no obligation to exercise any of the rights
or powers vested in it by this  Indenture at the request,  order or direction of
any of the Securityholders, pursuant to the provisions of this Indenture, unless
such  Securityholders  shall have  offered to the Trustee  security or indemnity
satisfactory  to it against the costs,  expenses  and  liabilities  which may be
incurred therein or thereby;  nothing herein contained shall,  however,  relieve
the Trustee of the  obligation,  upon the occurrence of an Event of Default with
respect  to a series of the  Securities  (which has not been cured or waived) to
exercise with respect to Securities of that series such of the rights and powers
vested in it by this Indenture,  and to use the same degree of care and skill in
their exercise,  as a prudent man would exercise or use under the  circumstances
in the conduct of his own affairs;

     (e) The Trustee  shall not be liable for any action  taken or omitted to be
taken by it in good  faith and  believed  by it to be  authorized  or within the
discretion or rights or powers conferred upon it by this Indenture;

     (f) The Trustee shall not be bound to make any investigation into the facts
or  matters  stated  in  any  resolution,  certificate,  statement,  instrument,
opinion, report, notice, request, consent,  direction,  order, demand, approval,
bond, security, or other papers or documents,  unless requested in writing so to
do by the  holders  of not less  than a  majority  in  principal  amount  of the
outstanding  Securities of the particular series affected thereby (determined as
provided in Section  8.04);  provided,  however,  that if the  payment  within a
reasonable time to the Trustee of the costs,  expenses or liabilities  likely to
be incurred by it in the making of such  investigation is, in the opinion of the
Trustee, not reasonably assured to the Trustee by the security afforded to it by
the terms of this  Indenture,  the  Trustee  may  require  reasonable  indemnity
against such costs, expenses or liabilities as a condition to so proceeding. The
reasonable expense of every such examination shall be paid by the Company or, if
paid by the Trustee, shall be repaid by the Company upon demand. Notwithstanding
the foregoing,  the Trustee, in its direction,  may make such further inquiry or
investigation  into such  facts or  matters  as it may see fit.  In  making  any
investigation required or authorized by this subparagraph,  the Trustee shall be
entitled to examine books, records and premises of the Company, personally or by
agent or attorney;

     (g) The  Trustee  may  execute  any of the  trusts or powers  hereunder  or
perform  any  duties  hereunder  either  directly  or by or  through  agents  or
attorneys  and the  Trustee  shall  not be  responsible  for any  misconduct  or
negligence  on the part of any agent or attorney  appointed  with due care by it
hereunder;

     (h) The  permissive  right of the Trustee to do things  enumerated  in this
Indenture shall not be construed as a duty.

     SECTION 7.03.  (a)....The  recitals  contained herein and in the Securities
(other than the Certificate of  Authentication on the Securities) shall be taken
as the statements of the Company,  and the Trustee assumes no responsibility for
the correctness of the same.

     (b) The Trustee makes no  representations as to the validity or sufficiency
of this Indenture or of the Securities.

     (c) The Trustee shall not be accountable  for the use or application by the
Company of any of the Securities or of the proceeds of such  Securities,  or for
the use or application of any monies paid over by the Trustee in accordance with
any provision of this Indenture or established  pursuant to Section 2.01, or for
the use or application of any monies received by any paying agent other than the
Trustee.

     SECTION 7.04. The Trustee or any paying agent or Security Registrar, in its
individual or any other capacity,  may become the owner or pledgee of Securities
with the same  rights  it would  have if it were not  Trustee,  paying  agent or
Security Registrar.

     SECTION  7.05.  Subject  to the  provisions  of Section  11.04,  all monies
received by the Trustee shall, until used or applied as herein provided, be held
in  trust  for the  purposes  for  which  they  were  received,  but need not be
segregated  from other funds  except to the extent  required by law. The Trustee
shall be under no liability for interest on any monies  received by it hereunder
except such as it may agree in writing with the Company to pay thereon.

     SECTION  7.06.  (a)......The  Company  covenants  and  agrees to pay to the
Trustee  from time to time,  and the Trustee  shall be entitled  to,  reasonable
compensation  (which  shall not be limited by any  provision of law in regard to
the compensation of a trustee of an express trust) for all services  rendered by
it in the  execution  of the  trusts  hereby  created  and in the  exercise  and
performance  of any of the powers and duties  hereunder of the Trustee,  and the
Company  will pay or reimburse  the Trustee upon its request for all  reasonable
expenses,  disbursements  and  advances  incurred  or  made  by the  Trustee  in
accordance  with  any  of  the  provisions  of  this  Indenture  (including  the
reasonable  compensation  and the reasonable  expenses and  disbursements of its
counsel and agents and of all persons not  regularly  in its employ)  except any
such expense, disbursement or advance as may arise from its negligence,  willful
misconduct  or bad faith.  The Company also  covenants to indemnify  the Trustee
(and its officers, agents, directors and employees) for, and to hold it harmless
against,  any loss,  liability or expense incurred without  negligence,  willful
misconduct  or bad faith on the part of the  Trustee  and  arising  out of or in
connection with the acceptance or  administration  of this trust,  including the
reasonable costs and expenses of defending itself against any claim or liability
in connection  with the exercise or  performance  of any of its powers or duties
hereunder.

     (b) The  obligations  of the Company under this Section to  compensate  and
indemnify  the  Trustee  and to pay  or  reimburse  the  Trustee  for  expenses,
disbursements and advances shall constitute additional  indebtedness  hereunder.
Such  additional  indebtedness  shall be  secured by a lien prior to that of the
Securities upon all property and funds held or collected by the Trustee as such,
except  funds  held in  trust  for the  benefit  of the  holders  of  particular
Securities.

     (c) Without  prejudice to any other rights  available to the Trustee  under
applicable  law,  when the  Trustee  incurs  expenses  or  renders  services  in
connection with an Event of Default, the expenses (including  reasonable charges
and expenses of its counsel) and  compensation  for its services are intended to
constitute  expenses  of  administration   under  applicable  federal  or  state
bankruptcy, insolvency or similar law.

     (d) The provisions of this Section 7.06 shall survive the  satisfaction and
discharge of this Indenture or the appointment of a successor trustee.

     SECTION 7.07. Except as otherwise provided in Section 7.01, whenever in the
administration  of the  provisions  of this  Indenture the Trustee shall deem it
necessary or desirable that a matter be proved or established prior to taking or
suffering or omitting to take any action  hereunder,  such matter  (unless other
evidence  in respect  thereof be herein  specifically  prescribed)  may,  in the
absence of bad faith on the part of the  Trustee,  be deemed to be  conclusively
proved and established by an Officers'  Certificate delivered to the Trustee and
such certificate,  in the absence of bad faith on the part of the Trustee, shall
be full warrant to the Trustee for any action  taken,  suffered or omitted to be
taken by it under the provisions of this Indenture upon the faith thereof.

     SECTION  7.08.  If the Trustee has acquired or shall  acquire a conflicting
interest within the meaning of the Trust Indenture Act, the Trustee shall either
eliminate such interest or resign,  to the extent and in the manner provided by,
and subject to the provisions of, the Trust Indenture Act and this Indenture.

     SECTION  7.09.  There shall at all times be a Trustee  with  respect to the
Securities issued hereunder which shall at all times be a corporation  organized
and doing  business  under the laws of the United States of America or any State
or Territory  thereof or of the District of Columbia,  or a corporation or other
person permitted to act as trustee by the Commission, authorized under such laws
to exercise corporate trust powers,  having a combined capital and surplus of at
least 50 million dollars,  and subject to supervision or examination by Federal,
State,  Territorial,  or  District of Columbia  authority.  If such  corporation
publishes  reports of  condition  at least  annually,  pursuant to law or to the
requirements of the aforesaid  supervising or examining authority,  then for the
purposes of this Section,  the combined  capital and surplus of such corporation
shall be deemed to be its combined  capital and surplus as set forth in its most
recent report of condition so published. The Company may not, nor may any person
directly or indirectly controlling,  controlled by, or under common control with
the Company, serve as Trustee. In case at any time the Trustee shall cease to be
eligible in accordance  with the  provisions of this Section,  the Trustee shall
resign immediately in the manner and with the effect specified in Section 7.10.

     SECTION 7.10. (a).....The Trustee or any successor hereafter appointed, may
at any time  resign  with  respect to the  Securities  of one or more  series by
giving  written  notice  thereof to the  Company and by  transmitting  notice of
resignation by mail, first class postage prepaid, to the Securityholders of such
series,  as their names and addresses  appear upon the Security  Register.  Upon
receiving  such notice of  resignation,  the Company  shall  promptly  appoint a
successor  trustee  with  respect  to  Securities  of  such  series  by  written
instrument, in duplicate,  executed by order of the Board of Directors, one copy
of which instrument shall be delivered to the resigning  Trustee and one copy to
the successor trustee.  If no successor trustee shall have been so appointed and
have  accepted  appointment  within 30 days after the  mailing of such notice of
resignation,   the  resigning  Trustee  may  petition  any  court  of  competent
jurisdiction  for  the  appointment  of a  successor  trustee  with  respect  to
Securities of such series,  or any  Securityholder of that series who has been a
bona fide  holder of a  Security  or  Securities  for at least six  months  may,
subject to the  provisions  of Section 6.08, on behalf of himself and all others
similarly  situated,  petition any such court for the appointment of a successor
trustee.  Such court may  thereupon  after such  notice,  if any, as it may deem
proper and prescribe, appoint a successor trustee.

     (b) In case at any time any of the following shall occur:

          (1) the Trustee  shall fail to comply with the  provisions  of Section
     7.08 after written request therefor by the Company or by any Securityholder
     who has been a bona fide  holder of a Security or  Securities  for at least
     six months; or

          (2) The Trustee  shall cease to be  eligible  in  accordance  with the
     provisions of Section 7.09 and shall fail to resign after  written  request
     therefor by the Company or by any such Securityholder; or

          (3) the Trustee shall become incapable of acting, or shall be adjudged
     a bankrupt or  insolvent,  or a receiver of the Trustee or of its  property
     shall be appointed,  or any public  officer shall take charge or control of
     the   Trustee  or  of  its   property   or  affairs   for  the  purpose  of
     rehabilitation, conservation or liquidation;

then,  in any such case,  the Company may remove the Trustee with respect to all
Securities and appoint a successor trustee by written instrument,  in duplicate,
executed by order of the Board of Directors,  one copy of which instrument shall
be  delivered to the Trustee so removed and one copy to the  successor  trustee,
or,  subject  to the  provisions  of  Section  6.08,  unless,  with  respect  to
subsection  (b)(1) above,  the Trustee's duty to resign is stayed as provided in
Section  310(b) of the Trust  Indenture Act, any  Securityholder  who has been a
bona fide  holder of a Security  or  Securities  for at least six months may, on
behalf of  himself  and all others  similarly  situated,  petition  any court of
competent  jurisdiction  for the removal of the Trustee and the appointment of a
successor trustee. Such court may thereupon after such notice, if any, as it may
deem proper and prescribe, remove the Trustee and appoint a successor trustee.

     (c)  The  holders  of a  majority  in  aggregate  principal  amount  of the
Securities  of any  series at the time  outstanding  may at any time  remove the
Trustee with respect to such series and appoint a successor trustee.

     (d)  Any  resignation  or  removal  of the  Trustee  and  appointment  of a
successor  trustee with respect to the Securities of a series pursuant to any of
the  provisions  of this  Section  shall become  effective  upon  acceptance  of
appointment by the successor trustee as provided in Section 7.11.

     (e)  Any  successor  trustee  appointed  pursuant  to this  Section  may be
appointed  with respect to the  Securities  of one or more series or all of such
series,  and at any time there  shall be only one  Trustee  with  respect to the
Securities of any particular series.

     SECTION 7.11  (a)....In  case of the  appointment  hereunder of a successor
trustee  with  respect  to all  Securities,  every  such  successor  trustee  so
appointed  shall  execute,  acknowledge  and  deliver to the  Company and to the
retiring  Trustee an instrument  accepting such  appointment,  and thereupon the
resignation or removal of the retiring  Trustee shall become  effective and such
successor  trustee,  without any further act, deed or  conveyance,  shall become
vested with all the rights,  powers,  trusts and duties of the retiring Trustee;
but, on the  request of the  Company or the  successor  trustee,  such  retiring
Trustee  shall,  upon payment of its charges,  execute and deliver an instrument
transferring to such successor trustee all the rights, powers, and trusts of the
retiring  Trustee and shall duly assign,  transfer and deliver to such successor
trustee all property and money held by such retiring Trustee hereunder,  subject
to any prior lien provided for in Section 7.06(b).

     (b) In  case of the  appointment  hereunder  of a  successor  trustee  with
respect to the Securities of one or more (but not all) series, the Company,  the
retiring  Trustee and each  successor  trustee with respect to the Securities of
one or more series shall  execute and deliver an indenture  supplemental  hereto
wherein each successor trustee shall accept such appointment and which (1) shall
contain  such  provisions  as shall be  necessary  or  desirable to transfer and
confirm to, and to vest in,  each  successor  trustee  all the  rights,  powers,
trusts and duties of the retiring Trustee with respect to the Securities of that
or those series to which the appointment of such successor trustee relates,  (2)
shall  contain  such  provisions  as shall be deemed  necessary  or desirable to
confirm that all the rights,  powers,  trusts and duties of the retiring Trustee
with respect to the  Securities of that or those series as to which the retiring
Trustee is not retiring shall continue to be vested in the retiring Trustee, and
(3) shall add to or change any of the  provisions of this  Indenture as shall be
necessary  to  provide  for or  facilitate  the  administration  of  the  trusts
hereunder by more than one Trustee,  it being  understood that nothing herein or
in such supplemental indenture shall constitute such Trustees co-trustees of the
same  trust,  that  each  such  Trustee  shall be  trustee  of a trust or trusts
hereunder separate and apart from any trust or trusts hereunder  administered by
any other such Trustee and that no Trustee shall be  responsible  for any act or
failure  to act on the  part  of any  other  Trustee  hereunder;  and  upon  the
execution and delivery of such supplemental indenture the resignation or removal
of the retiring Trustee shall become  effective to the extent provided  therein,
such  retiring  Trustee  shall with respect to the  Securities  of that or those
series  to which the  appointment  of such  successor  trustee  relates  have no
further  responsibility  for  the  exercise  of  rights  and  powers  or for the
performance  of the  duties and  obligations  vested in the  Trustee  under this
Indenture,  and each such  successor  trustee,  without any further act, deed or
conveyance,  shall become vested with all the rights,  powers, trusts and duties
of the retiring  Trustee with respect to the  Securities of that or those series
to which the appointment of such successor  trustee relates;  but, on request of
the Company or any successor  trustee,  such retiring Trustee shall duly assign,
transfer and deliver to such successor  trustee,  to the extent  contemplated by
such  supplemental  indenture,  the  property  and money  held by such  retiring
Trustee  hereunder  with  respect to the  Securities  of that or those series to
which the appointment of such successor trustee relates.

     (c) Upon request of any such successor  trustee,  the Company shall execute
any and all instruments  for more fully and certainly  vesting in and confirming
to such  successor  trustee all such  rights,  powers and trusts  referred to in
paragraph (a) or (b) of this Section, as the case may be.

     (d) No successor trustee shall accept its appointment unless at the time of
such  acceptance  such  successor  trustee  shall be  qualified  under the Trust
Indenture Act and eligible under this Article.

     (e) Upon  acceptance of appointment  by a successor  trustee as provided in
this  Section,  the Company  shall  transmit  notice of the  succession  of such
trustee hereunder by mail, first class postage prepaid, to the  Securityholders,
as their names and addresses appear upon the Security  Register.  If the Company
fails to transmit such notice within ten days after acceptance of appointment by
the  successor  trustee,  the  successor  trustee  shall cause such notice to be
transmitted at the expense of the Company.

     SECTION  7.12.  Any  corporation  into which the  Trustee  may be merged or
converted or with which it may be  consolidated,  or any  corporation  resulting
from any merger,  conversion  or  consolidation  to which the Trustee shall be a
party,  or  any  corporation  succeeding  to  all  or  substantially  all of the
corporate  trust business of the Trustee,  shall be the successor of the Trustee
hereunder,  provided such corporation shall be qualified under the provisions of
the Trust  Indenture  Act and eligible  under the  provisions  of Section  7.09,
without the  execution  or filing of any paper or any further act on the part of
any of the parties hereto, anything herein to the contrary  notwithstanding.  In
case any Securities  shall have been  authenticated,  but not delivered,  by the
Trustee then in office, any successor by merger,  conversion or consolidation to
such  authenticating  Trustee  may adopt such  authentication  and  deliver  the
Securities so  authenticated  with the same effect as if such successor  Trustee
had itself authenticated such Securities.

     SECTION  7.13.  If and when the  Trustee  shall  become a  creditor  of the
Company (or any other obligor upon the Securities), the Trustee shall be subject
to the  provisions of the Trust  Indenture  Act  regarding  collection of claims
against the Company (or any other obligor upon the Securities).


                                  ARTICLE EIGHT
                         CONCERNING THE SECURITYHOLDERS

     SECTION 8.01. Whenever in this Indenture it is provided that the holders of
a  majority  or  specified  percentage  in  aggregate  principal  amount  of the
Securities of a particular  series may take any action  (including the making of
any demand or request, the giving of any notice, consent or waiver or the taking
of any other  action),  the fact that at the time of taking any such  action the
holders of such  majority  or  specified  percentage  of that series have joined
therein may be  evidenced  by any  instrument  or any number of  instruments  of
similar tenor executed by such holders of Securities of that series in person or
by agent or proxy appointed in writing.

     If the Company  shall  solicit from the  Securityholders  of any series any
request,  demand,  authorization,  direction,  notice,  consent, waiver or other
action,   the  Company  may,  at  its  option,  as  evidenced  by  an  Officers'
Certificate,  fix in advance a record date for such series for the determination
of  Securityholders  entitled  to  give  such  request,  demand,  authorization,
direction,  notice,  consent, waiver or other action, but the Company shall have
no  obligation to do so. If such a record date is fixed,  such request,  demand,
authorization,  direction,  notice, consent, waiver or other action may be given
before or after the record date, but only the  Securityholders  of record at the
close of business on the record date shall be deemed to be  Securityholders  for
the purposes of determining whether  Securityholders of the requisite proportion
of outstanding  Securities of that series have authorized or agreed or consented
to such request, demand,  authorization,  direction,  notice, consent, waiver or
other  action,  and for that purpose the  outstanding  Securities of that series
shall be computed as of the record date;  provided  that no such  authorization,
agreement or consent by such  Securityholders on the record date shall be deemed
effective  unless it shall become  effective  pursuant to the provisions of this
Indenture not later than six months after the record date.

     In  determining  whether the holders of the requisite  aggregate  principal
amount of Securities  of a particular  series have  concurred in any  direction,
consent  or waiver  under this  Indenture,  the  principal  amount of a Discount
Security that shall be deemed to be  outstanding  for such purposes shall be the
amount of the principal  thereof that would be due and payable as of the date of
such  determination  upon a declaration of acceleration of the maturity  thereof
pursuant to Section 6.01.

     SECTION  8.02.  Subject to the  provisions  of Section  7.01,  proof of the
execution of any  instrument  by a  Securityholder  (such proof will not require
notarization)  or his agent or proxy and proof of the  holding  by any person of
any of the Securities shall be sufficient if made in the following manner:

          (a) The fact  and date of the  execution  by any  such  person  of any
     instrument  may  be  proved  in any  reasonable  manner  acceptable  to the
     Trustee.

          (b) The  ownership  of  Securities  shall be  proved  by the  Security
     Register of such  Securities or by a certificate of the Security  Registrar
     thereof.

          (c) The  Trustee  may  require  such  additional  proof of any  matter
     referred to in this Section as it shall deem necessary.

     SECTION 8.03.  Prior to the due presentment for registration of transfer of
any  Security,  the  Company,  the  Trustee,  any paying  agent and any Security
Registrar  may deem and treat the  person in whose name such  Security  shall be
registered  upon the books of the Company as the absolute owner of such Security
(whether or not such Security shall be overdue and notwithstanding any notice of
ownership or writing  thereon made by anyone other than the Security  Registrar)
for the purpose of  receiving  payment of or on account of the  principal of and
premium, if any, and (subject to Section 2.03) interest on such Security and for
all other purposes; and neither the Company nor the Trustee nor any paying agent
nor any Security Registrar shall be affected by any notice to the contrary.

     SECTION 8.04. In determining whether the holders of the requisite aggregate
principal  amount of  Securities  of a particular  series have  concurred in any
direction,  consent or waiver under this  Indenture,  Securities  of that series
which are owned by the Company or any other  obligor on the  Securities  of that
series or by any person  directly or indirectly  controlling or controlled by or
under common  control with the Company or any other obligor on the Securities of
that  series  shall be  disregarded  and  deemed not to be  outstanding  for the
purpose of any such  determination,  except that for the purpose of  determining
whether the Trustee shall be protected in relying on any such direction, consent
or waiver,  only Securities of such series which the Trustee  actually knows are
so owned shall be so disregarded. Securities so owned which have been pledged in
good faith may be regarded as outstanding  for the purposes of this Section,  if
the pledgee  shall  establish to the  satisfaction  of the Trustee the pledgee's
right so to act with  respect to such  Securities  and that the pledgee is not a
person  directly or indirectly  controlling  or controlled by or under direct or
indirect common control with the Company or any such other obligor. In case of a
dispute as to such right,  any decision by the Trustee  taken upon the advice of
counsel shall be full protection to the Trustee.

     SECTION  8.05.  At any time prior to (but not after) the  evidencing to the
Trustee, as provided in Section 8.01, of the taking of any action by the holders
of the majority or percentage in aggregate principal amount of the Securities of
a particular  series specified in this Indenture in connection with such action,
any holder of a Security  of that  series  which is shown by the  evidence to be
included in the  Securities  the holders of which have  consented to such action
may, by filing  written  notice with the  Trustee,  and upon proof of holding as
provided in Section 8.02,  revoke such action so far as concerns such  Security.
Except as aforesaid any such action taken by the holder of any Security shall be
conclusive  and binding upon such holder and upon all future  holders and owners
of  such  Security,  and  of  any  Security  issued  in  exchange  therefor,  on
registration of transfer thereof or in place thereof, irrespective of whether or
not any notation in regard thereto is made upon such Security.  Any action taken
by the holders of the majority or  percentage in aggregate  principal  amount of
the Securities of a particular  series specified in this Indenture in connection
with such action shall be conclusively binding upon the Company, the Trustee and
the holders of all the Securities of that series.


                                  ARTICLE NINE
                             SUPPLEMENTAL INDENTURES

     SECTION  9.01.  In  addition  to  any  supplemental   indenture   otherwise
authorized  by  this  Indenture,   the  Company,  when  authorized  by  a  Board
Resolution,  and the Trustee may from time to time and at any time enter into an
indenture  or  indentures  supplemental  hereto  (which  shall  conform  to  the
provisions of the Trust Indenture Act as then in effect), without the consent of
the Securityholders, for one or more of the following purposes:

     (a) to evidence the  succession of another  person to the Company,  and the
assumption  by any such  successor  of the  covenants  of the Company  contained
herein or otherwise established with respect to the Securities; or

     (b) to add  to  the  covenants  of  the  Company  such  further  covenants,
restrictions,  conditions or provisions for the protection of the holders of the
Securities of all or any series,  and to make the occurrence,  or the occurrence
and continuance, of a default in any of such additional covenants, restrictions,
conditions  or  provisions a default or an Event of Default with respect to such
series permitting the enforcement of all or any of the several remedies provided
in this Indenture as herein set forth; provided, however, that in respect of any
such additional covenant, restriction,  condition or provision such supplemental
indenture  may provide for a  particular  period of grace after  default  (which
period may be shorter or longer than that allowed in the case of other defaults)
or may provide for an immediate  enforcement  upon such default or may limit the
remedies  available  to the Trustee  upon such default or may limit the right of
the holders of a majority in aggregate  principal  amount of the  Securities  of
such series to waive such default; or

     (c) to cure  any  ambiguity  or to  correct  or  supplement  any  provision
contained  herein or in any  supplemental  indenture  which may be  defective or
inconsistent  with any other provision  contained  herein or in any supplemental
indenture,  or to make such other  provisions  in regard to matters or questions
arising under this Indenture as shall not be inconsistent with the provisions of
this  Indenture and shall not  adversely  affect the interests of the holders of
the Securities of any series; or

     (d) to change or eliminate any of the  provisions  of this  Indenture or to
add any new provision to this Indenture;  provided,  however,  that such change,
elimination  or addition  shall become  effective only when there is no Security
outstanding  of any series  created prior to the execution of such  supplemental
indenture that is entitled to the benefit of such provisions; or

     (e) to establish the form or terms of Securities of any series as permitted
by Section 2.01; or

     (f) to add any  additional  Events of  Default  with  respect to all or any
series of outstanding Securities; or

     (g) to provide collateral security for the Securities; or

     (h) to provide for the authentication and delivery of bearer securities and
coupons appertaining thereto representing  interest, if any, thereon and for the
procedures for the  registration,  exchange and replacement  thereof and for the
giving of notice to, and the solicitation of the vote or consent of, the holders
thereof, and for any other matters incidental thereto; or

     (i) to evidence and provide for the acceptance of appointment  hereunder by
a separate or successor  Trustee with respect to the  Securities  of one or more
series and to add to or change any of the  provisions of this Indenture as shall
be  necessary  to provide for or  facilitate  the  administration  of the trusts
hereunder  by more than one  Trustee,  pursuant to the  requirements  of Article
Seven; or

     (j) to change any place or places  where (1) the  principal of and premium,
if any,  and  interest,  if any,  on all or any  series of  Securities  shall be
payable, (2) all or any series of Securities may be surrendered for registration
of transfer, (3) all or any series of Securities may be surrendered for exchange
and (4)  notices  and  demands  to or upon the  Company in respect of all or any
series of Securities and this Indenture may be served;  provided,  however, that
any such place shall be located in New York, New York or be the principal office
of the Company; or

     (k) to provide  for the  payment by the  Company of  additional  amounts in
respect of certain  taxes  imposed on certain  holders and for the  treatment of
such additional amounts as interest and for all matters incidental thereto; or

     (l) to provide for the  issuance of  Securities  denominated  in a currency
other than  Dollars or in a composite  currency  and for all matters  incidental
thereto.

     Without  limiting the generality of the foregoing,  if the Trust  Indenture
Act as in effect at the date of the execution and delivery of this  Indenture or
at any time thereafter shall be amended and

          (x) if any such  amendment  shall  require one or more  changes to any
     provisions hereof or the inclusion herein of any additional provisions,  or
     shall by operation  of law be deemed to effect such changes or  incorporate
     such  provisions by reference or otherwise,  this Indenture shall be deemed
     to have  been  amended  so as to  conform  to such  amendment  to the Trust
     Indenture Act, and the Company and the Trustee may,  without the consent of
     any Securityholders,  enter into a supplemental  indenture hereto to effect
     or evidence such changes or additional provisions; or

          (y) if any such amendment  shall permit one or more changes to, or the
     elimination  of, any provisions  hereof which, at the date of the execution
     and delivery  hereof or at any time  thereafter,  are required by the Trust
     Indenture Act to be contained  herein,  this  Indenture  shall be deemed to
     have been  amended to effect such changes or  elimination,  and the Company
     and the Trustee may, without the consent of any Securityholders, enter into
     a supplemental indenture hereto to effect such changes or elimination; or

          (z) if, by reason of any such amendment, one or more provisions which,
     at the date of the execution and delivery hereof or at any time thereafter,
     are required by the Trust  Indenture  Act to be  contained  herein shall be
     deemed to be  incorporated  herein by reference or otherwise,  or otherwise
     made  applicable  hereto,  and shall no longer be required to be  contained
     herein,  the  Company  and the  Trustee  may,  without  the  consent of any
     Securityholders,  enter into a supplemental  indenture hereto to effect the
     elimination of such provisions.

     The Trustee is hereby  authorized to join with the Company in the execution
of  any  such  supplemental  indenture,  and to  make  any  further  appropriate
agreements  and  stipulations  which may be therein  contained,  but the Trustee
shall not be  obligated  to enter  into any such  supplemental  indenture  which
affects the Trustee's own rights,  duties or immunities  under this Indenture or
otherwise.

     Any supplemental indenture authorized by the provisions of this Section may
be executed by the Company and the Trustee without the consent of the holders of
any of  the  Securities  at the  time  outstanding,  notwithstanding  any of the
provisions of Section 9.02.

     SECTION 9.02.  With the consent  (evidenced as provided in Section 8.01) of
the holders of not less than a majority  in  aggregate  principal  amount of the
Securities of all series affected by such  supplemental  indenture or indentures
at the time outstanding  voting as one class, the Company,  when authorized by a
Board  Resolution,  and the  Trustee may from time to time and at any time enter
into an indenture or indentures  supplemental hereto (which shall conform to the
provisions  of the Trust  Indenture  Act as then in effect)  for the  purpose of
adding any  provisions  to or changing in any manner or  eliminating  any of the
provisions of this Indenture or of any supplemental indenture or of modifying in
any manner the rights of the holders of the Securities of such series under this
Indenture;  provided,  however,  that no such  supplemental  indenture shall (i)
extend  the fixed  maturity  of any  Securities  of any  series,  or reduce  the
principal  amount  thereof,  or reduce the rate or extend the time of payment of
interest thereon,  or reduce any premium payable upon the redemption thereof, or
reduce the amount of the principal of a Discount  Security that would be due and
payable upon a declaration of acceleration of the maturity  thereof  pursuant to
Section  6.01,  without  the  consent  of the  holders  of  each  Security  then
outstanding  and affected,  (ii) reduce the aforesaid  percentage of Securities,
the holders of which are required to consent to any such supplemental indenture,
or reduce the  percentage  of  Securities,  the holders of which are required to
waive any  default  and its  consequences,  without the consent of the holder of
each  Security  then  outstanding  and  affected  thereby,  or (iii)  modify any
provision of Section  6.01(c)  (except to increase the  percentage  of principal
amount of securities  required to rescind and annul any  declaration  of amounts
due and payable under the Securities) without the consent of the holders of each
Security then outstanding and affected thereby.

     Upon  the  request  of  the  Company,  accompanied  by a  Board  Resolution
authorizing  the  execution  of any such  supplemental  indenture,  and upon the
filing with the Trustee of evidence of the consent of  Securityholders  required
to consent thereto as aforesaid,  the Trustee shall join with the Company in the
execution of such  supplemental  indenture  unless such  supplemental  indenture
affects the Trustee's own rights,  duties or immunities  under this Indenture or
otherwise,  in which case the  Trustee may in its  discretion,  but shall not be
obligated to, enter into such supplemental indenture.

     A  supplemental  indenture that changes or eliminates any covenant or other
provision of this  Indenture  that has expressly  been  included  solely for the
benefit of one or more  particular  series of  Securities,  or that modifies the
rights of holders of  Securities of such series with respect to such covenant or
other  provision,  shall be deemed not to affect the rights under this Indenture
of the holders of Securities of any other series.

     It shall not be  necessary  for the consent of the  Securityholders  of any
series affected thereby under this Section to approve the particular form of any
proposed  supplemental  indenture,  but it shall be  sufficient  if such consent
shall approve the substance thereof.

     Promptly  after  the  execution  by the  Company  and  the  Trustee  of any
supplemental  indenture pursuant to the provisions of this Section,  the Trustee
shall transmit by mail, first class postage prepaid, a notice,  setting forth in
general   terms  the   substance  of  such   supplemental   indenture,   to  the
Securityholders  of all series  affected  thereby as their  names and  addresses
appear  upon the  Security  Register.  Any  failure of the  Trustee to mail such
notice, or any defect therein,  shall not, however,  in any way impair or affect
the validity of any such supplemental indenture.

     SECTION 9.03. Upon the execution of any supplemental  indenture pursuant to
the provisions of this Article or of Section 10.01,  this Indenture shall,  with
respect  to  such  series,  be and be  deemed  to be  modified  and  amended  in
accordance   therewith  and  the  respective  rights,   limitations  of  rights,
obligations,  duties and  immunities  under this  Indenture of the Trustee,  the
Company and the  holders of  Securities  of the series  affected  thereby  shall
thereafter  be  determined,  exercised  and  enforced  hereunder  subject in all
respects to such modifications and amendments,  and all the terms and conditions
of any such  supplemental  indenture  shall be and be  deemed  to be part of the
terms and conditions of this Indenture for any and all purposes.

     SECTION  9.04.  Securities  of  any  series,  affected  by  a  supplemental
indenture,  authenticated and delivered after the execution of such supplemental
indenture  pursuant to the  provisions of this  Article,  Article Two or Article
Seven or of Section 10.01,  may bear a notation in form approved by the Company,
provided such form meets the requirements of any exchange upon which such series
may be listed, as to any matter provided for in such supplemental  indenture. If
the Company shall so determine,  new Securities of that series so modified as to
conform,  in the opinion of the Board of Directors,  to any modification of this
Indenture  contained in any such  supplemental  indenture may be prepared by the
Company,  authenticated  by the  Trustee  and  delivered  in  exchange  for  the
Securities of that series then outstanding.

     SECTION 9.05. The Trustee, subject to the provisions of Section 7.01, shall
be entitled to receive, and shall be fully protected in relying upon, an Opinion
of Counsel as  conclusive  evidence  that any  supplemental  indenture  executed
pursuant to this Article is  authorized  or  permitted  by, and conforms to, the
terms of this Article and that it is proper for the Trustee under the provisions
of this Article to join in the execution thereof.


                                   ARTICLE TEN
                         CONSOLIDATION, MERGER AND SALE

     SECTION  10.01.  Nothing  contained  in  this  Indenture  or in  any of the
Securities shall prevent any consolidation or merger of the Company with or into
any other  corporation  or other  entity  (whether  or not  affiliated  with the
Company),  or successive  consolidations  or mergers in which the Company or its
successor or successors shall be a party or parties,  or shall prevent any sale,
conveyance,  transfer or other  disposition of all or  substantially  all of the
property  of the Company or its  successor  or  successors  as an  entirety,  or
substantially as an entirety, to any other corporation or entity (whether or not
affiliated  with the Company or its successor or  successors)  and authorized to
acquire and operate the same;  provided,  however,  the Company hereby covenants
and agrees that,  (i) upon any such  consolidation,  merger,  sale,  conveyance,
transfer or other disposition,  the due and punctual payment of the principal of
(premium,  if any)  and  interest  on all of the  Securities  of all  series  in
accordance with the terms of each series,  according to their tenor, and the due
and punctual  performance  and observance of all the covenants and conditions of
this Indenture  with respect to each series or established  with respect to such
series pursuant to Section 2.01 to be kept or performed by the Company, shall be
expressly  assumed,  by  supplemental  indenture  (which  shall  conform  to the
provisions of the Trust Indenture Act as then in effect) satisfactory in form to
the Trustee  executed and  delivered to the Trustee by the entity formed by such
consolidation,  or into  which the  Company  shall have been  merged,  or by the
entity  which shall have  acquired  such  property  and (ii) in case the Company
shall consolidate with or merge into another Person or convey, sell, transfer or
otherwise dispose of all or substantially all of its property, the Person formed
by such  consolidation  or into which the Company is merged or the Person  which
acquires by conveyance,  sale, transfer or otherwise all or substantially all of
the Company's property shall be organized and validly existing under the laws of
the United States of America, any state thereof or the District of Columbia.

     SECTION 10.02.  (a)....In  case of any such  consolidation,  merger,  sale,
conveyance,  transfer  or  other  disposition  and upon  the  assumption  by the
successor corporation, by supplemental indenture,  executed and delivered to the
Trustee and satisfactory in form to the Trustee, of the due and punctual payment
of the principal of and premium,  if any, and interest on all of the  Securities
of all series  outstanding  and the due and punctual  performance  of all of the
covenants and conditions of this  Indenture or established  with respect to each
series of the Securities pursuant to Section 2.01 to be kept or performed by the
Company with respect to each series, such successor corporation shall succeed to
and be substituted for the Company, with the same effect as if it had been named
herein as the party of the first part, and thereupon (provided, that in the case
of a lease, the term of the lease is at least as long as the longest maturity of
any Securities  outstanding at such time) the predecessor  corporation  shall be
relieved  of  all  obligations  and  covenants  under  this  Indenture  and  the
Securities. Such successor corporation thereupon may cause to be signed, and may
issue  either  in its  own  name  or in the  name of the  Company  or any  other
predecessor  obligor on the  Securities,  any or all of the Securities  issuable
hereunder  which  theretofore  shall not have been  signed  by the  Company  and
delivered to the Trustee; and, upon the order of such successor company, instead
of the Company, and subject to all the terms, conditions and limitations in this
Indenture  prescribed,  the Trustee  shall  authenticate  and shall  deliver any
Securities which previously shall have been signed and delivered by the officers
of the predecessor Company to the Trustee for authentication, and any Securities
which  such  successor  corporation  thereafter  shall  cause to be  signed  and
delivered to the Trustee for that purpose. All the Securities so issued shall in
all respects  have the same legal rank and benefit  under this  Indenture as the
Securities theretofore or thereafter issued in accordance with the terms of this
Indenture  as though all of such  Securities  had been issued at the date of the
execution hereof.

     (b) In case of any such consolidation,  merger, sale, conveyance,  transfer
or other disposition such changes in phraseology and form (but not in substance)
may be made in the Securities thereafter to be issued as may be appropriate.

     (c) Nothing  contained in this Indenture or in any of the Securities  shall
prevent  the  Company  from  merging  into  itself or  acquiring  by purchase or
otherwise all or any part of the property of any other  corporation  (whether or
not affiliated with the Company).

     SECTION 10.03. The Trustee,  subject to the provisions of Section 7.01, may
receive  an  Opinion  of   Counsel  as   conclusive   evidence   that  any  such
consolidation,  merger, sale, conveyance, transfer or other disposition, and any
such assumption, comply with the provisions of this Article.


                                 ARTICLE ELEVEN
                    SATISFACTION AND DISCHARGE OF INDENTURE;
                                UNCLAIMED MONIES

     SECTION 11.01.  If at any time: (a) the Company shall have delivered to the
Trustee for  cancellation all Securities of a series  theretofore  authenticated
(other than any Securities  which shall have been destroyed,  lost or stolen and
which  shall  have  been  replaced  or paid as  provided  in  Section  2.07  and
Securities  for whose payment money has  theretofore  been deposited in trust or
segregated and held in trust by the Company and thereupon  repaid to the Company
or discharged from such trust, as provided in Section 11.04); or (b) the Company
shall  deposit or cause to be deposited  with the Trustee as trust funds (i) the
entire amount in monies or Eligible  Obligations or (ii) a combination of monies
and Eligible  Obligations,  sufficient in the opinion of a nationally recognized
firm of  independent  public  accountants  expressed in a written  certification
thereof  delivered to the Trustee,  to pay at maturity or upon redemption  under
arrangements satisfactory to the Trustee for the giving of notice of redemption,
all Securities of a particular  series not theretofore  delivered to the Trustee
for cancellation,  including principal (and premium, if any) and interest due or
to become due to their date of  maturity  or date fixed for  redemption,  as the
case may be, and if such deposit shall be made prior to the stated maturity date
of the  Securities  of that  series,  the Company  shall have  delivered  to the
Trustee an Opinion of Counsel to the effect that the holders of such  Securities
will not  recognize  gain,  loss or income for federal  income tax purposes as a
result of the  satisfaction and discharge of this Indenture with respect to such
series and such holders will be subject to federal  income  taxation on the same
amounts and in the same manner and at the same times as if such satisfaction and
discharge  had not  occurred,  and if the Company  shall also pay or cause to be
paid all  other  sums  payable  hereunder  with  respect  to such  series by the
Company,  then this Indenture shall thereupon cease to be of further effect with
respect to such series except for the provisions of Sections 2.05,  2.07,  4.02,
7.06,  7.10 and  11.04,  which  shall  survive  until  the date of  maturity  or
redemption  date,  as the case may be, and Sections  7.06,  7.10 and 11.04 which
shall  survive to such date and  thereafter,  and the Trustee,  on demand of the
Company  and at the  cost and  expense  of the  Company,  shall  execute  proper
instruments  acknowledging  satisfaction of and discharging  this Indenture with
respect to such series.

     SECTION  11.02.  All  monies or  Eligible  Obligations  deposited  with the
Trustee  pursuant to Sections 11.01 or 11.02 shall be held in trust and shall be
available  for  payment as due,  either  directly  or through  any paying  agent
(including the Company  acting as its own paying  agent),  to the holders of the
particular  series of  Securities  for the payment or  redemption  of which such
monies or Eligible Obligations have been deposited with the Trustee.

     SECTION 11.03.  In connection with the  satisfaction  and discharge of this
Indenture all monies or Eligible Obligations then held by any paying agent under
the provisions of this Indenture shall,  upon demand of the Company,  be paid to
the Trustee and  thereupon  such paying agent shall be released from all further
liability with respect to such monies or Eligible Obligations.

     SECTION 11.04. Any monies or Eligible Obligations deposited with any paying
agent or the  Trustee,  or then held by the  Company,  in trust for  payment  of
principal of or premium or interest on the  Securities  of a  particular  series
that are not applied but remain  unclaimed by the holders of such Securities for
at least two years after the date upon which the principal of (and  premium,  if
any) or  interest  on such  Securities  shall have  respectively  become due and
payable,  upon the written request of the Company and unless otherwise  required
by mandatory provisions of applicable escheat or abandoned or unclaimed property
law,  shall be repaid to the  Company on May 31 of each year or (if then held by
the Company) shall be discharged from such trust; and thereupon the paying agent
and the Trustee  shall be released  from all further  liability  with respect to
such monies or  Eligible  Obligations,  and the holder of any of the  Securities
entitled to receive  such payment  shall  thereafter,  as an  unsecured  general
creditor, look only to the Company for the payment thereof.


                                 ARTICLE TWELVE
                IMMUNITY OF INCORPORATORS, STOCKHOLDERS, OFFICERS
                                  AND DIRECTORS

     SECTION  12.01.  No  recourse  under or upon any  obligation,  covenant  or
agreement of this Indenture,  or of any Security, or for any claim based thereon
or  otherwise  in  respect  thereof,  shall  be had  against  any  incorporator,
stockholder,  officer  or  director,  past,  present  or future as such,  of the
Company or of any  predecessor  or  successor  corporation,  either  directly or
through the Company or any such predecessor or successor corporation, whether by
virtue of any constitution, statute or rule of law, or by the enforcement of any
assessment  or penalty or otherwise;  it being  expressly  understood  that this
Indenture and the obligations issued hereunder are solely corporate obligations,
and that no such personal  liability whatever shall attach to, or is or shall be
incurred by, the incorporators,  stockholders, officers or directors as such, of
the Company or of any  predecessor  or  successor  corporation,  or any of them,
because of the creation of the indebtedness  hereby  authorized,  or under or by
reason of the obligations,  covenants or agreements  contained in this Indenture
or in any of the  Securities  or  implied  therefrom;  and that any and all such
personal  liability of every name and nature,  either at common law or in equity
or by  constitution  or  statute,  of,  and any and all such  rights  and claims
against,  every such  incorporator,  stockholder,  officer or  director as such,
because of the creation of the indebtedness  hereby  authorized,  or under or by
reason of the obligations,  covenants or agreements  contained in this Indenture
or in any of the Securities or implied  therefrom,  are hereby  expressly waived
and released as a condition  of, and as a  consideration  for, the  execution of
this Indenture and the issuance of such Securities.


                                ARTICLE THIRTEEN
                            MISCELLANEOUS PROVISIONS

     SECTION 13.01. All the covenants, stipulations,  promises and agreements in
this  Indenture  contained  by or on  behalf  of  the  Company  shall  bind  its
successors and assigns, whether so expressed or not.

     SECTION  13.02.  Any act or proceeding  by any provision of this  Indenture
authorized  or  required  to be done or  performed  by any board,  committee  or
officer of the Company shall and may be done and  performed  with like force and
effect by the corresponding board,  committee or officer of any corporation that
shall at the time be the lawful sole successor of the Company.

     SECTION 13.03.  The Company by instrument in writing  executed by authority
of  two-thirds  of its Board of  Directors  and  delivered  to the  Trustee  may
surrender  any of the powers  reserved to the Company  under this  Indenture and
thereupon such power so surrendered  shall  terminate both as to the Company and
as to any successor corporation.

     SECTION 13.04.  Except as otherwise expressly provided herein any notice or
demand which by any  provision of this  Indenture is required or permitted to be
given or served by the  Trustee  or by the  holders of  Securities  to or on the
Company may be given or served by being deposited first class postage prepaid in
a post office letter box addressed (until another address is filed in writing by
the Company with the Trustee),  as follows:  American  Electric  Power  Company,
Inc., 1 Riverside Plaza, Columbus, Ohio 43215, Attention: Treasurer. Any notice,
election,  request or demand by the Company or any Securityholder to or upon the
Trustee  shall be  deemed  to have  been  sufficiently  given  or made,  for all
purposes,  if given or made in  writing  at the  Corporate  Trust  Office of the
Trustee.

     SECTION  13.05.  This  Indenture and each Security  shall be deemed to be a
contract  made  under the laws of the State of New  York,  and for all  purposes
shall be construed in accordance with the laws of said State.

     SECTION 13.06.  (a)......Upon  any  application or demand by the Company to
the Trustee to take any action under any of the  provisions  of this  Indenture,
the Company shall furnish to the Trustee an Officers'  Certificate  stating that
all conditions precedent provided for in this Indenture relating to the proposed
action have been  complied  with and an Opinion of Counsel  stating  that in the
opinion of such counsel all such  conditions  precedent have been complied with,
except  that in the case of any  such  application  or  demand  as to which  the
furnishing of such documents is  specifically  required by any provision of this
Indenture  relating to such  particular  application  or demand,  no  additional
certificate or opinion need be furnished.

     (b)  Each  certificate  or  opinion  provided  for in  this  Indenture  and
delivered to the Trustee with respect to compliance with a condition or covenant
in this  Indenture  (other  than the  certificate  provided  pursuant to Section
5.03(d) of this Indenture)  shall include (1) a statement that the person making
such  certificate  or opinion has read such covenant or  condition;  (2) a brief
statement as to the nature and scope of the  examination or  investigation  upon
which the  statements or opinions  contained in such  certificate or opinion are
based;  (3) a statement that, in the opinion of such person,  he or she has made
such  examination  or  investigation  as is  necessary  to enable  him or her to
express an informed  opinion as to whether or not such covenant or condition has
been complied  with; and (4) a statement as to whether or not, in the opinion of
such person, such condition or covenant has been complied with.

     SECTION  13.07.  Except as provided  pursuant to Section 2.01 pursuant to a
Company Order,  or established in one or more  indentures  supplemental  to this
Indenture,  in any case where the date of maturity of  principal  or an Interest
Payment Date of any Security or the date of redemption, purchase or repayment of
any  Security  shall not be a Business Day then payment of interest or principal
(and premium,  if any) may be made on the next succeeding  Business Day with the
same force and effect as if made on the nominal date of maturity or  redemption,
and no interest shall accrue for the period after such nominal date.

     SECTION  13.08.  If and to the extent that any provision of this  Indenture
limits,  qualifies or conflicts with the duties  imposed by the Trust  Indenture
Act, such imposed duties shall control.

     SECTION   13.09.   This   Indenture  may  be  executed  in  any  number  of
counterparts,  each of which shall be an original;  but such counterparts  shall
together constitute but one and the same instrument.

     SECTION 13.10. In case any one or more of the provisions  contained in this
Indenture or in the  Securities of any series shall for any reason be held to be
invalid, illegal or unenforceable in any respect, such invalidity, illegality or
unenforceability  shall not affect any other  provisions of this Indenture or of
such Securities, but this Indenture and such Securities shall be construed as if
such  invalid or illegal or  unenforceable  provision  had never been  contained
herein or therein.

     SECTION  13.11.  The Company will have the right at all times to assign any
of its rights or obligations  under the Indenture to a direct or indirect wholly
owned  subsidiary  of the  Company;  provided  that,  in the  event  of any such
assignment, the Company will remain liable for all such obligations.  Subject to
the  foregoing,  this Indenture is binding upon and inures to the benefit of the
parties thereto and their respective  successors and assigns. This Indenture may
not otherwise be assigned by the parties thereto.

     SECTION 13.12.  The Article and Section  Headings in this Indenture and the
Table of Contents are for convenience only and shall not affect the construction
hereof.

     SECTION 13.13.  Whenever this Indenture  provides for any action by, or the
determination of any rights of, holders of Securities of any series in which not
all of such Securities are  denominated in the same currency,  in the absence of
any provision to the contrary in the form of Security of any particular  series,
any amount in  respect  of any  Security  denominated  in a currency  other than
Dollars shall be treated for any such action or  determination of rights as that
amount of Dollars  that could be  obtained  for such  amount on such  reasonable
basis of exchange and as of the record date with respect to  Securities  of such
series (if any) for such action or  determination  of rights (or, if there shall
be no applicable  record date, such other date reasonably  proximate to the date
of such  action or  determination  of rights) as the  Company  may  specify in a
written notice to the Trustee or, in the absence of such written notice,  as the
Trustee may determine.

     The Bank of New  York,  as  Trustee,  hereby  accepts  the  trusts  in this
Indenture declared and provided,  upon the terms and conditions  hereinabove set
forth.

     IN WITNESS  WHEREOF,  the parties  hereto have caused this  Indenture to be
duly executed,  and their respective  corporate seals to be hereunto affixed and
attested, all as of the day and year first above written.

                                   AMERICAN ELECTRIC POWER COMPANY, INC.


                                   By /s/ Geoffrey S. Chatas
                                          Assistant Treasurer
Attest:


By /s/ Thomas G. Berkemeyer
       Assistant Secretary
                                         THE BANK OF NEW YORK,
                                         as Trustee

                                           By  /s/ Paul Schmalzel
                                                   Vice President
Attest:

By /s/ Thomas Zakrzewski
       Trust Officer




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4
<SEQUENCE>5
<FILENAME>x4b.txt
<DESCRIPTION>(B) FIRST SUPPLEMENTAL INDENTURE
<TEXT>

<PAGE>

                                                                    Exhibit 4(b)


                      AMERICAN ELECTRIC POWER COMPANY, INC.


                                       AND


                              THE BANK OF NEW YORK,
                                   as Trustee


                             -----------------------



                          FIRST SUPPLEMENTAL INDENTURE

                             Dated as of May 1, 2001


                                       TO


                                    INDENTURE


                             Dated as of May 1, 2001


                 6.125% Senior Notes, Series A due May 15, 2006


                             -----------------------

     FIRST  SUPPLEMENTAL  INDENTURE,  dated as of the 1st day of May, 2001 (this
"First Supplemental Indenture"),  between AMERICAN ELECTRIC POWER COMPANY, INC.,
a corporation  duly  organized  and existing  under the laws of the State of New
York (hereinafter  sometimes referred to as the "Company"),  and THE BANK OF NEW
YORK, a New York banking corporation, as trustee (hereinafter sometimes referred
to as the  "Trustee")  under the  Indenture  dated as of May 1, 2001 between the
Company and the Trustee (the "Original Indenture").  The Original Indenture,  as
supplemented by this First Supplemental Indenture, is hereinafter referred to as
the "Indenture".

     WHEREAS,  the Company has executed and delivered the Original  Indenture to
the Trustee to provide for the issuance of unsecured  promissory  notes or other
evidences of indebtedness (the "Securities") in an unlimited aggregate principal
amount,  said  Notes to be  issued  from  time to time in one or more  series as
provided in the Indenture; and

     WHEREAS,  pursuant  to the terms of the  Original  Indenture,  the  Company
desires to provide for the establishment of a new series of its Securities (said
series  being  hereinafter  referred to as the  "Series A Notes"),  the form and
substance  of such  Series A Notes  and the  terms,  provisions  and  conditions
thereof to be set forth as provided  in the  Original  Indenture  and this First
Supplemental Indenture; and

     WHEREAS,  the Company desires and has requested the Trustee to join with it
in the  execution  and delivery of this First  Supplemental  Indenture,  and all
requirements  necessary  to  make  this  First  Supplemental  Indenture  a valid
instrument,  in accordance with its terms, and to make the Series A Notes,  when
executed by the Company and  authenticated  and  delivered by the  Trustee,  the
valid  obligations of the Company,  have been  performed and fulfilled,  and the
execution and delivery hereof have been in all respects duly authorized;

     NOW  THEREFORE,  in  consideration  of the purchase and  acceptance  of the
Series A Notes by the holders thereof,  and for the purpose of setting forth, as
provided in the Original Indenture, the form and substance of the Series A Notes
and the terms,  provisions and  conditions  thereof,  the Company  covenants and
agrees with the Trustee as follows:


                                   ARTICLE ONE
                         GENERAL TERMS AND CONDITIONS OF
                               THE SERIES A NOTES

     SECTION  1.01.  There  shall  be and  is  hereby  authorized  a  series  of
Securities  designated the "6.125%  Senior Notes,  Series A due May 15, 2006, in
the initial aggregate principal amount of $1,000,000,000,  which amount shall be
as set forth in the Company  Order for the  authentication  and  delivery of the
Series A Notes pursuant to Section 2.04 of the Original Indenture.  The Series A
Notes shall mature and the principal shall be due and payable  together with all
accrued and unpaid interest  thereon on May 15, 2006, and shall be issued in the
form of registered Series A Notes without coupons.

     SECTION 1.02. The Series A Notes shall be issued initially in the form of a
Global Note or Notes in an aggregate  principal  amount equal to all outstanding
Series A Notes, to be registered in the name of the Depository,  or its nominee,
and held by the Trustee,  as custodian  for the  Depository.  The Company  shall
execute a Global Note or Notes in such  aggregate  principal  amount and deliver
the same to the Trustee for  authentication  and delivery as hereinabove  and in
the Original Indenture provided.  Payments of principal of (and premium, if any)
and interest on the Series A Notes  represented by a Global Note will be made to
the  Depository.  The  Depository for the Series A Notes shall be The Depository
Trust Company, New York, New York.

     SECTION 1.03. (a) If,  pursuant to the provisions of Section 2.11(c) of the
Original  Indenture,  the  Series  A Notes  are  issued  in  certificated  form,
principal,  premium, if any, and interest on the Series A Notes will be payable,
the transfer of such Series A Notes will be registrable  and such Series A Notes
will be exchangeable  for Series A Notes bearing  identical terms and provisions
at the office or agency of the Company only upon surrender of such  certificated
Series A Note and such other documents as required by the Indenture.

     (b)  Subject  to any terms of the  Series A Notes  issued as Global  Notes,
payment of the principal of (and  premium,  if any) and interest on the Series A
Notes will be made at the office or agency of the  Company  maintained  for that
purpose in the  Borough of  Manhattan,  the City and State of New York,  in such
coin or  currency  of the United  States of America as at the time of payment is
legal  tender for the  payment of public and  private  debts and in  immediately
available funds; provided, however, that at the option of the Company payment of
interest  may be made by wire  transfer  of  immediately  available  funds to an
account of the Person entitled  thereto as such account shall be provided to the
Security  Registrar  at least 10 days prior to the  relevant  payment date or by
check in New York  Clearinghouse  Funds  mailed  to the  address  of the  person
entitled  thereto  as  such  address  shall  appear  in the  Security  Register;
provided,  further,  for so  long  as the  Series  A  Notes  are  listed  on the
Luxembourg Stock Exchange,  payment may be made in Luxembourg,  initially at the
corporate trust office of Kredietbank S.A., Luxembourgoise, as Luxembourg paying
agent.

     SECTION 1.04.  Each Series A Note shall bear interest at the rate of 6.125%
per annum from the original date of issuance until the principal thereof becomes
due and payable, and on any overdue principal and (to the extent that payment of
such interest is enforceable under applicable law) on any overdue installment of
interest at the same rate per annum,  payable  semi-annually  in arrears on each
May 15 and  November  15 (each,  an  "Interest  Payment  Date"),  commencing  on
November  15, 2001.  Interest  (other than  interest  payable on  redemption  or
maturity) shall be payable to the person in whose name such Series A Note or any
predecessor  Series A Note is registered at the close of business on the regular
record date for such  interest  installment.  The  regular  record date for such
interest  installment  shall be the close of business on the May 1 or November 1
(whether  or not a Business  Day) next  preceding  the  Interest  Payment  Date.
Interest  payable on  redemption  or maturity  shall be payable to the person to
whom the principal is paid. Any such interest installment not punctually paid or
duly provided for shall forthwith cease to be payable to the registered  holders
on such  regular  record  date,  and may be paid to the person in whose name the
Series A Note (or one or more Predecessor Securities) is registered at the close
of business on a special  record date to be fixed by the Trustee for the payment
of such  defaulted  interest,  notice  whereof shall be given to the  registered
holders of the Series A Notes not less than 10 days prior to such special record
date,  or may be paid at any time in any other  lawful  manner not  inconsistent
with the requirements of any securities exchange on which the Series A Notes may
be listed, and upon such notice as may be required by such exchange, all as more
fully provided in Section 2.03 of the Original Indenture.

     The amount of interest payable for any period will be computed on the basis
of a 360-day year of twelve 30-day  months.  In the event that any date on which
the Series A Notes mature or are redeemed, or date on which payment is scheduled
to be made  pursuant to a redemption  or any  interest  payment  date,  is not a
Business Day, then payment of interest  payable on such date will be made on the
next  succeeding  day which is a Business Day (and without any interest or other
payment in respect of any such delay),  except that,  if such Business Day is in
the next succeeding calendar year, such payment shall be made on the immediately
preceding  Business  Day, in each case with the same force and effect as if made
on such date.

     SECTION  1.05.  The Series A Notes shall be  unsecured  and  unsubordinated
obligations  of the  Company  ranking  pari passu with all other  unsecured  and
unsubordinated indebtedness of the Company.

     SECTION  1.06.  The Series A Notes shall not be subject to any sinking fund
provision.

     SECTION  1.07.  The Company  shall be subject to the  provisions  described
under "Restrictive Covenants" in the form of the Security attached as Exhibit A.


                                   ARTICLE TWO
                        REDEMPTION OF THE SERIES A NOTES

     SECTION  2.01.  (a) The Company shall have the right to redeem the Series A
Notes as set forth  under  "Redemption  -  Optional  Redemption"  in the form of
Security attached as Exhibit A hereto.

          (b) The  Company  shall have the right to redeem the Series A Notes as
     set forth under  "Redemption  - Redemption  For Tax Reasons" in the form of
     Security attached as Exhibit A hereto.

          (c) Any redemption pursuant to this Section will be made upon not less
     than 30 nor  more  than 60 days'  notice.  If the  Series A Notes  are only
     partially redeemed pursuant to Section 2.01(a),  the Notes will be redeemed
     by lot or in  such  other  manner  as  the  Trustee  shall  deem  fair  and
     appropriate in its discretion; provided, that if at the time of redemption,
     the Series A Notes are  represented by a Global Note, the Depository  shall
     determine by lot the  principal  amount of such Series A Notes held by each
     Series A Noteholder to be redeemed.


                                  ARTICLE THREE
                              FORM OF SERIES A NOTE

     SECTION  3.01.  (a) The  Series A Notes and the  Trustee's  Certificate  of
Authentication  to be endorsed  thereon are to be  substantially  in the form of
Exhibit A hereto.

     (b) The terms and  provisions of the Series A Notes as set forth in Exhibit
A are hereby  incorporated in and expressly made part of this First Supplemental
Indenture.


                                  ARTICLE FOUR
                            MISCELLANEOUS PROVISIONS

     SECTION  4.01.  Except  as  otherwise  expressly  provided  in  this  First
Supplemental  Indenture  or in the form of  Series A Note or  otherwise  clearly
required by the context hereof or thereof, all terms used herein or in said form
of Series A Note that are  defined  in the  Original  Indenture  shall  have the
several meanings respectively assigned to them thereby.

     SECTION  4.02.  The  Original  Indenture,  as  supplemented  by this  First
Supplemental  Indenture,  is in all respects  ratified and  confirmed,  and this
First Supplemental Indenture shall be deemed part of the Indenture in the manner
and to the extent herein and therein provided.

     SECTION 4.03. The recitals herein contained are made by the Company and not
by the Trustee,  and the Trustee assumes no  responsibility  for the correctness
thereof.  The Trustee makes no  representation as to the validity or sufficiency
of this First Supplemental Indenture.

     SECTION  4.04.  This First  Supplemental  Indenture  may be executed in any
number of counterparts each of which shall be an original; but such counterparts
shall together constitute but one and the same instrument.

     SECTION  4.05.  The Bank of New York is hereby  appointed the Paying Agent,
authenticating  agent and Security Registrar in the United States for the Series
A Notes. In addition, so long as the Series A Notes are listed on the Luxembourg
Stock  Exchange,  the Company will maintain a paying agent and transfer agent in
Luxembourg.  The Company's initial paying agent and transfer agent in Luxembourg
shall be Kredietbank  S.A.,  Luxembourgoise,  currently  located at 43 Boulevard
Royal, L-2955 Luxembourg.

     IN WITNESS WHEREOF,  the parties hereto have caused this First Supplemental
Indenture  to be duly  executed,  and  their  respective  corporate  seals to be
hereunto  affixed  and  attested,   on  the  date  or  dates  indicated  in  the
acknowledgments and as of the day and year first above written.

                                           AMERICAN ELECTRIC POWER COMPANY, INC.


                                           By:  /s/ Geoffrey S. Chatas
                                                    Assistant Treasurer



                                           THE BANK OF NEW YORK,
                                           as Trustee

                                           By:  /s/ Paul Schmalzel
                                                    Vice President



                                                                      Exhibit A


Unless this  certificate  is presented by an  authorized  representative  of The
Depository Trust Company (55 Water Street,  New York, New York) to the issuer or
its agent for registration of transfer, exchange or payment, and any certificate
to be issued is registered in the name of Cede & Co. or in such other name as is
requested by an authorized  representative  of The Depository  Trust Company and
any payment is made to Cede & Co., ANY TRANSFER,  PLEDGE OR OTHER USE HEREOF FOR
VALUE OR  OTHERWISE BY OR TO ANY PERSON IS WRONGFUL  inasmuch as the  registered
owner hereof,  Cede & Co., has an interest herein.  Except as otherwise provided
in Section 2.11 of the Indenture, this Security may be transferred, in whole but
not in  part,  only to  another  nominee  of the  Depository  or to a  successor
Depository or to a nominee of such successor Depository.

No.   R1

                      AMERICAN ELECTRIC POWER COMPANY, INC.
          $1,000,000,000 6.125% Senior Notes, Series A due May 15, 2006


CUSIP:  025537 AA 9                        Original Issue Date:  May 10, 2001

Stated Maturity:  May 15, 2006              Interest Rate:  6.125%

Principal Amount:  $____________

Redeemable:       Yes  X         No
In Whole:         Yes  X         No
In Part:          Yes  X         No

     AMERICAN  ELECTRIC  POWER COMPANY,  INC., a corporation  duly organized and
existing  under the laws of the  State of New York  (herein  referred  to as the
"Company",  which term  includes any successor  corporation  under the Indenture
hereinafter  referred to), for value received,  hereby promises to pay to CEDE &
CO. or registered  assigns,  the Principal  Amount specified above on the Stated
Maturity  specified above, and to pay interest on said Principal Amount from the
Original Issue Date  specified  above or from the most recent  interest  payment
date (each such date,  an "Interest  Payment  Date") to which  interest has been
paid or duly provided for, semi-annually in arrears on May 15 and November 15 in
each  year,  commencing  November  15,  2001,  at the  Interest  Rate per  annum
specified  above,  until  the  Principal  Amount  shall  have  been paid or duly
provided  for.  Interest  shall be  computed  on the basis of a 360-day  year of
twelve 30-day months.

     The interest so payable,  and punctually  paid or duly provided for, on any
Interest  Payment Date, as provided in the Indenture,  as  hereinafter  defined,
shall be paid to the Person in whose name this Note (or one or more  Predecessor
Securities)  shall have been  registered at the close of business on the regular
record date with respect to such Interest Payment Date, which shall be the May 1
or November 1, as the case may be,  immediately  preceding such Interest Payment
Date,  provided that interest  payable on the Stated  Maturity or any redemption
date shall be paid to the Person to whom  principal is paid.  Any such  interest
not so punctually  paid or duly provided for shall forthwith cease to be payable
to the Holder on such regular  record date and shall be paid as provided in said
Indenture.

     If any Interest Payment Date, any redemption date or Stated Maturity is not
a Business  Day,  then payment of the amounts due on this Note on such date will
be made on the next  succeeding  Business  Day, and no interest  shall accrue on
such  amounts  for the  period  from  and  after  such  Interest  Payment  Date,
redemption date or Stated Maturity,  as the case may be, with the same force and
effect as if made on such date.

     This Note is one of a duly  authorized  series of Securities of the Company
(herein sometimes referred to as the "Notes"),  specified in the Indenture,  all
issued or to be issued in one or more series  under and pursuant to an Indenture
dated as of May 1, 2001 duly executed and delivered  between the Company and The
Bank of New York, a  corporation  organized  and existing  under the laws of the
State of New York,  as  trustee  (herein  referred  to as the  "Trustee")  (such
Indenture,  as originally executed and delivered and as thereafter  supplemented
and  amended  being  hereinafter  referred  to as  the  "Indenture"),  to  which
Indenture and all indentures supplemental thereto or Company Orders reference is
hereby made for a description of the rights, limitations of rights, obligations,
duties and immunities  thereunder of the Trustee, the Company and the holders of
the Notes. By the terms of the Indenture,  the Securities are issuable in series
which may vary as to amount,  date of  maturity,  rate of interest  and in other
respects as in the Indenture  provided.  This Note is one of the series of Notes
designated on the face hereof.

Restrictive Covenants

     Limitation upon Liens of Certain Subsidiaries

               For so long as any Securities of this series remain  outstanding,
          the Company will not create or incur or allow any of its  subsidiaries
          to create  or incur any  pledge  or  security  interest  on any of the
          capital stock of a Public  Utility  Subsidiary  held by the Company or
          one of its subsidiaries or a Significant Subsidiary.

          For purposes of this covenant:

               (i) Public Utility  Subsidiary  means, at any particular  time, a
          direct or indirect  subsidiary  of the Company  that, as a substantial
          part of its  business,  distributes  or transmits  electric  energy to
          retail or wholesale  customers at rates or tariffs that are  regulated
          by either a state or Federal regulatory authority.

               (ii)  Significant  Subsidiary  means, at any particular time, any
          direct  subsidiary  of  ours  whose   consolidated   gross  assets  or
          consolidated  gross revenues  (having  regard to the Company's  direct
          beneficial  interest in the shares,  or the like, of that  subsidiary)
          represent at least 25% of the Company's  consolidated  gross assets or
          consolidated  gross  revenues  appearing  in the most  recent  audited
          financial statements of the Company as of the date of determination.

     Limitation upon Mergers, Consolidations and Sale of Assets

               The  provisions  of  Article  Ten  of  the  Indenture   shall  be
          applicable to the Securities of this series.

Redemption

     Optional Redemption

     This Note may be redeemed  by the  Company at its  option,  in whole at any
time or in part from time to time,  upon not less than  thirty but not more than
sixty days' previous  notice given by mail to the registered  owners of the Note
at a redemption  price equal to the greater of (i) 100% of the principal  amount
of the  Note  being  redeemed  and  (ii) the sum of the  present  values  of the
remaining  scheduled  payments  of  principal  and  interest  on the Note  being
redeemed  (excluding  the  portion of any such  interest  accrued to the date of
redemption)  discounted  (for  purposes  of  determining  present  value) to the
redemption  date on a semi-annual  basis  (assuming a 360-day year consisting of
twelve  30-day  months) at the  Treasury  Rate (as defined  below) plus 25 basis
points, plus, in each case, accrued interest thereon to the date of redemption.

     "Treasury  Rate" means,  with respect to any redemption  date, the rate per
     annum equal to the semi-annual equivalent yield to maturity or interpolated
     (on a day count basis) of the Comparable  Treasury Issue,  assuming a price
     for  the  Comparable  Treasury  Issue  (expressed  as a  percentage  of its
     principal  amount)  equal  to  the  Comparable   Treasury  Price  for  such
     redemption date.

     "Comparable  Treasury  Issue"  means the United  States  Treasury  security
     selected  by an  Independent  Investment  Banker  as  having  an  actual or
     interpolated  maturity  comparable to the remaining term of the Notes to be
     redeemed that would be utilized, at the time of selection and in accordance
     with customary financial practice,  in pricing new issues of corporate debt
     securities of a comparable maturity to the remaining term of the Notes.

     "Comparable Treasury Price" means, with respect to any redemption date, (i)
     the average of the Reference Treasury Dealer Quotations for such redemption
     date, after excluding the highest and lowest such Reference Treasury Dealer
     Quotation  or (ii) if the  Trustee  obtains  fewer than four such  Treasury
     Dealer Quotations, the average of all such quotations.

     "Independent Investment Banker" means one of the Reference Treasury Dealers
     appointed by the Trustee after consultation with the Company.

     "Reference Treasury Dealer" means each of Merrill Lynch,  Pierce,  Fenner &
     Smith Incorporated,  Credit Suisse First Boston Corporation and UBS Warburg
     LLC or their  affiliates  which  are  primary  U.S.  Government  securities
     dealers,  and  their  respective  successors  and two  other  primary  U.S.
     Government securities dealers selected by the Trustee;  provided,  however,
     that if any of the  foregoing  or  their  affiliates  shall  cease  to be a
     primary  U.S.  Government  securities  dealer  in The  City of New  York (a
     "Primary  Treasury  Dealer"),  another  Primary  Treasury  Dealer  shall be
     substituted by the Company.

     "Reference Treasury Dealer Quotation" means, with respect to each Reference
     Treasury  Dealer and any  redemption  date for the Notes,  the average,  as
     determined by the Trustee,  of the bid and asked prices for the  Comparable
     Treasury  Issue  (expressed  in each case as a percentage  of its principal
     amount) quoted in writing to the Trustee by such Reference  Treasury Dealer
     at 3:30  p.m.  New York  time on the  third  Business  Day  preceding  such
     redemption date.

          The Company  shall not be required to (i) issue,  exchange or register
     the  transfer  of any Notes  during a period  beginning  at the  opening of
     business 15 days before the day of the mailing of a notice of redemption of
     less than all the outstanding  Notes and ending at the close of business on
     the day of such  mailing,  nor (ii) register the transfer of or exchange of
     any Notes called for redemption. This Global Note is exchangeable for Notes
     in definitive  registered form only under certain limited circumstances set
     forth in the Indenture.

          In the event of  redemption  of this Note in part only,  a new Note or
     Notes of this series, of like tenor, for the unredeemed portion hereof will
     be issued in the name of the Holder hereof upon the surrender of this Note.

     Redemption for Tax Reasons

     If,  as a result  of any  change  in,  or  amendment  to,  the laws (or any
regulations  or rulings  promulgated  thereunder)  of the United  States (or any
political subdivision or taxing authority thereof or therein), or any change in,
or  amendments   to,  an  official   position   regarding  the   application  or
interpretation of such laws,  regulations or rulings,  which change or amendment
is announced or becomes  effective on or after the date of the original issuance
of the Securities of this series,  the Company  becomes or, based upon a written
opinion of independent counsel selected by the Company, will become obligated to
pay  Additional  Amounts as described  below with respect to  Securities of this
series, the Company may, at its option, redeem, as a whole, but not in part, the
Securities  of this  series  on not less  than 30 nor more  than 60 days'  prior
notice,  at a redemption  price equal to 100% of their principal amount together
with interest accrued but unpaid thereon to the date fixed for redemption.

Payment of Additional Amounts

     The  Company  will,  subject to the  limitations  set forth  below,  pay as
additional interest on the Securities of this series, such additional amounts as
are  necessary  in order that the net payment by the Company or the paying agent
of the  principal of and interest on the  Securities  of this series to a Holder
who is a  Non-U.S.  Holder,  after  deduction  for any  present  or future  tax,
assessment  or other  governmental  charge of the United  States or a  political
subdivision or taxing authority thereof or therein,  imposed by withholding with
respect  to the  payment,  will not be less  than  the  amount  provided  in the
Securities  of this  series to be then due and payable  ("Additional  Amounts");
provided, however, that the foregoing obligation to pay Additional Amounts shall
not apply:

          (i) to any  tax,  assessment  or  other  governmental  charge  that is
     imposed  or  withheld  solely  by  reason of the  Holder,  or a  fiduciary,
     settlor, beneficiary,  member or shareholder of the Holder if the Holder is
     an estate, trust,  partnership or corporation,  or a person holding a power
     over  an  estate  or  trust  administered  by  a  fiduciary  holder,  being
     considered as:

               (A) being or having been  present or engaged in trade or business
          in the United  States or having had a permanent  establishment  in the
          United States;

               (B)  having a current  or  former  relationship  with the  United
          States, including a relationship as a citizen or resident thereof;

               (C) being or having been a foreign or domestic  personal  holding
          company,  a passive foreign investment company or a controlled foreign
          corporation  with respect to the United States or a  corporation  that
          has accumulated earnings to avoid United States federal income tax;

               (D)  being  or  having  been a  "10-percent  shareholder"  of the
          Company as defined in Section  871(h)(3) of the United States Internal
          Revenue Code of 1986, as amended, or any successor provision; or

               (E) being a bank  receiving  payments on an  extension  of credit
          made pursuant to a loan agreement  entered into in the ordinary course
          of its trade or business;

          (ii) to any  holder  that  is not the  sole  beneficial  owner  of the
     Securities of this series, or a portion thereof,  or that is a fiduciary or
     partnership,  but only to the extent  that a  beneficiary  or settlor  with
     respect to the fiduciary,  a beneficial  owner or member of the partnership
     would not have been entitled to the payment of an additional amount had the
     beneficiary,  settlor,  beneficial  owner or member  received  directly its
     beneficial or distributive share of the payment;

          (iii) to any tax,  assessment  or other  governmental  charge  that is
     imposed  or  withheld  by reason of the  failure of the holder or any other
     person  to  comply  with   certification,   identification  or  information
     reporting requirements concerning the nationality,  residence,  identity or
     connection with the United States, or otherwise with respect to the status,
     of the Holder or beneficial  owner of the Securities of this series (or any
     beneficiary, settlor, beneficial owner or member thereof), if compliance is
     required by statute, by regulation of the United States Treasury Department
     or by an  applicable  income  tax  treaty to which the  United  States is a
     party, or by any official  interpretation or ruling promulgated pursuant to
     any of the  foregoing,  as a  precondition  to  exemption  from  such  tax,
     assessment or other governmental charge;

          (iv) to any tax,  assessment  or  other  governmental  charge  that is
     imposed  otherwise  than by  withholding by the Company or the paying agent
     from the payment;

          (v) to any  tax,  assessment  or  other  governmental  charge  that is
     imposed or  withheld  solely by reason of a change in law,  regulation,  or
     administrative or judicial  interpretation that becomes effective more than
     30 days after the payment  becomes due or is duly provided  for,  whichever
     occurs later;

          (vi) to any estate, inheritance, gift, sales, excise, transfer, wealth
     or personal property tax or similar tax,  assessment or other  governmental
     charge;

          (vii) to any tax,  assessment or other governmental charge required to
     be  withheld  by any paying  agent  from any  payment  of  principal  of or
     interest on any  Securities  of this  series,  if such  payment can be made
     without such withholding by any other paying agent; or

          (viii) in the case of any combination of items (i), (ii), (iii), (iv),
     (v), (vi) or (vii).

     The  Securities of this series are subject in all cases to any tax,  fiscal
or  other  law  or  regulation  or  administrative  or  judicial  interpretation
applicable  thereto.  Except as specifically  provided by the provisions of this
Security,  the Company shall not be required to make any payment with respect to
any tax,  assessment or other governmental charge imposed by any government or a
political subdivision or taxing authority thereof or therein.

     In particular, the Company will not pay any Additional Amounts
on any Securities of this series:

          (i) where  withholding  or  deduction  is  imposed  on a payment to an
     individual  and is  required  to be made  pursuant  to any  European  Union
     Directive on the taxation of savings  implementing  the  conclusions of the
     ECOFIN Council meeting of November 26 and 27, 2000 or any law  implementing
     or complying with, or introduced in order to conform to, that Directive, or

          (ii)  presented for payment by or on behalf of a beneficial  owner who
     would have been able to avoid the  withholding  or deduction by  presenting
     the relevant Series A Note to another paying agent in a member state or the
     European Union.

          As discussed  above,  "U.S.  Holder" means a beneficial  holder of the
     Securities  of this  series that is (i) a citizen or resident of the United
     States,  (ii) a corporation or partnership created or organized in or under
     the laws of the United States or any political  subdivision thereof,  (iii)
     an estate the income of which is subject to United  States  federal  income
     taxation  regardless of its source,  or (iv) a trust that (a) is subject to
     the  supervision of a court within the United States and the control of one
     or more United States  persons as described in section  7701(a)(30)  of the
     Internal  Revenue Code of 1986, as amended,  or (b) has a valid election in
     effect under applicable U.S. Treasury regulations to be treated as a United
     States person.

          "Non-U.S.  Holder" means a holder of Securities of this series that is
     not a U.S. Holder.

     In case an Event of  Default,  as  defined  in the  Indenture,  shall  have
occurred and be  continuing,  the principal of all of the Notes may be declared,
and upon such declaration shall become, due and payable, in the manner, with the
effect and subject to the conditions provided in the Indenture.

     The Indenture contains  provisions for defeasance at any time of the entire
indebtedness of this Note upon compliance by the Company with certain conditions
set forth therein.

     The Indenture contains  provisions  permitting the Company and the Trustee,
with the  consent  of the  Holders  of not less  than a  majority  in  aggregate
principal  amount of the Securities of all series affected by such  supplemental
indenture or indentures at the time outstanding  voting as one class, as defined
in the Indenture,  to execute supplemental  indentures for the purpose of adding
any provisions to or changing in any manner or eliminating any of the provisions
of the Indenture or of any supplemental  indenture or of modifying in any manner
the rights of the Holders of the  Securities;  provided,  however,  that no such
supplemental  indenture shall (i) extend the fixed maturity of any Securities of
any series, or reduce the principal amount thereof, or reduce the rate or extend
the time of payment of interest thereon,  or reduce any premium payable upon the
redemption thereof, or reduce the amount of the principal of a Discount Security
that would be due and payable upon a declaration of acceleration of the maturity
thereof  pursuant  to the  Indenture,  without the consent of the holder of each
Security then outstanding and affected;  (ii) reduce the aforesaid percentage of
Securities,   the  holders  of  which  are  required  to  consent  to  any  such
supplemental indenture,  or reduce the percentage of Securities,  the holders of
which are  required  to waive any  default  and its  consequences,  without  the
consent of the holder of each Security then outstanding and affected thereby; or
(iii)  modify any  provision  of Section  6.01(c)  of the  Indenture  (except to
increase the  percentage of principal  amount of securities  required to rescind
and annul any  declaration  of amounts  due and payable  under the  Securities),
without the consent of the holder of each Security then outstanding and affected
thereby.  The Indenture  also contains  provisions  permitting  the Holders of a
majority in aggregate  principal  amount of the  Securities of any series at the
time outstanding affected thereby, on behalf of the Holders of the Securities of
such  series,  to  waive  any  past  default  in the  performance  of any of the
covenants contained in the Indenture,  or established  pursuant to the Indenture
with  respect  to such  series,  and its  consequences,  except a default in the
payment of the principal of or premium,  if any, or interest on any of the Notes
of such series. Any such consent or waiver by the registered Holder of this Note
(unless  revoked as provided in the  Indenture)  shall be conclusive and binding
upon such Holder and upon all future  Holders and owners of this Note and of any
Note issued in exchange  herefor or in place hereof  (whether by registration of
transfer  or  otherwise),  irrespective  of whether or not any  notation of such
consent or waiver is made upon this Note.

     No reference  herein to the  Indenture  and no provision of this Note or of
the  Indenture  shall alter or impair the  obligation  of the Company,  which is
absolute and  unconditional,  to pay the  principal of and premium,  if any, and
interest  on this  Note at the time and  place  and at the rate and in the money
herein prescribed.

     As provided in the Indenture and subject to certain limitations therein set
forth, this Note is transferable by the registered holder hereof on the Security
Register  of the  Company,  upon  surrender  of this  Note for  registration  of
transfer  at the  office or agency of the  Company as may be  designated  by the
Company  accompanied by a written  instrument or instruments of transfer in form
satisfactory  to the Company or the  Trustee  duly  executed  by the  registered
Holder hereof or his or her attorney duly  authorized in writing,  and thereupon
one or more new Notes of  authorized  denominations  and for the same  aggregate
principal  amount  and series  will be issued to the  designated  transferee  or
transferees.  No  service  charge  will be made for any such  transfer,  but the
Company  may  require  payment  of a sum  sufficient  to cover  any tax or other
governmental charge payable in relation thereto.

     Prior to due  presentment  for  registration  of transfer of this Note, the
Company,  the Trustee,  any paying agent and any Security Registrar may deem and
treat the registered  Holder hereof as the absolute owner hereof (whether or not
this Note shall be  overdue  and  notwithstanding  any  notice of  ownership  or
writing hereon made by anyone other than the Security Registrar) for the purpose
of receiving  payment of or on account of the principal  hereof and premium,  if
any, and interest due hereon and for all other purposes, and neither the Company
nor the  Trustee  nor any  paying  agent  nor any  Security  Registrar  shall be
affected by any notice to the contrary.

     No  recourse  shall  be had  for the  payment  of the  principal  of or the
interest on this Note,  or for any claim based  hereon,  or otherwise in respect
hereof,  or based on or in respect of the Indenture,  against any  incorporator,
stockholder,  officer or  director,  past,  present or future,  as such,  of the
Company or of any predecessor or successor corporation, whether by virtue of any
constitution, statute or rule of law, or by the enforcement of any assessment or
penalty or otherwise,  all such liability being, by the acceptance hereof and as
part  of the  consideration  for  the  issuance  hereof,  expressly  waived  and
released.

     The Notes of this  series are  issuable  only in  registered  form  without
coupons  in  denominations  of $1,000  and any  integral  multiple  thereof.  As
provided  in the  Indenture  and subject to certain  limitations,  Notes of this
series are exchangeable  for a like aggregate  principal amount of Notes of this
series of a  different  authorized  denomination,  as  requested  by the  Holder
surrendering the same.

     All terms used in this Note which are defined in the  Indenture  shall have
the meanings assigned to them in the Indenture.

     This  Note  shall  not be  entitled  to any  benefit  under  the  Indenture
hereinafter referred to, be valid or become obligatory for any purpose until the
Certificate of  Authentication  hereon shall have been signed by or on behalf of
the Trustee.

     IN WITNESS WHEREOF, the Company has caused this Note to be executed.


                          AMERICAN ELECTRIC POWER COMPANY, INC.


                         By:___________________________
                            Assistant Treasurer



                          CERTIFICATE OF AUTHENTICATION

     This  is  one of the  Notes  of the  series  of  Securities  designated  in
accordance with, and referred to in, the within-mentioned Indenture.

Dated:  May __, 2001

THE BANK OF NEW YORK, as Trustee


By:___________________________
   Authorized Signatory

     FOR  VALUE  RECEIVED,   the  undersigned  hereby  sell(s),   assign(s)  and
transfer(s) unto

(PLEASE INSERT SOCIAL SECURITY OR OTHER IDENTIFYING NUMBER OF ASSIGNEE)

- ---------------------------------------

- ----------------------------------------------------------------

- ----------------------------------------------------------------
(PLEASE PRINT OR TYPE NAME AND ADDRESS, INCLUDING ZIP CODE, OF
- ----------------------------------------------------------------
ASSIGNEE) the within Note and all rights thereunder, hereby
- ----------------------------------------------------------------
irrevocably constituting and appointing such person attorney to
- ----------------------------------------------------------------
transfer such Note on the books of the Issuer, with full
- ----------------------------------------------------------------
power of substitution in the premises.



Dated:________________________              _________________________



NOTICE:  The  signature  to this  assignment  must  correspond  with the name as
     written  upon the face of the  within  Note in  every  particular,  without
     alteration or enlargement or any change  whatever and NOTICE:  Signature(s)
     must be  guaranteed  by a  financial  institution  that is a member  of the
     Securities Transfer Agents Medallion Program ("STAMP"),  the Stock Exchange
     Medallion Program ("SEMP") or the New York Stock Exchange,  Inc.  Medallion
     Signature Program ("MSP").




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-4
<SEQUENCE>6
<FILENAME>x4c.txt
<DESCRIPTION>(C) SECOND SUPPLEMENTAL INDENTURE
<TEXT>

<PAGE>

                                                                    Exhibit 4(c)




================================================================================






                      AMERICAN ELECTRIC POWER COMPANY, INC.

                                       AND

                              THE BANK OF NEW YORK,

                                   as Trustee

                          Second Supplemental Indenture

                             Dated as of May 1, 2001

                                       To

                                    Indenture

                             Dated as of May 1, 2001

                     5.50% Putable Callable Notes, Series B

                          Putable Callable May 15, 2003






===============================================================================

     SECOND  SUPPLEMENTAL  INDENTURE,  dated  as of May 1,  2001  (this  "Second
Supplemental  Indenture"),  between  AMERICAN  ELECTRIC POWER  COMPANY,  INC., a
corporation  duly organized and existing under the laws of the State of New York
(hereinafter sometimes referred to as the "Company"),  and THE BANK OF NEW YORK,
a New York banking corporation, as trustee (hereinafter sometimes referred to as
the "Trustee") under the Indenture,  dated as of May 1, 2001 between the Company
and  the  Trustee  (the  "Original  Indenture").   The  Original  Indenture,  as
previously  supplemented and as to be supplemented from time to time,  including
by  this  Second  Supplemental  Indenture,  is  hereafter  referred  to  as  the
"Indenture."

                                   WITNESSETH:

     WHEREAS,  the Company has executed and delivered the Original  Indenture to
the Trustee to provide for the issuance of unsecured  promissory  notes or other
evidences of indebtedness (the "Securities") in an unlimited aggregate principal
amount,  to be issued from time to time in one or more series as provided in the
Original Indenture;

     WHEREAS,  pursuant  to the terms of the  Original  Indenture,  the  Company
desires to provide for the establishment of a new series of its Securities (said
series  being  hereinafter  referred to as the  "Series B Notes"),  the form and
substance  of such  Series B Notes  and the  terms,  provisions  and  conditions
thereof to be set forth as provided in the  Original  Indenture  and this Second
Supplemental Indenture; and

     WHEREAS,  the Company desires and has requested the Trustee to join with it
in the execution  and delivery of this Second  Supplemental  Indenture,  and all
requirements  necessary  to make  this  Second  Supplemental  Indenture  a valid
instrument,  in accordance with its terms, and to make the Series B Notes,  when
executed by the Company and  authenticated  and  delivered by the  Trustee,  the
valid  obligations of the Company,  have been  performed and fulfilled,  and the
execution and delivery hereof have been in all respects duly authorized;

     NOW  THEREFORE,  in  consideration  of the purchase and  acceptance  of the
Series B Notes by the holders thereof,  and for the purpose of setting forth, as
provided in the Original Indenture, the form and substance of the Series B Notes
and the terms,  provisions and  conditions  thereof,  the Company  covenants and
agrees with the Trustee as follows:

                                  ARTICLE One

               GENERAL TERMS AND CONDITIONS OF THE SERIES B NOTES

     Section  1.01.  There  shall  be and  is  hereby  authorized  a  series  of
Securities under the Original  Indenture  designated the "5.50% Putable Callable
Notes,  Series B,  Putable  Callable  May 15,  2003",  in the initial  aggregate
principal  amount of  $250,000,000,  which  amount  shall be as set forth in the
Company Order for the authentication and delivery of the Series B Notes pursuant
to Section 2.04 of the Original Indenture.

     Section 1.02. The Series B Notes will mature and the principal thereof will
be due and payable,  together with all accrued and unpaid interest  thereon,  on
May 15, 2013;  provided,  however,  that this  scheduled  maturity date shall be
extended if there is a Floating  Rate  Period,  in which case the Series B Notes
will mature on the tenth anniversary of the Floating Period Termination Date, in
which case the Series B Notes will mature not later than May 15, 2014.

     Section 1.03. (a) The Series B Notes shall bear interest as provided in the
form of Security attached as Appendix A hereto.

     (b) The amount of  interest  payable on the Series B Notes will be computed
on the basis of a 360-day year  consisting of twelve 30-day months,  except that
the interest  accruing during the Floating Rate Period, if any, will be computed
on the basis of the actual number of days in such period over a 360-day year.

     (c)  Subject  to any terms of the  Series B Notes  issued as Global  Notes,
payment of the principal of (and  premium,  if any) and interest on the Series B
Notes will be made at the office or agency of the  Company  maintained  for that
purpose in the  Borough of  Manhattan,  the City and State of New York,  in such
coin or  currency  of the United  States of America as at the time of payment is
legal  tender for the  payment of public and  private  debts and in  immediately
available funds; provided, however, that at the option of the Company payment of
interest  may be made by wire  transfer  of  immediately  available  funds to an
account of the Person entitled  thereto as such account shall be provided to the
Security  Registrar  at least 10 days prior to the  relevant  payment date or by
check in New York  Clearinghouse  Funds  mailed  to the  address  of the  person
entitled  thereto  as  such  address  shall  appear  in the  Security  Register;
provided,  further,  for so  long  as the  Series  B  Notes  are  listed  on the
Luxembourg Stock Exchange,  payment may be made in Luxembourg,  initially at the
corporate trust office of Kredietbank S.A., Luxembourgoise, as Luxembourg paying
agent.

     Section  1.04. In certain  circumstances  described in the form of Security
attached as Appendix A hereto,  the Trustee will be required,  for and on behalf
of the Holders of the Series B Notes, to exercise the option to put the Series B
Notes  to the  Company.  The Put  Option  referred  to in the  form of  Security
attached as Appendix A hereto  shall be exercised by the Trustee by the delivery
to the Company by hand or  facsimile  transmission  of the form of  notification
attached hereto as Appendix D.

     Section  1.05.  The Series B Notes shall be  unsecured  and  unsubordinated
obligations  of the  Company  ranking  pari passu with all other  unsecured  and
unsubordinated indebtedness of the Company.

     Section  1.06.  The Series B Notes shall not be subject to any sinking fund
provision.

     Section  1.07.  The Company  shall be subject to the  provisions  described
under  "Restrictive  Covenants"  in the form of Security  attached as Appendix A
hereto.

                                  ARTICLE Two

          REDEMPTION OF THE SERIES B NOTES AT THE OPTION OF THE COMPANY

     Section  2.01.  (a) The Company shall have the right to redeem the Series B
Notes as set forth under "Redemption - Post-Coupon Reset Optional Redemption" in
the form of Security attached as Appendix A hereto.

     (b) The  Company  shall  have the right to redeem the Series B Notes as set
forth under  "Redemption  - Redemption  For Tax Reasons" in the form of Security
attached as Appendix A hereto.

     (c) Any redemption pursuant to this Section will be made upon not less than
30 nor more  than 60 days'  notice.  If the  Series B Notes  are only  partially
redeemed  pursuant to paragraph (a) of this Section,  the Notes will be redeemed
by lot or in such other manner as the Trustee shall deem fair and appropriate in
its discretion;  provided, that if at the time of redemption, the Series B Notes
are  represented  by a Global Note, the  Depository  shall  determine by lot the
principal  amount of such Series B Notes held by each Series B Noteholder  to be
redeemed.

                                 ARTICLE Three

                              FORM OF SERIES B NOTE

     Section  3.01.  (a) The  Series B Notes and the  Trustee's  Certificate  of
Authentication  to be endorsed  thereon are to be  substantially  in the form of
Appendix A hereto.

     (b) The terms and provisions of the Series B Notes as set forth in Appendix
A hereto are  hereby  incorporated  in and  expressly  made part of this  Second
Supplemental Indenture.

                                  ARTICLE Four

                            MISCELLANEOUS PROVISIONS

     Section  4.01.  Except  as  otherwise  expressly  provided  in this  Second
Supplemental  Indenture or in the form of Security attached as Appendix A hereto
or otherwise clearly required by the context hereof or thereof,  all capitalized
terms used and not defined  herein or in said form of Security  that are defined
in the  Original  Indenture  shall  have the  meanings  assigned  to them in the
Original Indenture.

     Section 4.02. The Trustee will acknowledge the assignment by the Company of
the Call Option to UBS AG, London Branch by providing a letter  substantially in
the form of Appendix B hereto.

     Section  4.03.  UBS  Warburg  LLC  shall  acknowledge  its  appointment  as
Calculation Agent by providing a letter  substantially in the form of Appendix C
hereto.

     Section 4.04. The Bank of New York is hereby appointed the Paying Agent and
Security Registrar in the United States for the Series B Notes. In addition,  as
long as the  Series B Notes are listed on the  Luxembourg  Stock  Exchange,  the
Company  will  maintain a paying  agent and transfer  agent in  Luxembourg.  The
Company's  initial  paying  agent  and  transfer  agent in  Luxembourg  shall be
Kredietbank  S.A.,  Luxembourgoise,  currently  located at 43  Boulevard  Royal,
L-2955 Luxembourg.

     Section  4.05.  The  Company  and the  Trustee  shall  not  enter  into any
supplemental  indenture  pursuant to the Original  Indenture  that would modify,
amend or eliminate any provision of the Series B Notes that materially adversely
affects the interest of the  Callholder  or the  Calculation  Agent  without the
prior written  consent of the Callholder or the  Calculation  Agent, as the case
may be. The Trustee,  subject to the  provisions of Section 7.01 of the Original
Indenture, shall be entitled to receive, and shall be fully protected in relying
upon,  an  Opinion  of  Counsel as  conclusive  evidence  that any  supplemental
indenture  executed pursuant to this Section 4.05 is authorized or permitted by,
and  conforms  to, the terms of this  Section 4.05 and that it is proper for the
Trustee  under the  provisions  of this  Section  4.05 to join in the  execution
thereof.

     Section 4.06. The recitals contained in this Second Supplemental  Indenture
shall be taken as the  statements  of the  Company  and the  Trustee  assumes no
responsibility for their correctness. The Trustee makes no representations as to
the validity or sufficiency of this Second Supplemental Indenture.

     Section  4.07.  The  Original  Indenture,  as  supplemented  by this Second
Supplemental  Indenture,  is in all respects  ratified and  confirmed,  and this
Second Supplemental  Indenture shall be deemed part of the Original Indenture in
the manner and to the extent herein and therein provided.

     Section 4.08. If any provision  hereof limits,  qualifies or conflicts with
another  provision  hereof  which is  required  to be  included  in this  Second
Supplemental Indenture by any of the provisions of the Trust Indenture Act, such
required provision shall control.

     Section 4.09. In case any provision in this Second  Supplemental  Indenture
or in the  Series B Notes  shall  be  invalid,  illegal  or  unenforceable,  the
validity,  legality and  enforceability  of the remaining  provisions hereof and
thereof shall not in any way be affected or impaired thereby.

     Section 4.10. This Second Supplemental  Indenture shall be governed by, and
construed in accordance with, the laws of the State of New York,  without regard
to principles of conflicts of law except  Section 5-1401 of the New York General
Obligations Law.

     Section  4.11.  This Second  Supplemental  Indenture may be executed in any
number  of  counterparts,  each of which so  executed  shall be  deemed to be an
original,  but all such counterparts shall together  constitute one and the same
instrument.

     IN WITNESS WHEREOF, the parties hereto have caused this Second Supplemental
Indenture to be duly executed as of the day and year first above written.

                     AMERICAN ELECTRIC POWER COMPANY, INC.


                     By:  /s/ Geoffrey S. Chatas
                              Name: Geoffrey S. Chatas
                              Title: Assistant Treasurer


                     THE BANK OF NEW YORK, as Trustee, Paying Agent and
                     Securities Registrar


                     By:  /s/ Paul Schmalzel
                              Name:Paul Schmalzel
                              Title: Vice President





                                                                   APPENDIX A

                               (FORM OF SECURITY)

     Unless this Certificate is presented by an authorized representative of The
Depository  Trust Company,  a New York corporation  ("DTC"),  to the Company (as
defined herein) or its agent for registration of transfer,  exchange or payment,
and any  certificate  issued is  registered in the name of Cede & Co. or in such
other  name as is  requested  by an  authorized  representative  of DTC (and any
payment  is made to Cede & Co. or to such  other  entity as is  requested  by an
authorized representative of DTC), ANY TRANSFER, PLEDGE, OR OTHER USE HEREOF FOR
VALUE OR  OTHERWISE BY OR TO ANY PERSON IS WRONGFUL  inasmuch as the  registered
owner hereof,  Cede & Co., has an interest herein.  Except as otherwise provided
in Section 2.11 of the Indenture, this Security may be transferred, in whole but
not in part, only to another nominee of DTC or to a successor Depository or to a
nominee of such successor Depository.

No. P-1

                      AMERICAN ELECTRIC POWER COMPANY, INC.

                     5.50% Putable Callable Note, Series B,
                          Putable Callable May 15, 2003

CUSIP: 025537AB7                                                  $250,000,000

Scheduled Maturity Date: May 15, 2013
Initial Interest Rate: 5.50%
Initial Coupon Reset Date: May 15, 2003
Initial Interest Payment Dates: May 15 and November 15

     American  Electric  Power  Company,  Inc, a corporation  duly organized and
existing  under the laws of the  State of New York  (herein  referred  to as the
"Company,"  which  term  includes  any  successor  Person  under  the  Indenture
hereinafter  referred to), for value received,  hereby promises to pay to CEDE &
CO., or registered assigns, the principal sum of [ ] MILLION DOLLARS ($ ) on the
Scheduled Maturity Date,  provided,  however, in the event the Company exercises
its Floating  Period Option,  the maturity date of the Securities of this series
will be extended to the tenth  anniversary  of the Floating  Period  Termination
Date, in which case the Securities of this series will mature not later than May
15,  2014 (the  "Maturity  Date"),  and to pay  interest on said  principal  sum
semi-annually  on each Initial  Interest  Payment Date  commencing  November 15,
2001,  at the  Initial  Interest  Rate per annum,  during  the  period  from and
including the date of issuance to but  excluding the Initial  Coupon Reset Date.
After the  Initial  Coupon  Reset  Date,  interest  will be  payable at the rate
determined by the Calculation  Agent in accordance with the procedures set forth
herein, under the caption "Tender of the Securities of this Series; Remarketing"
until the principal  hereof is paid or made available for payment.  The interest
on the Securities of this series accruing from the Initial Coupon Reset Date (if
such date is not the  Floating  Rate  Coupon  Reset  Date) or from the  Floating
Period  Termination  Date (if the Initial Coupon Reset Date is the Floating Rate
Coupon Reset Date) will be payable semi-annually on each day that is a six-month
anniversary of such date (such days, the "Floating Rate Interest Payment Dates",
and the Initial Interest Payment Dates to and including the Initial Coupon Reset
Date, are sometimes  referred to as the "Interest Payment Dates").  The interest
accruing  during  any  Floating  Rate Reset  Period  will be payable on the next
following  Reference  Rate Reset Date if such date is a Business Day or, if not,
then on the next following Business Day. Interest payments will be in the amount
of  interest  accrued  from  and  including  the  date of  issuance  or the next
preceding  date to which  interest  has been  paid or duly  provided  for to but
excluding the next Interest  Payment Date,  redemption date or maturity date, as
the case may be. In the event that any Interest  Payment  Date or other  payment
date is not a Business  Day,  then payment of interest or  principal  payable on
such date will be made on the next succeeding day which is a Business Day and no
interest  shall accrue in respect of the amounts which payment is so delayed for
the period from and after such  Interest  Payment  Date or other  payment  date,
except  that,  in the case of an Interest  Payment  Date or other  payment  date
occurring  during the Floating  Rate  Period,  interest on the  principal  which
payment has been so delayed or with  respect to which the  interest  payment has
been so delayed will continue to accrue until the next succeeding  Business Day.
The  interest so  payable,  and  punctually  paid or duly  provided  for, on any
Interest Payment Date will, as provided in the Indenture,  be paid to the Person
in  whose  name  this  Security  (or  one or  more  Predecessor  Securities)  is
registered  at the  close  of  business  on the  regular  record  date  for such
interest, which, as long as the Securities of this series are issued as a Global
Security,  shall be the Business Day  immediately  preceding  the  corresponding
Interest  Payment Date,  provided that interest  payable on the Maturity Date or
any redemption date shall be paid to the person to whom principal is paid.

     Any  such  interest  not so  punctually  paid or  duly  provided  for  will
forthwith  cease to be payable to the Holder on such regular record date and may
either  be paid to the  Person  in  whose  name  this  Security  (or one or more
Predecessor  Securities)  is  registered  at the close of  business on a special
record  date  for the  payment  of such  Defaulted  Interest  to be fixed by the
Trustee,  notice  whereof shall be given to Holders of Securities of this series
not less than 10 days prior to such special  record date,  or may be paid at any
time in any other lawful manner not  inconsistent  with the  requirements of any
securities  exchange on which the  Securities of this series may be listed,  and
upon such notice as may be required by such exchange, all as more fully provided
in the Indenture.

     Reference  is hereby made to the further  provisions  of this  Security set
forth  herein,  which  further  provisions  shall for all purposes have the same
effect as if set forth at this place.

     Unless the  certificate of  authentication  hereon has been executed by the
Trustee  referred  to herein by manual  signature,  this  Security  shall not be
entitled to any benefit under the  Indenture or be valid or  obligatory  for any
purpose.

     IN WITNESS  WHEREOF,  the  Company has caused  this  instrument  to be duly
executed.

                              AMERICAN ELECTRIC POWER
                                   COMPANY, INC.


                              By:
                                   ---------------------------
                                   Name: Geoffrey S. Chatas
                                   Title: Assistant Treasurer



                          CERTIFICATE OF AUTHENTICATION

     This is one of the Securities of the series  designated in accordance with,
and referred to in, the within-mentioned Indenture.

Dated: May 10, 2001             THE BANK OF NEW YORK, as Trustee



                                By:
                                   -------------------------------
                                   Authorized Signatory


                      AMERICAN ELECTRIC POWER COMPANY, INC.

                     5.50% Putable Callable Notes, Series B
                          Putable Callable May 15, 2003

     This  Security  is one of a duly  authorized  issue  of  securities  of the
Company (the "Securities"),  issued and to be issued in one or more series under
an Indenture, dated as of May 1, 2001 (the "Original Indenture"),  as previously
supplemented and as to be supplemented by a second supplemental indenture, dated
as of  May 1,  2001  (the  "Second  Supplemental  Indenture"  and  the  Original
Indenture,  as so supplemented,  the  "Indenture"),  between the Company and The
Bank of New York, a New York  banking  corporation,  as trustee (the  "Trustee,"
which term includes any successor trustee under the Indenture), and reference is
hereby  made  to  the  Indenture  for a  statement  of  the  respective  rights,
limitations  of rights,  duties and  immunities  thereunder of the Company,  the
Trustee and the Holders and of the terms upon which the Securities  are, and are
to  be,  authenticated  and  delivered.  This  Security  is  a  Global  Security
representing the aggregate  principal amount of the Company's Series B Notes set
forth herein.  The  Securities of the series of which this Global  Security is a
part shall be issued in the initial aggregate principal amount of $250,000,000.

     Any capitalized  term used herein and not otherwise  defined shall have the
meaning ascribed to such term under the caption "Definitions"
below.

     The Company has  assigned to UBS AG,  London  Branch,  as  Callholder,  the
option to  purchase  the  Securities  of this  series  on May 15,  2003 from the
Holders, in whole but not in part (the "Call Option"), in exchange for an amount
equal to the Call  Price (as  defined  below).  The  Callholder  may at any time
assign its rights and obligations under the Call Option;  provided that (i) such
rights and  obligations  are  assigned  in whole and not in part,  and (ii) such
assigning  Callholder  provides the Company (unless the Company is a participant
in the  assignment)  and the  Trustee  with  written  notice of such  assignment
contemporaneously  with  such  assignment.   Upon  receipt  of  such  notice  of
assignment,  the Trustee  shall treat the  assignee  as the  Callholder  for all
purposes  hereunder.  A  Callholder  may assign its rights under the Call Option
without notice to, or consent of, the Holders of the Securities of this series.

     If the Callholder elects to remarket the Securities of this series,  except
in the limited circumstances described herein, (i) the Securities of this series
will be subject to mandatory tender to the Callholder,  on the terms and subject
to the conditions described herein, and (ii) on and after any Coupon Reset Date,
the  Securities  of this  series  will  bear  interest  at the  applicable  rate
determined by the Calculation  Agent in accordance with the procedures set forth
herein.

Tender of the Securities of this Series; Remarketing

          Call Option

          On a  Business  Day not  earlier  than 20  Business  Days prior to the
Initial  Coupon Reset Date, and not later than 4:00 p.m., New York City time, on
the 15th  Business Day prior to the Initial  Coupon Reset Date,  the  Callholder
will  notify the  Company  and the Trustee in writing as to whether it elects to
purchase the  Securities of this series for  remarketing.  If the  Callholder so
elects,  the Securities of this series will be subject to mandatory tender,  and
will be deemed tendered, to the Callholder for purchase and remarketing, and the
Callholder  will be obligated to purchase  and remarket the  Securities  of this
series on the  Initial  Coupon  Reset Date and,  if the  Company  exercises  its
Floating Period Option,  on the Floating Period  Termination Date, in accordance
with the terms and subject to the conditions described herein; provided, however
that if the Initial Coupon Reset Date or Floating Period Termination Date is not
a Business  Day,  the  foregoing  actions  will be taken on the next  succeeding
Business Day.

          On the Fixed Rate Coupon  Reset Date,  the  Securities  of this series
will be  remarketed by the  Callholder at a fixed rate of interest  equal to the
Interest Rate to Maturity.  If the Callholder  elects to purchase the Securities
of this series for remarketing and if the Company  exercises its Floating Period
Option,  the  maturity of the  Securities  of this series will be  automatically
extended to the tenth  anniversary of the Floating Period  Termination  Date. If
the Company so elects,  the  Securities of this series will bear interest at the
Floating  Period Interest Rate until the Floating  Period  Termination  Date, at
which time the  Securities  of this series will be remarketed at a fixed rate of
interest equal to the Interest Rate to Maturity,  unless the Company is required
to redeem the Securities of this series.

          The call price of the tendered Securities of this series will be equal
to 100% of their aggregate principal amount on the Initial Coupon Reset Date, or
the Dollar Price on the Floating Period Termination Date (the "Call Price").  In
the event of  exercise of the Call  Option,  then (i) not later than 12:00 noon,
New York City time,  on the Initial  Coupon  Reset Date or the  Floating  Period
Termination Date, as the case may be, the Callholder will deliver the applicable
Call Price in immediately available funds to the Trustee for payment of the Call
Price on that Coupon Reset Date and (ii) the Holders of the  Securities  of this
series  will be  required  to  deliver  the  Securities  of this  series  to the
Callholder  against  payment  therefor  on that  Coupon  Reset Date  through the
facilities  of DTC;  provided,  however,  that if any Coupon Reset Date is not a
Business Day the actions required by the foregoing clauses shall be taken on the
next succeeding Business Day.

          If the Callholder  elects to exercise the Call Option,  the obligation
of the Callholder to pay the Call Price and the corresponding  obligation of the
Holders to deliver the Securities of this series to the Callholder is subject to
the automatic termination events described below.

          Automatic Termination

          The Call Option will  automatically and immediately  terminate without
any  further  action by the  Callholder,  the  Company or the  Trustee,  and the
Trustee will exercise on the applicable Coupon Reset Date the Put Option for and
on behalf of the Holders as set forth herein,  upon the occurrence of any one or
more of the following events:

                    (i) at any time,  an Event of  Default  with  respect to the
          Securities of this series under Section 6.01(a)(1), (2), (4) or (5) of
          the Original Indenture;

                    (ii) if the Call  Notice has been timely  given,  then after
          the fourth  Business Day prior to a Coupon Reset Date until 12:00 p.m.
          New York City time on such Coupon  Reset Date (or if such Coupon Reset
          Date  is not a  Business  Day,  then  until  such  time  on  the  next
          succeeding  Business  Day),  a  Market  Disruption  Event  shall  have
          occurred  and  the  effect  of  such  event  is  such  as to  make  it
          impracticable,  in the reasonable judgment of the Callholder set forth
          in a written notice given to the Company and the Trustee,  to remarket
          the  Securities  of this series at a fixed rate or floating rate or to
          enforce contracts for the sale of the Securities of this series;

                    (iii) if the Call Notice has been timely given, no Reference
          Corporate Dealer or Reference Money Market Dealer, as the case may be,
          shall have  provided a timely Fixed Rate Bid or Floating  Rate Bid, as
          the case may be,  for the  Securities  of this  series  in the  manner
          described  under  the  "Determination  of  Applicable  Interest  Rate"
          section herein;

                    (iv) at any time, a legal defeasance or covenant  defeasance
          with respect to the Securities of this series shall have occurred; or

                    (v) at any time,  a  redemption  of the  Securities  of this
          series  pursuant  to  Section  2.01(b)  of  the  Second   Supplemental
          Indenture.

          Optional Termination

          The Call Option will  immediately  terminate  upon the election of the
Callholder  set forth in a written  notice  given to the Company and the Trustee
following the occurrence of any one or more of the following events at any time:

                    (i) an Event of Default  with respect to the  Securities  of
          this series under Section 6.01(a)(3) of the Original Indenture;

                    (ii) any or all of the  Securities of this series shall have
          been purchased by the Company prior to the Initial Coupon Reset Date;

                    (iii) (A) an event of  default  with  respect  to any senior
          indebtedness of the Company (having a principal  amount of $50,000,000
          or more)  other than the  Securities  of this series (as such event of
          default is defined in any note, indenture,  credit agreement, or other
          similar  document  relating to such senior  indebtedness)  which shall
          have  resulted in such senior  indebtedness  becoming  due and payable
          under  such  document  before  it would  otherwise  have  been due and
          payable,  or (B) a  default  in  making  any  payment  on the due date
          thereof under any one or more of such notes, agreements,  documents or
          instruments  relating to senior  indebtedness of the Company (having a
          principal  amount of $50,000,000 or more) other than the Securities of
          this series (after giving effect to any applicable notice  requirement
          or grace period);

                    (iv) at any  time on or prior to the  Initial  Coupon  Reset
          Date (or if the Initial  Coupon Reset Date is not a Business Day, then
          at any  time on or prior to the next  succeeding  Business  Day),  the
          Company or any unsecured and unsubordinated  debt issued or guaranteed
          by the Company is either (i) rated less than Baa3 by Moody's Investors
          Services,  Inc.  ("Moody's") and less than BBB- by Standard and Poor's
          Ratings  Services,  a  division  of The  McGraw-Hill  Companies,  Inc.
          ("S&P") (ii) rated less than Baa3 by Moody's or less than BBB- by S&P
          if rated by only one of such  rating  agencies;  or (iii) not rated by
          either Moody's or S&P

                    (v) due to the adoption of, or any change in, any applicable
          law after the date of the issuance of the  Securities  of this series,
          or due to the promulgation of, or any change in, the interpretation by
          any  court,   tribunal  or   regulatory   authority   with   competent
          jurisdiction  of any  applicable  law  after  such  date,  it  becomes
          unlawful for the Company or the  Callholder to perform any absolute or
          contingent  obligation  to make a payment or  delivery or to receive a
          payment or delivery in respect of a swap  agreement (as defined in the
          United States Bankruptcy Code);

                    (vi) the  Securities  of this series are not  maintained  in
          book-entry form with DTC or any successor thereto; or

                    (vii) without the prior written  consent of the  Callholder,
          the  Indenture  shall have been  amended in any manner,  or  otherwise
          contain any  provision  not  contained  therein as of the date hereof,
          that in  either  case in the  reasonable  judgment  of the  Callholder
          materially  changes the nature of the Securities of this series or the
          remarketing procedures relating thereto.

          The  Company  will  promptly  notify  the  Trustee  in  writing of any
termination of the Call Option.

          No Holder shall have any rights or claims  against the Callholder as a
result of the  Callholder  purchasing or not  purchasing  the Securities of this
series.

          If  the  Callholder  elects  to  exercise  the  Call  Option,  on  the
applicable  Coupon  Reset Date,  or if such Coupon  Reset Date is not a Business
Day, on the next succeeding Business Day, the Callholder will sell the aggregate
principal  amount of the  Securities  of this series at the Dollar  Price to the
Reference Corporate Dealer or to the Reference Money Market Dealer, whichever is
applicable,  providing the lowest Fixed or Floating Rate Bid, in the case of the
Initial  Coupon  Reset  Date,  or the lowest  Fixed Rate Bid, in the case of the
Floating Period  Termination  Date. If the lowest applicable Bid is submitted by
two or more of the applicable  Reference  Dealers,  the Callholder will sell the
Securities of this series to one or more of such Reference  Dealers,  as it will
determine in its sole discretion.

          If the  Call  Option  has not  been  exercised,  or in the  event  the
Callholder  is not required or fails to deliver the Call Price to the Trustee by
12:00 noon,  New York City time on the relevant  Coupon  Reset Date,  or if such
Coupon Reset Date is not a Business Day on the next succeeding Business Day, the
Company will be required to redeem all of the  Securities  of this series on the
applicable  Coupon  Reset  Date at a price  equal  to  100% of  their  aggregate
principal amount, plus accrued and unpaid interest, if any, if such Coupon Reset
Date is the Initial Coupon Reset Date, or at the Dollar Price,  plus accrued and
unpaid  interest,  if any,  if such  Coupon  Reset Date is the  Floating  Period
Termination  Date in accordance  with the procedures set forth under the section
"Put Option" herein.

          Put Option

          If the  Call  Option  has not  been  exercised,  or in the  event  the
Callholder  is not required or fails to deliver the Call Price to the Trustee by
12:00 noon,  New York City time,  on the relevant  Coupon Reset Date, or if such
Coupon  Reset  Date is not a  Business  Day at such time on the next  succeeding
Business  Day,  the Trustee will be required for and on behalf of the Holders of
the  Securities  of this series to exercise the option to put the  Securities of
this series to the Company  pursuant to the terms  hereof ("Put  Option").  Upon
exercise  of the Put Option,  the Company  will be required to redeem all of the
Securities  of this series on the  applicable  Coupon Reset Date at a redemption
price equal to 100% of the aggregate  principal amount of the Securities of this
series,  if such Coupon Reset Date is the Initial  Coupon Reset Date,  or at the
Dollar Price, if such Coupon Reset Date is the Floating Period  Termination Date
(in each case,  the "Put  Redemption  Price").  The Put Option will be exercised
automatically  by the  Trustee,  for and on behalf of the  Holders,  if the Call
Option has not been exercised, or in the event the Callholder is not required or
fails to deliver  the Call Price to the  Trustee as  aforesaid.  If the  Trustee
exercises the Put Option,  the Company will deliver the Put Redemption  Price to
the Trustee, together with the accrued and unpaid interest due on the applicable
Coupon  Reset  Date,  by no later  than 2:00 p.m.,  New York City time,  on such
Coupon  Reset Date,  or if such Coupon  Reset Date is not a Business Day at such
time on the next  succeeding  Business Day, and the Holders of the Securities of
this series will be  required  to deliver the  Securities  of this series to the
Company  against  payment  therefor  on  such  Coupon  Reset  Date  through  the
facilities  of DTC. No Holder of any  Security  of this  series or any  interest
therein has the right to consent or object to the Trustee's duty to exercise the
Put Option.  Notwithstanding anything herein to the contrary, the failure of the
Trustee to  exercise  the Put Option  shall not  affect  the  obligation  of the
Company,  which is absolute and unconditional,  to redeem the Securities of this
series on the  applicable  Coupon  Reset  Date if the Call  Option  has not been
exercised,  or in the event the  Callholder  is not required or fails to deliver
the Call Price to the  Trustee as  aforesaid,  and no Holder of any  Security of
this series shall have any claim against the Trustee for its failure to exercise
the Put Option.

          Determination of Applicable Interest Rate

          From and after the issuance date to but  excluding the Initial  Coupon
Reset Date and from and after the Fixed Rate Coupon Reset Date to but  excluding
the  Maturity  Date,  interest  shall  accrue on the basis of a 360-day  year of
twelve 30-day months.

          If the  Callholder  elects to purchase the  Securities of this series,
then by 3:30 p.m.,  New York City time,  on the third  Business Day  immediately
preceding the applicable Coupon Reset Date, the Calculation Agent will determine
either (a) the  Floating  Rate Spread,  in the case of the Initial  Coupon Reset
Date where the Company has elected to exercise its Floating  Period  Option,  or
(b) the Interest  Rate to Maturity,  to the nearest one hundredth of one percent
per annum,  unless the  Company is  required  to redeem the  Securities  of this
series.  Each Floating  Period Interest Rate will equal the sum of the Reference
Rate and the Floating Rate Spread,  and the Interest Rate to Maturity will equal
the sum of the Base  Rate and the  Applicable  Spread.  Both the  Floating  Rate
Spread  and the  Applicable  Spread  will be  based on the  Dollar  Price of the
Securities of this series.  The Floating Period Interest Rate, the Interest Rate
to Maturity and the Dollar Price for the  Securities of this series as announced
by the Calculation Agent,  absent manifest error, will be binding and conclusive
upon the beneficial owners of the Securities of this series, the Company and the
Trustee.

          Following the Callholder's election to purchase the Securities of this
series in  connection  with the  Initial  Coupon  Reset  Date,  but prior to the
Floating Period  Notification  Date, which will be the fourth Business Day prior
to the  Initial  Coupon  Reset Date,  the  Company  may elect,  by notice to the
Callholder  and the  Trustee,  to exercise its Floating  Period  Option.  If the
Company so elects,  the  Securities  of this  series  will bear  interest at the
Floating Period Interest Rate until the Floating Period  Termination Date, which
will be the earlier of May 15, 2004,  or the date which  otherwise  would be the
first  Reference  Rate Reset Date  following  the  Floating  Period  Termination
Notification Date. The Floating Period Termination  Notification Date will be at
least four Business Days prior to such  Reference  Rate Reset Date. In the event
that the Company exercises its Floating Period Option,  the maturity date of the
Securities  of this  series will be  extended  to the tenth  anniversary  of the
Floating  Period  Termination  Date, in which case the Securities of this series
will mature not later than May 15, 2014. The amount of interest payable for each
day that the Securities of this series are outstanding  during the Floating Rate
Period will be  calculated  by dividing the  Floating  Period  Interest  Rate in
effect for such day by 360 and multiplying  the result by the Dollar Price.  The
amount of interest payable for any Floating Rate Reset Period will be calculated
by adding the interest payable for each day in the Floating Rate Reset Period.

          As long as the  Securities of this series are listed on the Luxembourg
Stock  Exchange  ("LSE"),  (i) the Company shall notify LSE, not later than five
Business Days prior to the Scheduled Maturity Date, of any extension of maturity
and (ii) the Calculation  Agent shall notify LSE of the Floating Period Interest
Rate for any Floating Rate Period no later than the first day of such period.

          If the Callholder  has exercised the Call Option,  the Company and the
Calculation  Agent will complete the following  steps in order to determine each
Coupon Reset Rate.  The Company and the  Calculation  Agent will use  reasonable
efforts to cause the  actions  set forth  below to be  completed  in as timely a
manner as possible.

          (a) The Company will  provide the  Calculation  Agent with a list,  no
later  than five  Business  Days  prior to the  applicable  Coupon  Reset  Date,
containing the names and addresses of up to five Reference  Corporate Dealers or
Reference Money Market Dealers, as the case may be, from which it would like the
Calculation  Agent to obtain Fixed Rate Bids or Floating  Rate Bids, as the case
may be, for the purchase of the Securities of this series.

          (b) Within one Business Day following receipt by the Calculation Agent
of the dealer list referred to above, the Calculation Agent will provide to each
dealer on that list:  (i) a copy of the  prospectus  dated  April 19, 2001 and a
copy of the prospectus  supplement dated May 4, 2001 relating to the offering of
the Securities of this series; (ii) a copy of the form of the Securities of this
series;  and (iii) a written request that each dealer submit a Fixed Rate Bid or
Floating  Rate Bid, as the case may be, to the  Calculation  Agent by 3:30 p.m.,
New York City time  ("Bid  Deadline"),  on the third  Business  Day prior to the
applicable  Coupon Reset Date ("Bid Date").  Each dealer will be provided  with:
(i) the name of the  Company;  (ii) an estimate of the Dollar  Price;  (iii) the
principal  amount and maturity of the  Securities of this series;  and (iii) the
method by which interest will be calculated on the Securities of this series.

          (c) Following  receipt of the bids, the Calculation Agent will provide
written  notice to the Company of: (i) the name of each of the dealers from whom
the  Calculation  Agent received bids on the Bid Date; (ii) the bid submitted by
each of those dealers; and (iii) the Dollar Price.

          (d)  Immediately  after  calculating  the Dollar  Price and the Coupon
Reset Rate or Rates,  the Calculation  Agent will provide written notice thereof
to the Company, the Trustee and the dealer submitting the lowest applicable bid.

          Settlement

          In the event that the  Securities  of this series are purchased by the
Callholder,  the Callholder will pay to the Trustee, in same day funds not later
than 12:00 noon,  New York City time,  on the Initial  Coupon Reset Date,  or if
such Coupon Reset Date is not a Business Day at such time on the next succeeding
Business Day, an amount equal to 100% of the aggregate  principal  amount of the
Securities of this series, or on the Floating Period Termination Date, an amount
equal to the Dollar Price.

          On any such Coupon  Reset Date,  or if such Coupon Reset Date is not a
Business Day on the next succeeding  Business Day, the Callholder will cause the
Trustee to make payment of the purchase  price for the  tendered  Securities  of
this series that have been  purchased for  remarketing  by the Callholder to DTC
for  payment  to the DTC  Participant  of each  tendering  beneficial  owner  of
Securities of this series.  This payment will be made against  delivery  through
DTC of the beneficial  owner's  Securities of this series by book-entry  through
DTC by the close of business on the Coupon  Reset Date,  or if such Coupon Reset
Date is not a Business Day, on the next succeeding Business Day.

          The  Company  will  make,  or cause the  Trustee  to make,  payment of
interest to DTC for payment to the DTC Participant of each  beneficial  owner of
the Securities of this series,  due on a Coupon Reset Date by book-entry through
DTC, by the close of business on such Coupon Reset Date, or if such Coupon Reset
Date is not a Business Day on the next succeeding Business Day.

          The  transactions  described  above will be executed on the applicable
Coupon  Reset Date,  through DTC, or if such Coupon Reset Date is not a Business
Day on the next  succeeding  Business Day, in accordance  with the procedures of
DTC,  and the  accounts  of the  respective  Participants  will be  debited  and
credited, and the Securities of this series delivered by book-entry as necessary
to effect the purchases and sales thereof.

          All payments of principal and interest in respect of the Securities of
this series in book-entry form will be made in immediately  available funds. The
Securities of this series will trade in DTC's Same-Day Funds  Settlement  System
until the  Scheduled  Maturity  Date, as it may be extended,  or the  redemption
date,  as the case may be, or until the  Securities of this series are issued in
certificated form.

          The tender and settlement  procedures  described above,  including the
provisions for payment to selling  beneficial  owners of tendered  Securities of
this series, or for payment by the purchasers of Securities of this series, in a
remarketing, may be modified to the extent required by DTC or, if the book-entry
system is no longer available for the Securities of this series at the time of a
remarketing,  to the extent required to facilitate the tendering and remarketing
of Securities of this series in certificated  form. In addition,  the Callholder
may modify the settlement  procedures set forth above in order to facilitate the
settlement process.

          Initially the  Securities of this series will be issued in the form of
a Global  Security in an aggregate  principal  amount  equal to all  outstanding
Securities  of this series  registered in the name of Cede & Co. (as nominee for
The Depository Trust Company ("DTC"), the initial securities  depositary for the
Securities  of this  series),  and may bear such  legends as DTC may  reasonably
request.  So long as the  Securities  of this  series are held  solely in global
form,  the regular record date shall be the Business Day  immediately  preceding
the  relevant  Interest  Payment  Date;  if the  Securities  of this  series are
registered in the names of additional Holders,  the Company shall have the right
to select a regular record date for such Securities of this series,  which shall
be at least one  Business  Day but not more than 60  Business  Days prior to the
relevant  Interest  Payment Date.  So long as the  Securities of this series are
outstanding  in global form  registered  in the name of DTC or its nominee,  all
payments of principal  (and  premium,  if any) and interest  will be made by the
Company in immediately available funds. In case the Company shall be required to
repurchase  the  Securities  of this series held by DTC or its nominee,  payment
will be made by the Company by book entry  through  DTC by 2 p.m.  New York City
time, on the applicable  Coupon Reset Date against  delivery through DTC of such
Securities of this series.

          As  long  as DTC or its  nominee  (or a  custodian  thereof)  holds  a
certificate  representing the Securities of this series in the book-entry system
of DTC, no  certificates  for the Securities of this series will be delivered to
any beneficial owner. In addition,  the Company agrees to (1) use its reasonable
best efforts to maintain the  Securities of this series in book-entry  form with
DTC or any  successor  thereto,  and to appoint a  successor  depositary  to the
extent  necessary to maintain the Securities of this series in book-entry  form,
and (2) except as otherwise  described herein,  waive any discretionary right it
otherwise has under the  Indenture to cause the  Securities of this series to be
issued in certificated form.

          The Calculation Agent

          The Company  shall  appoint a  calculation  agent with  respect to the
Securities of this series (the  "Calculation  Agent"),  which initially shall be
UBS Warburg  LLC.  The  Calculation  Agent shall incur no  liability  for, or in
respect  of, any action  taken,  omitted to be taken or  suffered  by it in such
capacity in  reliance  upon any  certificate,  affidavit,  instruction,  notice,
request,  direction,  order, statement or other paper, document or communication
reasonably  believed by it to be  genuine.  Any order,  certificate,  affidavit,
instruction,  notice, request, direction,  statement or other communication from
the  Company  made  or  given  by it and  sent,  delivered  or  directed  to the
Calculation  Agent under,  pursuant to, or as permitted by, any provision of the
Indenture   shall  be   sufficient   for  purposes  of  the  Indenture  if  such
communication is in writing and signed by any officer or attorney-in-fact of the
Company.  The Calculation Agent may consult with counsel satisfactory to it, and
the advice of such counsel shall constitute full and complete  authorization and
protection of such Calculation  Agent with respect to any action taken,  omitted
to be taken or suffered by it hereunder in good faith and in accordance with and
in reliance upon the advice of such counsel.

          The Calculation Agent, in its individual capacity,  may, as if it were
not the  Calculation  Agent,  (i) buy, sell, hold and deal in Securities of this
series  and may  exercise  any vote or join in any  action  which any  Holder of
Securities  of this series may be entitled to exercise or take or (ii) engage in
any financial or other transaction with the Company or any of its subsidiaries.

          In  acting in  connection  with the  Securities  of this  series,  the
Calculation  Agent  shall  be  obligated  only to  perform  such  duties  as are
specifically set forth herein, and no other duties or obligations on the part of
the  Calculation  Agent,  in its  capacity  as  such,  shall be  implied  by the
Indenture. In acting under the Indenture,  the Calculation Agent in its capacity
as such does not assume any obligation towards, or any relationship of agency or
trust for or with, the Holders of the Securities of this series.

          The  Calculation  Agent may resign at any time as  Calculation  Agent,
such  resignation  to be  effective  10 Business  Days after the delivery to the
Company and the Trustee of written notice of such resignation. In such case, the
Company shall appoint a successor  Calculation  Agent. In addition,  the Company
may at any time remove the  existing  Calculation  Agent and appoint a successor
Calculation  Agent if  Reasonable  Cause  exists at such time by giving  written
notice to the existing Calculation Agent and the Trustee and specifying the date
when the termination shall become effective.  "Reasonable  Cause" shall mean the
failure  or  inability  of  the  existing   Calculation  Agent  to  perform  any
obligations it may have hereunder for any reason.

          Any successor Calculation Agent appointed by the Company shall execute
and deliver to the predecessor Calculation Agent, the Company and the Trustee an
instrument  accepting such  appointment and thereupon the successor  Calculation
Agent shall,  without any further act or instrument,  become vested with all the
rights,  immunities,  duties and obligations of the initial  Calculation  Agent,
with like effect as if originally named as initial  Calculation Agent hereunder,
and the predecessor  Calculation  Agent shall thereupon be obligated to deliver,
and the successor Calculation Agent shall be entitled to receive,  copies of any
available records maintained by the predecessor  Calculation Agent in connection
with the performance of its obligations hereunder.  The Company shall notify the
Trustee in writing upon any such appointment.

          The Company shall  indemnify and hold harmless the  Calculation  Agent
and any successor thereof, and its officers and employees,  from and against all
actions, claims, damages, liabilities, losses and reasonable expenses (including
reasonable legal fees and reasonable  disbursements)  relating to or arising out
of actions or omissions of the  Calculation  Agent  hereunder,  except  actions,
claims, damages, liabilities, losses and expenses caused by the bad faith, gross
negligence  or willful  misconduct of the  Calculation  Agent or its officers or
employees. This paragraph shall survive the termination of the Indenture and the
payment in full of all obligations under the Securities of this series,  whether
by redemption, repayment or otherwise.

          Notwithstanding  any other provision of the Indenture,  the rights and
obligations  of the  Calculation  Agent  hereunder are those of the  Calculation
Agent and its legal successors.  Any entity into which the Calculation Agent may
be merged,  converted or consolidated,  or any entity resulting from any merger,
conversion or  consolidation  to which the Calculation  Agent may be a party, or
any entity to which the Calculation Agent may sell or otherwise  transfer all or
substantially all of its business,  shall, to the extent permitted by applicable
law, automatically succeed the Calculation Agent.

Payment of Additional Amounts

     The  Company  will,  subject to the  limitations  set forth  below,  pay as
additional interest on the Securities of this series, such additional amounts as
are  necessary  in order that the net payment by the Company or the paying agent
of the  principal of and interest on the  Securities  of this series to a Holder
who is a  Non-U.S.  Holder,  after  deduction  for any  present  or future  tax,
assessment  or other  governmental  charge of the United  States or a  political
subdivision or taxing authority thereof or therein,  imposed by withholding with
respect  to the  payment,  will not be less  than  the  amount  provided  in the
Securities  of this  series to be then due and payable  ("Additional  Amounts");
provided, however, that the foregoing obligation to pay Additional Amounts shall
not apply:

     (i) to any tax,  assessment or other governmental charge that is imposed or
withheld solely by reason of the Holder, or a fiduciary,  settlor,  beneficiary,
member  or  shareholder  of  the  Holder  if the  Holder  is an  estate,  trust,
partnership or corporation,  or a person holding a power over an estate or trust
administered by a fiduciary holder, being considered as:

          (A) being or having  been  present or engaged in trade or  business in
     the United  States or having had a  permanent  establishment  in the United
     States;

          (B) having a current or former  relationship  with the United  States,
     including a relationship as a citizen or resident thereof;

          (C)  being or having  been a  foreign  or  domestic  personal  holding
     company,  a passive  foreign  investment  company or a  controlled  foreign
     corporation  with respect to the United  States or a  corporation  that has
     accumulated earnings to avoid United States federal income tax;

          (D) being or having been a "10-percent  shareholder" of the Company as
     defined in Section  871(h)(3) of the United States Internal Revenue Code of
     1986, as amended, or any successor provision; or

          (E) being a bank  receiving  payments on an  extension  of credit made
     pursuant to a loan  agreement  entered into in the  ordinary  course of its
     trade or business;

     (ii) to any holder that is not the sole beneficial  owner of the Securities
of this series, or a portion thereof, or that is a fiduciary or partnership, but
only to the extent that a beneficiary  or settlor with respect to the fiduciary,
a beneficial owner or member of the partnership  would not have been entitled to
the payment of an additional  amount had the  beneficiary,  settlor,  beneficial
owner or member received  directly its beneficial or  distributive  share of the
payment;

     (iii) to any tax,  assessment or other governmental  charge that is imposed
or withheld by reason of the failure of the holder or any other person to comply
with  certification,   identification  or  information  reporting   requirements
concerning the  nationality,  residence,  identity or connection with the United
States,  or otherwise  with respect to the status,  of the Holder or  beneficial
owner of the Securities of this series (or any beneficiary,  settlor, beneficial
owner or member thereof), if compliance is required by statute, by regulation of
the United States Treasury  Department or by an applicable  income tax treaty to
which the United States is a party, or by any official  interpretation or ruling
promulgated  pursuant to any of the foregoing,  as a  precondition  to exemption
from such tax, assessment or other governmental charge;

     (iv) to any tax,  assessment or other  governmental  charge that is imposed
otherwise  than by  withholding  by the  Company  or the  paying  agent from the
payment;

     (v) to any tax,  assessment or other governmental charge that is imposed or
withheld solely by reason of a change in law,  regulation,  or administrative or
judicial  interpretation  that  becomes  effective  more than 30 days  after the
payment becomes due or is duly provided for, whichever occurs later;

     (vi) to any estate,  inheritance,  gift, sales, excise, transfer, wealth or
personal property tax or similar tax, assessment or other governmental charge;

     (vii) to any tax,  assessment or other  governmental  charge required to be
withheld by any paying agent from any payment of principal of or interest on any
Securities of this series,  if such payment can be made without such withholding
by any other paying agent; or

     (viii) in the case of any combination of items (i), (ii), (iii), (iv), (v),
(vi) or (vii).

     The  Securities of this series are subject in all cases to any tax,  fiscal
or  other  law  or  regulation  or  administrative  or  judicial  interpretation
applicable  thereto.  Except as specifically  provided by the provisions of this
Security,  the Company shall not be required to make any payment with respect to
any tax,  assessment or other governmental charge imposed by any government or a
political subdivision or taxing authority thereof or therein.

     In  particular,  the  Company  will not pay any  Additional  Amounts on any
Securities of this series:

     (i) where withholding or deduction is imposed on a payment to an individual
and is  required to be made  pursuant to any  European  Union  Directive  on the
taxation of savings  implementing  the conclusions of the ECOFIN Council meeting
of  November 26 and 27,  2000 or any law  implementing  or  complying  with,  or
introduced in order to conform to, that Directive, or

     (ii) presented for payment by or on behalf of a beneficial  owner who would
have been able to avoid the  withholding or deduction by presenting the relevant
Series B Note to another paying agent in a member state or the European Union.

Redemption

     Post-Coupon Reset Optional Redemption

     If the  Callholder  elects to remarket the  Securities  of this series on a
Coupon Reset Date,  the  Securities  of this series will be subject to mandatory
tender to the Callholder for remarketing on such date, subject to the conditions
described herein under "Tender of Securities of this Series; Remarketing."

     After the Fixed Rate Coupon Reset Date,  the  Securities of this series are
redeemable,  in whole or in part,  at any time, at the  Company's  option,  at a
Redemption  Price equal to the greater of: (i) 100% of the  principal  amount of
the Securities of this series then outstanding to be redeemed,  and (ii) the sum
of the present  values of the  remaining  scheduled  payments of  principal  and
interest  thereon  (exclusive  of  interest  accrued to the date of  redemption)
discounted to the redemption date on a semiannual basis (assuming a 360-day year
consisting of twelve  30-day  months) at the Optional  Redemption  Treasury Rate
plus 20  basis  points,  plus in  each  case  accrued  interest  thereon  to the
redemption date. The Company will mail notice of redemption at least 30 days but
not more than 60 days before the  applicable  redemption  date to each holder of
the Securities of this series to be redeemed. If the Company elects to partially
redeem the  Securities  of this series,  the  Securities  of this series will be
redeemed  by lot or in such  other  manner as the  Trustee  shall  deem fair and
appropriate in its discretion,  provided, that if at the time of redemption, the
Securities of this Series are represented by a Global  Security,  the Depository
shall  determine by lot the  principal  amount of such  Securities  held by each
holder  to  be  redeemed.  The  redemption  price  determined  by  the  Optional
Redemption  Independent  Investment  Banker,  absent  manifest  error,  shall be
binding and conclusive  upon the Holders of the  Securities of this series,  the
Company and the Trustee. Notwithstanding Section 3.02 of the Original Indenture,
the notice of such redemption  need not set forth the redemption  price but only
the manner of calculation  thereof. The Company shall give the Trustee notice of
such redemption price immediately after the calculation thereof.

     Upon payment of the redemption price plus accrued and unpaid  interest,  if
any, to the date of  redemption,  interest will cease to accrue on and after the
applicable  redemption date on the Securities of this series or portions thereof
called for redemption.

     Redemption for Tax Reasons

     If,  as a result  of any  change  in,  or  amendment  to,  the laws (or any
regulations  or rulings  promulgated  thereunder)  of the United  States (or any
political subdivision or taxing authority thereof or therein), or any change in,
or  amendments   to,  an  official   position   regarding  the   application  or
interpretation of such laws,  regulations or rulings,  which change or amendment
is announced or becomes  effective on or after the date of the original issuance
of the Securities of this series,  the Company  becomes or, based upon a written
opinion of independent counsel selected by the Company, will become obligated to
pay  Additional  Amounts as described  above with respect to  Securities of this
series, the Company may, at its option, redeem, as a whole, but not in part, the
Securities  of this  series  on not less  than 30 nor more  than 60 days'  prior
notice,  at a redemption  price equal to 100% of their principal amount together
with interest accrued but unpaid thereon to the date fixed for redemption.

Restrictive Covenants

     Limitation upon Liens of Certain Subsidiaries

     For so long  as any  Securities  of this  series  remain  outstanding,  the
Company will not create or incur or allow any of its  subsidiaries  to create or
incur any pledge or security  interest  on any of the capital  stock of a Public
Utility  Subsidiary  held  by  the  Company  or one  of  its  subsidiaries  or a
Significant Subsidiary.

     For purposes of this covenant:

     (i) Public Utility  Subsidiary  means, at any particular  time, a direct or
indirect  subsidiary of the Company that, as a substantial part of its business,
distributes  or transmits  electric  energy to retail or wholesale  customers at
rates or tariffs  that are  regulated  by either a state or  Federal  regulatory
authority.

     (ii)  Significant  Subsidiary  means,  at any  particular  time, any direct
subsidiary  of ours  whose  consolidated  gross  assets  or  consolidated  gross
revenues  (having  regard to the  Company's  direct  beneficial  interest in the
shares, or the like, of that subsidiary) represent at least 25% of the Company's
consolidated  gross assets or consolidated  gross revenues appearing in the most
recent  audited   financial   statement  of  the  Company  as  of  the  date  of
determination.

            Lmitation upon Mergers, Consolidations and Sale of Assets

     The  provisions of Article Ten of the Indenture  shall be applicable to the
Securities of this series.

General

     Tax Treatment.  By purchasing  the  Securities of this series,  each Holder
agrees (in the absence of an administrative  determination or judicial ruling to
the contrary) to follow the Company's treatment of the Securities of this series
as fixed rate debt  instruments that mature on the Initial Coupon Reset date for
U.S. federal income tax purposes.

     Usury. The interest rate on the Securities of this series shall in no event
be higher than the  maximum  rate  permitted  by New York law as the same may be
modified by United States law of general application.

     Defeasance.  The Indenture  contains  provisions  for defeasance of (a) the
entire  indebtedness  evidenced  by this  Security  and (b) certain  restrictive
covenants  upon  compliance  by the Company  with certain  conditions  set forth
therein;  provided,  however,  the  Securities of this series are not subject to
defeasance on or before the Initial Coupon Reset Date.

     Events of Default.  If an Event of Default  with respect to  Securities  of
this series shall occur and be  continuing,  the principal of the  Securities of
this  series may be  declared  due and payable in the manner and with the effect
provided in the Indenture.

     Amendment  to  Indenture;   Waiver  of  Defaults.  The  Indenture  contains
provisions  permitting  the  Company  and the  Trustee,  with the consent of the
Holders  of not less  than a  majority  in  aggregate  principal  amount  of the
Securities of all series affected by such  supplemental  indenture or indentures
at the time  outstanding  voting as one class,  as defined in the Indenture,  to
execute  supplemental  indentures for the purpose of adding any provisions to or
changing in any manner or eliminating  any of the provisions of the Indenture or
of any  supplemental  indenture  or of modifying in any manner the rights of the
Holders  of  the  Securities;  provided,  however,  that  no  such  supplemental
indenture  shall (i) extend the fixed  maturity of any Securities of any series,
or reduce the principal amount thereof, or reduce the rate or extend the time of
payment of interest  thereon,  or reduce any premium payable upon the redemption
thereof, or reduce the amount of the principal of a Discount Security that would
be due and payable upon a declaration of  acceleration  of the maturity  thereof
pursuant to the  Indenture,  without the consent of the holder of each  Security
then  outstanding  and  affected;   (ii)  reduce  the  aforesaid  percentage  of
Securities,   the  holders  of  which  are  required  to  consent  to  any  such
supplemental indenture,  or reduce the percentage of Securities,  the holders of
which are  required  to waive any  default  and its  consequences,  without  the
consent of the holder of each Security then outstanding and affected thereby; or
(iii) modify any provision of Section 6.01(c) of the Original  Indenture (except
to increase the percentage of principal amount of Securities required to rescind
and annul any  declaration  of amounts  due and payable  under the  Securities),
without the consent of the holder of each Security then outstanding and affected
thereby.  The Indenture  also contains  provisions  permitting  the Holders of a
majority in aggregate  principal  amount of the  Securities of any series at the
time outstanding affected thereby, on behalf of the Holders of the Securities of
such  series,  to  waive  any  past  default  in the  performance  of any of the
covenants contained in the Indenture,  or established  pursuant to the Indenture
with  respect  to such  series,  and its  consequences,  except a default in the
payment of the  principal  of or  premium,  if any,  or  interest  on any of the
Securities of such series.  Any such consent or waiver by the registered  Holder
of this  Security  (unless  revoked  as  provided  in the  Indenture)  shall  be
conclusive  and binding upon such Holder and upon all future  Holders and owners
of this  Security  and of any  Security  issued in exchange  herefor or in place
hereof  (whether by  registration  of transfer or  otherwise),  irrespective  of
whether or not any notation of such consent or waiver is made upon this Note.

     Obligations  Unconditional.  No reference  herein to the  Indenture  and no
provision  of this  Security  or of the  Indenture  shall  alter or  impair  the
obligation  of the  Company,  which is absolute  and  unconditional,  to pay the
principal of (and premium, if any) and interest, if any, on this Security at the
times, place and rates, and in the coin or currency, herein prescribed.

     Transfer and Exchange.  This Security shall be exchangeable  for Securities
registered  in the names of Persons  other than the  Depositary  with respect to
such series or its nominee  only as  provided  in Section  2.05 of the  Original
Indenture.  As provided  in the  Indenture  and  subject to certain  limitations
therein  set  forth,  the  transfer  of a  Security  of the series of which this
Security is a part is  registrable in the Security  Register,  upon surrender of
this  Security  for  registration  of  transfer  at the  office or agency of the
Company in any place where the principal of (and premium,  if any) and interest,
if any, on this  Security are payable,  duly  endorsed by, or  accompanied  by a
written  instrument  of  transfer  in form  satisfactory  to the Company and the
Security  Registrar  duly  executed by, the Holder  hereof or his attorney  duly
authorized in writing,  and thereupon one or more new  Securities of this series
and of like  tenor,  of  authorized  denominations  and for the  same  aggregate
principal amount, will be issued to the designated transferee or transferees.

     The Securities of this series are issuable only in registered  form without
coupons in minimum  denominations  of $1,000 or any integral  multiple of $1,000
over such  minimum  denomination.  As provided in the  Indenture  and subject to
certain   limitations   therein  set  forth,   Securities  of  this  series  are
exchangeable for a like aggregate  principal amount of Securities of this series
and of like tenor of a different  authorized  denomination,  as requested by the
Holder surrendering the same.

     No service  charge shall be made for any such  registration  of transfer or
exchange,  but the Company may require  payment of a sum sufficient to cover any
tax or other governmental charge payable in connection therewith.

     Prior to due presentment of this Security for registration of transfer, the
Company,  the  Trustee and any agent of the Company or the Trustee may treat the
Person in whose name this  Security is  registered  as the owner  hereof for all
purposes,  whether or not this Security be overdue, and neither the Company, the
Trustee nor any such agent shall be affected by notice to the contrary.

     Governing  Law.  This  Security  shall  be  governed  by and  construed  in
accordance  with the laws of the State of New York without  regard to principles
of conflict of law except  Section  5-1401 of the New York  General  Obligations
Law.

Definitions

     Set forth below are definitions of certain capitalized terms used herein.

     "Additional  Amounts" means such amounts as are necessary in order that the
net payment by the Company or the paying agent of the  principal of and interest
on the  Securities  of this series to a Holder who is a Non-U.S.  Holder,  after
deduction for any present or future tax, assessment or other governmental change
of the United States or a political  subdivision or taxing authority  thereof or
therein,  imposed by withholding  with respect to the payment,  will not be less
than the amount  provided  in the  Securities  of this series to be then due and
payable.

     "Applicable  Spread" means the lowest Fixed Rate Bid, expressed as a spread
(in the form of a  percentage  or in basis  points)  above the Base Rate for the
Securities of this series  obtained by the  Calculation  Agent by 3:30 p.m., New
York City time, on the Fixed Rate  Determination  Date, from the Fixed Rate Bids
quoted to the Calculation Agent by up to five Reference Corporate Dealers.

     "Base Rate" means 5.30%.

     "Business  Day" means any day other  than a Saturday  or Sunday or a day on
which banking  institutions  in New York City are authorized or obligated by law
or executive order to close.

     "Calculation  Agent" means the Calculation Agent appointed  pursuant to the
provisions set forth herein, initially UBS Warburg LLC.

     "Call Notice" means written notice by the Callholder to the Company and the
Trustee that it elects to purchase the Securities of this series for remarketing
on the Initial Coupon Reset Date.

     "Call  Option"  means the option of the  Callholder  which,  if  exercised,
results in the  obligation of the  Callholder to purchase the Securities of this
series for  remarketing  on the  Initial  Coupon  Reset Date and, if the Company
exercises its Floating Period Option,  to purchase the Securities of this series
for remarketing on the Floating Period  Termination  Date, as more  particularly
described in the "Call Option" section in this Security.

     "Comparable  Treasury  Issues" for the  Securities of this series means the
U.S.  Treasury security or securities  selected by the Calculation  Agent, as of
the first  Determination  Date, as having an actual or interpolated  maturity or
maturities  comparable  to the remaining  term of the  Securities of this series
being purchased by the Callholder.

     "Comparable Treasury Price" means, with respect to the Initial Coupon Reset
Date: (i) the offer prices for the Comparable  Treasury  Issues  (expressed,  in
each case, as a percentage of its principal amount) at 12:00 noon, New York City
time, on the first  Determination  Date, as set forth on "Telerate Page 500" (or
such other page as may replace "Telerate Page 500") or (ii) if such page (or any
successor  page) is not  displayed or does not contain such offer prices on such
Determination  Date, the average of the Reference Treasury Dealer Quotations for
such  Determination  Date, after excluding the highest and lowest such Reference
Treasury Dealer Quotations,  or if the Calculation Agent obtains fewer than four
such Reference  Treasury  Dealer  Quotations,  the average of all such Reference
Treasury Dealer Quotations.

     "Coupon Reset Date(s)" means (1) May 15, 2003,  assuming the Callholder has
elected to  purchase  the  Securities  of this  series and the  Company  has not
elected to exercise  its  Floating  Period  Option,  or (2) May 15, 2003 and the
Floating  Period  Termination  Date,  if,  in the  case of the  Floating  Period
Termination  Date,  the  Company has elected to  exercise  its  Floating  Period
Option.

     "Coupon Reset Rate" means the interest rate to be paid on the Securities of
this series from and including each Coupon Reset Date.

     "Determination  Date" means each of the Floating Rate Spread  Determination
Date or the Fixed Rate Determination Date.

     "Dollar Price" means,  with respect to the Securities of this series and as
determined by the Calculation  Agent, (1) the principal amount of the Securities
of this  series,  plus (2) the premium  equal to the excess,  if any, of (A) the
present value,  as of the Initial Coupon Reset Date, of the Remaining  Scheduled
Payments for such  Securities of this series,  discounted to the Initial  Coupon
Reset Date on a semi-annual  basis (assuming a 360-day year consisting of twelve
30-day  months)  at the  Treasury  Rate,  over (B) the  principal  amount of the
Securities  of this  series.  The Dollar Price will be  determined  on the third
Business Day prior to the Initial Coupon Reset Date.

     "Fixed  Rate Bid" means an  irrevocable  offer to  purchase  the  aggregate
outstanding  principal  amount of the  Securities  of this  series at the Dollar
Price,  but assuming:  (i) a settlement date that is the Fixed Rate Coupon Reset
Date  applicable to such Securities of this series,  without  accrued  interest;
(ii) a maturity  date that is the tenth  anniversary  of the Fixed  Rate  Coupon
Reset Date;  (iii) a stated annual interest rate equal to the Base Rate plus the
spread  bid  by  the  applicable  Reference  Corporate  Dealer;  (iv)  that  the
Securities of this series are callable by the Company pursuant to the make-whole
redemption  provisions  described in the "Optional  Termination" section in this
Security; and (v) that the interest is payable semi-annually, with such interest
payment dates to be determined.

     "Fixed Rate Coupon Reset Date" means May 15, 2003,  assuming the Callholder
has elected to purchase  the  Securities  of this series and the Company has not
elected  to  exercise  its  Floating  Period  Option,  or  the  Floating  Period
Termination  Date,  if the Company has elected to exercise its  Floating  Period
Option.

     "Fixed Rate  Determination  Date" means the third Business Day prior to the
Fixed Rate Coupon Reset Date.

     "Floating Period Interest Rate" means the sum of the Reference Rate and the
Floating Rate Spread.

     "Floating Period  Notification Date" means the fourth Business Day prior to
the Initial Coupon Reset Date.

     "Floating  Period Option" means the Company's  right, on any date after the
Callholder  elects to purchase  the  Securities  of this series but prior to the
fourth  Business  Day prior to the Initial  Coupon  Reset  Date,  to require the
Callholder  to remarket the  Securities  of this series at the  Floating  Period
Interest Rate.

     "Floating Period Termination Date" means the earlier of May 15, 2004 or the
date which  otherwise would be the first Reference Rate Reset Date following the
Floating Period Termination Notification Date.

     "Floating Period Termination Notification Date" means the date on which the
Company  gives  notice to the  Callholder  and the  Trustee of its  election  to
terminate  the Floating  Rate Period which shall be at least four  Business Days
prior to the next Reference Rate Reset Date.

     "Floating  Rate Bid" means an  irrevocable  offer to purchase the aggregate
outstanding  principal  amount of the  Securities  of this  series at the Dollar
Price,  but  assuming:  (i) a settlement  date that is the Floating  Rate Coupon
Reset Date; (ii) a maturity date equal to the Floating Period  Termination Date;
(iii) a stated annual  interest rate equal to the Reference  Rate (which will be
adjusted  monthly)  plus the Floating  Rate Spread;  (iv) that  interest will be
payable each month on the Reference  Rate Reset Date; (v) that the Securities of
this series are subject to mandatory  tender to, and purchase by, the Callholder
at the Dollar Price on the Floating Period  Termination  Date; and (vi) that the
Company  will redeem the  Securities  of this series at the Dollar  Price on the
Floating Period Termination Date, if not previously purchased by the Callholder.

     "Floating  Rate  Coupon  Reset  Date"  means May 15,  2003 in the event the
Company has elected to exercise its Floating Period Option.

     "Floating Rate Interest Payment Date" means the Floating Period Termination
Date and each Reference Rate Reset Date during the Floating Rate Period,  except
the first Reference Rate Reset Date.

     "Floating  Rate Period"  means the period from and  including  the Floating
Rate Coupon Reset Date to but excluding the Floating Period Termination Date.

     "Floating  Rate Reset Period" means the period from and including the first
Reference  Rate Reset Date, to but excluding the next  following  Reference Rate
Reset Date,  and thereafter the period from and including a Reference Rate Reset
Date to but excluding the next  following  Reference  Rate Reset Date;  provided
that the final  Floating  Rate Reset Period will run to but exclude the Floating
Period Termination Date.

     "Floating  Rate Spread"  means the lowest  Floating Rate Bid expressed as a
spread (in the form of a percentage or in basis points) above the Reference Rate
for the  Securities  of this series  obtained by the  Calculation  Agent by 3:30
p.m., New York City time, on the Floating Rate Spread  Determination  Date, from
the Floating Rate Bids quoted to the  Calculation  Agent by up to five Reference
Money Market Dealers.

     "Floating  Rate Spread  Determination  Date" means the third  Business  Day
prior to the Floating Rate Coupon Reset Date.

     "Initial Coupon Reset Date" means May 15, 2003.

     "Interest  Rate  to  Maturity"  means  the  sum of the  Base  Rate  and the
Applicable Spread,  which will be based on the Dollar Price of the Securities of
this series.

     "London  Business Day" means any day on which dealings in U.S.  dollars are
transacted in the London Inter-Bank Market.

     "Market  Disruption  Event" means any of the  following  in the  reasonable
judgment of the Calculation Agent and the Company:  (i) a suspension or material
limitation in trading in securities  generally on the New York Stock Exchange or
the  establishment  of minimum  prices on such  exchange;  (ii) a suspension  or
material limitation in trading in the Company's securities on the New York Stock
Exchange;  (iii) a general moratorium on commercial banking activities  declared
by either U.S.  federal or New York State  authorities;  (iv) a material adverse
change  in the  existing  financial  markets  in the  United  States;  (v) a new
material  outbreak  or  escalation  of major  hostilities  involving  the United
States, or the declaration of a national  emergency or war by the United States;
or (vi) a material  disruption of the U.S.  government  securities market,  U.S.
corporate bond market, or U.S. federal wire system.

     "Non-U.S. Holder" means a holder of Securities of this series that is not a
U.S. Holder.

     "Optional  Redemption  Treasury Rate" means, with respect to any redemption
date  for the  Securities  of this  series,  the  rate  per  annum  equal to the
semiannual  equivalent  yield to maturity or interpolated (on a day count basis)
of the Optional Redemption  Comparable Treasury Issue,  assuming a price for the
Optional Redemption  Comparable Treasury Issue (expressed as a percentage of its
principal amount) equal to the Optional Redemption Comparable Treasury Price for
such redemption date.

     "Optional  Redemption  Comparable  Treasury  Issue" means the United States
Treasury security or securities selected by an Optional  Redemption  Independent
Investment Banker as having an actual or interpolated maturity comparable to the
remaining  term of the  Securities  of this series to be redeemed  that would be
utilized,  at the time of selection and in accordance  with customary  financial
practice,  in pricing new issues of corporate  debt  securities  of a comparable
maturity to the remaining term of Securities of this series.

     "Optional  Redemption  Independent  Investment  Banker"  means  one  of the
Optional  Redemption  Reference  Treasury Dealers appointed by the Trustee after
consultation with the Company.

     "Optional Redemption  Comparable Treasury Price" means, with respect to any
redemption  date for the  Securities  of this  series,  (A) the  average  of the
Optional  Redemption  Reference  Treasury Dealer  Quotations for such redemption
date, after excluding the highest and lowest such Optional Redemption  Reference
Treasury Dealer  Quotations,  or (B) if the Trustee obtains fewer than four such
Optional  Redemption  Reference Treasury Dealer  Quotations,  the average of all
such quotations.

     "Optional  Redemption  Reference  Treasury Dealer  Quotations"  means, with
respect to each Optional Redemption Reference Treasury Dealer and any redemption
date for the  Securities  of this series,  the  average,  as  determined  by the
Trustee,  of the bid and asked  prices for the  Optional  Redemption  Comparable
Treasury Issue (expressed in each case as a percentage of its principal  amount)
quoted in writing to the Trustee by such Optional Redemption  Reference Treasury
Dealer at 3:30  p.m.  New York time on the third  Business  Day  preceding  such
redemption date.

     "Optional Redemption Reference Treasury Dealer" means each of Credit Suisse
First Boston Corporation, Merrill Lynch, Pierce, Fenner & Smith Incorporated and
UBS Warburg LLC, or their  affiliates  that are Primary  Treasury  Dealers,  and
their respective successors,  and two other Primary Treasury Dealers selected by
the Trustee; provided, however, that if any of the foregoing or their affiliates
shall  cease to be a Primary  Treasury  Dealer,  the  Company  shall  substitute
therefor another Primary Treasury Dealer.

     "Post-Coupon  Reset  Redemption  Date"  means any date after the Fixed Rate
Coupon Reset Date on which the Company  elects to redeem the  Securities of this
series in whole or in part pursuant to the terms set forth herein.

     "Primary Treasury Dealer" means a primary U.S. Government securities dealer
in The City of New York.

     "Put Option" means the  obligation of the Trustee to put the  Securities of
this series to the  Company for and on behalf of the Holders of such  Securities
as described under the heading "Put Option" herein.

     "Reference  Corporate  Dealer" means each of up to five leading  dealers of
publicly traded debt securities,  including the Company's debt securities, which
shall be selected by the Company and agreed to by the  Callholder,  such consent
not to be unreasonably  withheld.  The Company will advise the Calculation Agent
of its selection of Reference Corporate Dealers no later than five Business Days
prior to the Fixed  Rate  Coupon  Reset  Date.  One of the  Reference  Corporate
Dealers the Company selects will be UBS Warburg LLC, if UBS AG, London Branch is
then the Callholder.

     "Reference Money Market Dealer" means each of up to five leading dealers of
publicly traded debt securities,  including the Company's debt securities, which
the  Company  shall  select,  who are  also  leading  dealers  in  money  market
instruments,   and  agreed  to  by  the  Callholder,  such  consent  not  to  be
unreasonably  withheld.  The Company  will advise the  Calculation  Agent of its
selection of Reference  Money Market  Dealers no later than five  Business  Days
prior to the Floating Rate Coupon Reset Date. One of the Reference  Money Market
Dealers the Company selects will be UBS Warburg LLC, if UBS AG, London Branch is
then the Callholder.

     "Reference  Rate" means the rate for each  Floating Rate Reset Period which
will be the rate for  deposits  in U.S.  dollars for a period of one month which
appears on Telerate Page 3750 (or any successor  page) as of 11:00 a.m.,  London
time, on the applicable Reference Rate Determination Date. If no rate appears on
Telerate Page 3750 on the Reference Rate  Determination  Date,  the  Calculation
Agent will request the principal London offices of four major reference banks in
the London Inter-Bank  Market, to provide the Calculation  Agent, in the case of
each such bank, with its offered  quotation for deposits in U.S. dollars for the
period of one  month,  commencing  on the first day of the  Floating  Rate Reset
Period, to prime banks in the London  Inter-Bank  Market at approximately  11:00
a.m., London time, on that Reference Rate  Determination Date and in a principal
amount that is representative  for a single  transaction in U.S. dollars in that
market at that time. If at least two quotations are provided, then the Reference
Rate will be the average of those  quotations.  If fewer than two quotations are
provided, then the Reference Rate will be the average (rounded, if necessary, to
the nearest one  hundredth  of a percent) of the rates  quoted at  approximately
11:00 a.m.,  New York City time, on the  Reference  Rate  Determination  Date by
three major banks in New York City selected by the  Calculation  Agent for loans
in U.S. dollars to leading European banks,  having a one-month maturity and in a
principal amount that is representative for a single transaction in U.S. dollars
in that market at that time. If the banks selected by the Calculation  Agent are
not providing quotations in the manner described in this paragraph, the rate for
the Floating Rate Reset Period following the Reference Rate  Determination  Date
will be the rate in effect on that Reference Rate Determination Date.

     "Reference Rate Determination  Date" will be the second London Business Day
preceding each Reference Rate Reset Date.

     "Reference  Rate Reset Date" means May 15,  2003 and the  fifteenth  day of
each month  thereafter  until,  but excluding,  the Floating Period  Termination
Date;  provided,  however,  if such  Reference Rate Reset Date is not a Business
Day, the Reference  Rate Reset Date will be postponed  until the next  following
Business Day.

     "Reference Treasury Dealer" means each of up to five dealers to be selected
by the Company,  and their  respective  successors;  provided that if any of the
foregoing ceases to be, and has no affiliate that is, a primary U.S.  Government
securities dealer ("Primary Treasury  Dealer"),  the Company will substitute for
it another Primary  Treasury Dealer.  One of the Reference  Treasury Dealers the
Company  selects will be UBS Warburg LLC, if UBS AG,  London  Branch is then the
Callholder.

     "Reference   Treasury  Dealer  Quotations"  means,  with  respect  to  each
Reference Treasury Dealer,  the offer prices for the Comparable  Treasury Issues
(expressed  in each case as a  percentage  of its  principal  amount)  quoted in
writing to the Calculation  Agent by such Reference  Treasury  Dealer,  by 12:00
noon, New York City time, on the first Determination Date.

     "Remaining  Scheduled  Payments"  means,  with respect to the Securities of
this series,  the  remaining  scheduled  payments of the  principal and interest
thereon,  calculated  at the Base Rate  applicable  to such  Securities  of this
series,  that would be due from but excluding  the Initial  Coupon Reset Date to
and including the Maturity Date.

     "Telerate Page 500" means the display  designated as "Telerate Page 500" on
Dow Jones Markets (or such other page as may replace "Telerate Page 500" on such
service) or such other service  displaying  the offer prices for the  Comparable
Treasury Issues, as may replace Dow Jones Markets.

     "Telerate  Page 3750" means the display page so designated on the Dow Jones
Markets Limited (or such other page as may replace  "Telerate Page 3750" on such
service) or such other  service or services as may be  nominated  by the British
Bankers'  Association  for the purpose of displaying  London  interbank  offered
rates for U.S. dollars deposits.

     "Treasury  Rate" for the  Securities of this series means,  with respect to
the  Initial  Coupon  Reset Date,  the rate per annum  equal to the  semi-annual
equivalent  yield to maturity or  interpolated  (on a day count  basis) yield to
maturity of the Comparable Treasury Issues,  assuming a price for the Comparable
Treasury Issues (expressed as a percentage of their principal  amounts) equal to
the Comparable Treasury Price for such Initial Coupon Reset Date.

     "U.S.  Holder" means a beneficial  holder of the  Securities of this series
that is: (i) a citizen or resident of the United  States,  (ii) a corporation or
partnership  created or organized  in or under the laws of the United  States or
any  political  subdivision  thereof,  (iii) an  estate  the  income of which is
subject to United States federal income  taxation  regardless of its source,  or
(iv) a trust that (a) is subject to the supervision of a court within the United
States and the  control of one or more United  States  persons as  described  in
section 7701(a)(30) of the Internal Revenue Code of 1986, as amended, or (b) has
a valid  election in effect under  applicable  U.S.  Treasury  regulations to be
treated as a United States person.

                                ----------------

                                   ASSIGNMENT

     FOR VALUE  RECEIVED,  the  undersigned  assigns and transfers  this Putable
Asset Term Securities to:

        (Insert assignee's social security or tax identification number)

                    (Insert address and zip code of assignee)

and irrevocably appoints
agent to  transfer  this  Security  on the  Security  Register.  The  agent  may
substitute another to act for him or her.


Date: ____________________

                                      Signature:____________________

                                      Signature Guarantee:___________


     (Sign exactly as your name appears on the other side of this Security)

                               SIGNATURE GUARANTEE

Signatures must be guaranteed by an "eligible guarantor institution" meeting the
requirements  of  the  Registrar,   which  requirements  include  membership  or
participation in the Security Transfer Agent Medallion Program ("STAMP") or such
other  "signature  guarantee  program" as may be  determined by the Registrar in
addition  to,  or in  substitution  for,  STAMP,  all  in  accordance  with  the
Securities Exchange Act of 1934, as amended.

                                                                     APPENDIX B


                                                        [Date]


                                 Acknowledgment


American Electric Power Company, Inc.
1 Riverside Plaza
Columbus, Ohio 43215

Ladies and Gentlemen:

     Reference is made to the Indenture dated as of May 1, 2001, as supplemented
by the Second Supplemental Indenture (the "Supplemental  Indenture") dated as of
May 1, 2001 (as supplemented, the "Indenture"),  between American Electric Power
Company,  Inc.,  a New York  corporation,  and The Bank of New York,  a New York
banking corporation, as Trustee, in connection with the offering of $250,000,000
aggregate  principal amount of 5.50% Putable  Callable Notes,  Series B, Putable
Callable May 15, 2003.  Capitalized terms used but not defined herein shall have
the meaning given to such terms in the Indenture.

     The undersigned  hereby  acknowledges  the assignment of the Call Option by
the Company pursuant to Section 4.02 of the Supplemental Indenture.

                            Very truly yours,

                            THE BANK OF NEW YORK, as Trustee


                            By:
                               ------------------------------
                               Authorized Signatory





Agreed and Acknowledged:


UBS AG, London Branch, as Callholder


By:
   ----------------------------------------------
     Name:
     Title:


By:
   ----------------------------------------------
     Name:
     Title:



                                                                   APPENDIX C


                                                   [Date]


                                 Acknowledgment


American Electric Power Company, Inc.
1 Riverside Plaza
Columbus, Ohio 43215

The Bank of New York
101 Barclay Street
New York, New York 10286

Ladies and Gentlemen:

     Reference is made to the Indenture dated as of May 1, 2001, as supplemented
by the Second Supplemental Indenture (the "Supplemental  Indenture") dated as of
May 1, 2001 (as supplemented, the "Indenture"),  between American Electric Power
Company,  Inc.,  a New York  corporation,  and The Bank of New York,  a New York
banking corporation, as Trustee, in connection with the offering of $250,000,000
aggregate  principal amount of 5.50% Putable  Callable Notes,  Series B, Putable
Callable May 15, 2003.  Capitalized terms used but not defined herein shall have
the meaning given to such terms in the Indenture.

     The undersigned  hereby  acknowledges its obligations as Calculation  Agent
under the Indenture pursuant to Section 4.03 of the Supplemental Indenture.

                                  Very truly yours,

                                  UBS Warburg LLC, as Calculation Agent


                                  By:
                                     ----------------------------------
                                       Name:
                                       Title:





                                                                    APPENDIX D


                                                              [Date]


                Form of Put Notice to be Delivered by the Trustee
                 To the Company Upon Exercise of the Put Option


American Electric Power Company, Inc.
1 Riverside Plaza
Columbus, Ohio 43215

Attention:  Treasurer

     The Bank of New York,  as Trustee  for  American  Electric  Power  Company,
Inc.'s $250,000,000  aggregate principal amount of 5.50% Putable Callable Notes,
Series B, Putable Callable May 15, 2003,  issued under the Indenture dated as of
May 1, 2001, as supplemented by a second supplemental  indenture dated as of May
1, 2001 (the  "Second  Supplemental  Indenture")  hereby gives notice of the Put
Option (as defined in the Second Supplemental Indenture) pursuant to Section 205
of the Second Supplemental Indenture.

                                   THE BANK OF NEW YORK, as Trustee


                                   By:
                                      ----------------------------------
                                      Authorized Signatory



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>7
<FILENAME>x10i2.txt
<DESCRIPTION>10(O) CHANGE INCONTROL AGREEMENT
<TEXT>
<PAGE>
                                                                  EXHIBIT 10(i)2

                      American Electric Power Company, Inc.
                          Stock Unit Accumulation Plan
                           For Non-Employee Directors
                          (As Amended January 1, 2002)

                                    Article 1
                                     Purpose

     The purposes of this  American  Electric  Power  Company,  Inc.  Stock Unit
Accumulation  Plan For  Non-Employee  Directors  (the  "Plan") are to enable the
Company  to  attract  and  retain  qualified  persons  to serve as  Non-Employee
Directors,  to solidify the common interests of its  Non-Employee  Directors and
shareholders by enhancing the equity  interest of Non-Employee  Directors in the
Company, and to encourage the highest level of Non-Employee Director performance
by providing  such  Non-Employee  Directors  with a proprietary  interest in the
Company's  performance  and progress by paying a portion of the  compensation of
the Non-Employee Directors in deferred Stock Units.


                                    Article 2
                                 Effective Date

The Plan shall be effective as of January 1, 1997.


                                    Article 3
                                   Definitions

Whenever  used in the  Plan,  the  following  terms  shall  have the  respective
meanings set forth below:

3.1  "Account"  means,  with  respect  to each  Participant,  the  Participant's
     separate  individual  account  established and maintained for the exclusive
     purpose of accounting for the Participant's award of Stock Units.

3.2  "Beneficiary"  means,  with respect to each  Participant,  the recipient or
     recipients  designated by the Participant  who are, upon the  Participant's
     death, entitled in accordance with the Plan's terms to receive the benefits
     to be paid with respect to the Participant.

3.3  "Board" means the Board of Directors of the Company.

3.4  "Committee" means the Committee on Directors of the Board.

3.5  "Common Stock" means the common stock, $6.50 par value, of the Company.

3.6  "Company"  means  American  Electric  Power  Company,   Inc.,  a  New  York
     corporation, and any successor thereto.

3.7  "Director" means an individual who is a member of the Board.

3.8  "Market Value" means the closing price of the Common Stock, as published in
     The Wall Street  Journal  report of the New York Stock Exchange - Composite
     Transactions on the date in question or, if the Common Stock shall not have
     been  traded on such date or if the New York  Stock  Exchange  is closed on
     such date,  then the first day prior  thereto on which the Common Stock was
     so traded.

3.9  "Non-Employee Director" means any person who serves on the Board and who is
     not an officer of the Company or employee of its Subsidiaries.

3.10 "Participant" means any Non-Employee  Director who has received an award of
     Stock Units.

3.11 "Retainer"  means the  designated  annual  cash  retainer,  currently  paid
     quarterly,  for Non-Employee Directors established from time to time by the
     Board  as  annual   compensation  for  services   rendered,   exclusive  of
     compensation  for service as a member of any  committee  designated  by the
     Board or in connection with any meeting of the Board or special assignment,
     and exclusive of  reimbursements  for expenses  incurred in  performance of
     service as a Director.

3.12 "Stock  Unit"  means a  measure  of value,  expressed  as a share of Common
     Stock,  credited to a Participant under this Plan. No certificates shall be
     issued with respect to such Stock Units,  but the Company shall  maintain a
     bookkeeping Account in the name of the Participant to which the Stock Units
     shall relate.

3.13 "Subsidiary"  means any  corporation  in which the Company owns directly or
     indirectly  through  its  Subsidiaries,  at least 50  percent  of the total
     combined  voting  power  of all  classes  of  stock,  or any  other  entity
     (including,  but not limited to,  partnerships and joint ventures) in which
     the Company owns at least 50 percent of the combined equity thereof.


3.14 "Termination"  means retirement from the Board or termination of service as
     a Director for any other reason.


                                    Article 4
                                Stock Unit Awards

4.1  Annual Awards

Each Non-Employee Director's Account shall be credited with 1,200 Stock Units as
of the  first day of the  month in which  the  Director  becomes a member of the
Board, and on the first day of such month for each year thereafter. In the event
of a change in the  Retainer,  the Committee  may  reconsider  the amount of the
annual  awards  and may  recommend  to the Board  changes in the number of Stock
Units to be awarded.

4.2 Retirement Program Termination Awards

On and as of December 31, 1996, each  Non-Employee  Director  serving as such on
such date who makes or has made an  irrevocable  election by January 31, 1997 to
waive participation in, and any and all benefits under, the Company's Retirement
Plan for Directors,  shall have credited to the Account of such Participant,  as
of January 1, 1997,  the  number of vested  and  nonforfeitable  Stock  Units as
follows:  R. M. Duncan 3,000;  R. W. Fri 600; A. G. Hansen 3,000;  L. A. Hudson,
Jr. 3,000; A. E. Peyton 3,000; D. G. Smith 900; L. G. Stuntz 1,200; M. Tanenbaum
2,400; and A. H. Zwinger 3,000.


                                    Article 5
                            Dividends and Adjustments

5.1 Reinvestment of Dividends

On each dividend payment date with respect to the Common Stock, the Account of a
Participant, with Stock Units held pursuant to Article 4, shall be credited with
an  additional  number of whole and  fractional  Stock Units,  computed to three
decimal  places,  equal to the product of the dividend  per share then  payable,
multiplied by the number of Stock Units then  credited to such Account,  divided
by the Market Value on the dividend payment date.

5.2 Adjustments

The number of Stock  Units  credited  to a  Participant's  Account  pursuant  to
Article 4 shall be appropriately  adjusted for any change in the Common Stock by
reason of any merger, reclassification,  consolidation,  recapitalization, stock
dividend, stock split or any similar change affecting the Common Stock.


                                    Article 6
                             Payment of Stock Units

6.1 Manner of Payment Upon Termination

Stock Units held in a Participant's  Account shall be paid to the Participant in
a lump sum in cash within 10 days after the Participant's Termination unless the
Participant  has filed an  election  with the  Company to defer such  payment as
provided in the following  sentence.  The Participant may elect (a) to defer the
lump sum payment  for one or more years up to a maximum of five years  following
Termination  or (b) to  receive  payment  of the Stock  Units in up to 10 annual
installments commencing within 10 days after Termination or the deferred payment
date  elected by the  Participant  pursuant  to part (a) of this  sentence.  The
election to defer payment beyond the  Participant's  Termination must be made at
least one year prior to such Termination.

6.2 Manner of Payment Upon Death

Notwithstanding  the Participant's  election,  if a Participant dies while Stock
Units are held in the Participant's Account, such Stock Units, whether vested or
unvested and forfeitable, will be paid in a lump sum in cash within 90 days from
the date of the  Participant's  death to the  Beneficiary  or the  Participant's
estate,  as the case may be. Upon  application  of the  Beneficiary or the legal
representative of the Participant's estate, the lump sum payment may be deferred
beyond 90 days for good cause if the Committee consents to such deferral.

6.3 Determination

Any cash payments of Stock Units shall be calculated on the basis of the average
of the Market  Value of the Common  Stock for the last 20 trading  days prior to
the  Participant's   Termination,   deferred   distribution   date,   respective
installment  payment dates or the date of the  Participant's  death, as the case
may be.

                                    Article 7
                             Beneficiary Designation

Each  Participant  shall be entitled to designate a Beneficiary or Beneficiaries
(which  may be an  entity  other  than a  natural  person)  who,  following  the
Participant's  death,  will be entitled to receive any payments to be made under
Section 6.2. At any time, and from time to time, any  designation may be changed
or  cancelled by the  Participant  without the consent of any  Beneficiary.  Any
designation,  change,  or cancellation  must be by written notice filed with the
Company and shall not be effective until received by the Company.  Payment shall
be made in accordance with the last unrevoked written designation of Beneficiary
that has been signed by the  Participant and delivered by the Participant to the
Company prior to the  Participant's  death. If the  Participant  designates more
than one Beneficiary,  any payments under Section 6.2 to the Beneficiaries shall
be made in equal shares unless the  Participant  has  designated  otherwise,  in
which  case the  payments  shall be made in the  proportions  designated  by the
Participant.  If no  Beneficiary  has been  named by the  Participant  or if all
Beneficiaries  predecease  the  Participant,   payment  shall  be  made  to  the
Participant's estate.


                                    Article 8
                          Transferability Restrictions

The Plan shall not in any  manner be liable  for,  or subject  to, the debts and
liabilities of any Participant or  Beneficiary.  No payee may assign any payment
due such party under the Plan.  No benefits at any time  payable  under the Plan
shall be subject  in any manner to  anticipation,  alienation,  sale,  transfer,
assignment, pledge, attachment,  garnishment, levy, execution, or other legal or
equitable process, or encumbrance of any kind.


                                    Article 9
                                 Funding Policy

The Company's  obligations  under the Plan shall be totally unfunded so that the
Company or any  Subsidiary is under merely a  contractual  duty to make payments
when due under the Plan.  The promise to pay shall not be  represented  by notes
and shall not be secured in any way.


                                   Article 10
                                Change in Control

Notwithstanding  any  provision  of this Plan to the  contrary,  if a "Change in
Control"  (as  defined  below) of the  Company  occurs,  Stock  Units  held in a
Participant's Account, whether vested or unvested and forfeitable,  will be paid
in a lump sum in cash to the  Participant  not later than 15 days after the date
of the Change in Control.  For this purpose, the balance in the Account shall be
determined  by the higher of (a) the  average of the Market  Value of the Common
Stock for the last 20 trading days prior to such Change in Control or (b) if the
Change in  Control  of the  Company  occurs as a result of a tender or  exchange
offer or  consummation of a corporate  transaction,  then the highest price paid
per share of Common Stock pursuant thereto.  Any  consideration  other than cash
forming  a part or all of the  consideration  for the  Common  Stock  to be paid
pursuant to the applicable  transaction  shall be valued at the valuation  price
thereon determined by the Board.

In addition,  the Company shall  reimburse a Participant  for the legal fees and
expenses  incurred if the  Participant  is required to seek to obtain or enforce
any  right  to  distribution.  In the  event  that it is  determined  that  such
Participant  is  properly  entitled  to  a  cash  distribution  hereunder,  such
Participant  shall also be  entitled  to  interest  thereon at the prime rate of
interest as published in The Wall Street  Journal plus two percent from the date
such  distribution  should have been made to and  including the date it is made.
Notwithstanding  any provisions of this Plan to the contrary,  the provisions of
this  Article may not be amended by an  amendment  effected  within  three years
following a Change in Control.

A "Change in Control" of the Company shall be deemed to have occurred if (a) any
"person" or "group"  (as such terms are used in Sections  13(d) and 14(d) of the
Securities  Exchange Act of 1934,  as amended  ("Exchange  Act")),  other than a
trustee or other fiduciary holding  securities under an employee benefit plan of
the Company,  becomes the "beneficial owner" (as defined in Rule 13d-3 under the
Exchange  Act),  directly  or  indirectly,  of more than 25  percent of the then
outstanding  voting  stock  of  the  Company;  (b)  during  any  period  of  two
consecutive  years,  individuals who at the beginning of such period  constitute
the Board,  together with any new  Directors  whose  election or nomination  for
election was approved by a vote of at least  two-thirds  of the  Directors  then
still in office who were  either  Directors  at the  beginning  of the period or
whose election or nomination for election was previously so approved,  cease for
any reason to constitute at least a majority of the Board;  or (c) the Company's
shareholders  approve a merger or  consolidation  of the Company  with any other
corporation,  other than a merger or  consolidation  which  would  result in the
voting  securities  of  the  Company   outstanding   immediately  prior  thereto
continuing to represent  (either by remaining  outstanding or by being converted
into voting securities of the surviving entity) at least 75 percent of the total
voting  power  represented  by the  voting  securities  of the  Company  or such
surviving entity outstanding immediately after such merger or consolidation;  or
(d) the  shareholders of the Company  approve a plan of complete  liquidation of
the Company,  or an agreement for the sale or disposition by the Company (in one
transaction  or a series of  transactions)  of all or  substantially  all of the
Company's assets.

Notwithstanding the foregoing,  a Change in Control shall not be deemed to occur
as a result of any event  described in (a) or (c) above, if Directors who were a
majority  of the  members of the Board  prior to such event and who  continue to
serve as  Directors  after  such  event  determine  that  the  event  shall  not
constitute a Change in Control.


                                   Article 11
                                 Administration

The Plan  shall be  administered  by the  Committee.  The  Committee  shall have
authority to interpret the Plan,  and to prescribe,  amend and rescind rules and
regulations   relating  to  the   administration  of  the  Plan,  and  all  such
interpretations,  rules and  regulations  shall be conclusive and binding on all
Participants. The Committee may employ agents, attorneys,  accountants, or other
persons (who also may be employees of a Subsidiary)  and allocate or delegate to
them powers,  rights, and duties, all as the Committee may consider necessary or
advisable to properly carry out the administration of the Plan.


                                   Article 12
                            Amendment and Termination

The Company,  by  resolution  duly  adopted by the Board,  shall have the right,
authority  and power to alter,  amend,  modify,  revoke,  or terminate the Plan;
except as provided in Article 10; and  provided  further,  that no  amendment or
termination  of the Plan shall  adversely  affect the rights of any  Participant
with respect to any Stock Units held in such Participant's  Account,  unless the
Participant shall consent thereto in writing.


                                   Article 13
                                  Miscellaneous

13.1 No Right to Continue as a Director

Nothing in this Plan shall be construed as  conferring  upon a  Participant  any
right to continue as a member of the Board.

13.2 No Interest as a Shareholder

Stock Units do not give a  Participant  any rights  whatsoever  with  respect to
shares of Common Stock.

13.3 No Right to Corporate Assets

Nothing  in this  Plan  shall  be  construed  as  giving  the  Participant,  the
Participant's  designated  Beneficiaries  or any  other  person  any  equity  or
interest of any kind in the assets of the Company or any  Subsidiary or creating
a trust of any kind or a fiduciary  relationship of any kind between the Company
or any  Subsidiary  and any person.  As to any claim for  payments due under the
provisions of the Plan, a Participant,  Beneficiary and any other persons having
a claim  for  payments  shall  be  unsecured  creditors  of the  Company  or any
Subsidiary.

13.4 Payment to Legal Representative for Participant

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

13.5 No Limit on Further Corporate Action

Nothing contained in the Plan shall be construed so as to prevent the Company or
any Subsidiary  from taking any corporate  action which is deemed by the Company
or any Subsidiary to be appropriate or in its best interest.

13.6 Governing Law

The Plan shall be construed and administered  according to the laws of the State
of New York to the extent that those laws are not  preempted  by the laws of the
United States of America.

13.7 Headings

The headings of articles,  sections,  subsections,  paragraphs or other parts of
the  Plan are for  convenience  of  reference  only  and do not  define,  limit,
construe, or otherwise affect its contents.



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>8
<FILENAME>x10o.txt
<DESCRIPTION>(O) CHANGE IN CONTROL AGREEMENT
<TEXT>

<PAGE>

                                                                   EXHIBIT 10(o)

                   AMERICAN ELECTRIC POWER SERVICE CORPORATION

                           CHANGE IN CONTROL AGREEMENT

                         FOR THE OFFICE OF THE CHAIRMAN

     Whereas,   American  Electric  Power  Service   Corporation,   a  New  York
corporation,   including   any   of   its   subsidiary   companies,   divisions,
organizations,  or  affiliated  entities  (collectively  referred to as "AEPSC")
considers  it  essential  to its best  interests  and the best  interests of the
shareholders  of  the  American  Electric  Power  Company,   Inc.,  a  New  York
corporation,  (hereinafter referred to as "Corporation") to foster the continued
employment of key management personnel; and

     Whereas,  the  uncertainty   attendant  to  a  Change  In  Control  of  the
Corporation  may result in the departure or distraction of management  personnel
to the detriment of AEPSC and the shareholders of the Corporation; and

     Whereas,  the Board of the  Corporation has determined that steps should be
taken to reinforce  and encourage  the  continued  attention  and  dedication of
members of AEPSC's  management to their assigned duties in the event of a Change
In Control of the Corporation.

     Now Therefore, AEPSC hereby establishes the American Electric Power Service
Corporation Change In Control Agreement (the "Agreement").

                                    ARTICLE I
                                   DEFINITIONS

     As used herein the  following  words and phrases  shall have the  following
respective meanings unless the context clearly indicates otherwise.

     (a) "Anniversary Date" means January 1 of each Calendar Year.

     (b) "Annual  Compensation"  means the sum of the Executive's  Annual Salary
and the Executive's Target Annual Incentive.

     (c)  "Annual  Salary"  means the  Executive's  regular  annual  base salary
immediately  prior  to the  Executive's  termination  of  employment,  including
compensation  converted  to other  benefits  under a  flexible  pay  arrangement
maintained  by AEPSC or deferred  pursuant to a written plan or  agreement  with
AEPSC, but excluding  allowances and  compensation  paid or payable under any of
AEPSC's long-term or short-term incentive plans or any similar payments.

     (d)  "Board"  means the  Board of  Directors  of  American  Electric  Power
Company, Inc.

     (e)  "Calendar  Year" means the twelve (12) month  period  commencing  each
January 1 and ending each December 31.

     (f) "Cause" shall mean

          (i) the  willful and  continued  failure of the  Executive  to perform
          substantially  the Executive's  duties with AEPSC (other than any such
          failure  resulting from incapacity due to physical or mental illness),
          after a written demand for substantial performance is delivered to the
          Executive  by  the  Board  or  an  elected   officer  of  AEPSC  which
          specifically  identifies  the manner in which the Board or the elected
          officer  believes that the Executive has not  substantially  performed
          the Executive's duties, or

          (ii) the willful engaging by the Executive in illegal conduct or gross
          misconduct which is materially and demonstrably  injurious to AEPSC or
          the  Corporation,  or a breach of the  Executive's  fiduciary  duty to
          AEPSC or the Corporation, as determined by the Board.

          For purposes of this provision,  no act or failure to act, on the part
     of the  Executive,  shall be  considered  "willful"  unless it is done,  or
     omitted to be done,  by the  Executive  in bad faith or without  reasonable
     belief that the Executive's action or omission was in the best interests of
     AEPSC or the Corporation.  Any act, or failure to act, based upon authority
     given pursuant to a resolution duly adopted by the Board or upon the advice
     of counsel for AEPSC or the Corporation,  shall be conclusively presumed to
     be done,  or omitted to be done,  by the Executive in good faith and in the
     best interests of AEPSC or the Corporation

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

     (h) "Code" means the Internal Revenue Code of 1986, as amended from time to
time.

     (i) "Commencement Date" means January 1, 2002, which shall be the beginning
date of the term of this Agreement.

     (j) "Disability" means the Executive's total and permanent disability
as defined in AEPSC's long-term disability plan covering the Executive
immediately prior to the Change In Control.

     (k) "Executive" means an employee of AEPSC who is designated by AEPSC as an
employee entitled to benefits, if any, under the terms of this Agreement.

     (l) "Good Reason" means;

          (1)  an  adverse  change  in  the   Executive's   status,   duties  or
          responsibilities  as an  executive  of AEPSC as in effect  immediately
          prior to the Change In Control, provided that the Executive shall have
          given AEPSC  written  notice of the alleged  adverse  change and AEPSC
          shall have  failed to cure such change  within  thirty (30) days after
          its receipt of such notice;

          (2)  failure  of AEPSC to pay or  provide  the  Executive  in a timely
          fashion  the salary or  benefits  to which the  Executive  is entitled
          under any  employment  agreement  between  AEPSC and the  Executive in
          effect on the date of the  Change  In  Control,  or under any  benefit
          plans or policies in which the Executive was participating at the time
          of the Change In Control, provided that such failure was other than an
          isolated,  insubstantial and inadvertent action not taken in bad faith
          and which is remedied by the  Corporation  within eight days following
          notice from the Executive;

          (3) the reduction of the  Executive's  salary as in effect on the date
          of the Change In Control;

          (4) the taking of any action by AEPSC  (including the elimination of a
          plan without  providing  substitutes  therefore,  the reduction of the
          Executive's  awards  thereunder or failure to continue the Executive's
          participation therein) that would substantially diminish the aggregate
          projected  value of the  Executive's  awards or benefits under AEPSC's
          benefit plans or policies in which the Executive was  participating at
          the time of the Change In Control;

          (5) a failure by AEPSC or the Corporation to obtain from any successor
          the assent to this Agreement contemplated by Article IV hereof; or

          (6) the  relocation,  without the Executive's  prior approval,  of the
          office at which the  Executive  is to  perform  services  on behalf of
          AEPSC to a location  more than  fifty  (50)  miles  from its  location
          immediately  prior to the Change In Control or a change,  without  the
          Executive's  prior  approval,   in  the  Executive's  business  travel
          obligation  subsequent  to the Change In  Control  that  requires  the
          Executive  to travel on a regular  and  continuous  basis in an amount
          that represents a significant increase,  from immediately prior to the
          Change In Control,  in the  portion of the  Executive's  working  time
          routinely devoted to business travel.

          Any circumstance described in this Article I (l) shall constitute Good
     Reason even if such circumstance  would not constitute a breach by AEPSC of
     the terms of an  employment  agreement  between  AEPSC and the Executive in
     effect on the date of the Change In Control.  The Executive shall be deemed
     to have terminated  employment for Good Reason effective upon the effective
     date stated in a written notice of such termination  given by the Executive
     to AEPSC (which notice shall not be given,  in  circumstances  described in
     Article I (1),  before  the end of the  thirty  (30) day  period  described
     therein, or in circumstances  described in Article I (l)(2), before the end
     of the eight day period  described  therein),  setting  forth in reasonable
     detail  the  facts  and  circumstances  claimed  to  provide  the basis for
     termination,  provided that the effective date may not precede, nor be more
     than sixty (60) days from, the date such notice is given.  The  Executive's
     continued employment shall not constitute consent to, or a waiver of rights
     with respect to, any circumstances constituting Good Reason hereunder.

     (m) "Retirement" shall mean an Executive's  termination of employment after
attainment of age 55 with five or more years of service with AEPSC.

     (n) "Target Annual Incentive" shall mean the award that the Executive would
have  received  under the Senior  Officer  Annual  Incentive  Compensation  Plan
("SOIP") or the Management Incentive  Compensation Plan ("MICP") for the year in
which the Executive's  termination  occurs, if one hundred percent (100%) of the
annual  target  award  has  been  earned.  Executives  participating  in  annual
incentive  compensation  plans that do not have predefined target levels will be
treated as though they were  participants in either the SOIP or MICP and will be
assigned  the same  annual  target  percent  as their  participating  peers in a
comparable salary grade.

     (o) "Qualifying  Termination"  shall mean following a Change In Control and
during the term of this Agreement the  Executive's  employment is terminated for
any reason excluding (i) the Executive's death, (ii) the Executive's Disability,
(iii)  the  Executive's  Retirement,  (iv)  by  AEPSC  for  Cause  or (v) by the
Executive  without Good Reason. In addition,  a Qualifying  Termination shall be
deemed to have  occurred  if,  prior to a Change  In  Control,  the  Executive's
employment  was  terminated  during the term of this  Agreement by AEPSC without
Cause, or by the Executive for Good Reason based on events or circumstances that
occurred,  (i) at the request of a person who has entered into an agreement with
AEPSC or the Corporation, the consummation of which would constitute a Change In
Control or (ii) otherwise in connection  with, as a result of or in anticipation
of a Change In Control.  The mere act of approving a Change In Control agreement
shall not in and of itself be deemed to constitute an event or  circumstance  in
anticipation of a Change In Control for purposes of this Article I (o).

                                   ARTICLE II
                                TERM OF AGREEMENT

     2.1 The initial term of this Agreement shall be for the period beginning on
the  Commencement  Date and ending on the December 31 immediately  following the
Commencement  Date. The term of this Agreement shall  automatically  be extended
for an  additional  Calendar  Year on the  first  Anniversary  Date  immediately
following the initial term of this  Agreement  without  further action by AEPSC,
and shall be  automatically  extended for an  additional  Calendar  Year on each
succeeding  Anniversary  Date,  unless  AEPSC shall have served  notice upon the
Executive  at least  sixty (60) days prior to such  Anniversary  Date of AEPSC's
intention that this Agreement shall not be extended,  provided, however, that if
a Change In  Control  of the  Corporation  shall  occur  during the term of this
Agreement, this Agreement shall terminate two years after the date the Change In
Control is completed.

     2.2 If an employee is  designated  as an Executive  after the  Commencement
Date or after an Anniversary  Date, the initial term of this Agreement  shall be
for the period  beginning on the date the employee is designated as an Executive
and ending on the December 31 immediately following.

     2.3 Notwithstanding  Section 2.1, the term of this Agreement shall end upon
any  termination of the Executive's  employment  prior to a Change In Control of
the Corporation. This Agreement shall also terminate if the Executive's position
is eliminated due to a downsizing, consolidation or restructuring of AEPSC other
than by reason of a Change In Control.

                                   ARTICLE III
         COMPENSATION UPON A CHANGE IN CONTROL FOLLOWED BY A TERMINATION

     3.1 Upon a Qualifying Termination,  the Executive shall be under no further
obligation  to perform  services  for AEPSC and shall be entitled to receive the
following payments and benefits:

     (a)  As soon as practicable  following the Executive's date of termination,
          AEPSC shall make a lump sum cash payment to the Executive in an amount
          equal to the sum of (1) the Executive's Annual Salary through the date
          of termination to the extent not theretofore  paid, (2) the product of
          (x)  the  current  plan  year's  Target  Annual  Incentive  and  (y) a
          fraction,  the  numerator  of  which  is the  number  of  days in such
          calendar year through the date of termination,  and the denominator of
          which is 365,  except  that annual  incentive  plans which do not have
          predetermined  annual target awards for participants  shall have their
          pro-rated incentive  compensation award for the current plan year paid
          as soon as practicable, and (3) any accrued vacation pay, in each case
          the extent not theretofore paid and in full satisfaction of the rights
          of the Executive thereto;

     (b)  Within sixty (60) days of the Executive's return of the signed release
          form,  AEPSC shall make a lump sum cash payment to the Executive in an
          amount equal to three times the Executive's Annual Compensation; and

     (c)  For purposes of the American  Electric  Power  System  Excess  Benefit
          Plan,  or any  successor  thereto,  provided  that the  Executive is a
          participant thereunder, the Executive shall be credited with three (3)
          additional  years of service;  provided that if the Executive is older
          than age 62 as of the  Executive's  date of termination the additional
          years of  service  shall be  limited  to the  difference  between  the
          Executive's  age as of the  date  of  termination  and  the  date  the
          Executive  would  attain age 65,  and  assuming  that the  Executive's
          compensation  for the  additional  period of  service  would have been
          equal to the Executive's  compensation in effect as of the Executive's
          date of termination.

     3.2 The Executive shall be entitled to the continuing benefits as follows:

     (a)  For the  three  (3) year  period  following  the  Executive's  date of
          termination,  the  Executive  and  the  Executive's  family  shall  be
          provided  with  medical  and  dental  insurance  benefits  as  if  the
          Executive's  employment had not been  terminated;  provided,  however,
          that if the Executive becomes  reemployed with another employer and is
          eligible to receive  medical or other welfare  benefits  under another
          employer-provided   plan,  the  medical  and  other  welfare  benefits
          described herein shall be secondary to those provided under such other
          plan during such  applicable  period of  eligibility.  For purposes of
          determining eligibility (but not the time of commencement of benefits)
          of the Executive  for retiree  medical and dental  insurance  benefits
          under AEPSC's plans,  practices,  programs and policies, the Executive
          shall be  considered to have  remained  employed  during the three (3)
          year period and to have  retired on the last day of the three (3) year
          period;

     (b)  AEPSC shall,  at its sole expense as incurred,  provide the  Executive
          with  outplacement  services  the scope and provider of which shall be
          selected by the Executive at the Executive's sole discretion (but at a
          cost to AEPSC of not more than $30,000) or, at the Executive's option,
          the use of comparable and accessible office space, office supplies and
          equipment  and  secretarial  services  for a period  not to exceed one
          year, which in the aggregate are of comparable cost to the Corporation
          or AEPSC as the outplacement services;

     (c)  To the extent any benefits  described in this Article III, Section 3.2
          cannot  be  provided  pursuant  to the  appropriate  plan  or  program
          maintained by AEPSC,  AEPSC shall  provide such benefits  outside such
          plan or program at no additional  cost (including  without  limitation
          tax cost) to the Executive.

     3.3 Notwithstanding the foregoing;

     (a)  The severance  payments and benefits  provided under Sections  3.1(b),
          3.1(c)  and  3.2  hereof  shall  be  conditioned  upon  the  Executive
          executing  a  release  at  the  time  the  Executive's  employment  is
          terminated,  in the form  established by the  Corporation or by AEPSC,
          releasing the  Corporation,  AEPSC and their  shareholders,  partners,
          officers, directors,  employees and agents from any and all claims and
          from any and all causes of action of kind or character,  including but
          not  limited  to  all  claims  or  causes  of  action  arising  out of
          Executive's   employment   with  the   Corporation  or  AEPSC  or  the
          termination of such employment.

     (b)  The severance  payments and benefits  provided  under Sections 3.1 and
          3.2 hereof shall be subject to, and  conditioned  upon,  the waiver of
          any other cash severance  payment or other benefits  provided by AEPSC
          pursuant  to any  other  severance  agreement  between  AEPSC  and the
          Executive.  No amount shall be payable under this  Agreement to, or on
          behalf of the Executive,  if the Executive  elects  benefits under any
          other  cash  severance  plan or  program,  or any  other  special  pay
          arrangement  with  respect  to  the  termination  of  the  Executive's
          employment.

     (c)  The  Executive  agrees that at all times  following  termination,  the
          Executive will not,  without the prior written consent of AEPSC or the
          Corporation,   disclose  to  any  person,   firm  or  corporation  any
          "confidential  information," of AEPSC or the Corporation  which is now
          known to the  Executive  or which  hereafter  may become  known to the
          Executive as a result of the  Executive's  employment  or  association
          with AEPSC or the  Corporation,  unless  such  disclosure  is required
          under the terms of a valid and effective subpoena or order issued by a
          court or  governmental  body;  provided,  however,  that the foregoing
          shall not apply to  confidential  information  which becomes  publicly
          disseminated  by means  other than a breach of this  provision.  It is
          recognized  that damages in the event of breach of this Section 3.3(c)
          by the Executive would be difficult, if not impossible,  to ascertain,
          and it is therefore agreed that AEPSC and the Corporation, in addition
          to and without  limiting  any other  remedy or right that AEPSC or the
          Corporation  may have,  shall have the right to an injunction or other
          equitable relief in any court of competent jurisdiction, enjoining any
          such breach,  and the Executive hereby waives any and all defenses the
          Executive may have on the ground of lack of jurisdiction or competence
          of the court to grant such an  injunction or other  equitable  relief.
          The  existence  of  this  right  shall  not  preclude   AEPSC  or  the
          Corporation  from  pursuing  any other rights or remedies at law or in
          equity which AEPSC or the Corporation may have.

          "Confidential information" shall mean any confidential,  propriety and
          or trade secret information,  including, but not limited to, concepts,
          ideas, information and materials relating to AEPSC or the Corporation,
          client  records,   client  lists,  economic  and  financial  analysis,
          financial data, customer contracts, marketing plans, notes, memoranda,
          lists, books,  correspondence,  manuals, reports or research,  whether
          developed by AEPSC or the  Corporation  or developed by the  Executive
          acting  alone or  jointly  with  AEPSC or the  Corporation  while  the
          Executive was employed by AEPSC.

     3.4  Notwithstanding  anything to the  contrary in this  Agreement,  in the
event that any  payment or  distribution  by AEPSC to or for the  benefit of the
Executive,  whether paid or payable or distributed or distributable  pursuant to
the terms of this Agreement or otherwise (a "Payment"),  would be subject to the
excise tax imposed by Section 4999 of the Code or any interest or penalties with
respect to such excise tax (such excise tax,  together with any such interest or
penalties,  are hereinafter collectively referred to as the "Excise Tax"), AEPSC
shall pay to the  Executive an additional  payment (a "Gross-up  Payment") in an
amount such that after  payment by the  Executive  of all taxes  (including  any
interest or penalties imposed with respect to such taxes),  including any Excise
Tax imposed on any  Gross-up  Payment,  the  Executive  retains an amount of the
Gross-up  Payment equal to the Excise Tax imposed upon the  Payments.  AEPSC and
the  Executive  shall  make an  initial  determination  as to whether a Gross-up
Payment is required and the amount of any such Gross-up Payment. Executive shall
notify AEPSC immediately in writing of any claim by the Internal Revenue Service
which,  if  successful,  would  require  AEPSC to make a Gross-up  Payment (or a
Gross-up  Payment in excess of that, if any,  initially  determined by AEPSC and
the Executive) within five days of the receipt of such claim. AEPSC shall notify
the  Executive  in  writing  at  least  five  days  prior to the due date of any
response  required  with  respect to such  claim,  or such  shorter  time period
following  AEPSC's  receipt of the notice,  if it plans to contest the claim. If
AEPSC decides to contest such claim,  the Executive  shall  cooperate fully with
AEPSC in such action;  provided,  however,  AEPSC shall bear and pay directly or
indirectly all costs and expenses (including  additional interest and penalties)
incurred  in  connection  with  such  action  and shall  indemnify  and hold the
Executive  harmless,  on an after-tax  basis,  for any Excise Tax or income tax,
including  interest and penalties with respect  thereto,  imposed as a result of
AEPSC's action.  If, as a result of AEPSC's action with respect to a claim,  the
Executive  receives  a refund of any amount  paid by AEPSC with  respect to such
claim,  the Executive shall promptly pay such refund to AEPSC. If AEPSC fails to
timely  notify  the  Executive  whether  it will  contest  such  claim  or AEPSC
determines not to contest such claim,  then AEPSC shall  immediately  pay to the
Executive the portion of such claim, if any, which it has not previously paid to
the Executive.

     3.5 The obligations of AEPSC to pay the benefits  described in Sections 3.1
and 3.2 shall be  absolute  and  unconditional  and shall not be affected by any
circumstances,   including,  without  limitation,  any  set-off,   counterclaim,
recoupment,  defense or other right which AEPSC may have against the  Executive.
In no event shall the  Executive be obligated to seek other  employment  or take
any other action by way of  mitigation  of the amounts  payable to the Executive
under any of the  provisions  of this  Agreement,  nor  shall the  amount of any
payment  hereunder be reduced by any  compensation  earned by the Executive as a
result of employment by another  employer,  except as  specifically  provided in
Section 3.2.

                                   ARTICLE IV
                            SUCCESSOR TO CORPORATION

     4.1 This  Agreement  shall bind any successor of AEPSC or the  Corporation,
its assets or its businesses (whether direct or indirect,  by purchase,  merger,
consolidation or otherwise) in the same manner and to the same extent that AEPSC
or the Corporation  would be obligated under this Agreement if no succession had
taken place.

     4.2 In the case of any  transaction  in which a successor  would not by the
foregoing provision or by operation of law be bound by this Agreement, AEPSC and
the Corporation shall require such successor  expressly and  unconditionally  to
assume and agree to perform AEPSC's and the Corporation's obligations under this
Agreement,  in the  same  manner  and to the  same  extent  that  AEPSC  and the
Corporation  would be required to perform if no such succession had taken place.
The term "Corporation," as used in this Agreement, shall mean the Corporation as
hereinbefore  defined and any successor or assignee to the business assets which
by reason hereof becomes bound by this Agreement.

                                    ARTICLE V
                                  MISCELLANEOUS

     5.1 Any notices and all other  communications  provided for herein shall be
in writing and shall be deemed to have been duly given when delivered or mailed,
by certified or registered  mail,  return  receipt  requested,  postage  prepaid
addressed  to  AEPSC  at  its  principal  office  and to  the  Executive  at the
Executive's residence or at such other addresses as AEPSC or the Executive shall
designate in writing.

     Section 5.2 No  provision  of this  Agreement  may be  modified,  waived or
discharged  except in a writing  specifically  referring to such  provision  and
signed  by  either  AEPSC or the  Executive  against  whom  enforcement  of such
modification,  waiver or discharge  is sought.  No waiver by either AEPSC or the
Executive of the breach of any condition or provision of this Agreement shall be
deemed a waiver of any other  condition  or  provision  at the same or any other
time.

     5.3 The validity,  interpretation,  construction  and  performance  of this
Agreement shall be governed by the laws of the State of Ohio.

     5.4 The invalidity or  unenforceability  of any provision of this Agreement
shall not affect the validity or  enforceability  of any other provision of this
Agreement, which shall remain in full force and effect.

     5.5 This  Agreement  does not constitute a contract of employment or impose
on the  Executive,  AEPSC  or the  Corporation  any  obligation  to  retain  the
Executive as an employee, to change the status of the Executive's employment, or
to change AEPSC's policies regarding the termination of employment.

     5.6 If the  Executive  institutes  any legal action in seeking to obtain or
enforce  or  is  required  to  defend  in  any  legal  action  the  validity  or
enforceability  of, any right or benefit provided by this Agreement,  AEPSC will
pay for all actual and reasonable legal fees and expenses incurred (as incurred)
by the Executive,  regardless of the outcome of such action; provided,  however,
that if such action instituted by the Executive is found by a court of competent
jurisdiction to be frivolous,  the Executive shall not be entitled to legal fees
and  expenses  and shall be liable to AEPSC for  amounts  already  paid for this
purpose.

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



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>9
<FILENAME>x10r2.txt
<DESCRIPTION>10(R)(2)  RESOLUTIONS OF CSW
<TEXT>

<PAGE>

                                                                EXHIBIT 10(r)(2)

                         CERTIFIED COPY OF A RESOLUTION

                          OF THE BOARD OF DIRECTORS OF

                       CENTRAL AND SOUTH WEST CORPORATION


     RESOLVED: That the Board of Directors of Central and South West Corporation
     hereby authorizes the appropriate  officers of the Corporation to establish
     additional  pension  benefits  through  the  Central  and South West System
     Special  Executive  Retirement Plan, which shall contain  substantially the
     same  terms  and  conditions  as are set out in the  said  plan  which  has
     heretofore  been  approved  by the Board of  Directors,  a copy of which is
     attached to these minutes and incorporated herein by reference.

     It is the intent of this Board of Directors, by taking this action, to:

          1.   Grant to Thomas V.  Shockley,  III  additional  years of credited
               service in excess of the actual credited service earned under the
               Central and South West System Pension Plan.

          2.   Provide for payment of pension benefits for retirement commencing
               at age 60 or later based on thirty years of credited service less
               benefits  payable under the basic Pension Plan in accordance with
               the provisions of the Special Executive Retirement Plan.

     FURTHER RESOLVED: That the Board of Directors approves and ratifies any and
     all actions  heretofore taken in connection with this plan on behalf of Mr.
     Thomas V.  Shockley,  III. This  resolution  and the  authorization  herein
     contained shall become effective immediately.

I, Thomas S. Ashford, do hereby certify that I am Secretary of Central and South
West Corporation,  a Delaware corporation,  and as such Secretary and the keeper
of the corporate records and seal of said Corporation,  and as said Secretary, I
do hereby  further  certify  that the above and  foregoing is a true and correct
copy of a  certain  resolution  as the same  appears  upon the  records  of said
Corporation  duly  adopted by the Board of Directors  of said  Corporation  at a
meeting of said Board duly  called and held on the 18th day of April,  1991,  at
which meeting a quorum of said Board was present and voting throughout.


IN WITNESS  WHEREOF,  I have  hereunto  set my hand and affixed the seal of said
Corporation this 19th day of March, 2002.



                              /s/Thomas S. Ashford
                                 Secretary

SEAL

</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-12
<SEQUENCE>10
<FILENAME>x12.txt
<TEXT>
<PAGE>
<TABLE>
                                                                                                  EXHIBIT 12
                      AMERICAN ELECTRIC POWER COMPANY, INC.
                       Ratio of Earnings to Fixed Charges
                         (in millions except ratio data)
<CAPTION>
                                                                      Year Ended December 31,
                                                           1997       1998       1999      2000       2001
<S>                                                       <C>        <C>       <C>        <C>        <C>
Fixed Charges:
  Interest on Long-term Debt . . . . . . . . . . . .      $  698     $  682    $  773     $  768     $  733
  Interest on Short-term Debt. . . . . . . . . . . .         107        134       149        259        148
  Miscellaneous Interest Charges . . . . . . . . . .          50         77        77        161        132
  Estimated Interest Element in Lease Rentals. . . .         221        222       212        223        223
  Preferred Stock Dividends. . . . . . . . . . . . .          45         29        28         32         15
        Total Fixed Charges. . . . . . . . . . . . .      $1,121     $1,144    $1,239     $1,443     $1,251

Earnings:
  Income Before Income Taxes . . . . . . . . . . . .      $1,414     $1,477    $1,468     $  899     $1,572
  Plus Fixed Charges (as above). . . . . . . . . . .       1,121      1,144     1,239      1,443      1,251
  Less Undistributed Earnings in Equity Investments.          36         42        46         46         28
       Total Earnings. . . . . . . . . . . . . . . .      $2,499     $2,579    $2,661     $2,296     $2,795

Ratio of Earnings to Fixed Charges . . . . . . . . .        2.22       2.25      2.14       1.59       2.23
</TABLE>




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-13
<SEQUENCE>11
<FILENAME>x13.txt
<TEXT>
2001 Annual Reports


American Electric Power Company, Inc.
AEP Generating Company
Appalachian Power Company
Central Power and Light Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
West Texas Utilities Company


Audited Financial Statements and
Management's Discussion and Analysis

<PAGE>
<TABLE>
<CAPTION>
                                    Contents
                                                                                                      Page
<S>                                                                                                  <C>
Glossary of Terms                                                                                        i

Forward Looking Information                                                                              iv

American Electric Power Company, Inc. and Subsidiary Companies
         Selected Consolidated Financial Data                                                           A-1
         Management's Discussion and Analysis of Results of Operations                                  A-2
         Consolidated Statements of Income                                                             A-12
         Consolidated Balance Sheets                                                                   A-13
         Consolidated Statements of Cash Flows                                                         A-15
         Consolidated Statements of Common Shareholders' Equity and                                    A-16
           Comprehensive Income
         Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries                          A-17
         Schedule of Consolidated Long-term Debt of Subsidiaries                                       A-18
         Index to Notes to Consolidated Financial Statements                                           A-19
         Management's Responsibility                                                                   A-20
         Independent Auditors' Report                                                                  A-21

AEP Generating Company
         Selected Financial Data                                                                        B-1
         Management's Narrative Analysis of Results of Operations                                       B-2
         Statements of Income and Statements of Retained Earnings                                       B-3
         Balance Sheets                                                                                 B-4
         Statements of Cash Flows                                                                       B-6
         Statements of Capitalization                                                                   B-7
         Index to Notes to Financial Statements                                                         B-8
         Independent Auditors' Report                                                                   B-9

Appalachian Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                           C-1
         Management's Discussion and Analysis of Results of Operations                                  C-2
         Consolidated Statements of Income and Consolidated Statements of                               C-7
           Comprehensive Income
         Consolidated Balance Sheets                                                                    C-8
         Consolidated Statements of Cash Flows                                                         C-10
         Consolidated Statements of Retained Earnings                                                  C-11
         Consolidated Statements of Capitalization                                                     C-12
         Schedule of Long-term Debt                                                                    C-13
         Index to Notes to Consolidated Financial Statements                                           C-14
         Independent Auditors' Report                                                                  C-15

Central Power and Light Company and Subsidiaries
         Selected Consolidated Financial Data                                                           D-1
         Management's Discussion and Analysis of Results of Operations                                  D-2
         Consolidated Statements of Income                                                              D-6
         Consolidated Balance Sheets                                                                    D-7
         Consolidated Statements of Cash Flows                                                          D-9
         Consolidated Statements of Retained Earnings                                                  D-10
         Consolidated Statements of Capitalization                                                     D-11
         Schedule of Long-term Debt                                                                    D-12
         Index to Notes to Consolidated Financial Statements                                           D-13
         Independent Auditors' Report                                                                  D-14


<PAGE>

Columbus Southern Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                           E-1
         Management's Narrative and Analysis of Results of Operations                                   E-2
         Consolidated Statements of Income and
            Consolidated Statements of Retained Earnings                                                E-6
         Consolidated Balance Sheets                                                                    E-7
         Consolidated Statements of Cash Flows                                                          E-9
         Consolidated Statements of Capitalization                                                     E-10
         Schedule of Long-term Debt                                                                    E-11
         Index to Notes to Consolidated Financial Statements                                           E-12
         Independent Auditors' Report                                                                  E-13

Indiana Michigan Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                           F-1
         Management's Discussion and Analysis of Results of Operations                                  F-2
         Consolidated Statements of Income and Consolidated Statements of                               F-7
             Comprehensive Income
         Consolidated Balance Sheets                                                                    F-8
         Consolidated Statements of Cash Flows                                                         F-10
         Consolidated Statements of Retained Earnings                                                  F-11
         Consolidated Statements of Capitalization                                                     F-12
         Schedule of Long-term Debt                                                                    F-13
         Index to Notes to Consolidated Financial Statements                                           F-15
         Independent Auditors' Report                                                                  F-16

Kentucky Power Company
         Selected Financial Data                                                                        G-1
         Management's Narrative Analysis of Results of Operations                                       G-2
         Statements of Income, Statements of Comprehensive Income                                       G-6
             and Statements of Retained Earnings
         Balance Sheets                                                                                 G-7
         Statements of Cash Flows                                                                       G-9
         Statements of Capitalization                                                                  G-10
         Schedule of Long-term Debt                                                                    G-11
         Index to Notes to Financial Statements                                                        G-12
         Independent Auditors' Report                                                                  G-13

Ohio Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                           H-1
         Management's Discussion and Analysis of Results of Operations                                  H-2
         Consolidated Statements of Income and Consolidated Statements of                               H-7
             Comprehensive Income
         Consolidated Balance Sheets                                                                    H-8
         Consolidated Statements of Cash Flows                                                         H-10
         Consolidated Statements of Retained Earnings                                                  H-11
         Consolidated Statements of Capitalization                                                     H-12
         Schedule of Long-term Debt                                                                    H-13
         Index to Notes to Consolidated Financial Statements                                           H-15
         Independent Auditors' Report                                                                  H-16

Public Service Company of Oklahoma and Subsidiaries
         Selected Consolidated Financial Data                                                           I-1
         Management's Narrative Analysis of Results of Operations                                       I-2
         Consolidated Statements of Income and
            Consolidated Statements of Retained Earnings                                                I-5
         Consolidated Balance Sheets                                                                    I-6
         Consolidated Statements of Cash Flows                                                          I-8
         Consolidated Statements of Capitalization                                                      I-9
         Schedule of Long-term Debt                                                                    I-10
         Index to Notes to Consolidated Financial Statements                                           I-11
         Independent Auditors' Report                                                                  I-12

Southwestern Electric Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                           J-1
         Management's Discussion and Analysis of Results of Operations                                  J-2
         Consolidated Statements of Income and
            Consolidated Statements of Retained Earnings                                                J-6
         Consolidated Balance Sheets                                                                    J-7
         Consolidated Statements of Cash Flows                                                          J-9
         Consolidated Statements of Capitalization                                                     J-10
         Schedule of Long-term Debt                                                                    J-11
         Index to Notes to Consolidated Financial Statements                                           J-12
         Independent Auditors' Report                                                                  J-13

West Texas Utilities Company
         Selected Financial Data                                                                        K-1
         Management's Narrative Analysis of Results of Operations                                       K-2
         Statements of Income and Statements of Retained Earnings                                       K-6
         Balance Sheets                                                                                 K-7
         Statements of Cash Flows                                                                       K-9
         Statements of Capitalization                                                                  K-10
         Schedule of Long-term Debt                                                                    K-11
         Index to Notes to Consolidated Financial Statements                                           K-12
         Independent Auditors' Report                                                                  K-13

Notes to Financial Statements                                                                           L-1

Management's Discussion and Analysis of Financial Condition,
    Contingencies and Other Matters                                                                     M-1
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                GLOSSARY OF TERMS
         When the following terms and abbreviations appear in the text of this
report, they have the meanings indicated below.

               Term                                Meaning
<S>                                 <C>
2004 True-up Proceeding............ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the
                                            amount of stranded costs and the recovery of such costs.
AEGCo.............................. AEP Generating Company, an electric utility subsidiary of AEP.
AEP................................ American Electric Power Company, Inc.
AEP Consolidated................... AEP and its majority owned subsidiaries consolidated.
AEP Credit,Inc.                     AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
                                            revenues for affiliated and unaffiliated domestic electric utility companies.
AEP East electric operating
companies.......................... APCo, CSPCo, I&M, KPCo and OPCo.
AEPR............................... AEP Resources, 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.
AEPSC.............................. American Electric Power Service Corporation, a service subsidiary providing management and
                                            professional services to AEP and its subsidiaries.
AEP Power Pool..................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo.  The Pool shares the
                                            generation, cost of generation and resultant wholesale system sales of the member
                                            companies.
AEP West electric operating
companies.......................... CPL, PSO, SWEPCo and WTU.
AFUDC.............................. Allowance for funds used during construction, a noncash nonoperating income item that is
                                            capitalized and recovered through depreciation over the service life of domestic
                                            regulated electric utility plant.
Alliance RTO....................... Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated
                                            utilities.
Amos Plant......................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and
                                            OPCo.
APCo............................... Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission................ Arkansas Public Service Commission.
Buckeye............................ Buckeye Power, Inc., an unaffiliated corporation.
CLECO.............................. Central Louisiana Electric Company, Inc., an unaffiliated corporation.
COLI............................... Corporate owned life insurance program.
Cook Plant......................... The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CPL................................ Central Power and Light Company, an AEP electric utility subsidiary.
CSPCo.............................. Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW...............................  Central and South West Corporation, a subsidiary of AEP.
CSW Energy......................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
                                            outside the United States.
D.C. Circuit Court................. The United States Court of Appeals for the District of Columbia Circuit.
DHMV............................... Dolet Hills Mining Venture.
DOE................................ United States Department of Energy.
ECOM............................... Excess Cost Over Market.
ENEC............................... Expanded Net Energy Costs.
EITF............................... The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT.............................. The Electric Reliability Council of Texas.
EWGs............................... Exempt Wholesale Generators.
FASB............................... Financial Accounting Standards Board.
Federal EPA........................ United States Environmental Protection Agency.
FERC............................... Federal Energy Regulatory Commission.
FMB ............................... First Mortgage Bond.
FUCOs.............................. Foreign Utility Companies.
GAAP............................... Generally Accepted Accounting Principles.
I&M................................ Indiana Michigan Power Company, an AEP electric utility subsidiary.
IPC................................ Installment Purchase Contract.
IRS................................ Internal Revenue Service.
IURC............................... Indiana Utility Regulatory Commission.
ISO................................ Independent system operator.
Joint Stipulation.................. Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding.
KPCo............................... Kentucky Power Company, an AEP electric utility subsidiary.
KPSC............................... Kentucky Public Service Commission.
KWH................................ Kilowatthour.
LIG................................ Louisiana Intrastate Gas.
Michigan Legislation............... The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
                                            customer choice of electricity supplier.
Midwest ISO........................ An independent operator of transmission assets in the Midwest.
MLR................................ Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool......................... AEP System's Money Pool.
MPSC............................... Michigan Public Service Commission.
MTN................................ Medium Term Notes.
MW................................. Megawatt.
MWH................................ Megawatthour.
NEIL............................... Nuclear Electric Insurance Limited.
Nox................................ Nitrogen oxide.
NOx Rule........................... A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states
                                            including seven of the states in which AEP companies operates.
NP................................. Notes Payable.
NRC................................ Nuclear Regulatory Commission.
Ohio Act........................... The Ohio Electric Restructuring Act of 1999.
Ohio EPA........................... Ohio Environmental Protection Agency.
OPCo..............................  Ohio Power Company, an AEP electric utility subsidiary.
OVEC............................... Ohio Valley Electric Corporation, an electric utility company in which AEP and  CSPCo own a
                                            44.2% equity interest.
PCBs............................... Polychlorinated Biphenyls.
PJM................................ Pennsylvania - New Jersey - Maryland regional transmission organization.
PRP..............................   Potentially Responsible Party.
PSO................................ Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO............................... The Public Utilities Commission of Ohio.
PUCT............................... The Public Utility Commission of Texas.
PUHCA.............................. Public Utility Holding Company Act of 1935, as amended.
PURPA.............................. The Public Utility Regulatory Policies Act of 1978.
RCRA............................... Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............ AEP subsidiaries who are SEC registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
                                            SWEPCo and WTU.
Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
                                            Indiana owned by AEGCo and I&M.
RTO................................ Regional Transmission Organization.
SEC................................ Securities and Exchange Commission.
SFAS............................... Statement of Financial Accounting Standards issued by the Financial Accounting Standards
                                            Board.
SFAS 71............................ Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain
                                            Types of Regulation.

<PAGE>


SFAS 101........................... Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of
                                            Application of Statement 71.
SFAS 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of
                                            Long-Lived Assets and for Long-Lived Assets to be Disposed of.
SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
                                            and Hedging Activities.
SNF................................ Spent Nuclear Fuel.
SPP................................ Southwest Power Pool.
STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light
                                            Company, an AEP electric utility subsidiary .
STPNOC............................. STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf
                                            of its joint owners including CPL.
Superfund.........................  The Comprehensive Environmental, Response, Compensation and Liability Act.
SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary.
Texas Appeals Court................ The Third District of Texas Court of Appeals.
Texas Legislation.................. Legislation enacted in 1999 to restructure the electric utility industry in Texas.
Travis District Court.............. State District Court of Travis County, Texas.
TVA ............................... Tennessee Valley Authority.
U.K................................ The United Kingdom.
UN................................. Unsecured Note.
VaR................................ Value at Risk, a method to quantify risk exposure.
Virginia SCC....................... Virginia State Corporation Commission.
WV................................. West Virginia.
WVPSC.............................. Public Service Commission of West Virginia.
WPCo............................... Wheeling Power Company, an AEP electric distribution subsidiary.
WTU................................ West Texas Utilities Company, an AEP electric utility subsidiary.
Yorkshire.......................... Yorkshire Electricity Group plc, a U.K. regional electricity company owned jointly by AEP
                                            and New Century Energies until April 2001.
Zimmer Plant....................... William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
                                            Southern Power Company, an AEP subsidiary.
</TABLE>
<PAGE>

FORWARD LOOKING INFORMATION

This discussion includes forward-looking statements within the meaning of
Section 21E of the Securities Exchange Act of 1934. These forward-looking
statements reflect assumptions, and involve a number of risks and uncertainties.
Among the factors both foreign and domestic that could cause actual results to
differ materially from forward looking statements are: electric load and
customer growth; abnormal weather conditions; available sources of and prices
for coal and gas; availability of generating capacity; risks related to energy
trading and construction under contract; the speed and degree to which
competition is introduced to our power generation business; the structure and
timing of a competitive market for electricity and its impact on prices, the
ability to


recover net regulatory assets, other stranded costs and implementation costs in
connection with deregulation of generation in certain states; the timing of the
implementation of AEP's restructuring plan; new legislation and government
regulations; the ability to successfully control costs; the success of new
business ventures; international developments affecting our foreign investments;
the economic climate and growth in our service and trading territories both
domestic and foreign; the ability of the Company to successfully challenge new
environmental regulations and to successfully litigate claims that the Company
violated the Clean Air Act; inflationary trends; litigation concerning AEP's
merger with CSW; changes in electricity and gas market prices and interest
rates; fluctuations in foreign currency exchange rates, and other risks and
unforeseen events.


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

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Selected Consolidated Financial Data
Year Ended December 31,                    2001           2000            1999            1998            1997
- -----------------------                    ----           ----            ----            ----            ----
<S>                                      <C>            <C>             <C>             <C>             <C>
INCOME STATEMENTS DATA (in millions):
Total Revenues                           $61,257        $36,706         $24,745         $18,420         $11,427
Operating Income                           2,395          2,004           2,304           2,258           2,180
Income Before Extraordinary Items
  and Cumulative Effect                    1,003            302             986             975             949
Extraordinary Losses                         (50)           (35)            (14)           -               (285)
Cumulative Effect of
  Accounting Change                           18           -               -               -               -
Net Income                                   971            267             972             975             664

Year Ended December 31,                    2001           2000            1999            1998            1997
- -----------------------                    ----           ----            ----            ----            ----
BALANCE SHEETS DATA (in millions):
Property, Plant and Equipment            $40,709        $38,088         $36,938         $35,655         $33,496
Accumulated Depreciation
  and Amortization                        16,166         15,695          15,073          14,136          13,229
                                          ------         ------          ------          ------          ------
     Net Property,
       Plant and Equipment               $24,543        $22,393         $21,865         $21,519         $20,267
                                         =======        =======         =======         =======         =======

Total Assets                             $47,281        $53,350         $35,693         $33,418         $30,092

Common Shareholders' Equity                8,229          8,054           8,673           8,452           8,220

Cumulative Preferred Stocks
  of Subsidiaries*                           156            161             182             350             377

Trust Preferred Securities                   321            334             335             335             335

Long-term Debt*                           12,053         10,754          11,524          11,113           9,354

Obligations Under Capital Leases*            451            614             610             539             549


Year Ended December 31,                    2001             2000            1999           1998           1997
- -----------------------                    ----             ----            ----           ----           ----
COMMON STOCK DATA:
Earnings per Common Share:
Before Extraordinary Item and
  Cumulative Effect                       $ 3.11           $0.94            $3.07         $3.06           $2.99
Extraordinary Losses                       (0.16)           (.11)            (.04)          -              (.90)
Cumulative Effect of
  Accounting Change                         0.06             -                -             -               -
                                            ----             ---              ---           ---             ---

Earnings Per Share                        $ 3.01           $0.83            $3.03         $3.06           $2.09
                                          ======           =====            =====         =====           =====

Average Number of Shares
  Outstanding (in millions)                  322             322              321           318             316

Market Price Range: High                  $51.20         $48-15/16       $48-3/16       $53-5/16           $ 52

                    Low                    39.25          25-15/16        30-9/16       42-1/16          39-1/8

Year-end Market Price                      43.53            46-1/2         32-1/8       47-1/16          51-5/8

Cash Dividends on Common**                 $2.40            $2.40           $2.40         $2.40           $2.40
Dividend Payout Ratio**                     79.7%           289.2%           79.2%         78.4%          114.8%
Book Value per Share                      $25.54           $25.01          $26.96        $26.46          $25.91
</TABLE>
The consolidated financial statements give retroactive effect to AEP's merger
with CSW, which was accounted for as a pooling of interests.

*Including portion due within one year **Based on AEP historical dividend rate.

<PAGE>


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Management's Discussion and Analysis of Results of Operations


     American Electric Power Company, Inc. (AEP) is one of the largest investor
owned electric public utility holding companies in the US. We provide
generation, transmission and distribution service to over 4.9 million retail
customers in eleven states (Arkansas, Indiana, Kentucky, Louisiana, Michigan,
Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia) through our
electric utility operating companies. We market and trade electricity and
natural gas in the US and Europe.

     We have a significant presence throughout the domestic energy value chain.
Our US electric assets include:
o        38,000 megawatts of generating capacity (the largest US generation
         portfolio with a significant cost advantage in the Midwest and
         Southwest markets);
o        38,000 miles of transmission lines and
o        186,000 miles of distribution lines

Our natural gas assets include:
o        128 Bcf of gas storage facilities
o        6,400 miles of gas pipelines in Louisiana and Texas which provide a
         basis for market knowledge.

With our coal and transportation assets we:
o        control over 7,000 railcars
o        control over 1,800 barges and 37 tug boats
o        operate two coal handling terminals with 20 million tons of capacity.
o        produce over 7 million tons of coal annually in the US.

AEP is one of the largest traders of electricity and natural gas in the US:
o        over 576 million MWH of electricity trades in 2001
o        over 3,800 billion cubic feet (Bcf) of gas trades in 2001

In addition we:
o        consume 80 million tons of coal annually
o        consume 310 Bcf of natural gas annually

AEP's focus is in the US but we also have smaller footprints in other parts of
the world:
o        a growing energy trading operation in Europe based in the UK.
o        4,000 megawatts of generating capacity in the United Kingdom which
         represents 16% of the UK's total generation capacity.

     Other foreign investments include distribution operations in the U.K.,
Australia, and Brazil. We have additional generating facilities in China and
Mexico. We also offer engineering and construction services worldwide.

Business Strategy

     Our strategy is a balanced business model of regulated and unregulated
businesses backed by assets, supported by enterprise-wide risk management and a
strong balance sheet. We have been focused on the wholesale side of the business
since it provides the greater growth opportunities. But, this is complemented by
a robust regulated business that has a predictable earnings stream and cash
flows. Strong risk management and a disciplined analysis of markets protected us
from the California energy crisis and Enron's bankruptcy filing.

     Our balanced business model is one where AEP integrates its assets,
marketing, trading and market analysis and resources to create a superior
knowledge about the commodity markets which keeps us a step ahead of our
competition. Our power, gas, coal, and barging assets and operations provide us
with market knowledge and customer connectivity giving us the ability to make
informed marketing and trading decision and to customize our products and
services.

     AEP provides investors with a balanced portfolio since it has:
o    a growing unregulated wholesale energy marketing and trading business
o    predictable cash flow and earnings streams from the regulated electricity
     business, and
o    a high dividend yield relative to today's low-interest rate environment.

     We are currently in the process of restructuring our assets and operations
to separate the regulated operations from the non-regulated operations.

     We filed with the SEC for approval to form two separate legal holding
company subsidiaries of AEP Co. Inc., the parent company. Approval is needed
from the SEC under the PUHCA and the FERC to make these organizational changes.
Certain state regulatory commissions have intervened in the FERC proceedings. We
have reached a settlement with those state commissions and are awaiting the
FERC's approval before the SEC will make a final ruling on our filing.

     We are implementing a corporate separation restructuring plan to support
our objective of unlocking shareholder value for our domestic businesses. Our
plan provides for:
o    transparency and clarity to investors,
o    a simpler structure to conduct business, and to anticipate and monitor
     performance,
o    compliance with states' restructuring laws promoting customer choice, and
o    more efficient financing.

     The new corporate structure will consist of a regulated holding company and
an unregulated holding company. The regulated holding company's investments will
be in integrated utilities and Ohio and Texas wires. The unregulated holding
company's investments will be in Ohio and Texas generation, independent power
producers, gas pipe line and storage, UK generation, barging, coal mining and
marketing and trading.

     The risks in our business are:
o    Margin erosion on electric trading as markets mature,
o    Diminished opportunities for signifi-cant gains as volatility declines,
o    Retail price reductions mandated with the implementation of customer choice
     in Texas and Ohio,
o    Movement towards re-regulation in California through market caps and
     other challenges to the continuation of deregulation of the retail
     electricity supply business in the U.S.,
o    The continued negative impact of a slowly recovering economy.

     Our business plan considers these risks and we believe that we can deliver
earnings growth of 6-8% annually across the energy value chain through the
disciplined integration of strategic assets and intellectual capital to generate
these returns for our shareholders.

     Our strategies to achieve our business plan are:
o        Unregulated
         o        Disciplined approach to asset acquisition and disposition
         o        Value-driven asset optimiz-ation through the linkage of
                  superior commercial, analytical and technical skills
         o        Broad participation across all energy markets with a
                  disciplined and opportunistic allocation of risk capital
         o        Continued investment in both technology and process
                  improvement to enhance our competitive advantage
         o        Continued expansion of intellectual capital through ongoing
                  recruiting, performance-linked compensation and the
                  development of a structure that promotes sound decision-making
                  and innovation at all levels.

o        Regulated
         o        Maintain moderate but steady earnings growth
         o        Maximize value of trans-mission assets and protect revenue
                  stream through RTO/Alliance membership
         o        Continue process improve-ment to maintain distribution
                  service quality while en-hancing financial performance
         o        Optimize generation assets through enhanced availability of
                  off-system sales
         o        Manage regulatory process to maximize retention of earnings
                  improvement

     Our significant accomplishments in 2001 were :
o        Adding the following assets to integrate with and support our trading
         and marketing competitive advantage:
         o        4,200 miles of gas pipeline, 118 Bcf gas storage and re-lated
                  gas marketing contracts
         o        1,200 hopper barges and 30 tugboats
         o        4,000 megawatts of coal-fired generation in England
         o        160 megawatts of wind generation in Texas
         o        coal mining properties, coal reserves, mining operations and
                  royalty interests in Colorado, Kentucky, Ohio, Pennsylvania
                  and West Virginia
o        Entering into new markets through the acquisition of existing contracts
         and hiring key staff including 57 employees from Enron's London based
         international coal trading group in December 2001 and Enron's Nordic
         energy trading group in January 2002. We now trade power and gas in the
         UK, France, Germany, and the Netherlands and coal throughout the world
o        Adding other energy-related  commodities to our power and gas portfolio
         i.e. coal, SO2 allowances,  natural gas liquids (NGLs)and oil
o        Disposing of the following assets that did not fit our strategy:
         o        120 MWs of generation in Mexico,
         o        Above market coal mines in Ohio and West Virginia,
         o        A 50 % investment in Yorkshire, a U.K. electric supply and
                  distribution company,
         o        An investment in a Chilean electric company
         o        Datapult, an energy information data and analysis tool.

     In  addition we sold 500 MWs of  generating  capacity in Texas under a FERC
order that approved our merger with CSW. Our divesture of  non-strategic  assets
is somewhat limited by the pooling of interest accounting  requirements  applied
to the merger of CSW and AEP in June 2000. We are presently  evaluating  certain
tele-communications  and foreign  investments for possible disposal and have not
yet decided  whether to dispose of such  investments.  Disposal  of  investments
determined to be non-strategic will be considered in accordance with the pooling
of  interests  restrictions  which  end  in  June  2002.  We  are  committed  to
continually  evaluate  the need to  reallocate  resources  to areas with greater
potential,  to match  investments with our strategy and to pare investments that
do  not  produce   sufficient  return  and  shareholder  value.  Any  investment
dispositions could affect future results of operations.

Outlook for 2002

     Growth in 2002 will be driven in part by our continued strategic
development of wholesale products and geographies, as demonstrated in recent
months by our move into global coal markets and Nordic energy. A full year of
operation of assets acquired in 2001 - Houston Pipe Line, Quaker Coal, the MEMCO
barge line and two power plants in the United Kingdom - will also contribute to
growth in 2002 earnings.

     Although we expect that the future outlook for results of operations is
excellent there are contingencies and challenges. We discuss these matters in
detail in the Notes to Financial Statements and in this Management's Discussion
and Analysis. We intend to work diligently to resolve these matters by finding
workable solutions that balance the interests of our customers, our employees
and our shareholders.

        As discussed above we expect to continue evaluating certain investments
for possible disposal due to either their non-strategic nature or limited future
earnings potential for AEP. Any dispositions could result in gains or losses
being recorded in our income statement.

<PAGE>

Results of Operations

     In 2001 AEP's principal operating business segments and their major
activities were:

o        Wholesale:
         o        Generation of electricity for sale to retail and wholesale
                  customers
         o        Gas pipeline and storage services
         o        Marketing and trading of electricity, gas and coal
         o        Coal mining, bulk commodity barging operations and other
                  energy supply related business.
o        Energy Delivery
         o        Domestic electricity trans-mission,
         o        Domestic electricity distri-bution
o        Other Investments
         o        Foreign electric distribution and supply investments,
         o        Telecommunication services.

Net Income

        Net income increased to $971 million or $3.01 per share from $267
million or $0.83 per share. The increase of $704 million or $2.18 per share was
due to the growth of AEP's wholesale marketing and trading business, increased
revenues and the controlling of our operating and maintenance costs in the
energy delivery business, and declining capital costs. Also contributing to the
earnings improvement in 2001 was the effect of 2000 charges for a disallowance
of COLI-related tax deductions, expenses of the merger with CSW, write-offs
related to non-regulated investments and restart costs of the Cook Nuclear
Plant. The favorable effect on comparative net income of these 2000 charges was
offset in part by current year losses from Enron's bankruptcy and extraordinary
losses for the effects of deregulation and a loss on reacquired debt.


        The decline in net income to $267 million or $0.83 per share in 2000
from $972 million or $3.03 per share in 1999 was primarily due to the 2000
charges described above and an extraordinary losses from the discontinuance of
regulatory accounting for generation in certain states.

        A strong performance in the first nine months of 2001 was partially
offset by unfavorable operating conditions in the fourth quarter. Extremely mild
November and December weather combined with weak economic conditions in the
fourth quarter, reduced retail energy sales and wholesale margins. Heating
degree days in the fourth quarter were down 33% from the same period in 2000.
Although the fourth quarter was disappointing, 2001 net income before
extraordinary items and cumulative effect of accounting change reached the $1
billion mark.

        Our wholesale business continues to perform well despite a slowing
economy that reduced both wholesale energy margins and energy use by industrial
customers. Our wholesale business, which includes generation, retail and
wholesale sales of power and natural gas and trading of power and natural gas
and natural gas pipeline and storage services, contributed to the earnings
increase by successfully returning the Cook Plant to service in 2000 and by
growing AEP's wholesale business.

        Our energy delivery business, which consists of domestic electricity
transmission and distribution services, contributed to the increase in earnings
by controlling operating and maintenance expenses and by increasing revenues.

        Capital costs decreased due primarily to interest paid to the IRS in
2000 on a COLI deduction disallowance and declining short-term market interest
rate conditions.

<PAGE>

Critical Accounting Policies
Revenue Recognition - Traditional Electricity Supply and Delivery Activities -
As the owner of cost-based rate-regulated electric public utility companies, AEP
Co., Inc.'s consolidated financial statements recognize revenues on an accrual
basis for traditional electricity supply sales and for electricity transmission
and distribution delivery services. These revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general, expenses are recorded when incurred. As a
result of our cost based rate regulated operations, our financial statements
reflect the actions of regulators that can result in the recognition of revenues
and expenses in different time periods than enterprises that are not rate
regulated. In accordance with SFAS 71, "Accounting for the Effects of Certain
Types of Regulation," regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching in the same accounting period
regulated expenses with their recovery through regulated revenues.

        When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.


           We discontinued application of SFAS 71 for the generation portion of
our business in Ohio for OPCo and CSPCo in September 2000, in Virginia and West
Virginia for APCo in June 2000, in Texas for CPL, WTU, and SWEPCo in September
1999 and in Arkansas for SWEPCo in September 1999 in recognition of the passage
of legislation to transition to customer choice and market pricing for the
supply of electricity. We recorded extraordinary losses when we discontinued the
application of SFAS 71. See Note 2, "Extraordinary Items and Cumulative Effect"
for additional information.

Wholesale Energy Marketing and Trading Activities - We engage in non-regulated
wholesale electricity and natural gas marketing and trading transactions
(trading activities). Trading activities involve the purchase and sale of energy
under forward contracts at fixed and variable prices and buying and selling
financial energy contracts which includes exchange futures and options and
over-the-counter options and swaps. Although trading contracts are generally
short-term, there are also long-term trading contracts. We recognize revenues
from trading activities generally based on changes in the fair value of energy
trading contracts.

           Recording the net change in the fair value of trading contracts as
revenues prior to settlement is commonly referred to as mark-to-market (MTM)
accounting. It represents the change in the unrealized gain or loss throughout
the contract's term. When the contract actually settles, that is, the energy is
actually delivered in a sale or received in a purchase or the parties agree to
forego delivery and receipt and net settle in cash, the unrealized gain or loss
is reversed out of revenues and the actual realized cash gain or loss is
recognized in revenues for a sale or in purchased energy expense for a purchase.

<PAGE>


Therefore, over the term of the trading contracts an unrealized gain or loss is
recognized as the contract's market value changes. When the contract settles the
total gain or loss is realized in cash but only the difference between the
accumulated unrealized net gains or losses recorded in prior months and the cash
proceeds is recognized. Unrealized mark-to-market gains and losses are included
in the Balance Sheet as energy trading and derivative contract assets or
liabilities as appropriate.

        The majority of our trading activities represent physical forward
electricity and gas contracts that are typically settled by entering into
offsetting contracts. An example of our trading activities is when, in January,
we enter into a forward sales contract to deliver electricity or gas in July. At
the end of each month until the contract settles in July, we would record any
difference between the contract price and the market price as an unrealized gain
or loss in revenues. In July when the contract settles, we would realize the
gain or loss in cash and reverse to revenues the previously recorded unrealized
gain or loss. Prior to settlement, the change in the fair value of physical
forward sale and purchase contracts is included in revenues on a net basis. Upon
settlement of a forward trading contract, the amount realized is included in
revenues for a sales contract and realized costs are included in purchased
energy expense for a purchase contract with the prior change in unrealized fair
value reversed in revenues.

        Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity or gas in July. If we do nothing else with these contracts
until settlement in July and if the commodity type, volumes, delivery point,
schedule and other key terms match then the difference between the sale price
and the purchase price represents a fixed value to be realized when the
contracts settle in July. If the purchase contract is perfectly matched with the
sales contract, we have effectively fixed the profit or loss; specifically it is
the difference between the contracted settlement price of the two contracts.
Mark-to-market accounting for these contracts will have no further impact on
operating results but has an offsetting and equal effect on trading contract
assets and liabilities. Of course we could also do similar transactions but
enter into a purchase contract prior to entering into a sales contract. If the
sale and purchase contracts do not match exactly as to commodity type, volumes,
delivery point, schedule and other key terms, then there could be continuing
mark-to-market effects on revenues from recording additional changes in fair
values using mark-to-market accounting.

        Trading of electricity and gas options, futures and swaps, represents
financial transactions with unrealized gains and losses from changes in fair
values reported net in revenues until the contracts settle. When these contracts
settle, we record the net proceeds in revenues and reverse to revenues the prior
unrealized gain or loss.

        The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on Company-developed valuation models. These models
estimate future energy prices based on existing market and broker quotes and
supply and demand market data and assumptions. The fair values determined are
reduced by reserves to adjust for credit risk and liquidity risk. Credit risk is
the risk that the counterparty to the contract will fail to perform or fail to
pay amounts due AEP. Liquidity risk represents the risk that imperfections in
the market will cause the price to be less than or more than what the price
should be based purely on supply and demand. There are inherent risks related to
the underlying assumptions in models used to fair value open long-term trading
contracts. We have independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the Company-developed price models.

        We also mark to market derivatives that are not trading contracts in
accordance with generally accepted accounting principles. Derivatives are
contracts whose value is derived from the market value of an underlying
commodity.

        Our revenues of $61 billion for 2001 included $257 million of unrealized
net gains from marking to market open trading and derivative contracts. AEP's
net revenues, (revenues less fuel and energy purchases) excluding mark-to-market
revenues totaled $8.3 billion and were realized during 2001. Unrealized net
mark-to-market revenues are only 3% of total net revenues. A significant portion
of the net unrealized revenues from marking to market trading contracts and
derivatives included in our balance sheet at December 31, 2001 as energy trading
and derivative contract assets and liabilities, will be realized in 2002.

        We defer as regulatory assets or liabilities the effect on net income of
marking to market open electricity trading contracts in our regulated
jurisdictions since these transactions are included in cost of service on a
settlement basis for ratemaking purposes. Changes in mark-to-market valuations
impact net income in our non-regulated business.

        Volatility in energy commodities markets affects the fair values of all
of our open trading and derivative contracts exposing AEP to market risk causing
our results of operations to be more volatile. See "Market Risks" section below
for a discussion of the policies and procedures AEP uses to manage its exposure
to market and other risks from trading activities.

Revenues Increase

        Our revenues have increased significantly from the marketing and trading
of electricity and natural gas. The level of electricity trading transactions
tends to fluctuate due to the highly competitive nature of the short-term (spot)
energy market and other factors, such as affiliated and unaffiliated generating
plant availability, weather conditions and the economy. The FERC's introduction
of a greater degree of competition into the wholesale energy market, has had a
major effect on the volume of wholesale power marketing and trading especially
in the short-term market.

        AEP's total revenues increased 66.9% in 2001 and 48.3% in 2000. The
following table shows the components of revenues in millions.
                       For The Year Ended
                           December 31
                       2001    2000    1999
                       ----    ----    ----
                           (in millions)
WHOLESALE BUSINESS:
  Residential        $ 3,553 $ 3,511 $ 3,290
  Commercial           2,328   2,249   2,083
  Industrial           2,388   2,444   2,515
  Other Retail
   Customers             419     414     394

  Electricity Marketing
   and Trading        35,339  18,858  11,417
  Gas Marketing and
   Trading            14,369   6,127   2,290
  Unrealized MTM Income:
    Electric             210      38       2
    Gas                   47     132      21
  Other                  632     838     599
  Less Transmission and
   Distribution Revenues
   Assigned to Energy
   Delivery*          (3,356) (3,174) (3,068)
                     ------- ------- -------

TOTAL WHOLESALE
  BUSINESS            55,929  31,437  19,543
                     ------- ------- -------

ENERGY DELIVERY
 BUSINESS:
  Transmission         1,029   1,009     960
  Distribution         2,327   2,165   2,108
                     ------- ------- -------

TOTAL ENERGY DELIVERY  3,356   3,174   3,068
                     ------- ------- -------

OTHER INVESTMENTS:
  SEEBOARD             1,451   1,596   1,705
  CITIPOWER              350     338     318
  Other                  171     161     111
                     ------- ------- -------
TOTAL OTHER
  INVESTMENTS          1,972   2,095   2,134
                     ------- ------- -------

TOTAL REVENUES       $61,257 $36,706 $24,745
                     ======= ======= =======

*Certain revenues in Wholesale business include energy delivery revenues due
primarily to bundled tariffs that are assignable to the Energy Delivery
business.

        The $25 billion increase in 2001 revenues was due to substantial
increases in electric and gas trading volumes. The increase in sales of
purchased power and purchased gas during the past two years reflect AEP's
intention to be a leading national wholesale energy merchant. Wholesale natural
gas trading volume for 2001 was 3,874 Bcf, a 178% increase from 2000 volume of
1,391 Bcf. Electric trading volume increased 48% to 576 million MWH. We have
invested in resources required to optimize our assets and emerge as a leader in
the industry. The maturing of the Intercontinental Exchange, the development of
proprietary tools, and the increased staffing of energy traders have faciliated
increased power and gas sales. Our June 2001 purchase of Houston Pipe Line
enhanced our gas trading and marketing operation. Although we will trade and
market only when we believe profitable opportunites exist, we expect the
increased level of activity to continue.

        While wholesale marketing and trading volumes rose, kilowatthour sales
to industrial customers decreased by 5% in 2001. This decrease was due to the
economic recession. In the fourth quarter, sales to residential, commercial and
wholesale customers declined 9%. The recession reduced demand and wholesale
prices especially in the fourth quarter.

        While margins available from selling power that the company generates
generally are higher than from selling purchased power, such sales are limited
by the amount of generating assets owned. Furthermore, the profit available from
simply selling excess generation is reduced by the inherent market transparency
of such sales. The coordinated sales of excess generation in conjunction with
trading and marketing activity optimizes assets, mitigates risk, and increases
overall profit.

        The $12 billion increase in 2000 revenues was primarily due to a 27%
increase in wholesale electricity trading volume and increased retail fuel
revenues as a result of higher gas prices used to generate electricity. The
reduction in industrial revenues in 2000 is attributable to the expiration of a
long-term contract on December 31, 1999. The significant increase in 2000
electricity trading volume, which accounted for a 66% increase in electricity
trading revenues, resulted from: o efforts to grow AEP's energy marketing and
trading operations, o favorable market conditions, and o the availability of
additional generation

        Generation availability improved due to the return to service of one of
the Cook Plant nuclear units in June 2000 and to improved outage management. The
second Cook Plant unit which returned to service in December 2000 did not have a
significant impact on 2000 revenues. Gas revenues increased in 2000 due to
increased natural gas and gas liquid product prices.

Operating Expenses Increase

        Changes in the components of operating expenses were as follows:

                      Increase (Decrease)
                      From Previous Year
                   -------------------------
(Dollars in Millions)   2001         2000
                        ----         ----
                   Amount   %   Amount   %
Fuel and Purchased
 Energy           $24,035  83.7 $11,474 66.5
Maintenance and
 Other Operation      196   5.1     565 17.2
Non-recoverable
 Merger Costs        (182)(89.7)    203  N.M.
Depreciation and
 Amortization         133  10.6      38  3.1
Taxes Other Than
 Income Taxes         (22) (3.2)    (19)(2.7)
                  -------       -------
      Total       $24,160  69.6 $12,261 54.6
                  =======       =======

        Our fuel and purchased energy expense in 2001 increased 84% due to
increased trading volume and an increase in nuclear generation cost. The return
to service of the Cook Plant's two nuclear generating units in June 2000 and
December 2000 accounted for the increase in nuclear generation costs.

        Fuel and purchased energy expense increased 67% in 2000 due to increased
trading volume and a significant increase in the cost of natural gas used for
generation. Natural gas usage for generation declined 5% while the cost of
natural gas consumed rose 60%. Net income was not impacted by this significant
cost increase due to the operation of fuel recovery rate mechanisms. These fuel
recovery rate mechanisms generally provide for the deferral of fuel costs above
the amounts included in existing rates or the accrual of revenues for fuel costs
not yet recovered. Upon regulatory commission review and approval of the
unrecovered fuel costs, the accrued or deferred amounts are billed to customers.
With the introduction of customer choice of electricity supplier and a
transition to market-based generation rates, the protection offered by fuel
recovery mechanisms against changes in fuel costs was eliminated in Ohio
effective January 1, 2001 and in the ERCOT area of Texas effective January 1,
2002. As a result, AEP's exposure to the risk of fuel price increases that could
adversely affect future results of operations and cash flows is increasing. See
Note 1 for applicability of fuel recovery mechanisms by jurisdiction.

        Maintenance and other operation expense rose in 2001 mainly as a result
of additional traders' incentive compensation and accruals for severance costs
related to corporate restructuring.

        The increase in maintenance and other operation expense in 2000 was
mainly due to increased expenditures to prepare the Cook Plant nuclear units for
restart following an extended NRC monitored outage and increased usage and
prices of emissions allowances. The increase in Cook Plant restart costs
resulted from the effect of deferring restart costs in 1999 and an increase in
the restart expenditure level in 2000. Cook Plant began its extended outage in
September 1997 when both nuclear generating units were shut down because of
questions regarding the operability of certain safety systems. In 1999 a portion
of incremental restart expenses were deferred in accordance with IURC and MPSC
settlement agreements which resolved all jurisdictional rate-related issues
related to the Cook Plant's extended outage. With NRC approval Unit 2 returned
to service in June and achieved full power operation on July 5, 2000 and Unit 1
returned to service in December and achieved full power operation on January 3,
2001. The increase in emission allowance usage and prices resulted from the
stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments,
which became effective on January 1, 2000.

        With the consummation of the merger with CSW, certain deferred merger
costs were expensed in 2000. The merger costs charged to expense included
transaction and transition costs not allocable to and recoverable from
ratepayers under regulatory commission approved settlement agreements to share
net merger savings. As expected merger costs declined in 2001 after the merger
was consummated.

        Depreciation  and  amortization  expense  increased  in 2001  primarily
as a result of the  commencement  of  amortization  of transition  generation
regulatory  assets in the Ohio,  Virginia  and West  Virginia  jurisdictions
due to passage  of  restructuring legislation, the new businesses acquired in
2001 and additional investments in property, plant and equipment.

Interest, Preferred Stock Dividends, Minority Interest

        Interest expense deceased 15% in 2001 due to the effect of interest paid
the IRS on a COLI deduction disallowance in 2000 and lower average outstanding
short-term debt balances and a decrease in average short-term interest rates.

        In 2001 we issued a preferred member interest to finance the acquisition
of HPL and paid a preferred return of $13 million to the preferred member
interest.

        In 2000 interest increased by 17% due to additional interest expense
from the ruling disallowing COLI tax deductions and AEP's effort to maintain
flexibility for corporate separation by issuing short-term debt at flexible
rates. The use of fixed interest rate swaps has been employed to mitigate the
risk from floating interest rates.

Other Income

        Other income increased $166 million in 2001. This increase was primarily
caused by the sale in March 2001 of Frontera, a generating plant required to be
divested under a FERC approved merger settlement agree-ment, which produced a
pretax $73 million gain and the effect from the December 2000 impairment
writedown of $43 million to reflect the pending sale of AEP's Yorkshire
investment.

        Other income decreased $66 million in 2000 primarily due to a loss in
equity earnings from the 2000 write-down of the Yorkshire investment and losses
from certain non-regulated subsidiaries accounted for on an equity basis. Other
expenses increased in 2000 mainly from a charge for the discontinuance of an
electric storage water heater demand side management program of the regulated
business.

Income Taxes

        Although pre-tax book income increased considerably, income taxes
decreased due to the effect of recording in 2000 prior year federal income taxes
as a result of the disallowance of COLI interest deductions by the IRS and
nondeductible merger related costs in 2000.

        Income taxes increased in 2000 over 1999 levels primarily due to the
disallowance of the COLI interest deductions and the non-deductible merger
related costs discussed above.

Extraordinary Losses and Cumulative Effect

        In 2001 we recorded an extraordinary loss of $48 million net of tax to
write-off prepaid Ohio excise taxes stranded by Ohio deregulation. The
application of regulatory accounting for generation was discontinued in
2000 for the Ohio, Virginia and West Virginia jurisdictions which resulted in
the after tax extraordinary loss of $35 million.

        New accounting rules that became effective in 2001 regarding accounting
for derivatives required us to mark to market certain fuel supply contracts that
qualify as financial derivatives. The effect of initially adopting the new rules
at July 1, 2001 was a favorable earnings effect of $18 million, net of tax,
which is reported as a cumulative effect of accounting change.



<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Income
- ---------------------------------
(in millions - except per share amounts)
                                                                Year Ended December 31,
                                                             ----------------------------------
                                                             2001          2000            1999
                                                             ----          ----            ----
<S>                                                        <C>           <C>             <C>
REVENUES:
  Electricity Marketing and Trading                        $41,513       $25,178         $17,232
  Gas Marketing and Trading                                 14,416         6,259           2,311
  Domestic Electricity Delivery                              3,356         3,174           3,068
  Other Investment                                           1,972         2,095           2,134
                                                             -----         -----           -----
          TOTAL REVENUES                                    61,257        36,706          24,745
                                                            ------        ------          ------

EXPENSES:
  Fuel and Purchased Energy:
  Electricity Marketing and Trading                         37,558        21,246          13,646
  Gas Marketing and Trading                                 14,004         6,227           2,305
  Other Investment                                           1,191         1,245           1,293
                                                             -----         -----           -----
          TOTAL FUEL AND PURCHASED ENERGY                   52,753        28,718          17,244
  Maintenance and Other Operation                            4,037         3,841           3,276
  Non-recoverable Merger Costs                                  21           203            -
  Depreciation and Amortization                              1,383         1,250           1,212
  Taxes Other Than Income Taxes                                668           690             709
                                                               ---           ---             ---

         TOTAL EXPENSES                                     58,862        34,702          22,441
                                                            ------        ------          ------

OPERATING INCOME                                             2,395         2,004           2,304

OTHER INCOME                                                   302           136             202

OTHER EXPENSES                                                 130            81              42

LESS: INTEREST                                                 972         1,149             977
      PREFERRED STOCK DIVIDEND REQUIREMENTS OF SUBSIDIARIES     10            11              19
      MINORITY INTEREST IN FINANCE SUBSIDIARY                   13          -               -
                                                                --          ----            ----

INCOME BEFORE INCOME TAXES                                   1,572           899           1,468

INCOME TAXES                                                   569           597             482
                                                               ---           ---             ---

INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT       1,003           302             986

EXTRAORDINARY LOSSES (NET OF TAX):
  DISCONTINUANCE OF REGULATORY ACCOUNTING FOR GENERATION       (48)          (35)             (8)
  LOSS ON REACQUIRED DEBT                                       (2)         -                 (6)

CUMULATIVE EFFECT OF ACCOUNTING CHANGE                          18          -               -
                                                                --          ----            ----

NET INCOME                                                   $ 971         $ 267           $ 972
                                                             =====         =====           =====

AVERAGE NUMBER OF SHARES OUTSTANDING                           322           322             321
                                                               ===           ===             ===

EARNINGS PER SHARE:
  Income Before Extraordinary Item and Cumulative Effect    $ 3.11         $0.94           $3.07
  Extraordinary Losses                                       (0.16)         (.11)           (.04)
  Cumulative Effect of Accounting Change                       .06           -               -
                                                               ---           ---             ---

  Earnings Per Share (Basic and Dilutive)                   $ 3.01         $0.83           $3.03
                                                            ======         =====           =====

CASH DIVIDENDS PAID PER SHARE                                $2.40         $2.40           $2.40
                                                             =====         =====           =====
</TABLE>
See Notes to Consolidated Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
- ---------------------------
(in millions - except share data)
                                                                           December 31,
                                                                    -------------------------
                                                                    2001                 2000
                                                                    ----                 ----
<S>                                                               <C>                  <C>
ASSETS
- ------
CURRENT ASSETS:
  Cash and Cash Equivalents                                         $ 333                $ 342
  Accounts Receivable:
    Customers                                                         626                  888
    Miscellaneous                                                   1,365                2,883
    Allowance for Uncollectible Accounts                             (109)                 (72)
  Energy Trading and Derivative Contracts                           8,572               15,497
  Other                                                             1,776                1,363
                                                                    -----                -----

          TOTAL CURRENT ASSETS                                     12,563               20,901
                                                                   ------               ------

PROPERTY PLANT AND EQUIPMENT:
  Electric:
    Production                                                     17,477               16,328
    Transmission                                                    5,879                5,609
    Distribution                                                   11,310               10,843
  Other (including gas and coal mining assets
    And nuclear fuel)                                               4,941                4,077
  Construction Work in Progress                                     1,102                1,231
                                                                    -----                -----
           Total Property, Plant and Equipment                     40,709               38,088
  Accumulated Depreciation and Amortization                        16,166               15,695
                                                                   ------               ------

          NET PROPERTY, PLANT AND EQUIPMENT                        24,543               22,393
                                                                   ------               ------

REGULATORY ASSETS                                                   3,162                3,698
                                                                    -----                -----

INVESTMENTS IN POWER, DISTRIBUTION AND COMMUNICATIONS PROJECTS        677                  782
                                                                      ---                  ---

GOODWILL (NET OF AMORTIZATION)                                      1,494                1,382
                                                                    -----                -----

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS                   2,370                1,552
                                                                    -----                -----

OTHER ASSETS                                                        2,472                2,642
                                                                    -----                -----

            TOTAL                                                 $47,281              $53,350
                                                                  =======              =======
</TABLE>
See Notes to Consolidated Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
                                                                   December 31,
                                                             ------------------------
                                                             2001                2000
                                                             ----                ----
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
<S>                                                        <C>                 <C>
  Accounts Payable                                         $ 2,245             $ 2,627
  Short-term Debt                                            3,155               4,333
  Long-term Debt Due Within One Year*                        2,300               1,152
  Energy Trading and Derivative Contracts                    8,311              15,671
  Other                                                      2,088               2,154
                                                             -----               -----

          TOTAL CURRENT LIABILITIES                         18,099              25,937
                                                            ------              ------

LONG-TERM DEBT*                                              9,753               9,602
                                                             -----               -----

LONG-TERM ENERGY TRADING AND DERIVATIVE CONTRACTS            2,183               1,313
                                                             -----               -----

DEFERRED INCOME TAXES                                        4,823               4,875
                                                             -----               -----

DEFERRED INVESTMENT TAX CREDITS                                491                 528
                                                               ---                 ---

DEFERRED CREDITS AND REGULATORY LIABILITIES                    948                 637
                                                               ---                 ---

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2    194                 203
                                                               ---                 ---

OTHER NONCURRENT LIABILITIES                                 1,334               1,706
                                                             -----               -----

COMMITMENTS AND CONTINGENCIES (Note 8)

CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
  PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
  SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
  SUBSIDIARIES                                                 321                 334
                                                               ---                 ---

MINORITY INTEREST IN FINANCE SUBSIDIARY                        750                -
                                                               ---               -----

CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES*                    156                 161
                                                               ---                 ---

COMMON SHAREHOLDERS' EQUITY:
  Common Stock-Par Value $6.50:
                            2001          2000
                            ----          ----
    Shares Authorized. .600,000,000   600,000,000
    Shares Issued. . . .331,234,997   331,019,146
    (8,999,992 shares were held in treasury
     at December 31, 2001 and 2000)                          2,153               2,152
  Paid-in Capital                                            2,906               2,915
  Accumulated Other Comprehensive Income (Loss)               (126)               (103)
  Retained Earnings                                          3,296               3,090
                                                             -----               -----
          TOTAL COMMON SHAREHOLDERS' EQUITY                  8,229               8,054
                                                             -----               -----

            TOTAL                                          $47,281             $53,350
                                                           =======             =======
</TABLE>
*See Accompanying Schedules.

<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
- -------------------------------------
(in millions)
                                                                   Year Ended December 31,
                                                              -------------------------------------
                                                              2001            2000             1999
                                                              ----            ----             ----
<S>                                                          <C>             <C>              <C>
OPERATING ACTIVITIES:
  Net Income                                                  $ 971           $ 267            $ 972
  Adjustments for Noncash Items:
    Depreciation and Amortization                             1,413           1,299            1,294
    Deferred Federal Income Taxes                               163            (170)             180
    Deferred Investment Tax Credits                             (29)            (36)             (38)
    Amortization (Deferral) of Operating
      Expenses and Carrying Charges (net)                        40              48             (151)
    Equity in Earnings of Yorkshire Electricity Group plc      -                (44)             (45)
    Extraordinary Loss                                           50              35               14
    Cumulative Effect of Accounting Change                      (18)           -                -
    Deferred Costs Under Fuel Clause Mechanisms                 340            (449)            (191)
    Mark to Market of Energy Trading Contracts                 (257)           (170)             (23)
    Miscellaneous Accrued Expenses                             (384)            217              101
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                                 1,764          (1,632)             (80)
    Fuel, Materials and Supplies                                (82)            147             (162)
    Accrued Utility Revenues                                     26             (79)             (35)
    Accounts Payable                                           (461)          1,322               74
    Taxes Accrued                                              (147)            172               29
  Premium Options                                               (76)             74                8
  Payment of Disputed Tax and Interest Related to COLI         -                319              (16)
  Change in Other Assets                                       (213)            (92)             (87)
  Change in Other Liabilities                                  (147)            205             (245)
                                                               ----             ---             ----
        Net Cash Flows From Operating Activities              2,953           1,433            1,599
                                                              -----           -----            -----

INVESTING ACTIVITIES:
  Construction Expenditures                                  (1,832)         (1,773)          (1,680)
  Purchase of Houston Pipe Line                                (727)           -                -
  Purchase of U.K. Generation                                  (943)           -                -
  Purchase of Quaker Coal Co.                                  (101)           -                -
  Purchase of Memco                                            (266)           -                -
  Purchase of Indian Mesa                                      (175)           -                -
  Sale of Yorkshire                                             383            -                -
  Sale of Frontera                                              265            -                -
  Other                                                         (36)             19                7
                                                                ---              --                -
        Net Cash Flows Used For Investing Activities         (3,432)         (1,754)          (1,673)
                                                             ------          ------           ------

FINANCING ACTIVITIES:
  Issuance of Common Stock                                       10              14               93
  Issuance of Minority Interest                                 747            -                -
  Issuance of Long-term Debt                                  2,931           1,124            1,391
  Retirement of Cumulative Preferred Stock                       (5)            (20)            (170)
  Retirement of Long-term Debt                               (1,835)         (1,565)            (915)
  Change in Short-term Debt (net)                              (597)          1,308              812
  Dividends Paid on Common Stock                               (773)           (805)            (833)
  Dividends on Minority Interest in Subsidiary                   (5)           -                -
  Other Financing Activities                                   -               -                 (43)
                                                               ----            ----              ---
        Net Cash Flows From Financing Activities                473              56              335
                                                                ---              --              ---

Effect of Exchange Rate Change on Cash                           (3)             23               (2)
                                                                 --              --               --

Net Increase (Decrease) in Cash and Cash Equivalents             (9)           (242)             259
Cash and Cash Equivalents January 1                             342             584              325
                                                                ---             ---              ---
Cash and Cash Equivalents December 31                         $ 333           $ 342            $ 584
                                                              =====           =====            =====
</TABLE>
See Notes to Consolidated Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Common Shareholders' Equity and Comprehensive Income
- -------------------------------------------------------------------------------
(in millions)
                                                                               Accumulated
                                                                               Other
                                            Common Stock    Paid-In  Retained  Comprehensive
                                            Shares  Amount  Capital  Earnings  Income (Loss)   Total
<S>     <C>                                 <C>    <C>      <C>       <C>        <C>            <C>
JANUARY 1, 1999                             328    $2,134   $2,818    $3,493     $   7          $8,452
Issuances                                     3        15       77      -          -                92
Retirements and Other                        -       -           3      -          -                 3
Cash Dividends Declared                      -       -        -         (833)      -              (833)
Other                                        -       -        -           (2)      -                (2)
                                                                                                ------
                                                                                                 7,712
Comprehensive Income:
 Other Comprehensive Income, Net of Taxes
  Foreign Currency Translation Adjustment    -       -        -         -          (13)            (13)
  Minimum Pension Liability                  -       -        -         -            2               2
 Net Income                                  -       -        -          972       -               972
                                                                                                ------
   Total Comprehensive Income                                                                      961
                                            ---    ------   ------    ------     -----          ------

DECEMBER 31, 1999                           331     2,149    2,898     3,630        (4)          8,673
Issuances                                    -          3       11      -          -                14
Cash Dividends Declared                      -       -        -         (805)      -              (805)
Other                                        -       -           6        (2)      -                 4
                                                                                                ------
                                                                                                 7,886
Comprehensive Income:
 Other Comprehensive Income, Net of Taxes
  Foreign Currency Translation Adjustment    -       -        -         -         (119)           (119)
  Reclassification Adjustment
   For Loss Included in Net Income           -       -        -         -           20              20
 Net Income                                  -       -        -          267                       267
                                                                                                ------
   Total Comprehensive Income                                                                      168
                                            ---    ------   ------    ------     -----          ------

DECEMBER 31, 2000                           331     2,152    2,915     3,090      (103)         $8,054
Issuances                                    -          1        9      -          -                10
Cash Dividends Declared                      -       -        -         (773)      -              (773)
Other                                        -       -         (18)        8       -               (10)
                                                                                                ------
                                                                                                 7,281
Comprehensive Income:
 Other Comprehensive Income, Net of Taxes
  Foreign Currency Translation Adjustment    -       -        -         -          (14)            (14)
  Unrealized Gain (Loss) on
   Hedged Derivatives                                                               (3)             (3)
  Minimum Pension Liability                  -       -        -         -           (6)             (6)
 Net Income                                  -       -        -          971                       971
                                                                                                ------
   Total Comprehensive Income                                                                      948
                                            ---    ------   ------    ------     -----          ------

DECEMBER 31, 2001                           331    $2,153   $2,906    $3,296     $(126)         $8,229
                                            ===    ======   ======    ======     =====          ======
</TABLE>
See Notes to Consolidated Financial Statements.

<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries

                                                             December 31, 2001
                                       -------------------------------------------------------------------
                                         Call
                                       Price per             Shares              Shares       Amount (In
                                       Share (a)           Authorized(b)      Outstanding(f)  Millions)
- --------------------------------------------------------------------------------------------------------
<S>                                    <C>                    <C>                  <C>         <C>
Not Subject to Mandatory Redemption:
  4.00% - 5.00%                        $102-$110              1,525,903            614,608     $61
                                                                                               ===

Subject to Mandatory Redemption:
  5.90% - 5.92% (c)                       (d)                 1,950,000            333,100     $33
  6.02% - 6-7/8% (c)                        $100              1,650,000            513,450      52
  7% (e)                                  (e)                   250,000            100,000      10
                                                                                               ---
    Total Subject to Mandatory
      Redemption (c)                                                                           $95
                                                                                               ===
</TABLE>
<TABLE>
<CAPTION>
                                                             December 31, 2000
                                       -----------------------------------------------------------------
                                         Call
                                       Price per             Shares              Shares       Amount (In
                                       Share (a)           Authorized(b)      Outstanding(f)  Millions)
- --------------------------------------------------------------------------------------------------------
<S>                                    <C>                  <C>                  <C>         <C>
Not Subject to Mandatory Redemption:
  4.00% - 5.00%                        $102-$110            1,525,903            614,608      $ 61
                                                                                              ====

Subject to Mandatory Redemption:
  5.90% - 5.92% (c)                       (d)               1,950,000            333,100      $ 33
  6.02% - 6-7/8% (c)                        $100            1,650,000            513,450        52
  7% (e)                                  (e)                 250,000            150,000        15
                                                                                              ----
    Total Subject to Mandatory
      Redemption (c)                                                                          $100
                                                                                              ====

</TABLE>
NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES

(a)    At the option of the subsidiary the shares may be redeemed at the call
       price plus accrued dividends. The involuntary liquidation preference is
       $100 per share for all outstanding shares.
(b)    As of December 31, 2001 the subsidiaries had 13,642,750, 22,200,000 and
       7,713,495 shares of $100, $25 and no par value preferred stock,
       respectively, that were authorized but unissued.
(c)    Shares outstanding and related amounts are stated net of applicable
       retirements through sinking funds(generally at par) and reacquisitions of
       shares in anticipation of future requirements. The subsidiaries
       reacquired enough shares in 1997 to meet all sinking fund requirements on
       certain series until 2008 and on certain series until 2009 when all
       remaining
       outstanding shares must be redeemed. The sinking fund provisions of the
       series subject to mandatory redemption aggregate (after deducting sinking
       fund requirements) of $5 million in 2002 and $5 million in 2003.
(d)    Not callable prior to 2003; after that the call price is $100 per share.
(e)    With sinking fund.
(f)    The number of shares of preferred stock redeemed is 50,000 shares
       in 2001, 209,563 shares in 2000 and 1,698,276 shares in 1999.
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Long-term Debt of Subsidiaries

                              Weighted Average
Maturity                        Interest Rate    Interest Rates at December 31,        December 31,
- --------                      -----------------  ------------------------------   ----------------------
                              December 31, 2001       2001            2000         2001          2000
                              -----------------       ----            ----         ----          ----
                                                                                       (in millions)
                                                                                       -------------
<S>                                  <C>           <C>             <C>            <C>           <C>
FIRST MORTGAGE BONDS (a)
  2001-2003                          6.95%         6.00%-7.70%     5.91%-8.95%    $   852       $ 1,247
  2004-2008                          6.98%         6-1/8%-8.00%    6-1/8%-8%        1,092         1,140
  2020-2025                          7.66%         6-7/8%-8.80%    6-7/8%-8.80%       850         1,104

INSTALLMENT PURCHASE CONTRACTS (b)
  2001-2009                          4.30%         1.80%-7.70%     4.90%-7.70%        446           234
  2011-2030                          5.88%         1.55%-8.20%     4.875%-8.20%     1,234         1,447

NOTES PAYABLE (c)
  2001-2021                          5.41%         4.0483%-9.60%   6.20%-9.60%      2,237         1,181

SENIOR UNSECURED NOTES
  2001-2004                          4.81%         2.31%-7.45%     6.50%-7.45%      1,874         2,049
  2005-2009                          6.24%         6.125%-6.91%    6.24%-6.91%      1,763           475
  2038                               7.30%         7.20%-7-3/8%    7.20%-7-3/8%       340           340

JUNIOR DEBENTURES
  2025-2038                          8.05%         7.60%-8.72%     7.60%-8.72%        618           620

YANKEE BONDS AND EURO BONDS
  2001-2006                          8.71%         8.50%-8.875%    7.98%-8.875%       479           684

OTHER LONG-TERM DEBT (d)                                                              308           280

Unamortized Discount (net)                                                            (40)          (47)
                                                                                  -------       -------
Total Long-term Debt
  Outstanding (e)                                                                  12,053        10,754
Less Portion Due Within One Year                                                    2,300         1,152
                                                                                  -------       -------
Long-term Portion                                                                 $ 9,753       $ 9,602
                                                                                  =======       =======

</TABLE>
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES

(a) First mortgage bonds are secured by first mortgage liens on electric
property, plant and equipment.
(b) For certain series of installment purchase contracts interest rates are
subject to periodic adjustment. Certain series will be purchased on demand at
periodic interest-adjustment dates. Letters of credit from banks and standby
bond purchase agreements support certain series.
(c) Notes payable represent outstanding promissory notes issued under term loan
agreements and revolving credit agreements with a number of banks and other
financial institutions. At expiration all notes then issued and outstanding are
due and payable. Interest rates are both fixed and variable. Variable rates
generally relate to specified short-term interest rates.
(d) Other long-term debt consists of a liability along with accrued interest for
disposal of spent nuclear fuel (see Note 8 of the Notes to Consolidated
Financial Statements) and financing obligation under sale lease back agreements.
(e) Long-term debt outstanding at December 31, 2001 is payable as follows:

      Principal Amount (in millions)

2002                           $ 2,300
2003                             2,086
2004                               902
2005                               616
2006                             1,943
Later Years                      4,246
                               -------
Total Principal Amount          12,093
Unamortized Discount                40
                               -------
  Total                        $12,053
                               =======

<PAGE>

AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES
Index to Notes to Consolidated Financial Statements

The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.

                                                     Combined
                                                     Footnote
                                                     Reference

Significant Accounting Policies                      Note  1

Extraordinary Items and Cumulative Effect            Note  2

Merger                                               Note  3

Nuclear Plant Restart                                Note  4

Rate Matters                                         Note  5

Effects of Regulation                                Note  6

Customer Choice and Industry Restructuring           Note  7

Commitments and Contingencies                        Note  8

Acquisitions and Dispositions                        Note  9

Benefit Plans                                        Note 10

Stock-Based Compensation                             Note 11

Business Segments                                    Note 12

Risk Management, Financial Instruments
  And Derivatives                                    Note 13

Income Taxes                                         Note 14

Basic and Diluted Earnings Per Share                 Note 15

Supplementary Information                            Note 16

Power, Distribution and Communications Projects      Note 17

Leases                                               Note 18

Lines of Credit and Sale of Receivables              Note 19

Unaudited Quarterly Financial Information            Note 20

Trust Preferred Securities                           Note 21

Minority Interest in Finance Subsidiary              Note 22




<PAGE>


MANAGEMENT'S RESPONSIBILITY

         The management of American Electric Power Company, Inc. is responsible
for the integrity and objectivity of the information and representations in this
annual report, including the consolidated financial statements. These statements
have been prepared in conformity with generally accepted accounting principles,
using informed estimates where appropriate, to reflect the Company's financial
condition and results of operations. The information in other sections of the
annual report is consistent with these statements.

         The Company's Board of Directors has oversight responsibilities for
determining that management has fulfilled its obligation in the preparation of
the financial statements and in the ongoing examination of the Company's
established internal control structure over financial reporting. The Audit
Committee, which consists solely of outside directors and which reports directly
to the Board of Directors, meets regularly with management, Deloitte & Touche
LLP - independent auditors and the Company's internal audit staff to discuss
accounting, auditing and reporting matters. To ensure auditor independence, both
Deloitte & Touche LLP and the internal audit staff have unrestricted access to
the Audit Committee.

         The financial statements have been audited by Deloitte & Touche LLP,
whose report appears on the next page. The auditors provide an objective,
independent review as to management's discharge of its responsibilities insofar
as they relate to the fairness of the Company's reported financial condition and
results of operations. Their audit includes procedures believed by them to
provide reasonable assurance that the financial statements are free of material
misstatement and includes an evaluation of the Company's internal control
structure over financial reporting.





<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:

         We have audited the consolidated balance sheets of American Electric
Power Company, Inc. and its subsidiaries as of December 31, 2001 and 2000, and
the related consolidated statements of income, cash flows, and common
shareholders' equity and comprehensive income for each of the three years in the
period ended December 31, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits. The consolidated
financial statements give retroactive effect to the merger of American Electric
Power Company, Inc. and its subsidiaries and Central and South West Corporation
and its subsidiaries, which has been accounted for as a pooling of interests as
described in Note 3 to the consolidated financial statements. We did not audit
the consolidated statements of income, and cash flows, and stockholder's equity
and comprehensive income of Central and South West Corporation and its
subsidiaries for the year ended December 31, 1999, which statements reflect
total revenues of $5,516,000,000 for the year ended December 31, 1999. Those
consolidated statements, before the restatement described in Note 3, were
audited by other auditors whose report, dated February 25, 2000, has been
furnished to us, and our opinion, insofar as it relates to those amounts
included for Central and South West Corporation and its subsidiaries for 1999,
is based solely on the report of such other auditors.

         We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits and the report of
the other auditors provide a reasonable basis for our opinion.

         In our opinion, based on our audits and the report of the other
auditors, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of American Electric
Power Company, Inc. and its subsidiaries as of December 31, 2001 and 2000, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2001 in conformity with accounting principles
generally accepted in the United States of America.

         We also audited the adjustments described in Note 3 that were applied
to restate the 1999 financial statements to give retroactive effect to the
change in the method of accounting for vacation pay accruals. In our opinion,
such adjustments are appropriate and have been properly applied.



Deloitte & Touche LLP
Columbus, Ohio
February 22, 2002


<PAGE>















                             AEP GENERATING COMPANY


<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
Selected Financial Data
                                                            Year Ended December 31,
                                   ------------             -----------------------
                                        2001            2000            1999            1998            1997
                                        ----            ----            ----            ----            ----
                                                                 (in thousands)
<S>                                   <C>             <C>             <C>             <C>             <C>
INCOME STATEMENTS DATA:
  Operating Revenues                  $227,548        $228,516        $217,189        $224,146        $227,868
  Operating Expenses                   220,571         220,092         211,849         215,415         218,828
                                       -------         -------         -------         -------         -------
  Operating Income                       6,977           8,424           5,340           8,731           9,040
  Nonoperating Income                    3,484           3,429           3,659           3,364           3,603
  Interest Charges                       2,586           3,869           2,804           3,149           3,857
                                         -----           -----           -----           -----           -----
  Net Income                            $7,875          $7,984          $6,195          $8,946          $8,786
                                        ======          ======          ======          ======          ======

                                                      December 31,
                                   -------------------------------
                                        2001            2000            1999            1998            1997
                                        ----            ----            ----            ----            ----
                                                                 (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant              $648,254        $642,302        $640,093        $636,460        $633,450
  Accumulated Depreciation             337,151         315,566         295,065         277,855         257,191
                                       -------         -------         -------         -------         -------
  Net Electric Utility Plant          $311,103        $326,736        $345,028        $358,605        $376,259
                                      ========        ========        ========        ========        ========

  Total Assets                        $361,341        $374,602        $398,640        $403,892        $419,058
                                      ========        ========        ========        ========        ========

  Common Stock and Paid-in Capital    $ 24,434        $ 24,434        $ 30,235        $ 36,235        $ 40,235
  Retained Earnings                     13,761           9,722           3,673           2,770           2,528
                                        ------           -----           -----           -----           -----
  Total Common Shareholder's Equity   $ 38,195        $ 34,156        $ 33,908        $ 39,005        $ 42,763
                                      ========        ========        ========        ========        ========

  Long-term Debt (a)                  $ 44,793        $ 44,808        $ 44,800        $ 44,792        $ 69,570
                                      ========        ========        ========        ========        ========

  Total Capitalization
   And Liabilities                    $361,341        $374,602        $398,640        $403,892        $419,058
                                      ========        ========        ========        ========        ========

(a) Including portion due within one year.
</TABLE>
<PAGE>

AEP GENERATING COMPANY
Management's Narrative Analysis of Results of Operations



        AEP Generating Company is engaged in the generation and wholesale sale
of electric power to two affiliates under long-term agreements.

        Operating revenues are derived from the sale of Rockport Plant energy
and capacity to two affiliated companies, I&M and KPCo pursuant to FERC approved
long-term unit power agreements. Under the terms of its unit power agreement,
I&M is required to buy all of AEGCo's Rockport capacity when the unit power
agreement with KPCo expires in 2004. The unit power agreements provide for
recovery of costs including a FERC approved rate of return on common equity and
a return on other capital net of temporary cash investments. Under terms of the
unit power agreements, AEGCo accumulates all expenses monthly and prepares the
bills for its affiliates. In the month the expenses are incurred, AEGCo
recognizes the billing revenues and establishes a receivable from the affiliated
companies.

        Net income decreased $0.1 million or 1% as a result of a slight decrease
in the return on other capital. Lower interest charges caused the return on
other capital to decrease.

        Income statement items which changed significantly were:

                                           Increase
                                          (Decrease)
(dollars in millions)               From Previous Year
                                         Amount      %

Operating Revenues                       $(1.0)    N.M.
Other Operation Expense                    0.7       7
Maintenance Expense                       (0.8)     (8)
Taxes Other Than Income Taxes              0.4      10
Interest Charges                          (1.3)    (33)

N.M. = Not Meaningful


        The decrease in operating revenues reflects a decrease in the return on
other capital reflecting a decline in interest charges.

        Other operation expense increased due to the costs of an air quality
test project and increased benefits and compensation costs.

        The decrease in maintenance expense can be attributed to a shorter
duration of maintenance outages for boiler inspection and repair in 2001.

        Taxes other than income taxes increased due to an increase in Indiana
real and personal property taxes reflecting an unfavorable accrual adjustment
and a higher estimated liability accrued in 2001.

        The decrease in interest charges was primarily due to a decline in
interest rates in 2001. The Federal Reserve reduced short-term interest rates
eleven times in 2001. AEGCo benefited from the declining short-term interest
rates since its short-term borrowings and through July 13, 2001 its long-term
debt were based on short-term interest rates. AEGCo's long-term debt interest
rates varied daily until July 2001 when we chose to fix the rate at 4.05% for
five years.




<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
Statements of Income
                                                      Year Ended December 31,
                                              --------------------------------------
                                              2001            2000              1999
                                              ----            ----              ----
                                                      (in thousands)
<S>                                         <C>             <C>              <C>
OPERATING REVENUES:
  Sales to AEP Affiliates                   $227,338        $227,983         $152,559
  Other                                          210             533           64,630
                                                 ---   -----     ---   --      ------

            TOTAL OPERATING REVENUES         227,548         228,516          217,189
                                             -------   -     -------   -      -------

OPERATING EXPENSES:
  Fuel                                       102,828         102,978           94,481
  Rent - Rockport Plant Unit 2                68,283          68,283           68,283
  Other Operation                             11,025          10,295           10,451
  Maintenance                                  8,853           9,616           10,492
  Depreciation                                22,423          22,162           21,845
  Taxes Other Than Income Taxes                4,257           3,854            3,866
  Income Taxes                                 2,902           2,904            2,431
                                               -----   ---     -----   ---      -----

            TOTAL OPERATING EXPENSES         220,571         220,092          211,849
                                             -------   -     -------   -      -------

OPERATING INCOME                               6,977           8,424            5,340

NONOPERATING INCOME                               30               6               92

NONOPERATING EXPENSES                             16              17               27

NONOPERATING INCOME TAX CREDITS                3,470           3,440            3,594

INTEREST CHARGES                               2,586           3,869            2,804
                                               -----   ---     -----   ---      -----

NET INCOME                                    $7,875          $7,984           $6,195
                                              ======          ======           ======
</TABLE>
<TABLE>
<CAPTION>

Statements of Retained Earnings
                                                    Year Ended December 31,
                                              --------------------------------------
                                              2001             2000             1999
                                              ----             ----             ----
                                                         (in thousands)
<S>                                           <C>             <C>              <C>
RETAINED EARNINGS JANUARY 1                   $ 9,722         $3,673           $2,770

NET INCOME                                      7,875          7,984            6,195

CASH DIVIDENDS DECLARED                         3,836          1,935            5,292
                                                -----  -       -----   -        -----

RETAINED EARNINGS DECEMBER 31                 $13,761         $9,722           $3,673
                                              =======         ======           ======
</TABLE>
See Notes to Financial Statements beginning on page L-1.

<PAGE>
AEP GENERATING COMPANY
Balance Sheets
                                                       December 31,
                                                   ------------------------
                                                   2001                2000
                                                   ----                ----
                                                     (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                     $638,297            $635,215
  General                                           3,012               2,795
  Construction Work in Progress                     6,945               4,292
                                                    -----               -----
          Total Electric Utility Plant            648,254             642,302

  Accumulated Depreciation                        337,151             315,566
                                                  -------             -------

          NET ELECTRIC UTILITY PLANT              311,103             326,736
                                                  -------             -------

OTHER PROPERTY AND INVESTMENTS                        119                   6
                                                      ---                   -

CURRENT ASSETS:
  Cash and Cash Equivalents                           983               2,757
  Accounts Receivable:
   Affiliated Companies                            22,344              21,374
   Miscellaneous                                      147               2,341
  Fuel - at average cost                           15,243              11,006
  Materials and Supplies - at average cost          4,480               3,979
  Prepayments                                         244                 145
                                                      ---                 ---

          TOTAL CURRENT ASSETS                     43,441              41,602
                                                   ------              ------

REGULATORY ASSETS                                   5,207               5,504
                                                    -----               -----

DEFERRED CHARGES                                    1,471                 754
                                                    -----                 ---

                    TOTAL                        $361,341            $374,602
                                                 ========            ========


See Notes to Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
                                                                     December 31,
                                                                  ------------------------
                                                                  2001                2000
                                                                  ----                ----
                                                                      (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
<S>                                                             <C>                 <C>
  Common Stock - Par Value $1,000:
    Authorized and Outstanding - 1,000 Shares                     $1,000              $1,000
  Paid-in Capital                                                 23,434              23,434
  Retained Earnings                                               13,761               9,722
                                                                  ------               -----
    Total Common Shareholder's Equity                             38,195              34,156
  Long-term Debt                                                  44,793                -
                                                                  ------                ----


          TOTAL CAPITALIZATION                                    82,988              34,156
                                                                  ------              ------

OTHER NONCURRENT LIABILITIES                                          76                 358
                                                                      --                 ---

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                                -                 44,808
  Advances from Affiliates                                        32,049              28,068
  Accounts Payable:
    General                                                        7,582               6,109
    Affiliated Companies                                           1,654               7,724
  Taxes Accrued                                                    4,777               4,993
  Rent Accrued - Rockport Plant Unit 2                             4,963               4,963
  Other                                                            3,481               4,443
                                                                   -----               -----

          Total CURRENT LIABILITIES                               54,506             101,108
                                                                  ------             -------

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2      116,617             122,188
                                                                 -------             -------

REGULATORY LIABILITIES:
  Deferred Investment Tax Credits                                 56,304              59,718
  Amounts Due to Customers for Income Taxes                       22,725              23,996
                                                                  ------              ------

          Total REGULATORY LIABILITIES                            79,029              83,714
                                                                  ------              ------

DEFERRED INCOME TAXES                                             27,975              32,928
                                                                  ------              ------

DEFERRED CREDITS                                                     150                 150
                                                                     ---                 ---

CONTINGENCIES (Note 8)

                    TOTAL                                       $361,341            $374,602
                                                                ========            ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
Statements of Cash Flows
                                                                 Year Ended December 31,
                                                             --------------------------------------
                                                             2001             2000             1999
                                                             ----             ----             ----
                                                                     (in thousands)
<S>                                                        <C>              <C>              <C>
OPERATING ACTIVITIES:
  Net Income                                                $7,875           $7,984           $6,195
  Adjustments for Noncash Items:
    Depreciation                                            22,423           22,162           21,845
    Deferred Federal Income Taxes                           (6,224)          (5,842)          (5,282)
    Deferred Investment Tax Credits                         (3,414)          (3,396)          (3,448)
    Amortization of Deferred Gain on Sale and
      Leaseback - Rockport Plant Unit 2                     (5,571)          (5,571)          (5,571)
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable                                      1,224            1,392           (2,213)
    Fuel, Materials and Supplies                            (4,738)           6,486           (6,263)
    Accounts Payable                                        (4,597)         (13,157)          14,394
    Taxes Accrued                                             (216)             708            1,058
  Other Assets                                                (569)           1,636               (6)
  Other Liabilities                                         (1,244)            (404)          (1,564)
                                                            ------             ----           ------
            Net Cash Flows From Operating Activities         4,949           11,998           19,145
                                                             -----           ------           ------

INVESTING ACTIVITIES:
  Construction Expenditures                                 (6,868)          (5,190)          (8,349)
  Proceeds From Sales of Property                             -                -                 331
                                                              ----             ----              ---
            Net Cash Flows Used For Investing
              Activities                                    (6,868)          (5,190)          (8,018)
                                                            ------           ------           ------

FINANCING ACTIVITIES:
  Return of Capital to Parent Company                         -              (5,801)          (6,000)
  Change in Short-term Debt (net)                             -             (24,700)             250
  Change in Advances From Affiliates (net)                   3,981           28,068             -
  Dividends Paid                                            (3,836)          (1,935)          (5,292)
                                                            ------           ------           ------
            Net Cash Flows From (Used For)
              Financing Activities                             145           (4,368)         (11,042)
                                                               ---           ------          -------

Net Increase (Decrease) in Cash and Cash Equivalents        (1,774)           2,440               85
Cash and Cash Equivalents January 1                          2,757              317              232
                                                             -----              ---              ---
Cash and Cash Equivalents December 31                        $ 983           $2,757            $ 317
                                                             =====-          ======            =====
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $1,509,000, $3,531,000 and
$2,468,000 and for income taxes was $8,597,000, $6,820,000 and $6,565,000 in
2001, 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>

AEP GENERATING COMPANY
Statements of Capitalization
                                                                 December 31,
                                                             2001             2000
                                                             ----             ----
                                                                (in thousands)

<S>                                                        <C>              <C>
COMMON STOCK EQUITY (a)                                     $38,195          $ 34,156
                                                            -------          --------

LONG-TERM DEBT
Installment Purchase Contracts - City of Rockport (b)
 Series   Due Date
 1995 A,  2025 (c)                                           22,500           22,500
 1995 B,  2025 (c)                                           22,500           22,500
Unamortized Discount                                           (207)            (192)
Amount Due Within One Year                                     -             (44,808)
                                                               ----   -      -------
  Long-term Debt Excluding Amount Due Within One Year        44,793             -
                                                             ------   ----      ----
TOTAL CAPITALIZATION                                        $82,988         $ 34,156
                                                            =======         ========
</TABLE>
(a) In 2000 and 1999, AEGCo returned capital to AEP in the amounts of $5.8
million and $6 million, respectively. There were no other material transactions
affecting common stock and paid-in capital in 2001, 2000 and 1999.
(b)Installment purchase contracts were entered into in connection with the
issuance of pollution control revenue bonds by the City of Rockport, Indiana.
The terms of the installment purchase contracts require AEGCo to pay amounts
sufficient to enable the payment of interest and principal on the related
pollution control revenue bonds issued to refinance the construction costs of
pollution control facilities at the Rockport Plant.
(c) These series have an adjustable interest rate that can be a daily, weekly,
commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001,
AEGCo selected a daily rate which ranged from 0.9% to 5.6% during 2001 and from
1.65% to 6.1% during 2000 and averaged 2.8% in 2001 and 4.1% in 2000. Effective
July 13, 2001, AEGCo selected a term rate of 4.05% for five years ending July
12, 2006. The interest rates were 5% for Series A and 4.9% for Series B at
December 31, 2000.

See Notes to Financial Statements beginning on page L-1.

<PAGE>

AEP GENERATING COMPANY
Index to Notes to Financial Statements

The notes to AEGCo's financial statements are combined with the notes to
financial statements for AEP and its other subisidiary registrants. Listed below
are the combined notes that apply to AEGCo. The combined footnotes begin on page
L-1.

                                                           Combined
                                                           Footnote
                                                           Reference

Significant Accounting Policies                            Note  1

Effects of Regulation                                      Note  6

Commitments and Contingencies                              Note  8

Business Segments                                          Note 12

Risk Management, Financial Instruments and Derivatives     Note 13

Income Taxes                                               Note 14

Leases                                                     Note 18

Lines of Credit and Sale of Receivables                    Note 19

Unaudited Quarterly Financial Information                  Note 20

Related Party Transactions                                 Note 24

<PAGE>

INDEPENDENT AUDITORS' REPORT


To the Shareholder and Board of Directors
of AEP Generating Company:

         We have audited the accompanying balance sheets and statements of
capitalization of AEP Generating Company as of December 31, 2001 and 2000, and
the related statements of income, retained earnings, and cash flows for each of
the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

         We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

         In our opinion, such financial statements present fairly, in all
material respects, the financial position of AEP Generating Company as of
December 31, 2001 and 2000, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2001 in conformity
with accounting principles generally accepted in the United States of America.



Deloitte & Touche LLP
Columbus, Ohio
February 22, 2002


<PAGE>












                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES



<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
                                                               Year Ended December 31,
                                     2001              2000             1999                 1998                 1997
                                     ----              ----             ----                 ----                 ----
                                                                   (in thousands)
INCOME STATEMENTS DATA:
<S>                             <C>                <C>              <C>                   <C>                 <C>
  Operating Revenues             $6,999,430         $5,087,308       $3,970,647            $3,291,385          $1,720,010
  Operating Expenses              6,724,444          4,886,154        3,729,411             3,062,842           1,480,016
                                  ---------          ---------        ---------             ---------           ---------
  Operating Income                  274,986            201,154          241,236               228,543             239,994
  Nonoperating Income
   (Loss)                             6,868             11,752            8,096                (8,301)               (222)
  Interest Charges                  120,036            148,000          128,840               126,912             119,258
                                    -------            -------          -------               -------             -------
  Income Before
   Extraordinary Item               161,818             64,906          120,492                93,330             120,514
  Extraordinary Gain                   -                 8,938             -                     -                   -
                                       ----              -----             ----             ---------                ----
  Net Income                        161,818             73,844          120,492                93,330             120,514
  Preferred Stock
   Dividend
   Requirements                       2,011              2,504            2,706                 2,497               7,006
                                      -----              -----            -----                 -----               -----
  Earnings Applicable
   to Common Stock                 $159,807           $ 71,340         $117,786              $ 90,833            $113,508
                                   ========           ========         ========              ========            ========

                                                                      December 31,
                                     2001              2000             1999                  1998                1997
                                     ----              ----             ----                  ----                ----
                                                                   (in thousands)
BALANCE SHEETS DATA:
  Electric Utility
   Plant                         $5,664,657         $5,418,278       $5,262,951            $5,087,359          $4,901,046
  Accumulated
   Depreciation and
   Amortization                   2,296,481          2,188,796        2,079,490             1,984,856           1,869,057
                                  ---------          ---------        ---------             ---------           ---------
  Net Electric Utility
   Plant                         $3,368,176         $3,229,482       $3,183,461            $3,102,503          $3,031,989
                                 ==========         ==========       ==========            ==========          ==========

  Total Assets                   $5,107,938         $6,633,724       $4,354,400            $4,047,038          $3,883,430
                                 ==========         ==========       ==========            ==========          ==========

  Common Stock and
   Paid-in Capital                 $976,244           $975,676         $974,717              $924,091            $873,506
  Accumulated Other
   Comprehensive Income
   (Loss)                              (340)              -                -                     -                   -
  Retained Earnings                 150,797            120,584          175,854               179,461             207,544
                                    -------            -------          -------               -------             -------
  Total Common
   Shareholder's Equity          $1,126,701         $1,096,260       $1,150,571            $1,103,552          $1,081,050
                                 ==========         ==========       ==========            ==========          ==========

Cumulative Preferred Stock:
  Not Subject to
   Mandatory Redemption            $ 17,790           $ 17,790         $ 18,491              $ 19,359            $ 19,747
  Subject to Mandatory
   Redemption                        10,860             10,860           20,310                22,310              22,310
                                     ------             ------           ------                ------              ------
  Total Cumulative
   Preferred Stock                 $ 28,650           $ 28,650         $ 38,801              $ 41,669            $ 42,057
                                   ========           ========         ========              ========            ========

  Long-term Debt (a)             $1,556,559         $1,605,818       $1,665,307            $1,552,455          $1,494,535
                                 ==========         ==========       ==========            ==========          ==========

  Obligations Under
   Capital Leases (a)              $ 46,285           $ 63,160         $ 64,645              $ 65,175            $ 60,110
                                   ========           ========         ========              ========            ========

  Total Capitalization
   And Liabilities               $5,107,938         $6,633,724       $4,354,400            $4,047,038          $3,883,430
                                 ==========         ==========       ==========            ==========          ==========

(a) Including portion due within one year.
</TABLE>

<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations


         APCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to 917,000 retail customers in
southwestern Virginia and southern West Virginia. APCo as a member of the AEP
Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale
sales to neighboring utility systems and power marketers including power trading
transactions. APCo also sells wholesale power to municipalities.

         The cost of the AEP Power Pool's generating capacity is allocated among
the Pool members based on their relative peak demands and generating reserves
through the payment of capacity charges and the receipt of capacity credits. AEP
Power Pool members are also compensated for their out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's percentage share of revenues and
costs.

Critical Accounting Policies - Revenue Recognition

Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.


         When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.

Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to APCo as a member
of the AEP Power Pool. Trading activities involve the purchase and sale of
energy under physical forward contracts at fixed and variable prices and buying
and selling financial energy contracts which includes exchange traded futures
and options and over-the-counter options and swaps. Although trading contracts
are generally short-term, there are also long-term trading contracts. We
recognize revenues from trading activities generally based on changes in the
fair value of energy trading contracts.

           Recording the net change in the fair value of trading contracts prior
to settlement is commonly referred to as mark-to-market (MTM) accounting. It
represents the change in the unrealized gain or loss throughout the contract's
term. When the contract actually settles, that is, the energy is actually
delivered in a sale or received in a purchase or the parties agree to forego
delivery and receipt of electricity and net settle in cash, the unrealized gain
or loss is reversed and the actual realized cash gain or loss is recognized.
Therefore, over the trading contract's term an unrealized gain or loss is
recognized as the contract's market value changes. When the contract settles the
total gain or loss is realized in cash but only the difference between the
accumulated unrealized net gains or losses recorded in prior months and the cash
proceeds is recognized. Unrealized mark-to-market gains and losses are included
in the Balance Sheet as energy trading contract assets or liabilities as
appropriate.

           The majority of our trading activities represent physical forward
electricity contracts that are typically settled by entering into offsetting
contracts. An example of our trading activities is when, in January, we enter
into a forward sales contract to deliver electricity in July. At the end of each
month until the contract settles in July, we would record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract settles, we would realize our share of the
gain or loss in cash and reverse the previously recorded unrealized gain or
loss.

           Depending on whether the delivery point for the electricity is in
AEP's traditional marketing area or not determines where the contract is
reported on APCo's income statement. AEP's traditional marketing area is up to
two transmission systems from the AEP service territory. Physical forward
trading sale contracts with delivery points in AEP's traditional marketing area
are included in revenues when the contracts settle. Physical forward trading
purchase contracts with delivery points in AEP's traditional marketing area are
included in purchased power expense when they settle. Prior to settlement,
changes in the fair value of physical forward sale and purchase contracts in
AEP's traditional marketing area are included in revenues on a net basis.
Physical forward sales contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating income when the contract settles.
Physical forward purchase contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating expenses when the contract settles.
Prior to settlement, changes in the fair value of physical forward sale and
purchase contracts with delivery points outside of AEP's traditional marketing
area are included in nonoperating income on a net basis.

        Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
results of operations from recording additional changes in fair values using
mark-to-market accounting.

        Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior unrealized gain
or loss.

        The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.

         Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing APCo to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.

Results of Operations

Net Income

         Net income increased $88 million or 119% in 2001 primarily due to the
effect of a court decision related to a corporate owned life insurance (COLI)
program recorded in 2000. In February 2001 the U.S. District Court for the
Southern District of Ohio ruled against AEP and certain of its subsidiaries,
including APCo, in a suit over deductibility of interest claimed in AEP's
consolidated tax return related to COLI. In 1998 and 1999 APCo paid the disputed
taxes and interest attributable to the COLI interest deductions for taxable
years 1991-98. The payments were included in Other Property and Investments
pending the resolution of this matter. Also contributing to the increase in net
income was growth in and strong performance by the wholesale marketing and
trading business in the first half of 2001 offset in part by the effect of
extremely mild November and December weather combined with weak economic
conditions which reduced retail energy sales.

         The adverse court decision on COLI caused the $47 million decrease in
2000's net income. Income before extraordinary items decreased $56 million or
46% in 2000 primarily due to the COLI decision. An extraordinary gain from the
discontinuance of SFAS 71 regulatory accounting of $9 million after tax was
recorded in June 2000. (See Note 2, "Extraordinary Items and Cumulative
Effect".)

Operating Revenues

         Operating revenues increased 38% in 2001 and 28% in 2000 mainly due to
a significant increase in wholesale marketing and trading volume. The changes in
the components of revenues were as follows:

                    Increase (Decrease)
                    From Previous Year
                    (dollars in millions)
                     2001           2000
                  ---------------------------
                  Amount    %   Amount     %

Retail*          $  (38.9) (5) $      2  N.M.
Wholesale
 Marketing and
 Trading          1,859.1   52  1,091.2   44
Unrealized MTM       46.3  272    (22.0) N.M.
Other                 8.9   14    (18.2) (22)
                 --------      --------
  Total
   Marketing
   and Trading    1,875.4   43  1,053.0   32
Energy Delivery*     20.1    3      9.3    2
Sales to AEP
  Affiliates         16.6   11     54.4   54
                 --------      --------
     Total
      Revenues   $1,912.1   38 $1,116.7   28
                 ========      ========

N.M. = Not Meaningful

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.

         Wholesale marketing and trading revenues increased significantly in
2001 and 2000 as a result of an increase in electric marketing and trading
volume (39% in 2001 and 42% in 2000). The maturing of the Intercontinental
Exchange, the development of proprietary tools, and increased staffing of energy
traders have resulted in an increase in the number of forward electricity
purchase and sale contracts in AEP's traditional marketing area.

         While wholesale marketing and trading volumes rose, kilowatthour sales
to industrial customers decreased in 2001. This decrease was due to the economic
recession. Also, in the fourth quarter, sales to residential and commercial
customers declined. The recession reduced demand, especially, in the fourth
quarter.

         The increase in sales to AEP affiliates in 2000 is due to a significant
increase in AEP Power Pool transactions. As the quantity of energy sold by the
AEP Power Pool rose, APCo's contribution of energy to the Pool rose, accounting
for the increase in APCo's revenues from sales to AEP affiliates. The AEP Power
Pool was able to make additional sales to third parties in 2000 as a result of
an affiliated company's major industrial customer's decision not to continue its
purchased power agreement.

Operating Expenses

         The increase in operating expenses in 2001 of 38% is due to increases
in electricity marketing and trading expense and depreciation and amortization
expenses partially offset by decreases in income taxes, other operation expense
and fuel expenses. Operating expenses increased 31% in 2000 due to an increase
in electricity marketing and trading expense, power purchases from AEP
affiliates, other operation expense and income taxes offset in part by a
decrease in fuel expense. Changes in the components of operating expenses are as
follows:

                     Increase (Decrease)
                     From Previous Year
                   (dollars in millions)
                   2001             2000
               -----------------------------
                Amount    %    Amount    %

Fuel           $  (17.6) (5) $  (75.6) (17)
Marketing and
 Trading
 Purchases      1,904.7  57     906.4   37
AEP Affiliate
 Purchases         (8.9) (3)    224.8  172
Other Operation   (18.8) (7)     33.0   13
Maintenance         7.9   6       0.7    1
Depreciation and
  Amortization     17.3  11      14.2   10
Taxes Other Than
  Income Taxes    (11.8)(11)     (1.0)  (1)
Income Taxes      (34.5)(27)     54.2   72
               --------      --------
  Total        $1,838.3  38  $1,156.7   31
               ========      ========


         The decrease in fuel expense in 2001 is due to a decline in generation
as a result of scheduled plant maintenance. Fuel expense decreased in 2000 due
to the combined effect of the discontinuance of deferral accounting for over or
under recovery of fuel costs in the West Virginia jurisdiction effective January
1, 2000 under the terms of a rate settlement agreement and a decline in
generation due to scheduled plant maintenance.

         Electricity marketing and trading purchased power expense increased
substantially in 2001 and 2000 due to increases in trading volume and wholesale
electricity prices.

         Purchased power from AEP affiliates decreased in 2001 as the result of
a decrease in AEP Power Pool capacity charges due to a reduction in APCo's MLR.
The significant increase in purchased power from AEP affiliates in 2000 reflects
additional purchases of power from the AEP Power Pool as a result of increased
availability of generation. The AEP Power Pool was able to supply more power to
APCo since an affiliate's nuclear unit returned to service in June 2000, a major
industrial customer discontinued purchasing power from an affiliate in January
2000, and generating unit outage management improved.

         Other operation expense decreased in 2001 mainly due to the effect of
AEPSC billings in 2000 for the disallowance of the COLI program interest
deduction. Additionally, the decrease was the result of a gain recorded on the
disposition of SO2 emission allowances offset in part by increased wholesale
power trading incentive compensation expense. The increase in other operation
expense in 2000 was due to increased wholesale marketing and trading costs
including increased accruals for incentive compensation, increased use of
emission allowances due to stricter air quality standards of Phase II of the
1990 Clean Air Act Amendments which became effective January 1, 2000 and AEPSC
billings for the COLI disallowance.



<PAGE>


         During June 2000 we discontinued the application of SFAS 71 in the
Virginia and West Virginia jurisdictions. Consequently net generation-related
regulatory assets were transferred to the energy delivery business' regulated
distribution business where the Virginia and West Virginia jurisdictions
authorized the recovery of these transition regulatory assets through regulated
rates. Depreciation and amortization expense increased in 2001 and 2000 due to
accelerated amortization, beginning in July 2000, of the transition regulatory
assets. Additional investments in the energy delivery business' distribution and
transmission plant also contributed to the increases in depreciation and
amortization expense.

         The decrease in taxes other than income taxes in 2001 is due to the
elimination of the Virginia gross receipts tax as a result of a tax law change
due to deregulation in that state.

         Income taxes attributable to operations decreased in 2001 due to the
effect of the disallowance of COLI interest deductions in 2000 offset in part by
an increase in pre-tax operating income. The increase in income taxes
attributable to operations in 2000 was due to the disallowance of COLI interest
deductions.

Nonoperating Income and Nonoperating Expenses

         The increase in nonoperating income and nonoperating expenses for both
2001 and 2000 is due to considerable increases in the wholesale business'
trading transactions outside of the AEP System's traditional marketing area.


Interest Charges

         Interest charges decreased in 2001 primarily due to the effect of
recognizing in 2000 previously deferred interest payments to the IRS related to
the COLI disallowances and interest on resultant state income tax deficiencies.
Additionally, the decrease in 2001 is due to the retirement of first mortgage
bonds in 2000. The increase in interest charges in 2000 was due to the
recognition of deferred interest payments related to the COLI disallowances and
interest on the resultant prior years state income taxes.

Extraordinary Gain

         The extraordinary gain recorded in June 2000 was the result of the
discontinuance of SFAS 71 for the generation portion of APCo's business.




<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
                                                             Year Ended December 31,
                                                   -------------------------------------------
                                                   2001                2000               1999
                                                   ----                ----               ----
                                                                  (in thousands)
<S>                                            <C>                 <C>                <C>
OPERATING REVENUES:
  Electricity Marketing and Trading             $6,233,109          $4,357,712         $3,304,755
  Energy Delivery                                  595,036             574,918            565,660
  Sales to AEP Affiliates                          171,285             154,678            100,232
                                                   -------             -------            -------
     Total Operating Revenues                    6,999,430           5,087,308          3,970,647
                                                 ---------           ---------          ---------

OPERATING EXPENSES:
  Fuel                                             351,557             369,161            444,711
  Purchased Power:
    Electricity Marketing and Trading            5,253,983           3,349,279          2,442,819
    AEP Affiliates                                 346,878             355,774            130,991
  Other Operation                                  263,798             282,610            249,616
  Maintenance                                      132,373             124,493            123,834
  Depreciation and Amortization                    180,393             163,089            148,874
  Taxes Other Than Income Taxes                     99,878             111,692            112,722
  Income Taxes                                      95,584             130,056             75,844
                                                    ------             -------             ------
     Total Operating Expenses                    6,724,444           4,886,154          3,729,411
                                                 ---------           ---------          ---------

OPERATING INCOME                                   274,986             201,154            241,236

NONOPERATING INCOME                              2,320,649           1,415,530            684,080

NONOPERATING EXPENSES                            2,312,642           1,400,655            675,793

NONOPERATING INCOME TAX EXPENSE                      1,139               3,123                191

INTEREST CHARGES                                   120,036             148,000            128,840
                                                   -------             -------            -------

INCOME BEFORE EXTRAORDINARY ITEM                   161,818              64,906            120,492

EXTRAORDINARY GAIN - DISCONTINUANCE OF
 REGULATORY ACCOUNTING FOR GENERATION
 (Inclusive of Tax Benefit of $7,872,000)             -                  8,938               -
                                                      ----               -----               ----

NET INCOME                                         161,818              73,844            120,492

PREFERRED STOCK DIVIDEND REQUIREMENTS                2,011               2,504              2,706
                                                     -----               -----              -----

EARNINGS APPLICABLE TO COMMON STOCK               $159,807            $ 71,340           $117,786
                                                  ========            ========           ========
</TABLE>
<TABLE>
<CAPTION>
Consolidated Statements of Comprehensive Income
                                                                Year Ended December 31,
                                                   -------------------------------------------
                                                   2001                2000               1999
                                                   ----                ----               ----
                                                                   (in thousands)
<S>                                             <C>                  <C>               <C>
NET INCOME                                      $161,818             $73,844           $120,492

OTHER COMPREHENSIVE INCOME (LOSS)
  Foreign Currency Exchange Rate Hedge              (340)               -                  -
                                                    ----                ----               ----

COMPREHENSIVE INCOME                            $161,478             $73,844           $120,492
                                                ========             =======           ========

</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
                                                          December 31,
                                                   ------------------------
                                                   2001                2000
                                                   ----                ----
                                                         (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                    $2,093,532          $2,058,952
  Transmission                                   1,222,226           1,177,079
  Distribution                                   1,887,020           1,816,925
  General                                          257,957             254,371
  Construction Work in Progress                    203,922             110,951
                                                   -------             -------
          Total Electric Utility Plant           5,664,657           5,418,278
  Accumulated Depreciation and Amortization      2,296,481           2,188,796
                                                 ---------           ---------
          NET ELECTRIC UTILITY PLANT             3,368,176           3,229,482
                                                 ---------           ---------

OTHER PROPERTY AND INVESTMENTS                      53,736              56,967
                                                    ------              ------

LONG-TERM ENERGY TRADING CONTRACTS                 316,249             322,038
                                                   -------             -------

CURRENT ASSETS:
  Cash and Cash Equivalents                         13,663               5,847
  Advances to Affiliates                              -                  8,387
  Accounts Receivable:
   Customers                                       113,371             243,298
   Affiliated Companies                             63,368              63,919
   Miscellaneous                                    11,847              16,179
   Allowance for Uncollectible Accounts             (1,877)             (2,588)
  Fuel - at average cost                            56,699              39,076
  Materials and Supplies - at average cost          59,849              57,515
  Accrued Utility Revenues                          30,907              66,499
  Energy Trading Contracts                         566,284           2,024,222
  Prepayments                                       16,018               6,307
                                                    ------               -----

          TOTAL CURRENT ASSETS                     930,129           2,528,661
                                                   -------           ---------

REGULATORY ASSETS                                  397,383             447,750
                                                   -------             -------

DEFERRED CHARGES                                    42,265              48,826
                                                    ------              ------

                    TOTAL                       $5,107,938          $6,633,724
                                                ==========          ==========

See Notes to Financial Statements beginning on page L-1.

<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                                                        December 31,
                                                  ------------------------
                                                  2001                2000
                                                  ----                ----
                                                       (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized - 30,000,000 Shares
    Outstanding - 13,499,500 Shares              $260,458            $260,458
  Paid-in Capital                                 715,786             715,218
  Accumulated Other Comprehensive Income (Loss)      (340)               -
  Retained Earnings                               150,797             120,584
                                                  -------             -------
    Total Common Shareholder's Equity           1,126,701           1,096,260
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption            17,790              17,790
    Subject to Mandatory Redemption                10,860              10,860
  Long-term Debt                                1,476,552           1,430,812
                                                ---------           ---------
          TOTAL CAPITALIZATION                  2,631,903           2,555,722
                                                ---------           ---------

OTHER NONCURRENT LIABILITIES                       84,104             105,883
                                                   ------             -------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year               80,007             175,006
  Short-term Debt                                    -                191,495
  Advances From Affiliates                        291,817                -
  Accounts Payable - General                      131,387             153,422
  Accounts Payable - Affiliated Companies          84,518             107,556
  Taxes Accrued                                    55,583              63,258
  Customer Deposits                                13,177              12,612
  Interest Accrued                                 21,770              21,555
  Energy Trading Contracts                        549,703           2,080,025
  Other                                            75,299              85,378
                                                   ------              ------

          Total CURRENT LIABILITIES             1,303,261           2,890,307
                                                ---------           ---------

DEFERRED INCOME TAXES                             703,575             682,474
                                                  -------             -------

DEFERRED INVESTMENT TAX CREDITS                    38,328              43,093
                                                   ------              ------

LONG-TERM ENERGY TRADING CONTRACTS                257,129             258,788
                                                  -------             -------

REGULATORY LIABILITIES AND DEFERRED CREDITS        89,638              97,457
                                                   ------              ------

COMMITMENTS AND CONTINGENCIES (Note 8)

                    TOTAL                      $5,107,938          $6,633,724
                                               ==========          ==========

See Notes to Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
                                                                     Year Ended December 31,
                                                             ----------------------------------------
                                                             2001              2000              1999
                                                             ----              ----              ----
                                                                         (in thousands)
<S>                                                       <C>                 <C>              <C>
OPERATING ACTIVITIES:
  Net Income                                               $ 161,818           $73,844          $ 120,492
  Adjustments for Noncash Items:
    Depreciation and Amortization                            180,505           163,202            149,791
    Deferred Federal Income Taxes                             42,498             8,602             13,033
    Deferred Investment Tax Credits                           (4,765)           (4,915)            (4,972)
    Deferred Power Supply Costs (net)                          1,411           (84,408)            35,955
    Mark-to-Market of Energy Trading Contracts               (68,254)           (1,843)            (8,939)
    Provision for Rate Refunds                                  -               (4,818)             4,818
    Extraordinary Gain                                          -               (8,938)              -
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                                134,099          (166,911)            10,989
    Fuel, Materials and Supplies                             (19,957)           18,487             (4,812)
    Accrued Utility Revenues                                  35,592           (13,081)            (7,433)
    Accounts Payable                                         (45,073)          159,369             (9,273)
    Taxes Accrued                                             (7,675)           14,220             13,319
    Revenue Refunds Accrued                                     -                  181            (95,267)
    Incentive Plan Accrued                                    (2,451)           10,662              1,507
  Disputed Tax and Interest Related to COLI                     -               72,440             (4,124)
  Change in Operating Reserves                                (5,358)          (19,770)             7,451
  Rate Stabilization Deferral                                   -               75,601               -
  Change in Other Assets                                      19,418           (13,021)            (8,669)
  Change in Other Liabilities                                (27,954)            9,817            (22,455)
                                                             -------             -----            -------
            Net Cash Flows From Operating Activities         393,854           288,720            191,411
                                                             -------           -------            -------

INVESTING ACTIVITIES:
  Construction Expenditures                                 (306,046)         (199,285)          (211,416)
  Proceeds From Sales of Property and Other                    1,182               159             19,296
  Net Cost of Removal and Other                               (8,434)           (7,500)           (24,373)
                                                              ------            ------            -------
            Net Cash Flows Used For Investing
             Activities                                     (313,298)         (206,626)          (216,493)
                                                            --------          --------           --------

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company                     -                 -                50,000
  Issuance of Long-term Debt                                 124,588            74,788            227,236
  Retirement of Cumulative Preferred Stock                      -               (9,924)            (2,675)
  Retirement of Long-term Debt                              (175,000)         (136,166)          (116,688)
  Change in Short-term Debt (net)                           (191,495)           68,015             47,080
  Change in Advances From Affiliates                         300,204            (8,387)              -
  Dividends Paid on Common Stock                            (129,594)         (126,612)          (121,392)
  Dividends Paid on Cumulative Preferred Stock                (1,443)           (1,938)            (2,257)
                                                              ------            ------             ------
            Net Cash Flows From (Used For)
             Financing Activities                            (72,740)         (140,224)            81,304
                                                             -------          --------             ------

Net Increase (Decrease) in Cash and Cash Equivalents           7,816           (58,130)            56,222
Cash and Cash Equivalents January 1                            5,847            63,977              7,755
                                                               -----            ------              -----
Cash and Cash Equivalents December 31                        $13,663           $ 5,847            $63,977
                                                             =======           =======            =======
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $117,283,000, $124,579,000
and $125,900,000 and for income taxes was $56,981,000, $63,682,000 and
$55,157,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under
capital leases were $2,510,000, $14,116,000 and $13,868,000 in 2001, 2000 and
1999, respectively.

See Notes to Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
                                                          Year Ended December 31,
                                                    -----------------------------------------
                                                    2001              2000               1999
                                                    ----              ----               ----
                                                               (in thousands)

<S>                                               <C>               <C>                <C>
Retained Earnings January 1                       $120,584          $175,854           $179,461
  Net Income                                       161,818            73,844            120,492
                                                   -------            ------            -------
                                                   282,402           249,698            299,953
                                                   -------           -------            -------
Deductions:
  Cash Dividends Declared:
    Common Stock                                   129,594           126,612            121,392
    Cumulative Preferred Stock:
      4-1/2% Series                                    801               811                850
      5.90%  Series                                    278               307                425
      5.92%  Series                                    364               364                364
      6.85%  Series                                   -                  289                579
                                                      ----               ---                ---
              Total Cash Dividends Declared        131,037           128,383            123,610

  Capital Stock Expense                                568               731                489
                                                       ---               ---                ---
              Total Deductions                     131,605           129,114            124,099
                                                   -------           -------            -------

Retained Earnings December 31                     $150,797          $120,584           $175,854
                                                  ========          ========           ========
</TABLE>
See Notes to Financial Statements Beginning on Page L-1.

<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization

                                                                                          December 31,
                                                                                 -----------------------------
                                                                                     2001             2000
                                                                                     ----             ----
                                                                                        (in thousands)
<S>                                                                             <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $1,126,701        $1,096,260
                                                                                 ----------        ----------

PREFERRED STOCK: No par value - authorized shares 8,000,000

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series(a)      2001 (b)        Year Ended December 31,       December 31, 2001
- ------     ------------     ----------------------------     -----------------
                              2001      2000      1999
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4-1/2%         $110            -        7,011     8,671            177,905           17,790            17,790
                                                                                 ----------        ----------

Subject to Mandatory Redemption:

5.90% (c)      (d)             -       10,000    20,000             47,100            4,710             4,710
5.92% (c)      (d)             -         -         -                61,500            6,150             6,150
                                                                                 ----------        ----------

                                                                                     10,860            10,860
                                                                                 ----------        ----------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                639,365           739,015
Installment Purchase Contracts                                                      234,904           234,782
Senior Unsecured Notes                                                              518,247           468,113
Junior Debentures                                                                   161,507           161,367
Other Long-term Debt                                                                  2,536             2,541
Less Portion Due Within One Year                                                    (80,007)         (175,006)
                                                                                 ----------        ----------

  Long-term Debt Excluding Portion Due Within One Year                            1,476,552         1,430,812
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $2,631,903        $2,555,722
                                                                                 ==========        ==========
</TABLE>
(a)  The sinking fund provisions of each series subject to mandatory redemption
     have been met by purchase of shares in advance of the due date. APCo
     redeemed 84,500 shares of the 6.85% series of preferred stock subject to
     mandatory redemption in 2000.
(b)  The cumulative preferred stock is callable at the price indicated plus
     accrued dividends. The involuntary liquidation preference is $100 per
     share. The aggregate involuntary liquidation price for all shares of
     cumulative preferred stock may not exceed $300 million. The unissued shares
     of the cumulative preferred stock may or may not possess mandatory
     redemption characteristics upon issuance.
(c)  Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per
     share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92%
     series outstanding under sinking fund provisions at its option and all
     outstanding shares must be reacquired in 2008. Shares previously redeemed
     may be applied to meet the sinking fund requirement.
(d)  Not callable until after 2002.

See Notes to Financial Statements beginning on page L-1.


<PAGE>

APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt

First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2001       2000
                           ----       ----
                          (in thousands)
% Rate Due
6-3/8  2001 - March 1    $   -      $100,000
7.38   2002 - August 15    50,000     50,000
7.40   2002 - December 1   30,000     30,000
6.65   2003 - May 1        40,000     40,000
6.85   2003 - June 1       30,000     30,000
6.00   2003 - November 1   30,000     30,000
7.70   2004 - September 1  21,000     21,000
7.85   2004 - November 1   50,000     50,000
8.00   2005 - May 1        50,000     50,000
6.89   2005 - June 22      30,000     30,000
6.80   2006 - March 1     100,000    100,000
8.50   2022 - December 1   70,000     70,000
7.80   2023 - May 1        30,237     30,237
7.15   2023 - November 1   20,000     20,000
7.125  2024 - May 1        45,000     45,000
8.00   2025 - June 1       45,000     45,000
Unamortized Discount       (1,872)    (2,222)
                         --------   --------
  Total                  $639,365   $739,015
                         ========   ========

         First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.

Installment purchase contracts have been entered into, in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:

                             December 31,
                           2001       2000
                           ----       ----
                           (in thousands)
% Rate Due
Industrial Development
 Authority of
 Russell County, Virginia:

7.70   2007 - November 1 $ 17,500   $ 17,500
5.00   2021 - November 1   19,500     19,500

Putnam County, West Virginia:

5.45   2019 - June 1       40,000     40,000
6.60   2019 - July 1       30,000     30,000

Mason County, West Virginia:

7-7/8  2013 - November 1   10,000     10,000
6.85   2022 - June 1       40,000     40,000
6.60   2022 - October 1    50,000     50,000
6.05   2024 - December 1   30,000     30,000
Unamortized Discount       (2,096)    (2,218)
                         --------   --------
  Total                  $234,904   $234,782
                         ========   ========


         Under the terms of the installment purchase contracts, APCo is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.

Senior unsecured notes outstanding were as follows:

                            December 31,
                          2001       2000
                          ----       ----
                           (in thousands)
% Rate Due
 (a)   2001 - June 27   $   -      $ 75,000
 (a)   2003 - August 20  125,000       -
7.45   2004 - November 1  50,000     50,000
6.60   2009 - May 1      150,000    150,000
7.20   2038 - March 31   100,000    100,000
7.30   2038 - June 30    100,000    100,000
Unamortized Discount      (6,753)    (6,887)
                        --------   --------
  Total                 $518,247   $468,113
                        ========   ========

(a) A floating  interest rate is determined monthly.  The rate on December 31,
    2001 and 2000 was 2.839% and 6.95%, respectively.

Junior debentures outstanding were as follows:

                            December 31,
                         2001         2000
                         ----         ----
                          (in thousands)
8-1/4% Series A due
  2026 - September 30  $ 75,000     $ 75,000
8% Series B due 2027
  - March 31             90,000       90,000
Unamortized Discount     (3,493)      (3,633)
                       --------     --------
  Total                $161,507     $161,367
                       ========     ========

         Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of the Company.

         At December 31, 2001, future annual long-term debt payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2002                       $   80,007
2003                          225,007
2004                          121,008
2005                           80,010
2006                          100,011
Later Years                   964,730
                           ----------
  Total Principal Amount    1,570,773
Unamortized Discount          (14,214)
                           ----------
    Total                  $1,556,559
                           ==========
<PAGE>


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements

The notes to APCo's financial statements are combined with the notes to
financial statements for AEP and its other subsidiary registrants. Listed below
are the combined notes that apply to APCo. The combined footnotes begin on page
L-1.

                                                     Combined
                                                     Footnote
                                                     Reference

Significant Accounting Policies                      Note  1

Extraordinary Items and Cumulative Effect            Note  2

Rate Matters                                         Note  5

Effects of Regulation                                Note  6

Customer Choice and Industry Restructuring           Note  7

Commitments and Contingencies                        Note  8

Benefit Plans                                        Note 10

Business Segments                                    Note 12

Risk Management, Financial Instruments
  and Derivatives                                    Note 13

Income Taxes                                         Note 14

Supplementary Information                            Note 16

Leases                                               Note 18

Lines of Credit and Sale of Receivables              Note 19

Unaudited Quarterly Financial Information            Note 20

Related Party Transactions                           Note 24

<PAGE>

INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of
Directors of Appalachian Power Company:

     We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Appalachian Power Company and its
subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, comprehensive income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

    In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Appalachian Power Company and
its subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002

<PAGE>













                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES


<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
                                                                           Year Ended December 31,
                                    2001             2000               1999                 1998                  1997
                                    ----             ----               ----                 ----                  ----
                                                                   (in thousands)
INCOME STATEMENTS DATA:
<S>                            <C>               <C>               <C>                    <C>                 <C>
  Operating Revenues            $3,321,727        $2,349,503        $1,482,475             $1,406,117          $1,376,282
  Operating Expenses             3,025,996         2,042,405         1,188,490              1,123,330           1,124,963
                                 ---------         ---------         ---------              ---------           ---------
  Operating Income                 295,731           307,098           293,985                282,787             251,319
  Nonoperating Income
   (Loss)                            5,324             7,235             8,113                    760               8,277
  Interest Charges                 116,268           124,766           114,380                122,036             131,173
                                   -------           -------           -------                -------             -------
  Income Before
   Extraordinary Item              184,787           189,567           187,718                161,511             128,423
  Extraordinary Loss                (2,509)             -               (5,517)                  -                   -
                                    ------              ----            ------                   ----                ----
  Net Income                       182,278           189,567           182,201                161,511             128,423
  Preferred Stock
   Dividend
   Requirements                        242               241             6,931                  6,901               9,523
  Gain (Loss) on
   Reacquired Preferred
   Stock                              -                 -               (2,763)                  -                  2,402
                                      ----              ----            ------                   ----               -----
  Earnings Applicable
   To Common Stock                $182,036          $189,326          $172,507               $154,610            $121,302
                                  ========          ========          ========               ========            ========

                                                 Year Ended December 31,
                                    2001             2000               1999                   1998                1997
                                    ----             ----               ----                   ----                ----
                                                                   (in thousands)
BALANCE SHEETS DATA:
  Electric Utility
   Plant                        $5,769,707        $5,592,444         $5,511,894            $5,336,191          $5,215,749
  Accumulated
   Depreciation
   And Amortization              2,446,027         2,297,189          2,247,225             2,072,686           1,891,406
                                 ---------         ---------          ---------             ---------           ---------
  Net Electric Utility
   Plant                        $3,323,680        $3,295,255         $3,264,669            $3,263,505          $3,324,343
                                ==========        ==========         ==========            ==========          ==========
  Total Assets                  $5,115,986        $5,467,684         $4,847,850            $4,735,476          $4,897,380
                                ==========        ==========         ==========            ==========          ==========

  Common Stock and
   Paid-in Capital                $573,888          $573,888           $573,888              $573,888            $573,888
  Retained Earnings                826,197           792,219            758,894               734,387             828,777
                                   -------           -------            -------               -------             -------
  Total Common
   Shareholder's Equity         $1,400,085        $1,366,107         $1,332,782            $1,308,275          $1,402,665
                                ==========        ==========         ==========            ==========          ==========
  Preferred Stock                  $ 5,967           $ 5,967            $ 5,967              $163,204            $163,204
                                   =======           =======            =======              ========            ========

  CPL - Obligated,
   Mandatorily
   Redeemable Preferred
   Securities of
   Subsidiary Trust
   Holding Solely
   Junior Subordinated
   Dentures of CPL                $136,250          $148,500           $150,000              $150,000            $150,000
                                  ========          ========           ========              ========            ========

  Long-term Debt (a)            $1,253,768        $1,454,559         $1,454,541            $1,350,706          $1,414,335
                                ==========        ==========         ==========            ==========          ==========

  Total Capitalization
   And Liabilities              $5,115,986        $5,467,684         $4,847,850            $4,735,476          $4,897,380
                                ==========        ==========         ==========            ==========          ==========
</TABLE>
(a) Including portion due within one year.

<PAGE>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations


       CPL is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to approximately 689,000 retail
customers in southern Texas. CPL also sells electric power at wholesale to other
utilities, municipalities and rural electric cooperatives.

       Wholesale power marketing and trading activities are conducted on CPL's
behalf by AEP. CPL shares in the revenues and costs of the AEP Power Pool's
wholesale sales to and forward trades with other utility systems and power
marketers.

Critical Accounting Policies - Revenue Recognition

Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.

         When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.

Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to CPL. Trading
activities allocated to CPL involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the
fair value of energy trading contracts.

           Recording the net change in the fair value of trading contracts as
revenues prior to settlement is commonly referred to as mark-to-market (MTM)
accounting. It represents the change in the unrealized gain or loss throughout
the contract's term. When the contract actually settles, that is, the energy is
actually delivered in a sale or received in a purchase or the parties agree to
forego delivery and receipt of electricity and net settle in cash, the
unrealized gain or loss is reversed out of revenues and the actual realized cash
gain or loss is recognized in revenues for a sale or in purchased power expense
for a purchase. Therefore, over the trading contract's term an unrealized gain
or loss is recognized as the contract's market value changes. When the contract
settles the total gain or loss is realized in cash but only the difference
between the accumulated unrealized net gains or losses recorded in prior months
and the cash proceeds is recognized. Unrealized mark-to-market gains and losses
are included in the Balance Sheet as energy trading contract assets or
liabilities as appropriate.


<PAGE>


        Our trading activities represent physical forward electricity contracts
that are typically settled by entering into offsetting contracts. An example of
our trading activities is when, in January, we enter into a forward sales
contract to deliver electricity in July. At the end of each month until the
contract settles in July, we would record our share of any difference between
the contract price and the market price as an unrealized gain or loss in
revenues. In July when the contract settles, we would realize our share of the
gain or loss in cash and reverse to revenues the previously recorded unrealized
gain or loss. Prior to settlement, the change in the fair value of physical
forward sale and purchase contracts is included in revenues on a net basis. Upon
settlement of a forward trading contract, the amount realized is included in
revenues for a sales contract and realized costs are included in purchased power
expense for a purchase contract with the prior change in unrealized fair value
reversed in revenues.

        Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
revenues from recording additional changes in fair values using mark-to-market
accounting.


        The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.

       Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing CPL to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.

Results of Operations

         Although operating revenues increased, income before extraordinary item
decreased $5 million or 3% in 2001. The decrease was primarily a result of a
settlement of Texas municipal franchise fees (see Note 8) and increased
maintenance expense.

         Income before extraordinary item increased $2 million or 1% in 2000
primarily as a result of increased retail energy sales, the post merger sharing
of AEP's power marketing and trading operations which increased wholesale sales
to neighboring utilities and power marketers and the effect of an unfavorable
adjustment in 1999 as a result of FERC's approval of a transmission coordination
agreement. These items were offset in part by a rise in interest expense.

Operating Revenues Rise

         Operating revenues increased 41% in 2001 and 58% in 2000. Both
increases are primarily due to an increase in wholesale marketing and trading
activities.

         The following analyzes the changes in operating revenues:

                         Increase (Decrease)
                         From Previous Year
                              (dollars in millions)
                             2001              2000
                             ----              ----
                      Amount       %     Amount      %
                      ------       -     ------      -

Retail*               $ 4.2       -     $193.6     23
Wholesale
 Marketing
 and Trading          924.6     127      651.4    859
Unrealized
 MTM                   28.1     343       (8.2)     -
Other                  16.9      27       (8.9)   (12)
  Total
   Marketing
   and
   Trading            973.8      53      827.9     82
Energy
 Delivery*             (5.6)     (1)      29.1      6
Sales to AEP
 Affiliates             4.0      11       10.0     36
                        ---               ----
   Total
    Revenues          $972.2     41     $867.0     58
                      ======            ======

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.

        Retail operating revenues increased 23% in 2000 due to an increase in
fuel and purchased power related revenues, reflecting rising prices for natural
gas and purchased power, and an increase in weather-related demand for
electricity. Through December 31, 2001 the Texas fuel and purchased power clause
recovery mechanism provides for the accrual of revenues to recover fuel and
purchased power cost increases until reviewed and approved for billing to
customers by the PUCT. As a result increases in fuel and purchased power
expenses and related accrued revenues do not adversely affect results of
opertions.


        The significant increase in wholesale marketing and trading revenues in
2001 is attributable to a full year of participation in AEP's power marketing
and trading operations. Trading involves the purchase and sale of substantial
amounts of electricity with non-affiliated parties.

        The significant increase in wholesale marketing and trading revenues in
2000 is primarily attributable to CPL's initial participation in AEP's power
marketing and trading operations. Since becoming a subsidiary of AEP as a result
of the merger in June 2000, CPL shares in AEP's power marketing and trading
transactions with other non-affiliated entities.

Operating Expenses Increase

         Total operating expenses increased 48% in 2001 and 72% in 2000. The
2001 increase is due primarily to purchased power, taxes and maintenance,
partially offset by a decrease in fuel costs. The 2000 increase was primarily
due to increased costs of fuel and purchased power and a rise in other operation
expense. The changes in the components of operating expenses were:

                           Increase (Decrease)
                           From Previous Year
                              (dollars in millions)
                             2001              2000
                             ----              ----
                      Amount      %      Amount     %
                      ------      -      ------     -

Fuel                 $(58.8)    (11)    $146.9     36
Marketing
 And
 Trading
 Purchases            987.6     137      671.6    N.M.
AEP
 Affiliate
 Purchases             26.0      80       15.9     95
Other
 Operation              1.7       1       28.4     10
Maintenance            10.7      18       (9.6)   (14)
Depreciation
 And
Amortization          (10.4)     (6)       1.1      1
Taxes Other
 Than Income
 Taxes                 14.4      19        2.7      4
Income Taxes           12.4      12       (3.1)    (3)
                       ----               ----
    Total            $983.6      48     $853.9     72
                     ======             ======

N.M. = Not Meaningful

         The decrease in fuel expense in 2001 was primarily due to a reduction
in the average cost of fuel primarily from a decline in natural gas prices. CPL
uses natural gas as fuel for 71% of its generating capacity. The nature of the
natural gas market is such that both long-term and short-term contracts are
generally based on the current spot market price. Changes in natural gas prices
affect CPL's fuel expense, however, as explained above, they generally do not
impact results of operations.

         Fuel expense increased in 2000 primarily due to a rise in the average
cost of fuel reflecting large increases in natural gas prices.

       The significant increase in electricity marketing and trading purchased
power in 2001 and 2000 was attributable to our participation in AEP's power
marketing and trading operation.

       Purchased power from AEP affiliates increased largely due to higher
natural gas prices. Although gas prices declined in 2001, they were higher
during the first half of 2001 when CPL was making most of its purchases.
Throughout 2000 gas prices were increasing accounting for the rise in AEP
affiliated purchased power expense.

       Other operation expense increased in 2000 due primarily to an increase in
transmission expenses that resulted from new prices for the ERCOT transmission
grid. Each year ERCOT establishes new rates to allocate the costs of the Texas
transmission system to Texas electric utilities. In addition to higher
transmission expenses, other operation expense increased due to higher
administrative expenses resulting from the Company's share of STP voluntary
severance expenses and Texas regulatory expenses.

       The principal cause of the increase in maintenance expense in 2001 was
two refueling outages at the STP verses one in 2000. Also contributing to the
increase in maintenance expense were scheduled major overhauls of four power
plants.


       Maintenance expense decreased in 2000 as a result of a 10-year service
inspection and refueling of STP Units 1 and 2 performed in 1999.

       Taxes other than income taxes increased in 2001 due primarily to an
increase in franchise related taxes, including a settlement of disputed
franchise fees (see Note 8), and a new tax levied by the PUCT, the Texas System
Benefit Fund Assessment.

       The increase in income tax expense was primarily due to adjustments
associated with prior year tax returns and an increase in pre-tax book income.

Interest Charges

       The decrease in interest charges in 2001 was attributable to lower
average interest rates associated with short-term and long-term debt.

       The increase in interest charges in 2000 can be attributed to higher
average interest rates on debt.

Extraordinary Loss

       The extraordinary loss on reacquired debt recorded in 2001 was the result
of reacquisition of installment purchase contracts for Matagorda County,
Navigation District, Texas.

Preferred Stock Dividends

       Preferred stock dividends decreased in 2000 as a result of the redemption
of preferred stock in the fourth quarter of 1999, which resulted in a loss on
reacquired preferred stock recorded in 1999.





<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
                                                                  Year Ended December 31,
                                                           ----------------------------------------
                                                           2001              2000              1999
                                                           ----              ----              ----
                                                                       (in thousands)
<S>                                                 <C>                 <C>                <C>
OPERATING REVENUES:
  Electricity Marketing and Trading                  $2,806,783          $1,832,937         $1,005,037
  Energy Delivery                                       473,182             478,814            449,667
  Sales to AEP Affiliates                                41,762              37,752             27,771
                                                         ------              ------             ------
     TOTAL REVENUES                                   3,321,727           2,349,503          1,482,475

OPERATING EXPENSES:
  Fuel                                                  492,057             550,903            403,989
  Purchased Power:
    Electricity Marketing and Trading                 1,710,706             723,122             51,482
    AEP Affiliates                                       58,641              32,591             16,673
  Other Operation                                       321,227             319,539            291,131
  Maintenance                                            71,212              60,528             70,165
  Depreciation and Amortization                         168,341             178,786            177,702
  Taxes Other Than Income Taxes                          90,916              76,477             73,823
  Income Taxes                                          112,896             100,459            103,525
                                                        -------             -------            -------
    Total Operating Expenses                          3,025,996           2,042,405          1,188,490
                                                      ---------           ---------          ---------

OPERATING INCOME                                        295,731             307,098            293,985

NONOPERATING INCOME                                      22,552               5,830              6,420

NONOPERATING EXPENSES                                    17,626               3,668              3,593

NONOPERATING INCOME TAX EXPENSE (CREDIT)                   (398)             (5,073)            (5,286)

INTEREST CHARGES                                        116,268             124,766            114,380
                                                        -------             -------            -------

INCOME BEFORE EXTRAORDINARY ITEM                        184,787             189,567            187,718

EXTRAORDINARY LOSS ON REACQUIRED DEBT (Inclusive
 of Tax $1,351,000 and $2,971,000 for 2001 and
 1999, respectively)                                     (2,509)               -                (5,517)
                                                         ------                ----             ------

NET INCOME                                              182,278             189,567            182,201

PREFERRED STOCK DIVIDEND REQUIREMENTS                       242                 241              6,931

LOSS ON REACQUIRED PREFERRED STOCK                         -                   -                (2,763)
                                                           ----                ----             ------

EARNINGS APPLICABLE TO COMMON STOCK                    $182,036            $189,326           $172,507
                                                       ========            ========           ========
</TABLE>
See Notes to Financial Statements Beginning on Page L-1.

<PAGE>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
                                                          December 31,
                                                     -----------------------
                                                     2001               2000
                                                     ----               ----
                                                         (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                     $3,169,421          $3,175,867
  Transmission                                      663,655             581,931
  Distribution                                    1,279,037           1,221,750
  General                                           241,137             237,764
  Construction Work in Progress                     169,075             138,273
  Nuclear Fuel                                      247,382             236,859
                                                    -------             -------
          Total Electric Utility Plant            5,769,707           5,592,444
  Accumulated Depreciation and Amortization       2,446,027           2,297,189
                                                  ---------           ---------
          NET ELECTRIC UTILITY PLANT              3,323,680           3,295,255
                                                  ---------           ---------

OTHER PROPERTY AND INVESTMENTS                       47,950              44,225
                                                     ------              ------

LONG-TERM ENERGY TRADING CONTRACTS                   72,502              65,786
                                                     ------              ------

CURRENT ASSETS:
  Cash and Cash Equivalents                          10,909              14,253
  Accounts Receivable:
   General                                           38,459              67,787
   Affiliated Companies                               6,249              31,272
   Allowance for Uncollectible Accounts                (186)             (1,675)
  Fuel Inventory - at LIFO cost                      38,690              22,842
  Materials and Supplies - at average cost           55,475              53,108
  Under-recovered Fuel Costs                           -                127,295
  Energy Trading Contracts                          212,979             476,839
  Prepayments                                         2,742               3,014
                                                      -----               -----
          TOTAL CURRENT ASSETS                      365,317             794,735
                                                    -------             -------

REGULATORY ASSETS                                   226,806             202,440
                                                    -------             -------

REGULATORY ASSETS DESIGNATED FOR SECURITIZATION     959,294             953,249
                                                    -------             -------

NUCLEAR DECOMMISSIONING TRUST FUND                   98,600              93,592
                                                     ------              ------

DEFERRED CHARGES                                     21,837              18,402
                                                     ------              ------

                    TOTAL                        $5,115,986          $5,467,684
                                                 ==========          ==========

See Notes to Financial Statements beginning on page L-1.



<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
                                                               December 31,
                                                         ------------------------
                                                         2001                2000
                                                         ----                ----
                                                               (in thousands)
<S>                                                   <C>                <C>
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $25 Par Value:
    Authorized - 12,000,000 Shares
    Outstanding - 6,755,535 Shares                      $168,888           $168,888
  Paid-in Capital                                        405,000            405,000
  Retained Earnings                                      826,197            792,219
                                                         -------            -------
    Total Common Shareholder's Equity                  1,400,085          1,366,107
  Preferred Stock                                          5,967              5,967
  CPL - Obligated, Mandatorily Redeemable Preferred
   Securities of Subsidiary Trust Holding Solely
   Junior Subordinated Debentures of CPL                 136,250            148,500

Long-term Debt                                           988,768          1,254,559
                                                         -------          ---------
          TOTAL CAPITALIZATION                         2,531,070          2,775,133
                                                       ---------          ---------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                     265,000            200,000
  Advances from Affiliates                               354,277            269,712
  Accounts Payable - General                              65,307            128,957
  Accounts Payable - Affiliated Companies                 49,301             40,962
  Over-Recovered Fuel                                     57,762               -
  Taxes Accrued                                           83,512             55,526
  Interest Accrued                                        18,524             26,217
  Energy Trading Contracts                               219,486            485,521
  Other                                                   49,512             40,630
                                                          ------             ------

          Total CURRENT LIABILITIES                    1,162,681          1,247,525
                                                       ---------          ---------

DEFERRED INCOME TAXES                                  1,163,795          1,242,797
                                                       ---------          ---------

DEFERRED INVESTMENT TAX CREDITS                          122,892            128,100
                                                         -------            -------

LONG-TERM ENERGY TRADING CONTRACTS                        62,138             65,295
                                                          ------             ------

DEFERRED CREDITS                                          73,410              8,834
                                                          ------              -----

COMMITMENTS AND CONTINGENCIES (Note 8)

                    TOTAL                             $5,115,986         $5,467,684
                                                      ==========         ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
                                                                Year Ended December 31,
                                                                -----------------------
                                                          2001              2000               1999
                                                          ----              ----               ----
                                                                     (in thousands)
<S>                                                   <C>               <C>                <C>
OPERATING ACTIVITIES:
  Net Income                                           $ 182,278         $ 189,567          $ 182,201
  Adjustments for Noncash Items:
    Depreciation and Amortization                        168,341           178,786            177,702
    Extraordinary Loss on Reacquired Debt                  2,509              -                 5,517
    Deferred Income Taxes                                (72,568)           16,263             19,938
    Deferred Investment Tax Credits                       (5,208)           (5,207)            (5,207)
    Mark-to-Market of Energy Trading Contracts           (12,048)            8,191               -
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                             52,862           (32,902)           (13,426)
    Fuel, Materials and Supplies                         (18,215)            8,680             (4,476)
    Interest Accrued                                      (7,693)           11,494            (12,313)
    Fuel Recovery                                        185,057           (96,872)           (40,046)
    Accounts Payable                                     (55,311)           45,873             (3,061)
    Taxes Accrued                                         27,986            14,405             (5,734)
  Transmission Coordination Agreement Settlement            -               15,519            (15,519)
  Change in Other Assets                                  10,756               599          19,974
  Change in Other Liabilities                             11,174            12,233            (554)
                                                          ------            ------            -----
            Net Cash Flows From Operating Activities     469,920           366,629            304,996
                                                         -------           -------            -------

INVESTING ACTIVITIES:
  Construction Expenditures                             (193,732)         (199,484)          (210,823)
  Proceeds From Sales of Property and Other                 (354)             -                15,063
                                                            ----              ----             ------
            Net Cash Flows Used For Investing
             Activities                                 (194,086)         (199,484)          (195,760)
                                                        --------          --------           --------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                             260,162           149,248            358,887
  Retirement of Preferred Stock                             -                 -              (160,001)
  Retirement of Long-term Debt                          (475,606)         (151,440)          (261,700)
  Change in Advances from Affiliates (net)                84,565           (52,446)           161,860
  Special Deposit for Reacquisition of Long-term Debt       -               50,000            (50,000)
  Dividends Paid on Common Stock                        (148,057)         (156,000)          (148,000)
  Dividends Paid on Cumulative Preferred Stock              (242)             (249)            (7,835)
                                                            ----              ----             ------
            Net Cash Flows Used For
             Financing Activities                       (279,178)         (160,887)          (106,789)
                                                        --------          --------           --------

Net Increased (Decrease) in Cash and Cash Equivalents     (3,344)            6,258              2,447
Cash and Cash Equivalents January 1                       14,253             7,995              5,548
                                                          ------             -----              -----
Cash and Cash Equivalents December 31                    $10,909           $14,253            $ 7,995
                                                         =======           =======            =======
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts (including distributions on
Trust Preferred Securities) was $109,835,000, $110,010,000 and $125,222,000 and
for income taxes was $161,529,000, $48,141,000 and $78,393,000 in 2001, 2000 and
1999,respectively.

See Notes to Financial Statements beginning on page L-1.


<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
                                                 Year Ended December 31,
                                        -----------------------------------------
                                        2001              2000               1999
                                        ----              ----               ----
                                                   (in thousands)
<S>                                   <C>               <C>                <C>
BEGINNING OF PERIOD                   $792,219          $758,894           $734,387
NET INCOME                             182,278           189,567            182,201

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                       148,057           156,000            148,000
    Preferred Stock                        242               241              6,931
  Other                                      1                 1               -

LOSS ON REACQUIRED PREFERRED STOCK        -                 -                (2,763)
                                          ----              ----             ------

BALANCE AT END OF PERIOD              $826,197          $792,219           $758,894
                                      ========          ========           ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization

                                                                                  December 31,
                                                                         -----------------------------
                                                                             2001             2000
                                                                             ----             ----
                                                                                (in thousands)

<S>                                                                      <C>               <C>
COMMON SHAREHOLDERS' EQUITY                                              $1,400,085        $1,366,107
                                                                         ----------        ----------

PREFERRED STOCK - authorized shares 3,035,000 $100 par value

            Call Price                                           Shares
           December 31,      Number of Shares Redeemed        Outstanding
Series         2001            Year Ended December 31,     December 31, 2001
- ------     ------------     ----------------------------   -----------------
                              2001      2000      1999
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4.00%        $105.75           -         -         -             42,038       4,204             4,204
4.20%         103.75           -         -         -             17,476       1,748             1,748
Premium                                                                          15                15
                                                                         ----------        ----------
  Total Preferred Stock                                                       5,967             5,967
                                                                         ----------        ----------

TRUST PREFERRED SECURITIES:

 CPL-obligated, mandatorily redeemable preferred securities of subsidiary trust
 holding solely Junior Subordinated Debentures of CPL, 8.00%,
 due April 30, 2037                                                         136,250           148,500
                                                                         ----------        ----------

LONG-TERM (See Schedule of Long-term Debt):

First Mortgage Bonds                                                        614,200           615,000
Installment Purchase Contracts                                              489,568           489,559
Senior Unsecured Notes                                                      150,000           350,000
Less Portion Due Within One year                                           (265,000)         (200,000)
                                                                         ----------        ----------

Long-term Debt Excluding Portion Due Within One Year                        988,768         1,254,559
                                                                         ----------        ----------

     TOTAL CAPITALIZATION                                                $2,531,070        $2,775,133
                                                                         ==========        ==========
</TABLE>

See Notes to Financial Statements beginning on page L-1.

<PAGE>

CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt

First mortgage bonds outstanding were as follows:
                                     December 31,
                                -----------------
                                     2001         2000
                                     ----         ----
                                     (in thousands)
% Rate Due
7.25  2004 - October 1          $100,000      $100,000
7.50  2002 - December 1          115,000       115,000
6-7/8 2003 - February 1           49,200        50,000
7-1/8 2008 - February 1           75,000        75,000
7.50  2023 - April 1              75,000        75,000
6-5/8 2005 - July 1              200,000       200,000
Unamortized Discount                -             -
                                --------      -----
  Total                         $614,200      $615,000
                                ========      ========

         First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.

Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:

                                 December 31,
                                 2001         2000
                                 ----         ----
                                 (in thousands)
% Rate Due
Matagorda County
 Navigation District,
 Texas:
6.00  2028    - July 1         $120,265     $120,265
6.10  2028    - July 1             -         100,635
6-1/8 2030    - May 1            60,000       60,000
4.90  2030    - May 1              -         111,700
4.95  2030    - May 1              -          50,000
3.75  2030(a) - May 1           111,700         -
4.00  2030(a) - May 1            50,000         -
4.55  2029(a) - Nov 1           100,635         -
Guadalupe-Blanco
 River Authority
 District, Texas:

(b)  2015 - November 1           40,890       40,890

Red River Authority
 District, Texas:
6.00  2020 - June 1               6,330        6,330
Unamortized Discount               (252)        (261)
                               --------     --------
  Total                        $489,568     $489,559
                               ========     ========

(a)Installment Purchase Contract provides for bonds to be tendered in 2003 for
3.75% and 4.00% series and in 2006 for 4.55% series. Therefore, these
installment purchase contracts have been classified for payments in those years.
(b) A  floating  interest  rate is  determined  monthly.
The rate on December 31, 2001 was 1.9%.


         Under the terms of the installment purchase contracts, CPL is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.

Senior unsecured notes outstanding were as follows:
                                       December 31,
                                     -----------------
                                     2001         2000
                                     ----         ----
                                      (in thousands)
% Rate Due
    2001 - November 23          $   -         $200,000
(c) 2002 - February 22           150,000       150,000
                                --------      --------
  Total                         $150,000      $350,000
                                ========      ========

(c) A floating interest rate is determined monthly. The rate on December 31,
2001 and 2000 was 2.56% and 7.20%, respectively.

         At December 31, 2001, future annual long-term debt payments are as
follows:

                                           Amount
                                           ------
                                       (in thousands)
2002                                       $265,000
2003                                        210,900
2004                                        100,000
2005                                        200,000
2006                                        100,635
Later Years                                 377,485
                                            -------
  Total Principal Amount                  1,254,020
Unamortized Discount                           (252)
                                               ----
    Total                                $1,253,768
                                         ==========

<PAGE>

CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements

The notes to CPL financial statements are combined with the notes to financial
statements for AEP and its other subsidiary registrants. Listed below are the
combined notes that apply to CPL. The combined footnotes begin on page L-1.

                                                          Combined
                                                          Footnote
                                                          Reference

Significant Accounting Policies                           Note  1

Extraordinary Items and Cumulative Effect                 Note  2

Merger                                                    Note  3

Rate Matters                                              Note  5

Effects of Regulation                                     Note  6

Customer Choice and Industry Restructuring                Note  7

Commitments and Contingencies                             Note  8

Benefit Plans                                             Note 10

Business Segments                                         Note 12

Risk Management, Financial Instruments and Derivatives    Note 13

Income Taxes                                              Note 14

Leases                                                    Note 18

Lines of Credit and Sale of Receivables                   Note 19

Unaudited Quarterly Financial Information                 Note 20

Trust Preferred Securities                                Note 21

Jointly Owned Electric Utility Plant                      Note 23

Related Party Transactions                                Note 24




<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of Directors
of Central Power and Light Company:

         We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Central Power and Light Company and
subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, retained earnings, and cash flows for the years then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. The consolidated financial statements of the
Company for the year ended December 31, 1999, before the restatement described
in Note 3 to the consolidated financial statements, were audited by other
auditors whose report, dated February 25, 2000, expressed an unqualified opinion
on those statements.

         We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

         In our opinion, such 2001 and 2000 consolidated financial statements
present fairly, in all material respects, the financial position of Central
Power and Light Company and subsidiaries as of December 31, 2001 and 2000, and
the results of their operations and their cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States of
America.

         We also audited the adjustments described in Note 3 that were applied
to restate the 1999 consolidated financial statements to give retroactive effect
to the conforming change in the method of accounting for vacation pay accruals.
In our opinion, such adjustments are appropriate and have been properly applied.



Deloitte & Touche LLP
Columbus, Ohio
February 22, 2002



<PAGE>












                         COLUMBUS SOUTHERN POWER COMPANY
                                AND SUBSIDIARIES


<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
                                                      Year Ended December 31,
                                             2001               2000              1999               1998               1997
                                             ----               ----              ----               ----               ----
                                                                          (in thousands)
INCOME STATEMENTS DATA:
<S>                                     <C>                 <C>               <C>                <C>                <C>
  Operating Revenues                     $4,299,863          $3,165,615        $2,631,739         $2,102,295         $1,139,604
  Operating Expenses                      4,047,686           2,969,738         2,408,949          1,890,084            944,477
                                          ---------           ---------         ---------          ---------            -------
  Operating Income                          252,177             195,877           222,790            212,211            195,127
  Nonoperating Income
   (Loss)                                     7,738               5,153             2,709             (1,343)             3,137
  Interest Charges                           68,015              80,828            75,229             77,824             78,885
                                             ------              ------            ------             ------             ------
  Income Before
   Extraordinary Item                       191,900             120,202           150,270            133,044            119,379
  Extraordinary Loss                        (30,024)            (25,236)             -                  -                  -
                                            -------             -------              ----               ----               ----
  Net Income                                161,876              94,966           150,270            133,044            119,379
  Preferred Stock
   Dividend
   Requirements                               1,095               1,783             2,131              2,131              2,442
                                              -----               -----             -----              -----              -----
  Earnings Applicable to
   Common Stock                            $160,781             $93,183          $148,139           $130,913           $116,937
                                           ========             =======          ========           ========           ========

                                                        Year Ended December 31,
                                             2001                2000              1999              1998               1997
                                             ----                ----              ----              ----               ----
                                                                           (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant                  $3,354,320          $3,266,794        $3,151,619        $3,053,565         $2,976,110
  Accumulated Depreciation                 1,377,032           1,299,697         1,210,994         1,134,348          1,074,588
                                           ---------           ---------         ---------         ---------          ---------
  Net Electric Utility
   Plant                                  $1,977,288          $1,967,097        $1,940,625        $1,919,217         $1,901,522
                                          ==========          ==========        ==========        ==========         ==========

  Total Assets                            $3,105,868          $3,888,302        $2,809,990        $2,681,690         $2,613,860
                                          ==========          ==========        ==========        ==========         ==========

  Common Stock and
   Paid-in Capital                          $615,395            $614,380          $613,899          $613,518           $613,138
  Retained Earnings                          176,103              99,069           246,584           186,441            138,172
                                             -------              ------           -------           -------            -------
  Total Common
   Shareholder's Equity                     $791,498            $713,449          $860,483          $799,959           $751,310
                                            ========            ========          ========          ========           ========

  Cumulative Preferred
   Stock - Subject to
   Mandatory
   Redemption (a)                           $ 10,000            $ 15,000          $ 25,000          $ 25,000           $ 25,000
                                            ========            ========          ========          ========           ========

  Long-term Debt (a)                        $791,848            $899,615          $924,545          $959,786           $969,600
                                            ========            ========          ========          ========           ========

  Obligations Under
   Capital Leases (a)                       $ 34,887            $ 42,932          $ 40,270          $ 42,362           $ 38,587
                                            ========            ========          ========          ========           ========

  Total Capitalization and Liabilities
                                          $3,105,868          $3,888,302        $2,809,990        $2,681,690         $2,613,860
                                          ==========          ==========        ==========        ==========         ==========
</TABLE>
(a) Including portion due within one year.

<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Management's Narrative Analysis of Results of Operations


      Columbus Southern Power Company is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
678,000 retail customers in central and southern Ohio. CSPCo as a member of the
AEP Power Pool shares in the revenues and costs of the AEP Power Pool's
wholesale sales to neighboring utility systems and power marketers including
power trading transactions. CSPCo also sells wholesale power to municipalities.

      The cost of the AEP Power Pool's generating capacity is allocated among
the Pool members based on their relative peak demands and generating reserves
through the payment of capacity charges and receipt of capacity credits. AEP
Power Pool members are also compensated for their out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing AEP Power Pool revenues and costs. The result of this calculation is the
member load ratio (MLR) which determines each company's percentage share of AEP
Power Pool revenues and costs.

Critical Accounting Policies - Revenue Recognition

Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.

         When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.

Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to CSPCo as a
member of the AEP Power Pool. Trading activities involve the purchase and sale
of energy under physical forward contracts at fixed and variable prices and
buying and selling financial energy contracts which includes exchange traded
futures and options and over-the-counter options and swaps. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the
fair value of energy trading contracts.

           Recording the net change in the fair value of trading contracts prior
to settlement is commonly referred to as mark-to-market (MTM) accounting. It
represents the change in the unrealized gain or loss throughout the contract's
term. When the contract actually settles, that is, the energy is actually
delivered in a sale or received in a purchase or the parties agree to forego
delivery and receipt and net settle in cash, the unrealized gain or loss is
reversed and the actual realized cash gain or loss is recognized. Therefore,
over the trading contract's term an unrealized gain or loss is recognized as the
contract's market value changes. When the contract settles the total gain or
loss is realized in cash but only the difference between the accumulated
unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized. Unrealized mark-to-market gains and losses are included in the
Balance Sheet as energy trading contract assets or liabilities as appropriate.

           The majority of our trading activities represent physical forward
electricity contracts that are typically settled by entering into offsetting
contracts. An example of our trading activities is when, in January, we enter
into a forward sales contract to deliver electricity in July. At the end of each
month until the contract settles in July, we would record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract settles, we would realize our share of the
gain or loss in cash and reverse the previously recorded unrealized gain or
loss.

           Depending on whether the delivery point for the electricity is in
AEP's traditional marketing area or not determines where the contract is
reported on CSPCo's income statement. AEP's traditional marketing area is up to
two transmission systems from the AEP service territory. Physical forward
trading sale contracts with delivery points in AEP's traditional marketing area
are included in revenues when the contracts settle. Physical forward trading
purchase contracts with delivery points in AEP's traditional marketing area are
included in purchased power expense when they settle. Prior to settlement,
changes in the fair value of physical forward sale and purchase contracts in
AEP's traditional marketing area are included in revenues on a net basis.
Physical forward sales contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating income when the contract settles.
Physical forward purchase contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating expenses when the contract settles.
Prior to settlement, changes in the fair value of physical forward sale and
purchase contracts with delivery points outside of AEP's traditional marketing
area are included in nonoperating income on a net basis.

        Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
results of operations from recording additional changes in fair values using
mark-to-market accounting.

        Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior unrealized gain
or loss.
        The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.

        Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing CSPCo to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.

Results of Operations
Net Income Increases

        Income before extraordinary item increased by $72 million or 60% in 2001
primarily due to the effect of a court decision related to a corporate owned
life insurance (COLI) program recorded in 2000. In February 2001 the U.S.
District Court for the Southern District of Ohio ruled against AEP and certain
of its subsidiaries, including CSPCo, in a suit over the deductibility of
interest claimed in AEP's consolidated tax return related to COLI. In 1998 and
1999 CSPCo paid the disputed taxes and interest attributable to the COLI
interest deductions for taxable years 1991-98. The payments were included in
Other Property and Investments pending the resolution of this matter. Also
contributing to the increase in net income in 2001 was growth in and strong
performance by the wholesale business in the first half of 2001 offset in part
by the effect of extremely mild weather in November and December combined with
weak economic conditions which reduced retail energy sales.

Operating Revenues Increase

        Operating revenues increased 36% in 2001 due to the significant increase
in wholesale marketing and trading volume. Changes in the components of
operating revenues were as follows:

                                     Increase (Decrease)
                                From Previous Year
                                   (dollars in millions)
                                    Amount       %
Retail*                             $  (65.1)    (10)
Wholesale Marketing and
 Trading                             1,072.1      53
Unrealized MTM                          23.1      N.M.
Other                                    0.8       2
                                    --------
Total Marketing and
 Trading                             1,030.9      38
Energy Delivery*                        85.2      21
Sales to AEP Affiliates                 18.1      37
                                    --------
   Total Revenues                   $1,134.2      36
                                    ========

N.M. = Not Meaningful

*Reflects the allocation in 2000 of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.

        The significant increase in wholesale marketing and trading revenues was
caused by a 46% volume increase in 2001. The maturing of the Intercontinental
Exchange, the development of proprietary tools, and increased staffing of energy
traders has resulted in an increase in the number of forward electricity
purchase and sales contracts in AEP's traditional marketing area.



<PAGE>


Operating Expenses Rise

        Operating expenses increased by 36% in 2001 due primarily to a
significant increase in purchased power expense. Changes in the components of
operating expenses were:

                                Increase (Decrease)
                                 From Previous Year
                                   (dollars in millions)
                                    Amount         %

Fuel                            $  (14.0)         (7)
Marketing and Trading
 Purchases                       1,089.5          58
AEP Affiliate Purchases              4.4           2
Other Operation Expense             (0.4)          -
Maintenance Expense                 (7.2)        (10)
Depreciation and
 Amortization                       27.7          28
Taxes Other Than
  Income Taxes                     (11.7)        (10)
Income Taxes                       (10.3)         (9)
                                --------
     Total                      $1,078.0          36
                                ========

        Fuel costs decreased by $14 million due to a 12.5% decrease in
generation partially offset by increased coal prices of 6.3%

        The increase in marketing and trading purchases is reflective of the
increase in trading volume.

        Reversal of a quality of service regulatory liability accrual and
reduced maintenance of overhead distribution lines accounted for the decease in
maintenance expense.

        Depreciation and amortization expense increased significantly due to
amortization of transition regulatory assets which began in January 2001. With
the implementation of customer choice in Ohio on January 1, 2001, the PUCO
approved the Company's plan for recovery of generation-related regulatory assets
through frozen transition rates. Concurrent with the start of the transition
period, we began amortization of the transition regulatory assets. Depreciation
expense also increased due to additional plant investment.


        The decrease in taxes other than income taxes in 2001 is due to a
decrease in property tax rates on generation property partially offset by a new
state excise tax.

        The decrease in income tax expense was primarily due to an unfavorable
ruling in AEP's suit against the government over interest deductions claimed
relating to AEP's COLI program which was recorded in 2000 offset in part by an
increase in pre-tax income.

Nonoperating Income and Nonoperating Expense

        The increase in nonoperating income and nonoperating expense in 2001 was
due to a significant increase in the wholesale business trading transactions
outside of AEP's traditional marketing area.

Interest Charges Decrease

        Interest charges for 2001 decreased as a result of the recognition in
2000 of deferred interest payments to the IRS related to the COLI disallowances
as well as reduced debt in 2001.

Extraordinary Loss

       In 2001 we recorded an extraordinary loss of $30 million net of tax to
write-off prepaid Ohio excise taxes stranded by Ohio deregulation (see Note 2,
"Extraordinary Items and Cumulative Effect").



<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
                                                                Year Ended December 31,
                                                        ---------------------------------------------
                                                        2001                  2000               1999
                                                        ----                  ----               ----
                                                                    (in thousands)
<S>                                                 <C>                   <C>                <C>
OPERATING REVENUES:
  Electricity Marketing and Trading                  $3,749,133            $2,718,204         $2,222,741
  Energy Delivery                                       483,219               398,046            389,280
  Sales to AEP Affiliates                                67,511                49,365             19,718
                                                         ------            ----------         ----------
            Total Operating Revenues                  4,299,863             3,165,615          2,631,739
                                                      ---------             ---------          ---------

OPERATING EXPENSES:
  Fuel                                                  175,153               189,155            185,511
  Purchased Power:
    Electricity Marketing and Trading                 2,958,656             1,869,150          1,467,628
    AEP Affiliates                                      292,199               287,750            199,574
  Other Operation                                       221,342               221,775            190,614
  Maintenance                                            62,454                69,676             65,229
  Depreciation and Amortization                         127,364                99,640             94,532
  Taxes Other Than Income Taxes                         111,481               123,223            120,146
  Income Taxes                                           99,037               109,369             85,715
                                                         ------               -------             ------
            TOTAL OPERATING EXPENSES                  4,047,686             2,969,738          2,408,949
                                                      ---------             ---------          ---------

OPERATING INCOME                                        252,177               195,877            222,790

NONOPERATING INCOME                                   1,334,302               780,159            410,226

NONOPERATING EXPENSES                                 1,322,641               767,649            410,457

NONOPERATING INCOME TAX EXPENSE (CREDIT)                  3,923                 7,357             (2,940)

INTEREST CHARGES                                         68,015                80,828             75,229
                                                         ------                ------             ------

INCOME BEFORE EXTRAORDINARY ITEM                        191,900               120,202            150,270

EXTRAORDINARY LOSS - DISCONTINUANCE OF
 REGULATORY ACCOUNTING FOR GENERATION - Net of
 tax (Note 2)                                           (30,024)              (25,236)              -
                                                        -------               -------               ----

NET INCOME                                              161,876                94,966            150,270

PREFERRED STOCK DIVIDEND REQUIREMENTS                     1,095                 1,783              2,131
                                                          -----                 -----              -----

EARNINGS APPLICABLE TO COMMON STOCK                    $160,781              $ 93,183           $148,139
                                                       ========              ========           ========
</TABLE>
Consolidated Statements of Retained Earnings
<TABLE>
<CAPTION>
                                                                    Year Ended December 31,
                                                         ---------------------------------------------
                                                         2001                  2000               1999
                                                         ----                  ----               ----
                                                                       (in thousands)
<S>                                                   <C>                   <C>                <C>
Retained Earnings January 1                            $ 99,069              $246,584           $186,441
Net Income                                              161,876                94,966            150,270
                                                        -------                ------            -------
                                                        260,945               341,550            336,711
                                                        -------               -------            -------
Deductions:
Cash Dividends Declared:
  Common Stock                                           82,952               240,600             87,996
  Cumulative Preferred Stock - 7% Series                    875                 1,400              1,750
                                                            ---                 -----              -----
          Total Cash Dividends Declared                  83,827               242,000             89,746
Capital Stock Expense                                     1,015                   481                381
                                                          -----                   ---                ---
          Total Deductions                               84,842               242,481             90,127
                                                         ------               -------             ------
Retained Earnings December 31                          $176,103              $ 99,069           $246,584
                                                       ========              ========           ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.

<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
                                                     December 31,
                                               ------------------------
                                               2001                2000
                                               ----                ----
                                                    (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                $1,574,506          $1,564,254
  Transmission                                 401,405             360,302
  Distribution                               1,159,105           1,096,365
  General                                      146,732             156,534
  Construction Work in Progress                 72,572              89,339
                                                ------              ------
          Total Electric Utility Plant       3,354,320           3,266,794
  Accumulated Depreciation                   1,377,032           1,299,697
                                             ---------           ---------

          NET ELECTRIC UTILITY PLANT         1,977,288           1,967,097
                                             ---------           ---------

OTHER PROPERTY AND INVESTMENTS                  40,369              39,848
                                                ------              ------

LONG-TERM ENERGY TRADING CONTRACTS             193,915             171,820
                                               -------             -------

CURRENT ASSETS:
 Cash and Cash Equivalents                      12,358              11,600
 Accounts Receivable:
  Customers                                     41,770              73,711
  Affiliated Companies                          63,470              49,591
  Miscellaneous                                 16,968              18,807
  Allowance for Uncollectible Accounts            (745)               (659)
 Fuel - at average cost                         20,019              13,126
 Materials and Supplies - at average cost       38,984              38,097
 Accrued Utility Revenues                        7,087               9,638
 Energy Trading Contracts                      347,198           1,079,704
 Prepayments                                    28,733              46,735
                                                ------              ------
          TOTAL CURRENT ASSETS                 575,842           1,340,350
                                               -------           ---------

REGULATORY ASSETS                              262,267             291,553
                                               -------             -------

DEFERRED CHARGES                                56,187              77,634
                                                ------              ------

                    TOTAL                   $3,105,868          $3,888,302
                                            ==========          ==========

See Notes to Financial Statements beginning on page L-1.


<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                                                       December 31,
                                                   ---------------------
                                                   2001             2000
                                                   ----             ----
                                                     (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - No Par Value:
   Authorized - 24,000,000 Shares
   Outstanding - 16,410,426 Shares              $ 41,026           $ 41,026
  Paid-in Capital                                574,369            573,354
  Retained Earnings                              176,103             99,069
                                                 -------             ------
          Total Common Shareholder's Equity      791,498            713,449
  Cumulative Preferred Stock - Subject to
   Mandatory Redemption                           10,000             15,000
  Long-term Debt                                 571,348            899,615
                                                 -------            -------
          TOTAL CAPITALIZATION                 1,372,846          1,628,064
                                               ---------          ---------

OTHER NONCURRENT LIABILITIES                      36,715             47,584
                                                  ------             ------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year             220,500               -
  Advances from Affiliates                       181,384             88,732
  Accounts Payable - General                      62,393             89,846
  Accounts Payable - Affiliated Companies         83,697             72,493
  Taxes Accrued                                  116,364            162,904
  Interest Accrued                                10,907             13,369
  Energy Trading Contracts                       334,958          1,109,682
  Other                                           34,600             60,701
                                                  ------             ------
          TOTAL CURRENT LIABILITIES            1,044,803          1,597,727
                                               ---------          ---------

DEFERRED INCOME TAXES                            443,722            422,759
                                                 -------            -------

DEFERRED INVESTMENT TAX CREDITS                   37,176             41,234
                                                  ------             ------

LONG-TERM ENERGY TRADING CONTRACTS               157,706            138,073
                                                 -------            -------

DEFERRED CREDITS                                  12,900             12,861
                                                  ------             ------

COMMITMENTS AND CONTINGENCIES (Note 8)

                    TOTAL                     $3,105,868         $3,888,302
                                              ==========         ==========
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
                                                                 Year Ended December 31,
                                                           -----------------------------------------
                                                           2001              2000               1999
                                                           ----              ----               ----
                                                                     (in thousands)
<S>                                                   <C>                  <C>              <C>
OPERATING ACTIVITIES:
  Net Income                                           $ 161,876            $ 94,966         $ 150,270
  Adjustments for Noncash Items:
    Depreciation and Amortization                        128,500             100,182            94,962
    Deferred Federal Income Taxes                         24,108              (4,063)           10,481
    Deferred Investment Tax Credits                       (4,058)             (3,482)           (3,994)
    Deferred Fuel Costs (net)                               -                  5,352             8,889
    Mark to Market of Energy Trading Contracts           (44,680)             (3,393)           (2,369)
    Extraordinary Loss                                    30,024              25,236              -
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                             19,987             (29,737)            5,166
    Fuel, Materials and Supplies                          (7,780)             11,957            (7,777)
    Accrued Utility Revenues                               2,551              38,479            (7,990)
    Accounts Payable                                     (16,249)             81,284             9,292
  Disputed Tax and Interest Related to COLI                 -                 39,483            (2,240)
  Change in Other Assets                                 (42,066)           (121,115)          (14,898)
  Change in Other Liabilities                            (18,769)            132,441             3,388
                                                         -------             -------             -----
            Net Cash Flows From Operating Activities     233,444             367,590           243,180
                                                         -------             -------           -------

INVESTING ACTIVITIES:
  Construction Expenditures                             (132,532)           (127,987)         (115,321)
  Proceeds From Sales and Leaseback
   Transactions and Other                                 10,841               1,560             1,858
                                                          ------               -----             -----
            Net Cash Flows Used For Investing
             Activities                                 (121,691)           (126,427)         (113,463)
                                                        --------            --------          --------

FINANCING ACTIVITIES:
  Change in Advances from Affiliates (net)                92,652              88,732              -
  Issuance of Affiliated Long-term Debt                  200,000                -                 -
  Retirement of Preferred Stock                           (5,000)            (10,000)             -
  Retirement of Long-term Debt                          (314,733)            (25,274)          (35,523)
  Change in Short-term Debt (net)                           -                (45,500)           (7,000)
  Dividends Paid on Common Stock                         (82,952)           (240,600)          (87,996)
  Dividends Paid on Cumulative Preferred Stock              (962)             (1,575)           (1,750)
                                                            ----              ------            ------
            Net Cash Flows Used For
              Financing Activities                      (110,995)           (234,217)         (132,269)
                                                        --------            --------          --------

Net Increase (Decrease) in Cash and Cash Equivalents         758               6,946            (2,552)
Cash and Cash Equivalents January 1                       11,600               4,654             7,206
                                                          ------               -----             -----
Cash and Cash Equivalents December 31                    $12,358            $ 11,600           $ 4,654
                                                         =======            ========           =======
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $68,596,000, $68,506,000
and $72,007,000 and for income taxes was $80,485,000, $81,109,000 and
$71,809,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under
capital leases were $1,019,000, $10,777,000 and $6,855,000 in 2001, 2000 and
1999, respectively.

See Notes to Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization


                                                                                          December 31,
                                                                                 -----------------------------
                                                                                     2001             2000
                                                                                     ----             ----
                                                                                        (in thousands)

<S>                                                                             <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $  791,498        $  713,449
                                                                                 ----------        ----------

PREFERRED STOCK: $100 par value - authorized shares 2,500,000
                 $25  par value - authorized shares 7,000,000

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2001            Year Ended December 31,       December 31, 2001
- ------     ------------     ----------------------------     -----------------
                              2001      2000      1999
                              ----      ----      ----

Subject to Mandatory Redemption:

7.00%          (a)           50,000   100,000      -               100,000           10,000            15,000
                                                                                 ----------        ----------


LONG-TERM DEBT (See Schedule of Long-term Debt):

Notes - Affiliated                                                                  200,000
First Mortgage Bonds                                                                243,197           537,119
Installment Purchase Contracts                                                       91,220            91,166
Senior Unsecured Notes                                                              147,458           159,318
Junior Debentures                                                                   109,973           112,012
Less Portion Due Within One Years                                                  (220,500)             -
                                                                                 ----------        ----------

  Total Long-term Debt Excluding Portion Due Within One Year                        571,348           899,615
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $1,372,846        $1,628,064
                                                                                 ==========        ==========
</TABLE>

(a)  A sinking fund requires the redemption of 50,000 shares at $100 a share on
     or before August 1 of each year. The Company has the right, on each sinking
     fund date, to redeem an additional 50,000 shares which the Company did in
     August 2000. The sinking fund provisions of the 7% series aggregate
     $5,000,000 in 2002 and 2003.

See Notes to Financial Statements beginning on page L-1.
<PAGE>

COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt

First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2001       2000
                           ----       ----
                          (in thousands)
% Rate Due
7.25   2002 - October 1  $ 14,000   $ 56,500
7.15   2002 - November 1    6,500     20,000
6.80   2003 - May 1        13,000     45,000
6.60   2003 - August 1     25,000     40,000
6.10   2003 - November 1    5,000     20,000
6.55   2004 - March 1      26,500     50,000
6.75   2004 - May 1        26,000     50,000
8.70   2022 - July 1        2,000     35,000
8.40   2022 - August 1       -        15,000
8.55   2022 - August 1     15,000     15,000
8.40   2022 - August 15    14,000     25,500
8.40   2022 - October 15   13,000     13,000
7.90   2023 - May 1        40,000     50,000
7.75   2023 - August 1     33,000     33,000
7.45   2024 - March 1        -        30,000
7.60   2024 - May 1        11,000     41,000
Unamortized Discount         (803)    (1,881)
                         --------   --------
  Total                  $243,197   $537,119
                         ========   ========

         First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.

         Installment purchase contracts have been entered into in connection
with the issuance of pollution control revenue bonds by the Ohio Air Quality
Development Authority:

                             December 31,
                           2001       2000
                           ----       ----
                            (in thousands)
% Rate Due
- ------ -----------------
6-3/8  2020 - December 1  $48,550    $48,550
6-1/4  2020 - December 1   43,695     43,695
Unamortized Discount       (1,025)    (1,079)
                          -------    -------
Total                     $91,220    $91,166
                          =======    =======

         Under the terms of the installment purchase contracts, CSPCo is
required to pay amounts sufficient to enable the payment of interest on and the
principal (at stated maturities and upon mandatory redemptions) of related
pollution control revenue bonds issued to finance the construction of pollution
control facilities at the Zimmer Plant.


Senior unsecured notes outstanding were as follows:

                            December 31,
                          2001       2000
                          ----       ----
                           (in thousands)
% Rate Due
- ------ ------------------
6.85   2005 - October 3  $ 36,000  $ 48,000
6.51   2008 - February 1   52,000    52,000
6.55   2008 - June 26      60,000    60,000
Unamortized Discount         (542)     (682)
                         --------  --------
  Total                  $147,458  $159,318
                         ========  ========

Notes payable to parent company were as follows:
                            December 31,
                       ----------------------
                          2001         2000
                          ----         ----
                           (in thousands)
% Rate   Due
Variable 2002 - Sept 25 $200,000   $   -

Junior debentures outstanding were as follows:

                            December 31,
                         2001         2000
                         ----         ----
                          (in thousands)
% Rate Due
- ------ ------------------
8-3/8  2025 - Sept 30  $ 72,843     $ 75,000
7.92   2027 - March 31   40,000       40,000
Unamortized Discount     (2,870)      (2,988)
                       --------     --------
  Total                $109,973     $112,012
                       ========     ========

         Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of the Company.

         At December 31, 2001, future annual long-term debt payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2002                        $220,500
2003                          43,000
2004                          52,500
2005                          36,000
2006                            -
Later Years                  445,088
  Total Principal Amount     797,088
Unamortized Discount          (5,240)
                            ---------
    Total                   $791,848
                            ========



<PAGE>


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements

The notes to CSPCo's financial statements are combined with the notes to
financial statements for AEP and its other subsidiary registrants. Listed below
are the combined notes that apply to CSPCo. The combined footnotes begin on page
L-1.

                                                          Combined
                                                          Footnote
                                                          Reference

Significant Accounting Policies                           Note  1

Extraordinary Items and Cumulative Effect                 Note  2

Effects of Regulation                                     Note  6

Customer Choice and Industry Restructuring                Note  7

Commitments and Contingencies                             Note  8

Benefit Plans                                             Note 10

Business Segments                                         Note 12

Risk Management, Financial Instruments and Derivatives    Note 13

Income Taxes                                              Note 14

Supplementary Information                                 Note 16

Leases                                                    Note 18

Lines of Credit and Sale of Receivable                    Note 19

Unaudited Quarterly Financial Information                 Note 20

Jointly Owned Electric Utility Plant                      Note 23

Related Party Transactions                                Note 24




<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of Directors
of Columbus Southern Power Company:

         We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Columbus Southern Power Company and
its subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

         We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

         In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of Columbus Southern Power
Company and its subsidiaries as of December 31, 2001 and 2000, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2001 in conformity with accounting principles
generally accepted in the United States of America.



Deloitte & Touche LLP
Columbus, Ohio
February 22, 2002




<PAGE>











                         INDIANA MICHIGAN POWER COMPANY
                                AND SUBSIDIARIES



<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
                                                                         Year Ended December 31,
                                             2001                2000               1999               1998                1997
                                             ----                ----               ----               ----                ----
                                                                                (in thousands)
<S>                                    <C>                <C>                  <C>               <C>                 <C>
INCOME STATEMENTS DATA:
  Operating Revenues                    $4,803,625         $3,542,084           $2,920,187        $2,435,646          $1,391,917
  Operating Expenses                     4,643,920          3,576,786            2,811,535         2,269,639           1,184,129
                                        ----------         ----------           ----------        ----------          ----------
  Operating Income
   (Loss)                                  159,705            (34,702)             108,652           166,007             207,788
  Nonoperating Income
   (Loss)                                    9,730              9,933                4,530              (839)              4,415
  Interest Charges                          93,647            107,263               80,406            68,540              65,463
                                        ----------         ----------           ----------        ----------          ----------
  Net Income (Loss)                         75,788           (132,032)              32,776            96,628             146,740
  Preferred Stock
   Dividend
   Requirements                              4,621              4,624                4,885             4,824               5,736
                                        ----------         ----------           ----------        ----------          ----------
  Earnings (Loss)
   Applicable to
   Common Stock                         $   71,167         $ (136,656)          $   27,891        $   91,804          $  141,004
                                        ==========         ==========           ==========        ==========          ==========

                                                                             December 31,
                                            2001               2000               1999               1998                1997
                                            ----               ----               ----               ----                ----
                                                                                (in thousands)
BALANCE SHEETS DATA:

  Electric Utility
   Plant                                $4,923,721         $4,871,473           $4,770,027        $4,631,848          $4,514,497
  Accumulated
   Depreciation and
   Amortization                          2,436,972          2,280,521            2,194,397         2,081,355           1,973,937
                                        ----------         ----------           ----------        ----------          ----------
  Net Electric Utility
   Plant                                $2,486,749         $2,590,952           $2,575,630        $2,550,493          $2,540,560
                                        ==========         ==========           ==========        ==========          ==========

  Total Assets                          $4,817,008         $5,811,038           $4,576,696        $4,148,523          $3,967,798
                                        ==========         ==========           ==========        ==========          ==========

  Common Stock and
   Paid-in Capital                      $  789,800         $  789,656           $  789,323        $  789,189          $  789,056
  Accumulated Other
   Comprehensive Income
   (Loss)                                   (3,835)              -                   -                  -                   -
  Retained Earnings                         74,605              3,443              166,389           253,154             278,814
                                        ----------         ----------           ----------        ----------          ----------
  Total Common
   Shareholder's Equity                 $  860,570         $  793,099           $  955,712        $1,042,343          $1,067,870
                                        ==========         ==========           ==========        ==========          ==========

  Cumulative Preferred
   Stock:
    Not Subject to
     Mandatory
     Redemption                         $    8,736         $    8,736           $    9,248        $    9,273          $    9,435
    Subject to
     Mandatory
     Redemption (a)                         64,945             64,945               64,945            68,445              68,445
                                        ----------         ----------           ----------        ----------          ----------
      Total Cumulative
        Preferred Stock                 $   73,681         $   73,681           $   74,193        $   77,718          $   77,880
                                        ==========         ==========           ==========        ==========          ==========

  Long-term Debt (a)                    $1,652,082         $1,388,939           $1,324,326        $1,175,789          $1,049,237
                                        ==========         ==========           ==========        ==========          ==========

  Obligations Under
   Capital Leases (a)                   $   61,933         $  163,173           $  187,965        $  186,427          $  195,227
                                        ==========         ==========           ==========        ==========          ==========

  Total Capitalization
    And Liabilities                     $4,817,008         $5,811,038           $4,576,696        $4,148,523          $3,967,798
                                        ==========         ==========           ==========        ==========          ==========
</TABLE>
(a) Including portion due within one year.
(a)

<PAGE>


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations


       I&M is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to 567,000 retail customers in
its service territory in northern and eastern Indiana and a portion of
southwestern Michigan. As a member of the AEP Power Pool, I&M shares the
revenues and the costs of the AEP Power Pool's wholesale sales to neighboring
utilities and power marketers including power trading transactions. I&M also
sells wholesale power to municipalities and electric cooperatives.

       The cost of the AEP System's generating capacity is allocated among the
AEP Power Pool members based on their relative peak demands and generating
reserves through the payment of capacity charges and the receipt of capacity
credits. AEP Power Pool members are also compensated for the out-of-pocket costs
of energy delivered to the AEP Power Pool and charged for energy received from
the AEP Power Pool. The AEP Power Pool calculates each company's prior twelve
month peak demand relative to the total peak demand of all member companies as a
basis for sharing revenues and costs. The result of this calculation is each
company's member load ratio (MLR) which determines each company's percentage
share of revenues and costs.

       I&M is committed under unit power agreements to purchase all of AEGCo's
50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other
utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. A
long-term unit power agreement with an unaffiliated utility expired at the end
of 1999 for the sale of 455 MW of AEGCo's Rockport Plant capacity. An agreement
between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant
capacity to KPCo through 2004. Therefore, effective January 1, 2000, I&M began
purchasing 910 MW of AEGCo's 50% share of Rockport Plant capacity.


Critical Accounting Policies - Revenue Recognition

Regulatory Accounting - As a cost-based rate-regulated electric public utility
company, I&M's consolidated financial statements reflect the actions of
regulators that can result in the recognition of revenues and expenses in
different time periods than enterprises that are not rate regulated. In
accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.

        When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.



<PAGE>


Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to I&M as a member
of the AEP Power Pool. Trading activities involve the purchase and sale of
energy under physical forward contracts at fixed and variable prices and buying
and selling financial energy contracts which includes exchange traded futures
and options and over-the-counter options and swaps. The majority of trading
activities represent physical forward electricity contracts that are typically
settled by entering into offsetting physical contracts. Although trading
contracts are generally short-term, there are also long-term trading contracts.

           Accounting standards applicable to trading activities require that
changes in the fair value of trading contacts be recognized in revenues prior to
settlement and is commonly referred to as mark-to-market (MTM) accounting. Since
I&M is a cost-based rate-regulated entity, changes in the fair value of physical
forward sale and purchase contracts in AEP's traditional marketing area are
deferred as regulatory liabilities (gains) or regulatory assets (losses). The
deferral reflects the fact that power sales and purchases are included in
regulated rates on a settlement basis. AEP's traditional marketing area is up to
two transmission systems from the AEP service territory. The change in the fair
value of physical forward sale and purchase contracts outside AEP's traditional
marketing area is included in nonoperating income on a net basis.

         Mark-to-market accounting represents the change in the unrealized gain
or loss throughout the contract's term. When the contract actually settles, that
is, the energy is actually delivered in a sale or received in a purchase or the
parties agree to forego delivery and receipt of electricity and net settle in
cash, the unrealized gain or loss is reversed and the actual realized cash gain
or loss is recognized in the income statement. Therefore, as the contract's
market value changes over the contract's term an unrealized gain or loss is
deferred for contracts with delivery points in AEP's traditional marketing area
and for contracts with delivery points outside of AEP's traditional marketing
area the unrealized gain or loss is recognized as nonoperating income. When the
contract settles the total gain or loss is realized in cash and the impact on
the income statement depends on whether the contract's delivery points are
within or outside of AEP's traditional marketing area. For contracts with
delivery points in AEP's traditional marketing area, the total gain or loss
realized in cash is recognized in the income statement. Physical forward trading
sale contracts with delivery points in AEP's traditional marketing area are
included in revenues when the contracts settle. Physical forward trading
purchase contracts with delivery points in AEP's traditional marketing area are
included in purchased power expense when they settle. Prior to settlement,
changes in the fair value of physical forward sale and purchase contracts in
AEP's traditional marketing area are deferred as regulatory liabilities (gains)
or regulatory assets (losses). For contacts with delivery points outside of
AEP's traditional marketing area only the difference between the accumulated
unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized in the income statement. Physical forward sales contracts for
delivery outside of AEP's traditional marketing area are included in
nonoperating income when the contract settles. Physical forward purchase
contracts for delivery outside of AEP's traditional marketing area are included
in nonoperating expenses when the contract settles. Prior to settlement, changes
in the fair value of physical forward sale and purchase contracts with delivery
points outside of AEP's traditional marketing area are included in nonoperating
income on a net basis. Unrealized mark-to-market gains and losses are included
in the Balance Sheet as energy trading contract assets or liabilities as
appropriate.

        Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in non-operating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
non-operating income and reverse to nonoperating income the prior unrealized
gain or loss.

        The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.

        Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing I&M to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.

Results of Operations

       During 2000 both of the Cook Plant nuclear units were successfully
restarted after being shutdown in September 1997 due to questions regarding the
operability of certain safety systems which arose during a NRC architect
engineer design inspection. See discussion in Note 4 of the Notes to Financial
Statements.

A reduction in other operation and maintenance expense in 2001 reflects the
completion of restart work on the Cook Plant and was the primary reason for a
$208 million increase in net income. As a result of the costs incurred in 2000
to restart the Cook Plant nuclear units and a disallowance of interest
deductions for a corporate owned life insurance (COLI) program, net income
declined $165 million in 2000. In February 2001 the U.S. District Court for the
Southern District of Ohio ruled against AEP and certain of its subsidiaries,
including I&M, in a suit over deductibility of interest claimed in AEP's
consolidated tax return related to COLI. In 1998 and 1999 I&M paid the disputed
taxes and interest attributable to the COLI interest deductions for the taxable
years 1991-98 and deferred them.

Operating Revenues Increase

       Operating revenues increased 36% in 2001 and 21% in 2000 due to increased
wholesale marketing and trading sales. The following analyzes the changes in
operating revenues:

                    Increase (Decrease)
                    From Previous Year
                   (dollars in millions)
                     2001           2000
               ------------------------------
               Amount    %    Amount     %

Retail*       $   (2.3) N.M. $(88.6)   (12)
Marketing
 and Trading   1,210.7  52    564.0     32
Other              5.0  13    (13.0)   (26)
              --------       ------
               1,213.4  40    462.4     18
Energy
 Delivery*         3.4   1      0.1   N.M.
Sales to AEP
 Affiliates       44.7  21    159.4   313
              --------       ------
     Total    $1,261.5  36   $621.9    21
              ========       ======

N.M. = Not Meaningful

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.

       The increase in operating revenues in 2001 and 2000 is primarily due to
an increase in wholesale marketing and trading activities. The maturing of the
Intercontinental Exchange, the development of proprietary tools, and increased
staffing of energy traders have resulted in an increase in the number of forward
electricity purchase and sale contracts in AEP's traditional marketing area. A
decline in retail revenues partly offset the increase in wholesale marketing and
trading revenues. Retail revenues decreased in 2000 when the accrual of power
supply recovery revenues ceased at the end of 1999 pursuant to Cook Plant
settlement agreements. The accrued power supply recovery revenues are being
amortized over a five-year period ending December 31, 2003.

       I&M increased its sales to AEP affiliates in 2000 when additional
electricity became available. The return to service of the Cook Plant units and
purchasing more power from AEGCo due to the expiration of AEGCo's contract to
sell power to an unaffiliated entity, increased the amount of power I&M could
sell to its affiliates in the AEP Power Pool.

Operating Expenses Increase

       Total operating expenses increased 30% in 2001 and 27% in 2000 primarily
due to additional purchases of power for marketing and trading and due to the
expiration of an AEGCo unit power agreement to sell part of its Rockport Plant
generation to an unaffiliated utility. Also contributing to the increase in
operating expenses in 2000 was the unfavorable COLI tax ruling and costs related
to the extended Cook Plant outage and restart efforts. The changes in the
components of operating expenses were:

                     Increase (Decrease)
                      From Previous Year
                     (dollars in millions)
                       2001           2000
                -----------------------------
                Amount     %    Amount    %

Fuel            $   39.2   19   $ 25.5    14
Marketing and
 Trading
 Purchases       1,227.7   59    462.9    29
AEP Affiliate
 Purchases         (27.2) (10)    65.1    32
Other Operation   (147.8) (25)   137.5    30
Maintenance        (92.6) (42)    84.5    62
Depreciation and
 Amortization        9.3    6      4.9     3
Taxes Other Than
 Income Taxes        4.9    8     (5.2)   (8)
Income Taxes        53.6  N.M.    (9.9)  (95)
                 -------        ------
    Total       $1,067.1   30   $765.3    27
                ========        ======

N.M. = Not Meaningful

       The increase in fuel expense in 2001 and 2000 reflects an increase in
nuclear generation as the Cook Plant units returned to service following the
extended outage.

       Electricity marketing and trading purchased power expense increased in
2001 and 2000 due to AEP's effort to grow its wholesale marketing and trading
business. The decline in purchased power from AEP affiliates in 2001 reflects
generation from the Cook Plant replacing purchases from the AEP Power Pool.
Purchases from the AEP Power Pool declined 21% in 2001. As a result of the
expiration of AEGCo's power sale contract with an unaffiliated utility on
December 31, 1999, I&M was obligated to buy more of AEGCo's share of Rockport
Plant power. Purchases from AEGCo increased 91% in 2000.

       The decrease in other operation and maintenance expenses in 2001 was
primarily due to the cessation of expenditures to prepare the Cook Plant nuclear
units for restart with their return to service in 2000. Other operation and
maintenance expenses increased in 2000 primarily due to expenditures to prepare
the Cook Plant units for restart. In 1999 the IURC and MPSC approved settlement
agreements which allowed the deferral of $200 million of Cook Plant restart
costs in 1999 for amortization over five years from 1999 through 2003. As a
result, other operation and maintenance expense in 1999 reflected a net deferral
of $160 million. See discussion in Note 4 of the Notes to Financial Statements.

       The increase in depreciation and amortization charges in 2001 reflects
increased generation and distribution plant investments and amortization of
I&M's share of deferred merger costs.

       Taxes other than income taxes increased in 2001 due to higher real and
personal property tax expense from the effect of a favorable accrual adjustment
recorded in December 2000 to match estimated amounts with actual expenses. The
decrease in taxes other than income tax in 2000 is primarily attributable to
decreases in real and personal property taxes reflecting the favorable accrual
adjustment and Indiana gross receipts taxes reflecting an unfavorable accrual
adjustment related to the 1998 tax year recorded in 1999 for gross receipts tax.

       The significant increase in income taxes attributable to operations in
2001 is due to an increase in pre-tax operating income. Income taxes
attributable to operations decreased in 2000 due to a decrease in pre-tax
operating income.



<PAGE>


Nonoperating Income and Expenses Increase

       The increases in nonoperating income and expenses in 2001 and 2000 is
primarily due to increased volume of forward electricity trading transactions
outside AEP's traditional marketing area. Nonoperating power trading revenues
increased 70% in 2001 and 95% in 2000. Nonoperating power trading expenses
increased 70% in 2001 and 93% in 2000.

Interest Charges

       The decrease in 2001 interest charges reflects the recognition in 2000 of
deferred interest payments to the IRS on disputed income taxes from the
disallowance of tax deductions for COLI interest for the years 1991-1998.
Interest charges increased in 2000 due to increased borrowings to support
expenditures for the Cook Plant restart effort and the recognition of deferred
interest payments to the IRS on the disputed taxes.



<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
                                                            Year Ended December 31,
                                                    ------------------------------------------
                                                    2001               2000               1999
                                                    ----               ----               ----
                                                                (in thousands)
<S>                                             <C>                <C>                <C>
OPERATING REVENUES:
  Electricity Marketing and Trading              $4,234,176         $3,020,757         $2,558,338
  Energy Delivery                                   314,410            311,019            310,880
  Sales to AEP Affiliates                           255,039            210,308             50,969
                                                    -------            -------             ------

            TOTAL OPERATING REVENUES              4,803,625          3,542,084          2,920,187
                                                  ---------          ---------          ---------

OPERATING EXPENSES:
  Fuel                                              250,098            210,870            185,419
  Purchased Power:
    Electricity Marketing and Trading             3,293,255          2,065,509          1,602,658
    AEP Affiliates                                  238,237            265,475            200,372
  Other Operation                                   451,195            599,012            461,494
  Maintenance                                       127,263            219,854            135,331
  Depreciation and Amortization                     164,230            154,920            149,988
  Taxes other Than Income Taxes                      65,518             60,622             65,843
  Income Taxes                                       54,124                524             10,430
                                                     ------                ---             ------

            TOTAL OPERATING EXPENSES              4,643,920          3,576,786          2,811,535
                                                  ---------          ---------          ---------

OPERATING INCOME (LOSS)                             159,705            (34,702)           108,652

NONOPERATING INCOME                               1,474,572            869,895            452,019

NONOPERATING EXPENSES                             1,459,799            855,773            446,183

NONOPERATING INCOME TAX EXPENSE                       5,043              4,189              1,306

INTEREST CHARGES                                     93,647            107,263             80,406
                                                     ------            -------             ------

NET INCOME (LOSS)                                    75,788           (132,032)            32,776

PREFERRED STOCK DIVIDEND REQUIREMENTS                 4,621              4,624              4,885
                                                      -----              -----              -----

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK         $ 71,167         $ (136,656)          $ 27,891
                                                   ========         ==========           ========
</TABLE>
Consolidated Statements of Comprehensive Income
                                                Year Ended December 31,
                                     -----------------------------------------
                                     2001               2000              1999
                                     ----               ----              ----
                                               (in thousands)

NET INCOME (LOSS)                  $75,788           $(132,032)         $32,776

OTHER COMPREHENSIVE INCOME (LOSS)
  Cash Flows Interest Rate Hedge    (3,835)               -                -
                                    ------             -------             ----

COMPREHENSIVE INCOME (LOSS)        $71,953           $(132,032)         $32,776
                                   =======           =========          =======

See Notes to Financial Statements beginning on page L-1.

<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
                                                      December 31,
                                                2001                 2000
                                                ----                 ----
                                                     (in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
 Production                                  $2,758,160           $2,708,436
 Transmission                                   957,336              945,709
 Distribution                                   900,921              863,736
 General (including nuclear fuel)               233,005              257,152
 Construction Work in Progress                   74,299               96,440
                                                 ------               ------
         Total Electric Utility Plant         4,923,721            4,871,473
 Accumulated Depreciation and Amortization    2,436,972            2,280,521
                                              ---------            ---------
         NET ELECTRIC UTILITY PLANT           2,486,749            2,590,952
                                              ---------            ---------

NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
 FUEL DISPOSAL TRUST FUNDS                      834,109              778,720
                                                -------              -------

LONG-TERM ENERGY TRADING CONTRACTS              215,544              194,554
                                                -------              -------

OTHER PROPERTY AND INVESTMENTS                  127,977              131,417
                                                -------              -------

CURRENT ASSETS:
 Cash and Cash Equivalents                       16,804               14,835
 Advances to Affiliates                          46,309                 -
 Accounts Receivable:
  Customers                                      60,864              106,832
  Affiliated Companies                           31,908               48,706
  Miscellaneous                                  25,398               27,491
  Allowance for Uncollectible Accounts             (741)                (759)
 Fuel - at average cost                          28,989               16,532
 Materials and Supplies - at average cost        91,440               84,471
 Energy Trading Contracts                       399,195            1,222,925
 Accrued Utility Revenues                         2,072                 -
 Prepayments                                      6,497                6,066
                                                  -----                -----
         TOTAL CURRENT ASSETS                   708,735            1,527,099
                                                -------            ---------

REGULATORY ASSETS                               408,927              552,140
                                                -------              -------

DEFERRED CHARGES                                 34,967               36,156
                                                 ------               ------

           TOTAL                             $4,817,008           $5,811,038
                                             ==========           ==========

See Notes to Financial Statements beginning on page L-1.
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                                                          December 31,
                                                          ------------
                                                     2001               2000
                                                     ----               ----
                                                         (in thousands)

CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
 Common Stock - No Par Value:
   Authorized - 2,500,000 Shares
   Outstanding - 1,400,000 Shares                   $ 56,584           $ 56,584
   Paid-in Capital                                   733,216            733,072
   Accumulated Other Comprehensive Income (Loss)      (3,835)              -
   Retained Earnings                                  74,605              3,443
                                                      ------              -----
           Total Common Shareholder's Equity         860,570            793,099
   Cumulative Preferred Stock:
     Not Subject to Mandatory Redemption               8,736              8,736
     Subject to Mandatory Redemption                  64,945             64,945
   Long-term Debt                                  1,312,082          1,298,939
                                                   ---------          ---------
           TOTAL CAPITALIZATION                    2,246,333          2,165,719
                                                   ---------          ---------

OTHER NONCURRENT LIABILITIES:
 Nuclear Decommissioning                             600,244            560,628
 Other                                                87,025            108,600
                                                      ------            -------
           TOTAL OTHER NONCURRENT LIABILITIES        687,269            669,228
                                                     -------            -------

CURRENT LIABILITIES:
 Long-term Debt Due Within One Year                  340,000             90,000
 Advances from Affiliates                               -               253,582
 Accounts Payable - General                           90,817            119,472
 Accounts Payable - Affiliated Companies              43,956             75,486
 Taxes Accrued                                        69,761             68,416
 Interest Accrued                                     20,691             21,639
 Obligations Under Capital Leases                     10,840            100,848
 Energy Trading and Derivative Contracts             383,714          1,267,981
 Other                                                72,435             97,070
                                                      ------             ------
           TOTAL CURRENT LIABILITIES               1,032,214          2,094,494
                                                   ---------          ---------

DEFERRED INCOME TAXES                                400,531            487,945
                                                     -------            -------

DEFERRED INVESTMENT TAX CREDITS                      105,449            113,773
                                                     -------            -------

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2                               77,592             81,299
                                                      ------             ------

LONG-TERM ENERGY TRADING CONTRACTS                   175,581            156,343
                                                     -------            -------

DEFERRED CREDITS                                      92,039             42,237
                                                      ------             ------

COMMITMENTS AND CONTINGENCIES (Note 8)

             TOTAL                                $4,817,008         $5,811,038
                                                  ==========         ==========

See Notes to Financial Statements beginning on page L-1.





<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
                                                                   Year Ended December 31,
                                                          2001               2000               1999
                                                          ----               ----               ----
                                                                       (in thousands)
<S>                                                   <C>                <C>                 <C>
OPERATING ACTIVITIES:
  Net Income (Loss)                                    $75,788            $(132,032)           $32,776
  Adjustments for Noncash Items:
   Depreciation and Amortization                       166,360              163,391            153,921
   Amortization of Incremental Nuclear
    Refueling Outage Expenses (net)                        418                5,737              8,480
   Amortization (Deferral) of Nuclear
    Outage Costs (net)                                  40,000               40,000           (160,000)
   Deferred Federal Income Taxes                       (29,205)            (125,179)            85,727
   Deferred Investment Tax Credits                      (8,324)              (7,854)            (8,152)
   Mark-to-Market of Energy Trading Contracts          (19,502)             (10,859)            (2,602)
   Unrecovered Fuel and Purchased Power Costs           37,501               37,501            (84,696)
  Changes in Certain Current Assets
    And Liabilities:
   Accounts Receivable (net)                            64,841              (25,305)           (19,178)
   Fuel, Materials and Supplies                        (19,426)              10,743            (12,880)
   Accrued Utility Revenues                             (2,072)              44,428             (7,151)
   Accounts Payable                                    (60,185)              85,056             19,068
   Taxes Accrued                                         1,345               19,446             13,809
  Disputed Tax and Interest Related to COLI               -                  56,856             (3,228)
  Change in Other Assets                                (5,871)             (68,160)           (48,879)
  Change in Other Liabilities                           (5,461)              37,668             63,763
                                                        ------               ------             ------
     Net Cash Flows From Operating Activities          236,207              131,437             30,778
                                                       -------              -------             ------

INVESTING ACTIVITIES:
  Construction Expenditures                            (91,052)            (171,071)          (165,331)
  Buyout of Nuclear Fuel Leases                        (92,616)                -                  -
  Other                                                  1,074                  587              2,501
                                                         -----                  ---              -----
    Net Cash Flows Used For Investing Activities      (182,594)            (170,484)          (162,830)
                                                      --------             --------           --------

FINANCING ACTIVITIES:
 Issuance of Long-term Debt                            297,656              199,220            247,989
 Retirement of Cumulative Preferred Stock                 -                    (314)            (3,597)
 Retirement of Long-term Debt                          (44,922)            (148,000)          (109,500)
 Change in Advances from Affiliates (net)             (299,891)             253,582               -
 Change in Short-term Debt (net)                          -                (224,262)           115,562
 Dividends Paid on Common Stock                           -                 (26,290)          (114,656)
 Dividends Paid on Cumulative Preferred Stock           (4,487)              (3,368)            (5,856)
                                                        ------               ------             ------
    Net Cash Flows From (Used For)
     Financing Activities                              (51,644)              50,568            129,942
                                                       -------               ------            -------

Net Increase (Decrease) in Cash and
 Cash Equivalents                                        1,969               11,521             (2,110)
Cash and Cash Equivalents January 1                     14,835                3,314              5,424
                                                        ------                -----              -----
Cash and Cash Equivalents December 31                  $16,804             $ 14,835            $ 3,314
                                                       =======             ========            =======
</TABLE>
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was
$92,140,000,$82,511,000 and $78,703,000 and for income taxes was $100,470,000,
$73,254,000 and $(71,395,000) in 2001, 2000 and 1999, respectively. Noncash
acquisitions under capital leases were $1,023,000, $22,218,000 and $10,852,000
in 2001, 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
                                                              Year Ended December 31,
                                                   2001                2000                  1999
                                                   ----                ----                  ----
                                                                  (in thousands)
<S>                                              <C>              <C>                    <C>
Retained Earnings January 1                        $3,443           $ 166,389              $253,154
Net Income (Loss)                                  75,788            (132,032)               32,776
                                                   ------            --------                ------
                                                   79,231              34,357               285,930
                                                   ------              ------               -------
Deductions:
 Cash Dividends Declared:
   Common Stock                                      -                 26,290               114,656
   Cumulative Preferred Stock:
     4-1/8% Series                                    229                 230                   244
     4.56% Series                                      66                  66                    66
     4.12% Series                                      72                  74                    78
     5.90% Series                                     897                 897                   963
     6-1/4% Series                                  1,203               1,203                 1,250
     6.30% Series                                     834                 834                   834
     6-7/8% Series                                  1,186               1,186                 1,238
                                                    -----               -----                 -----
           Total Cash Dividends Declared            4,487              30,780               119,329
  Capital Stock Expense                               139                 134                   212
                                                      ---                 ---                   ---
            Total Deductions                        4,626              30,914               119,541
                                                    -----              ------               -------

Retained Earnings December 31                    $ 74,605             $ 3,443              $166,389
                                                 ========             =======              ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization

                                                                                            December 31,
                                                                                   ----------------------------
                                                                                       2001             2000
                                                                                       ----             ----
                                                                                          (in thousands)

<S>                                                                               <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                        $  860,570        $  793,099
                                                                                   ----------        ----------

PREFERRED STOCK:
$100 Par Value - Authorized 2,250,000 shares
$25 Par Value - Authorized 11,200,000 shares

              Call Price                                       Shares
              December 31,     Number of Shares Redeemed       Outstanding
Series           2001           Year Ended December 31,        December 31, 2001
- ------        ------------     ------------------------        -----------------
                                2001     2000     1999
                                ----     ----     ----

Not Subject to Mandatory Redemption:

    4-1/8%     106.125           -      3,750       97              55,389              5,539             5,539
    4.56%      102               -       -         150              14,412              1,441             1,441
    4.12%      102.728           -      1,375      -                17,556              1,756             1,756
                                                                                   ----------        ----------
                                                                                        8,736             8,736
                                                                                   ----------        ----------
Subject to Mandatory Redemption:

    5.90%  (a,b)                 -       -      15,000             152,000             15,200            15,200
    6-1/4% (a,b)                 -       -      10,000             192,500             19,250            19,250
    6.30%  (a,b)                 -       -        -                132,450             13,245            13,245
    6-7/8% (a,c)                 -       -      10,000             172,500             17,250            17,250
                                                                                   ----------        ----------
                                                                                       64,945            64,945
                                                                                   ----------        ----------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                  264,141           308,976
Installment Purchase Contracts                                                        310,239           309,717
Senior Unsecured Notes                                                                696,144           397,435
Other Long-term Debt                                                                  219,947           211,307
Junior Debentures                                                                     161,611           161,504
Less Portion Due Within One Year                                                     (340,000)          (90,000)
                                                                                   ----------        ----------

    Long-term Debt Excluding Portion Due Within One Year                            1,312,082         1,298,939
                                                                                   ----------        ----------

    TOTAL CAPITALIZATION                                                           $2,246,333        $2,165,719
                                                                                   ==========        ==========
</TABLE>
(a)  Not callable until after 2002. There are no aggregate sinking fund
     provisions through 2002. Sinking fund provisions require the redemption of
     15,000 shares in 2003 and 67,500 shares each year in 2004, 2005 and 2006.
     The sinking fund provisions of each series subject to mandatory redemption
     have been met by purchase of shares in advance of the due date.
(b)  Commencing in 2004 and continuing through 2008 the Company may redeem, at
     $100 per share, 20,000 shares of the 5.90% series, 15,000 shares of the
     6-1/4% series and 17,500 shares of the 6.30% series outstanding under
     sinking fund provisions at its option and all remaining outstanding shares
     must be redeemed not later than 2009. Shares previously redeemed may be
     applied to meet the sinking fund requirement.
(c)  Commencing in 2003 and continuing through the year 2007, a sinking fund
     will require the redemption of 15,000 shares each year and the redemption
     of the remaining shares outstanding on April 1, 2008, in each case at $100
     per share. Shares previously redeemed may be applied to meet the sinking
     fund requirement.

See Notes to Financial Statements beginning on page L-1.


<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt


First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2001       2000
                           ----       ----
                            (in thousands)
% Rate Due
7.63   2001 - June 1     $   -      $ 40,000
7.60   2002 - November 1   50,000     50,000
7.70   2002 - December 15  40,000     40,000
6.10   2003 - November 1   30,000     30,000
8.50   2022 - December 15  75,000     75,000
7.35   2023 - October 1    15,000     20,000
7.20   2024 - February 1   30,000     30,000
7.50   2024 - March 1      25,000     25,000
Unamortized Discount         (859)    (1,024)
                         --------   --------
                         $264,141   $308,976

         First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.

         Installment purchase contracts have been entered into, in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:

                             December 31,
                           2001       2000
                           ----       ----
                            (in thousands)
% Rate Due
- ------ -----------------
City of Lawrenceburg, Indiana:
7.00   2015 - April 1    $ 25,000   $ 25,000
5.90   2019 - November 1   52,000     52,000

City of Rockport, Indiana:
 (a)   2014 - August 1     50,000     50,000
7.60   2016 - March 1      40,000     40,000
6.55   2025 - June 1       50,000     50,000
 (b)   2025 - June 1       50,000     50,000

City of Sullivan, Indiana:
5.95   2009 - May 1        45,000     45,000
Unamortized Discount       (1,761)    (2,283)
                         --------   --------
                         $310,239   $309,717

(a)  A variable interest rate is determined weekly.  The average weighted
     interest rate was 2.4% for 2001 and 4.5% for 2000.
(b)  In June 2001 an auction  rate was  established.  Auction  rates are
     determined  by  standard  procedures  every 35 days.  The
     auction rate for June through December 2001 ranged from 1.55% to 2.9% and
     averaged 2.4%. Prior to June 25, 2001, an adjustable interest rate was a
     daily, weekly, commercial paper or term rate as designated by I&M. A weekly
     rate was selected which ranged from 1.9% to 4.9% in 2001 and from 2.9% to
     5.9% in 2000 and averaged 3.3% during 2001 and 4.2% during 2000.


         The terms of the installment purchase contracts require I&M to pay
amounts sufficient for the cities to pay interest on and the principal (at
stated maturities and upon mandatory redemptions) of related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain generating plants. On the variable rate series the principal is
payable at the stated maturities or on the demand of the bondholders at periodic
interest adjustment dates which occur weekly. The variable rate bonds due in
2014 are supported by a bank letter of credit which expires in 2002.
Accordingly, the variable rate installment purchase contracts have been
classified for repayment purposes based on the expiration date of the letter of
credit.

Senior unsecured notes outstanding were as follows:
                             December 31,
                        ---------------------
                           2001       2000
                           ----       ----
                           (in thousands)
% Rate Due
- ------ ------------------
 (a)   2002 - September 3 $200,000  $200,000
6-7/8  2004 - July 1       150,000   150,000
6.125  2006 - December 15  300,000      -
6.45   2008 - November 10   50,000    50,000
Unamortized Discount        (3,856)   (2,565)
                          --------  --------
                          $696,144  $397,435

(a)  A floating interest rate is determined quarterly. The rate on December 31,
     2001 and 2000 was 2.71% and 7.31%, respectively. The average interest rate
     was 5.1% in 2001 and 7.3% in 2000.


<PAGE>


Junior debentures outstanding were as follows:

                            December 31,
                         2001         2000
                         ----         ----
                          (in thousands)
% Rate Due
- ------ -----------------
8.00   2026 - March 31 $ 40,000     $ 40,000
7.60   2038 - June 30   125,000      125,000
Unamortized Discount     (3,389)      (3,496)
                       --------     --------
  Total                $161,611     $161,504
                       ========     ========

         Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of I&M.


         At December 31, 2001, future annual long-term debt payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2002                       $  340,000
2003                           30,000
2004                          150,000
2005                             -
2006                          300,000
Later Years                   841,947
                           ----------
  Total Principal Amount    1,661,947
Unamortized Discount           (9,865)
                           ----------
    Total                  $1,652,082
                           ==========



<PAGE>


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Financial Statements

The notes to I&M's financial statements are combined with the notes to financial
statements for AEP and its other subisidiary registrants. Listed below are the
combined notes that apply to I&M. The combined footnotes begin on page L-1.

                                                          Combined
                                                          Footnote
                                                          Reference

Significant Accounting Policies                           Note  1

Merger                                                    Note  3

Nuclear Plant Restart                                     Note  4

Effects of Regulation                                     Note  6

Customer Choice and Industry Restructuring                Note  7

Commitments and Contingencies                             Note  8

Benefit Plans                                             Note 10

Business Segments                                         Note 12

Risk Management, Financial Instruments and Derivatives    Note 13

Income Taxes                                              Note 14

Supplementary Information                                 Note 16

Leases                                                    Note 18

Lines of Credit and Sale of Receivables                   Note 19

Unaudited Quarterly Financial Information                 Note 20

Related Party Transactions                                Note 24




<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of Indiana Michigan Power Company:

       We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Indiana Michigan Power Company and
its subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, comprehensive income, retained earnings and cash flows for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

       We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

       In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Indiana Michigan Power Company
and its subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002





<PAGE>











                             KENTUCKY POWER COMPANY


<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
Selected Financial Data
                                                                    Year Ended December 31,
                                             2001             2000             1999                1998                 1997
                                             ----             ----             ----                ----                 ----
                                                                         (in thousands)
INCOME STATEMENTS DATA:

  Operating Revenues                    $1,659,395        $1,176,867          $918,121           $705,562            $359,543
  Operating Expenses                     1,611,717         1,127,129           863,446            653,669             312,687
                                   -     ---------  -      ---------   -       -------   -        -------   -         -------
  Operating Income                          47,678            49,738            54,675             51,893              46,856
  Nonoperating
   Income (Loss)                             1,248             2,070              (327)            (1,726)               (464)
  Interest Charges                          27,361            31,045            28,918             28,491              25,646
                                   ----     ------  --        ------   --       ------   --        ------   --         ------
  Net Income                              $ 21,565          $ 20,763          $ 25,430           $ 21,676            $ 20,746
                                          ========          ========          ========           ========            ========

                                                                      Year Ended December 31,
                                            2001              2000              1999              1998                1997
                                            ----              ----              ----              ----                ----
                                                                         (in thousands)
BALANCE SHEETS DATA:
<S>                                      <C>              <C>               <C>               <C>                 <C>
  Electric Utility
   Plant                                  $1,128,415       $1,103,064        $1,079,048        $1,043,711          $1,006,955
  Accumulated
   Depreciation and
   Amortization                              384,104          360,648           340,008           315,546             296,318
                                             -------          -------           -------           -------             -------
  Net Electric
   Utility Plant                            $744,311         $742,416          $739,040          $728,165            $710,637
                                            ========         ========          ========          ========            ========

  Total Assets                            $1,153,243       $1,509,064          $986,638          $921,847            $886,671
                                          ==========       ==========          ========          ========            ========

  Common Stock and
   Paid-in Capital                         $209,200          $209,200          $209,200          $199,200            $179,200
  Accumulated Other
   Comprehensive
   Income (Loss)                             (1,903)
  Retained Earnings                          48,833            57,513            67,110            71,452              78,076
                                             ------            ------            ------            ------              ------
  Total Common
   Shareholder's
   Equity                                  $256,130          $266,713          $276,310          $270,652            $257,276
                                           ========          ========          ========          ========            ========

  Long-term Debt (a)                       $346,093          $330,880          $365,782          $368,838            $341,051
                                           ========          ========          ========          ========            ========

  Obligations Under
   Capital Leases(a)                        $ 9,583          $ 14,184          $ 15,141          $ 18,977            $ 18,725
                                            =======          ========          ========          ========            ========

  Total
   Capitalization
   and Liabilities                       $1,153,243        $1,509,064          $986,638          $921,847            $886,671
                                         ==========        ==========          ========          ========            ========
</TABLE>
(a) Including portion due within one year.



<PAGE>



KENTUCKY POWER COMPANY
Management's Narrative Analysis of Results of Operations

       KPCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power serving 172,000 retail customers
in eastern Kentucky. KPCo as a member of the AEP Power Pool shares in the
revenues and costs of the AEP Power Pool's wholesale sales to neighboring
utility systems and power marketers including power trading transactions. KPCo
also sells wholesale power to municipalities.

       The cost of the AEP Power Pool's generating capacity is allocated among
the Pool members based on their relative peak demands and generating reserves
through the payment of capacity charges and the receipt of capacity credits. AEP
Power Pool members are also compensated for their out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.

Critical Accounting Policies - Revenue Recognition

Regulatory Accounting - As a cost-based rate-regulated electric public utility
company, KPCo's financial statements reflect the actions of regulators that can
result in the recognition of revenues and expenses in different time periods
than enterprises that are not rate regulated. In accordance with SFAS 71,
regulatory assets (deferred expenses) and regulatory liabilities (future revenue
reductions or refunds) are recorded to reflect the economic effects of
regulation by matching expenses with their recovery through regulated revenues
in the same accounting period.

        When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.

Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to KPCO as a member
of the AEP Power Pool. Trading activities involve the purchase and sale of
energy under physical forward contracts at fixed and variable prices and buying
and selling financial energy contracts which includes exchange traded futures
and options and over-the-counter options and swaps. The majority of trading
activities represent physical forward electricity contracts that are typically
settled by entering into offsetting physical contracts. Although trading
contracts are generally short-term, there are also long-term trading contracts.

Accounting standards applicable to trading activities require that changes in
the fair value of trading contacts be recognized in revenues prior to settlement
and is commonly referred to as mark-to-market (MTM) accounting. Since KPCO is a
cost-based rate-regulated entity, changes in the fair value of physical forward
sale and purchase contracts in AEP's traditional marketing area are deferred as
regulatory liabilities (gains) or regulatory assets (losses). AEP's traditional
marketing area is up to two transmission systems from the AEP Service territory.
The change in the fair value of physical forward sale and purchase contracts
outside AEP's traditional marketing area is included in nonoperating income on a
net basis.

Mark-to-market accounting represents the change in the unrealized gain or loss
throughout the contract's term. When the contract actually settles, that is, the
energy is actually delivered in a sale or received in a purchase or the parties
agree to forego delivery and receipt of electricity and net settle in cash, the
unrealized gain or loss is reversed and the actual realized cash gain or loss is
recognized in the income statement. Therefore, as the contract's market value
changes over the contract's term an unrealized gain or loss is deferred for
contracts with delivery points in AEP's traditional marketing area and for
contracts with delivery points outside of AEP's traditional marketing area the
unrealized gain or loss is recognized as nonoperating income. When the contract
settles the total gain or loss is realized in cash and the impact on the income
statement depends on whether the contract's delivery points are within or
outside of AEP's traditional marketing area. For contracts with delivery points
in AEP's traditional marketing area, the total gain or loss realized in cash is
recognized in the income statement. Physical forward trading sale contracts with
delivery points in AEP's traditional marketing area are included in revenues
when the contracts settle. Physical forward trading purchase contracts with
delivery points in AEP's traditional marketing area are included in purchased
power expense when they settle. Prior to settlement, changes in the fair value
of physical forward sale and purchase contracts in AEP's traditional marketing
area are deferred as regulatory liabilities (gains) or regulatory assets
(losses). For contacts with delivery points outside of AEP's traditional
marketing area only the difference between the accumulated unrealized net gains
or losses recorded in prior months and the cash proceeds is recognized in the
income statement. Physical forward sales contracts for delivery outside of AEP's
traditional marketing area are included in nonoperating income when the contract
settles. Physical forward purchase contracts for delivery outside of AEP's
traditional marketing area are included in nonoperating expenses when the
contract settles. Prior to settlement, changes in the fair value of physical
forward sale and purchase contracts with delivery points outside of AEP's
traditional marketing area are included in nonoperating income on a net basis.
Unrealized mark-to-market gains and losses are included in the Balance Sheet as
energy trading assets or liabilities as appropriate.

        Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior unrealized gain
or loss.

        The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.

        Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing KPCO to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.

Net Income Increases

       Net income increased $802 thousand or 4% in 2001 primarily due to the
effect of a court decision related to a corporate owned
life insurance (COLI) program recorded in 2000. In February 2001 the U.S.
District Court for the Southern District of Ohio ruled against AEP and certain
of its subsidiaries, including KPCo, in a suit over deductibility of interest
claimed in AEP's consolidated tax return related to COLI. In 1998 and 1999 KPCo
paid the disputed taxes and interest attributable to the COLI interest
deductions for taxable years 1992-98. The payments were included in Other
Property and Investments pending the resolution of this matter.

Operating Revenues Increase

       Operating revenues increased $482.5 million or 41% in 2001 as a result of
significant increases in trading activities in AEP's traditional marketing area.
Changes in the components of operating revenues were as follows:

                                      Increase (Decrease)
                                        From Previous Year
                                     (dollars in millions)
                                       Amount         %
Retail*                                $(13.5)         (9)
Wholesale Marketing
 and Trading                            486.4          57
Other                                    (0.7)         (4)
                                         ----
  Subtotal                              472.2          47
                                        -----

Energy Delivery*                          9.8           8
Sales to AEP Affiliates                   0.5           1
                                          ---

      Total                            $482.5          41
                                       ======

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.

       Retail revenues decreased as a result of mild weather conditions. Usage
by residential customers declined in response to warmer temperatures during
November and December 2001. Commercial and industrial sales were stable.

       The increase in wholesale marketing and trading revenues is driven by
increased trading volume. The maturing of the Intercontinental Exchange, the
development of propriety tools, and increased staffing of energy traders have
resulted in an increase in the number of forward electricity purchase and sale
contracts in AEP's traditional marketing area.

       Energy delivery revenues rose largely from providing additional
transmission services as a result of increased wholesale marketing and trading
transactions and from increased assignment of fees for transmission and
distribution delivery services.

Operating Expenses Increase

       Operating expenses increased $484.6 million in 2001 primarily due to
increases in purchased power for trading activity. Changes in the components of
operating expenses were as follows:

                                        Increase (Decrease)
                                        From Previous Year)
                                       (dollars in millions)
                                        Amount          %

Fuel                                    $ (4.0)         (5)
Marketing and Trading
 Purchases                               491.4          62
AEP Affiliate Purchases                    2.5           2
Other Operation                            5.9          11
Maintenance                               (3.4)        (13)
Depreciation and
 Amortization                              1.5           5
Taxes Other Than
 Income Taxes                              0.6           8
Income Taxes                              (9.9)        (51)
                                          ----
  Total                                 $484.6          43
                                        ======

        The decrease in fuel expense is a result of sharing profits from the
trading of power with customers in accordance with the Kentucky Public Service
Commission's fuel clause mechanism. Under this mechanism, the profits from
KPCo's portion of AEP's wholesale marketing and trading activities are shared
with retail customers. This sharing is recognized through credits to fuel
expense, thus reducing fuel expense.

        Increases in wholesale marketing and trading volume accounted for the
significant increase in purchased power expense.



<PAGE>


        The increase in other operation expense is attributable to increased
trading incentive compensation expense, reduced AEP transmission equalization
credits and expenses for a full year of factoring accounts receivable. Under the
AEP East Region Transmission Agreement, KPCo and certain affiliates share the
costs associated with the ownership of their transmission system based upon each
company's peak demand and investment. An increase in KPCo's peak demand relative
to its affiliates' peak demand was the main reason for the decline in
transmission equalization credits. Factoring of accounts receivable began in
June 2000. In 2001 we incurred a full year of factoring expenses compared with a
partial year in 2000.

        Lower maintenance expense in 2001 is a result of performing significant
planned maintenance at the Big Sandy Plant in 2000 for which there was no
comparable activity in the current year.

        Additions to property, plant and equipment accounted for the increase in
depreciation expense. These additions included capitalized software and general
distribution equipment upgrades and improvements.

        Taxes other than income taxes rose as a result of increases in real and
personal property tax accruals reflecting higher taxable property values.

        The decrease in income tax expense was primarily due to a decrease in
pre-tax book income and the effect of an unfavorable ruling in 2000 in AEP's
suit against the government over interest deductions claimed in prior years
related to AEP's COLI program.

Nonoperating Income and Nonoperating Expenses Increase

        The increase in nonoperating income and nonoperating expenses was due to
an increase in nonregulated electric trading activities outside AEP's
traditional marketing area.

Interest Charges Decrease

          The decline in interest expense was due to the effect of recognizing
in 2000 previously deferred interest payments to the IRS related to the COLI
disallowances and interest on resultant state income tax deficiencies.




<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
Statements of Income
                                                        Year Ended December 31,
                                             -----------------------------------------
                                             2001                2000             1999
                                             ----                ----             ----
                                                          (in thousands)
<S>                                     <C>                 <C>                <C>
OPERATING REVENUES:
  Electricity Marketing and Trading      $1,485,846          $1,013,700         $744,706
  Energy Delivery                           131,183             121,346          129,113
  Sales to AEP Affiliates                    42,366              41,821           44,302
                                             ------              ------           ------
      TOTAL REVENUES                      1,659,395           1,176,867          918,121
                                          ---------           ---------          -------

OPERATING EXPENSES:
  Fuel                                       70,635              74,638           84,369
  Purchased Power:
    Electricity Marketing and Trading     1,279,556             788,102          567,902
    AEP Affiliates                          130,204             127,707           84,000
  Other Operation                            59,175              53,325           52,468
  Maintenance                                22,444              25,866           21,452
  Depreciation and Amortization              32,491              31,028           29,221
  Taxes Other Than Income Taxes               7,854               7,251            8,091
  Income Taxes                                9,358              19,212           15,943
                                              -----              ------           ------
      TOTAL OPERATING EXPENSES            1,611,717           1,127,129          863,446
                                          ---------           ---------          -------

OPERATING INCOME                             47,678              49,738           54,675

NONOPERATING INCOME                         569,603             334,950          156,783

NONOPERATING EXPENSES                       567,679             331,751          157,276

NONOPERATING INCOME TAX EXPENSE (CREDIT)        684               1,129             (166)

INTEREST CHARGES                             27,361              31,045           28,918
                                             ------              ------           ------

NET INCOME                                 $ 21,565            $ 20,763         $ 25,430
                                           ========            ========         ========
</TABLE>
<TABLE>
<CAPTION>
Statements of Comprehensive Income
                                                         Year Ended December 31,
                                              -----------------------------------------
                                              2001                2000             1999
                                              ----                ----             ----
                                                            (in thousands)
<S>                                         <C>                 <C>              <C>
NET INCOME                                  $21,565             $20,763          $25,430

OTHER COMPREHENSIVE INCOME (LOSS)
  Cash Flow Interest Rate Hedge              (1,903)               -                -
                                             ------                ----             ----

COMPREHENSIVE INCOME                        $19,662             $20,763          $25,430
                                            =======             =======          =======
</TABLE>
<TABLE>
<CAPTION>
Statements of Retained Earnings
                                                         Year Ended December 31,
                                                  -------------------------------------
                                                  2001            2000             1999
                                                  ----            ----             ----
                                                              (in thousands)
<S>                                         <C>                 <C>              <C>
RETAINED EARNINGS JANUARY 1                 $57,513             $67,110          $71,452

NET INCOME                                   21,565              20,763           25,430

CASH DIVIDENDS DECLARED                      30,245              30,360           29,772
                                             ------              ------           ------

RETAINED EARNINGS DECEMBER 31               $48,833             $57,513          $67,110
                                            =======             =======          =======
</TABLE>
See Notes to Financial Statements Beginning on Page L-1.
<PAGE>
KENTUCKY POWER COMPANY
Balance Sheets
                                                         December 31,
                                                   ------------------------
                                                   2001                2000
                                                   ----                ----
                                                         (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                      $271,070            $271,107
  Transmission                                     374,116             360,563
  Distribution                                     402,537             387,499
  General                                           65,059              67,476
  Construction Work in Progress                     15,633              16,419
                                                    ------              ------
          Total Electric Utility Plant           1,128,415           1,103,064
  Accumulated Depreciation and Amortization        384,104             360,648
                                                   -------             -------
          NET ELECTRIC UTILITY PLANT               744,311             742,416
                                                   -------             -------

OTHER PROPERTY AND INVESTMENTS                       6,492               6,559
                                                     -----               -----

LONG-TERM ENERGY TRADING CONTRACTS                  77,972              76,503
                                                    ------              ------

CURRENT ASSETS:
  Cash and Cash Equivalents                          1,947               2,270
  Accounts Receivable:
   Customers                                        20,036              34,555
   Affiliated Companies                             16,012              22,119
   Miscellaneous                                     3,333               6,419
   Allowance for Uncollectible Accounts               (264)               (282)
  Fuel - at average cost                            12,060               4,760
  Materials and Supplies - at average cost          15,766              15,408
  Accrued Utility Revenues                           5,395               6,500
  Energy Trading Contracts                         139,605             480,739
  Prepayments                                        1,314                 766
                                                ----------                 ---
          TOTAL CURRENT ASSETS                     215,204             573,254
                                                   -------             -------

REGULATORY ASSETS                                   97,692              98,515
                                                    ------              ------

DEFERRED CHARGES                                    11 572              11,817
                                                    ------              ------

                    TOTAL                       $1,153,243          $1,509,064
                                                ==========          ==========

See Notes to Financial Statements beginning on page L-1.

<PAGE>
KENTUCKY POWER COMPANY
                                                            December 31,
                                                     ------------------------
                                                     2001                2000
                                                     ----                ----
                                                          (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - Par Value $50:
    Authorized - 2,000,000 Shares
    Outstanding - 1,009,000 Shares                  $ 50,450            $ 50,450
  Paid-in Capital                                    158,750             158,750
  Accumulated Other Comprehensive Income (Loss)       (1,903)               -
  Retained Earnings                                   48,833              57,513
                                                      ------              ------
    Total Common Shareholder's Equity                256,130             266,713
  Long-term Debt                                     251,093             270,880
                                                  ----------             -------
          TOTAL CAPITALIZATION                       507,223             537,593
                                                     -------             -------

OTHER NONCURRENT LIABILITIES                          11,929              18,348
                                                      ------              ------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                  95,000              60,000
  Advances from Affiliates                            66,200              47,636
  Accounts Payable - General                          24,050              32,043
  Accounts Payable - Affiliated Companies             22,557              37,506
  Customer Deposits                                    4,461               4,389
  Taxes Accrued                                       10,305              11,885
  Interest Accrued                                     5,269               5,610
  Energy Trading and Derivative Contracts            144,364             494,086
  Other                                               12,296              14,517
                                                      ------              ------
          Total CURRENT LIABILITIES                  384,502             707,672
                                                     -------             -------

DEFERRED INCOME TAXES                                168,304             165,935
                                                     -------             -------

DEFERRED INVESTMENT TAX CREDITS                       10,405              11,656
                                                      ------              ------

LONG-TERM ENERGY TRADING CONTRACTS                    63,412              61,478
                                                      ------              ------

DEFERRED CREDITS                                       7,468               6,382
                                                       -----               -----

COMMITMENTS AND CONTINGENCIES (Note 8)

                    TOTAL                         $1,153,243          $1,509,064
                                                  ==========          ==========

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
Statements of Cash Flows
                                                                 Year Ended December 31,
                                                         -----------------------------------------
                                                         2001              2000               1999
                                                         ----              ----               ----
                                                                     (in thousands)
<S>                                                    <C>               <C>                <C>
OPERATING ACTIVITIES:
  Net Income                                           $ 21,565           $20,763            $25,430
  Adjustments for Noncash Items:
    Depreciation and Amortization                        32,491            31,034             29,228
    Deferred Income Taxes                                 6,293             3,765              2,596
    Deferred Investment Tax Credits                      (1,251)           (1,252)            (1,292)
    Deferred Fuel Costs (net)                            (4,707)            2,948                828
    Mark-to-Market of Energy Trading Contracts           (1,454)           (4,376)              (863)
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                            23,694           (20,930)            (6,618)
    Fuel, Materials and Supplies                         (7,658)            8,386             (7,014)
    Accrued Utility Revenues                              1,105             7,237               (177)
    Accounts Payable                                    (22,942)           39,883              4,935
    Taxes Accrued                                        (1,580)            2,025              2,604
  Disputed Tax and Interest Related to COLI                -                5,943               (567)
  Change in Other Assets                                 (2,762)           62,653             11,547
  Change in Other Liabilities                            (9,446)          (62,702)           (13,837)
                                                         ------           -------            -------
            Net Cash Flows From Operating Activities     33,348            95,377             46,800
                                                         ------            ------             ------

INVESTING ACTIVITIES:
  Construction Expenditures                             (37,206)          (36,209)           (44,339)
  Proceeds From Sales of Property                           216               266                168
                                                            ---               ---                ---
            Net Cash Flows Used For Investing
             Activities                                 (36,990)          (35,943)           (44,171)
                                                        -------           -------            -------

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company                -                 -                10,000
  Issuance of Long-term Debt                             75,000            69,685             79,740
  Retirement of Long-term Debt                          (60,000)         (105,000)           (83,307)
  Change in Short-term Debt (net)                          -              (39,665)            19,315
  Change in Advances From Affiliates (net)               18,564            47,636               -
  Dividends Paid                                        (30,245)          (30,360)           (29,772)
                                                        -------           -------            -------
            Net Cash Flows From (Used For)
             Financing Activities                         3,319           (57,704)            (4,024)
                                                          -----           -------             ------

Net Increase (Decrease) in Cash and Cash Equivalents       (323)            1,730             (1,395)
Cash and Cash Equivalents January 1                       2,270               540              1,935
                                                          -----               ---              -----
Cash and Cash Equivalents December 31                    $1,947           $ 2,270              $ 540
                                                         ======           =======              =====
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $27,090,000, $28,619,000
and $29,845,000 and for income taxes was $7,549,000, $7,923,000 and $12,050,000
in 2001, 2000 and 1999, respectively. Noncash acquisitions under capital leases
were $817,000, $2,817,000 and $2,219,000 in 2001, 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
Statements of Capitalization
                                                                December 31,
                                                         ------------------------
                                                         2001                2000
                                                         ----                ----
                                                              (in thousands)

<S>                                                    <C>                 <C>
COMMON SHAREHOLDER'S EQUITY                            $256,130            $266,713
                                                       --------            --------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                     59,383             119,341
Senior Unsecured Notes                                  147,625             147,490
Notes Payable                                           100,000              25,000
Junior Debentures                                        39,085              39,049
Less Portion Due Within One Year                        (95,000)            (60,000)
                                                        -------             -------

  Long-term Debt Excluding Portion Due Within One Year  251,093             270,880
                                                        -------             -------

  TOTAL CAPITALIZATION                                 $507,223            $537,593
                                                       ========            ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
KENTUCKY POWER COMPANY
Schedule of Long-term Debt


First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2001       2000
                           ----       ----
                            (in thousands)
% Rate Due
8.95   2001 - May 10     $   -      $ 20,000
8.90   2001 - May 21         -        40,000
6.65   2003 - May 1        15,000     15,000
6.70   2003 - June 1       15,000     15,000
6.70   2003 - July 1       15,000     15,000
7.90   2023 - June 1       14,500     14,500
Unamortized Discount         (117)      (159)
                         --------   --------
                         $ 59,383   $119,341
                         ========   ========

First mortgage bonds are secured by first mortgage liens on electric utility
plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.

Senior unsecured notes outstanding were as follows:

                             December 31,
                           2001       2000
                           ----       ----
                            (in thousands)
% Rate Due
- ------ ------------------
 (a)   2002 - November 19 $ 70,000  $ 70,000
6.91   2007 - October 1     48,000    48,000
6.45   2008 - November 10   30,000    30,000
Unamortized Discount          (375)     (510)
                          --------  --------
                           147,625   147,490
Less Portion Due Within
 One Year                   70,000      -
                          --------  --------
  Total                   $ 77,625  $147,490
                          ========  ========

(a)  A floating interest rate is  determined monthly.  The rate on
     December 31, 2001 was 4.3% and on December 31, 2000 was 7.4%.

Notes payable to parent company were as follows:

                             December 31,
                           2001       2000
                           ----       ----
                            (in thousands)
% Rate Due
4.336  2003 - May 15      $15,000   $ -
6.501  2006 - May 15       60,000     -
                          -------   ------
                          $75,000   $ -
                          =======   ======


Notes payable to banks outstandings were as follows:

                              December 31,
                              2001     2000
                              ----     ----
                             (in thousands)
% Rate   Due
7.45     2002 - September 20   $25,000 $25,000
                               ======= =======

Junior debentures outstanding were as follows:

                            December 31,
                         2001         2000
                         ----         ----
                          (in thousands)
% Rate Due
8.72   2025 - June 30   $40,000      $40,000
Unamortized Discount       (915)        (951)
                        -------      -------
  Total                 $39,085      $39,049
                        =======      =======

Interest may be deferred and payment of principal and interest on the junior
debentures is subordinated and subject in right to the prior payment in full of
all senior indebtedness of the Company.

At December 31, 2001, future annual long-term debt payments are as follows:

                             Amount
                             ------
                         (in thousands)
2002                        $ 95,000
2003                          60,000
2004                            -
2005                            -
2006                          60,000
Later Years                  132,500
                            --------
  Total Principal Amount     347,500
Unamortized Discount           1,407
                            --------
    Total                   $346,093
                            ========
<PAGE>
KENTUCKY POWER COMPANY
Index to Notes to Financial Statements

The notes to KPCo's financial statements are combined with the notes to
financial statements for AEP and its other subisidiary registrants. Listed below
are the combined notes that apply to KPCo. The combined footnotes begin on page
L-1.

                                                          Combined
                                                          Footnote
                                                          Reference

Significant Accounting Policies                           Note  1

Merger                                                    Note  3

Effects of Regulation                                     Note  6

Commitments and Contingencies                             Note  8

Benefit Plans                                             Note 10

Business Segments                                         Note 12

Risk Management, Financial Instruments and Derivatives    Note 13

Income Taxes                                              Note 14

Leases                                                    Note 18

Lines of Credit and Sale of Receivables                   Note 19

Unaudited Quarterly Financial Information                 Note 20

Related Party Transactions                                Note 24



<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholder and Board of
Directors of Kentucky Power Company:

       We have audited the accompanying balance sheets and statements of
capitalization of Kentucky Power Company as of December 31, 2001 and 2000, and
the related statements of income, comprehensive income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 2001.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.

       We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

       In our opinion, such financial statements present fairly, in all material
respects, the financial position of Kentucky Power Company as of December 31,
2001 and 2000, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2001 in conformity with
accounting principles generally accepted in the United States of America.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002


<PAGE>













                       OHIO POWER COMPANY AND SUBSIDIARIES



<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
                                                                  Year Ended December 31,
                                     2001              2000                1999               1998                1997
                                     ----              ----                ----               ----                ----
                                                                   (in thousands)
<S>                              <C>                <C>                <C>                <C>                 <C>
INCOME STATEMENTS DATA:
  Operating Revenues              $6,262,402         $4,992,100         $4,196,893         $3,572,125          $1,965,818
  Operating Expenses               6,021,692          4,765,273          3,908,064          3,282,753           1,689,425
                                   ---------          ---------          ---------          ---------           ---------
  Operating Income                   240,710            226,827            288,829            289,372             276,393
  Nonoperating Income
   (Loss)                             18,686             (5,004)             7,000                588              14,822
  Interest Charges                    93,603            119,210             83,672             80,035              82,526
                                      ------            -------             ------             ------              ------
  Income Before
   Extraordinary Item                165,793            102,613            212,157            209,925             208,689
  Extraordinary Loss                 (18,348)           (18,876)              -                  -                   -
                                     -------            -------               ----               ----                ----
  Net Income                         147,445             83,737            212,157            209,925             208,689
  Preferred Stock
   Dividend
   Requirements                        1,258              1,266              1,417              1,474               2,647
                                       -----              -----              -----              -----               -----
  Earnings Applicable
   To Common Stock                  $146,187           $ 82,471           $210,740           $208,451            $206,042
                                    ========           ========           ========           ========            ========

                                                                    Year Ended December 31,
                                     2001                2000              1999               1998                1997
                                     ----                ----              ----               ----                ----
                                                                   (in thousands)
BALANCE SHEETS DATA:
  Electric Utility
   Plant                          $5,390,576          $5,577,631        $5,400,917         $5,257,841          $5,155,797
  Accumulated
   Depreciation                    2,452,571           2,764,130         2,621,711          2,461,376           2,349,995
                                   ---------           ---------         ---------          ---------           ---------
  Net Electric Utility
   Plant                          $2,938,005          $2,813,501        $2,779,206         $2,796,465          $2,805,802
                                  ==========          ==========        ==========         ==========          ==========
  Total Assets                    $4,916,067          $6,242,557        $4,677,209         $4,344,680          $4,163,202
                                  ==========          ==========        ==========         ==========          ==========

  Common Stock and
   Paid-in Capital                  $783,684            $783,684          $783,577           $783,536            $783,497
  Accumulated Other
   Comprehensive Income
   (Loss)                               (196)
  Retained Earnings                  401,297             398,086           587,424            587,500             590,151
                                     -------             -------           -------            -------             -------
  Total Common
   Shareholder's Equity           $1,184,785          $1,181,770        $1,371,001         $1,371,036          $1,373,648
                                  ==========          ==========        ==========         ==========          ==========

  Cumulative Preferred Stock:
   Not Subject to
    Mandatory Redemption            $ 16,648            $ 16,648          $ 16,937           $ 17,370            $ 17,542
   Subject to Mandatory
    Redemption (a)                     8,850               8,850             8,850             11,850              11,850
                                       -----               -----             -----             -------             ------
    Total Cumulative
     Preferred Stock                $ 25,498            $ 25,498          $ 25,787           $ 29,220            $ 29,392
                                    ========            ========          ========           ========            ========
  Long-term Debt (a)              $1,203,841          $1,195,493        $1,151,511         $1,084,928          $1,095,226
                                  ==========          ==========        ==========         ==========          ==========
  Obligations Under
   Capital Leases (a)               $ 80,666            $116,581          $136,543           $142,635            $157,487
                                    ========            ========          ========           ========            ========
  Total Capitalization
   and Liabilities                $4,916,067          $6,242,557        $4,677,209         $4,344,680          $4,163,202
                                  ==========          ==========        ==========         ==========          ==========
</TABLE>
(a) Including portion due within one year.
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations


OPCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 698,000 retail customers in northwestern,
east central, eastern and southern sections of Ohio. OPCo supplies electric
power to the AEP Power Pool and shares the revenues and costs of the AEP Power
Pool's wholesale sales to neighboring utility systems and power marketers
including power trading transactions. OPCo also sells wholesale power to
municipalities and cooperatives.

       The cost of the AEP Power Pool's generating capacity is allocated among
Pool members based on their relative peak demands and generating reserves
through the payment of capacity charges or the receipt of capacity credits. AEP
Power Pool members are also compensated for their out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.


Critical Accounting Policies - Revenue Recognition

Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.

         When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.

Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to OPCo as a member
of the AEP Power Pool. Trading activities involve the purchase and sale of
energy under physical forward contracts at fixed and variable prices and buying
and selling financial energy contracts which includes exchange traded futures
and options and over-the-counter options and swaps. Although trading contracts
are generally short-term, there are also long-term trading contracts. We
recognize revenues from trading activities generally based on changes in the
fair value of energy trading contracts.

           Recording the net change in the fair value of trading contracts prior
to settlement is commonly referred to as mark-to-market (MTM) accounting. It
represents the change in the unrealized gain or loss throughout the contract's
term. When the contract actually settles, that is, the energy is actually
delivered in a sale or received in a purchase or the parties agree to forego
delivery and receipt of electricity and net settle in cash, the unrealized gain
or loss is reversed and the actual realized cash gain or loss is recognized.
Therefore, over the trading contract's term an unrealized gain or loss is
recognized as the contract's market value changes. When the contract settles the
total gain or loss is realized in cash but only the difference between the
accumulated unrealized net gains or losses recorded in prior months and the cash
proceeds is recognized. Unrealized mark-to-market gains and losses are included
in the Balance Sheet as energy trading contract assets or liabilities as
appropriate.

           The majority of our trading activities represent physical forward
electricity contracts that are typically settled by entering into offsetting
contracts. An example of our trading activities is when, in January, we enter
into a forward sales contract to deliver electricity in July. At the end of each
month until the contract settles in July, we would record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract settles, we would realize our share of the
gain or loss in cash and reverse the previously recorded unrealized gain or
loss.

           Depending on whether the delivery point for the electricity is in
AEP's traditional marketing area or not determines where the contract is
reported on OPCo's income statement. AEP's tradititonal marketing area is up to
two transmission systems from the AEP service territory. Physical forward
trading sale contracts with delivery points in AEP's traditional marketing area
are included in revenues when the contracts settle. Physical forward trading
purchase contracts with delivery points in AEP's traditional marketing area are
included in purchased power expense when they settle. Prior to settlement,
changes in the fair value of physical forward sale and purchase contracts in
AEP's traditional marketing area are included in revenues on a net basis.
Physical forward sales contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating income when the contract settles.
Physical forward purchase contracts for delivery outside of AEP's traditional
marketing area are included in nonoperating expenses when the contract settles.
Prior to settlement, changes in the fair value of physical forward sale and
purchase contracts with delivery points outside of AEP's traditional marketing
area are included in nonoperating income on a net basis.

        Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
results of operations from recording additional changes in fair values using
mark-to-market accounting.

        Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior unrealized gain
or loss.

        The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.

        Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing OPCo to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.

Results of Operations

       Income before extraordinary item increased $63 million or 62% in 2001
primarily due to the effect of a court decision related to a corporate owned
life insurance (COLI) program recorded in 2000. In February 2001 the U.S.
District Court for the Southern District of Ohio ruled against AEP and certain
of its subsidiaries, including OPCo, in a suit over deductibility of interest
claimed in AEP's consolidated tax returns related to COLI. In 1998 and 1999 OPCo
paid the disputed taxes and interest attributable to the COLI interest
deductions for taxable years 1991-98. The payments were included in Other
Property and Investments pending the resolution of this matter. Net income was
also favorably impacted by the growth in and strong performance by the wholesale
business. The favorable effects of the COLI decision and wholesale business were
offset in part by the commencement of the amortization of transition regulatory
assets in 2001, the effect of mild winter weather and the recent economic
downturn.

       Income before extraordinary item decreased $110 million or 52% in 2000
due predominantly to the unfavorable COLI decision.

<PAGE>

Operating Revenues

       Operating revenues increased 25% in 2001 and 19% in 2000 because of the
significant increase in wholesale marketing and trading volume. The changes in
the components of revenues were as follows:

                      Increase (Decrease)
                      From Previous Year
                    (Dollars in Millions)
                      2001          2000
                -----------------------------
                Amount    %   Amount      %
                ------    -   ------      -
Retail*        $  (66.0) (8)  $(135.7)  (15)
Wholesale
 Marketing and
 Trading        1,294.0  42     738.0    32
Unrealized MTM     32.6  N.M.   (10.3) N.M.
Other              (4.3) (5)      2.8     4
               --------       -------
  Total
   Marketing and
   Trading      1,256.3  32     594.8   18
Energy
 Delivery*         85.1  18       7.4    2
Sale to AEP
 Affiliates       (71.1)(12)    193.0   50
               --------       -------

     Total     $1,270.3  25   $ 795.2   19
               ========       =======

* Reflects for 2000 the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.

       The increase in operating revenues in 2001 and 2000 resulted from
increased marketing and trading volume (32% in 2001 and 21% in 2000). The
maturing of the Intercontinental Exchange, the development of proprietory tools,
and increased staffing of energy traders has resulted in an increase in the
number of forward electricity purchase and sale contracts in AEP's traditional
marketing area.

       Sales to AEP affiliates decreased in 2001 because an affiliate was able
to supply more power to the Power Pool from two nuclear units that returned to
service in June and December 2000.

       As a result of one of OPCo's major industrial customers deciding not to
continue its power purchase agreement, OPCo was able to deliver additional power
to the power pool in 2000. This accounted for the increase in sales to AEP
affiliates in 2000.


Operating Expenses

       Operating expenses increased by 26% in 2001 mostly due to a significant
increase in wholesale trading purchases and the amortization of transition
regulatory assets partly offset by decreases in fuel expense and income taxes.
Operating expenses increased by 22% in 2000 mostly due to increases in fuel
expense, wholesale trading purchases, other operation expense and income taxes.

       Changes in the components of operating expenses were as follows:

                      Increase (Decrease)
                      From Previous Year
                    (dollars in millions)
                   2001           2000
                   ----           ----
                Amount     %    Amount    %

Fuel            $   (85.4) (11) $ 84.3    12
Marketing and
 Trading
 Purchases        1,327.7   46   597.6    26
AEP Affiliate
 Purchases           11.8   23    29.9   143
Other Operation      (4.0)  (1)   80.2    25
Maintenance          18.1   15     3.4     3
Depreciation
 and Amortization    84.0   54     6.9     5
Taxes Other Than
  Income Taxes       (9.7)  (6)    5.3     3
Income Taxes        (86.1) (46)   49.6    36
                 --------       ------
  Total Operating
   Expenses      $1,256.4   26  $857.2    22
                 ========       ======

       Fuel expense decreased 11% in 2001 mainly due to a 9% decrease in net
generation because of decreased sales to the AEP Power Pool caused by an
affiliate's two nuclear units returning to service. Fuel expense increased in
2000 due to increases in generation and the average cost of fuel consumed
reflecting shutdown costs included in the cost of coal delivered from affiliated
mining operations.

       Marketing and trading purchases expense increased substantially in 2001
and 2000 due to increases in trading volume. The increases in purchased power
from AEP affiliates were due to a significnt increase in AEP Power Pool
transactions in 2001 and 2000.

       Other operation expense increased in 2000 mainly due to increased power
generation costs. Increased emission allowance consumption and allowance prices
and increased costs of AEP's growing power marketing and trading operation,
including trader incentive compensation, accounted for the increase in power
generation costs. The increase in emission allowance usage and prices resulted
from the stricter air quality standards of Phase II of the 1990 Clean Air Act
Amendments which became effective on January 1, 2000.

       Maintenance expense increased in 2001 mainly due to boiler repairs at
Amos, Cardinal, Kammer, Mitchell, Muskingum and Sporn plants, and boiler
inspections at the Amos and Cardinal plants.

       The commencement of amortization of transition regulatory assets in
connection with the transition to customer choice and market-based pricing of
retail electricity supply under Ohio deregulation accounted for the significant
increase in depreciation and amortization expense in 2001.

       The decrease in taxes other than income taxes in 2001 was due to a
decrease in property tax expense reflecting a reduction in rates on generation
property under the Ohio Restructuring law partially offset by a new state excise
tax.

       Income taxes decreased in 2001 due to an unfavorable ruling in AEP's suit
against the government over interest deductions claimed relating to AEP's COLI
program, which was recorded in 2000 and a decrease in pre-tax book income. The
increase in income tax expense in 2000 was primarily due to the unfavorable
ruling relating to AEP's COLI program.


Nonoperating Income and Nonoperating Expense

       The increases in nonoperating income and nonoperating expenses in 2001
and 2000 were due to an increase in trading transactions outside of the AEP
System's traditional marketing area.

Interest Charges

       The major reason for the decrease in interest expense in 2001 was the
recognition in 2000 of deferred interest payments to the IRS related to COLI
disallowances. The increase in interest expense in 2000 was due to the
recognition of deferred interest payments related to the COLI disallowance.

Extraordinary Loss

       In the second quarter of 2001 an extraordinary loss of $18 million net of
tax was recorded to write-off prepaid Ohio excise taxes stranded by Ohio
deregulation. In 2000 the application of regulatory accounting for generation
under SFAS 71 was discontinued which resulted in an after tax extraordinary loss
of $19 million.



<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
                                                         Year Ended December 31,
                                               --------------------------------------------
                                               2001                2000                1999
                                               ----                ----                ----
                                                             (in thousands)
<S>                                        <C>                 <C>                <C>
OPERATING REVENUES:
  Electricity Marketing and Trading         $5,198,323          $3,942,066         $3,347,219
  Energy Delivery                              552,713             467,587            460,182
  Sales to AEP Affiliates                      511,366             582,447            389,492
                                               -------             -------            -------
            TOTAL OPERATING REVENUES         6,262,402           4,992,100          4,196,893
                                             ---------           ---------          ---------

OPERATING EXPENSES:
  Fuel                                         686,568             771,969            687,672
  Purchased Power:
    Electricity Marketing and Trading        4,225,124           2,897,461          2,299,909
    AEP Affiliates                              62,585              50,741             20,864
  Other Operation                              403,404             407,375            327,132
  Maintenance                                  142,878             124,735            121,299
  Depreciation and Amortization                239,982             155,944            149,055
  Taxes Other Than Income Taxes                159,778             169,527            164,213
  Income Taxes                                 101,373             187,521            137,920
                                               -------             -------            -------
            TOTAL OPERATING EXPENSES         6,021,692           4,765,273          3,908,064
                                             ---------           ---------          ---------

OPERATING INCOME                               240,710             226,827            288,829

NONOPERATING INCOME                          1,880,294           1,208,437            630,295

NONOPERATING EXPENSES                        1,863,988           1,195,283            628,723

NONOPERATING INCOME TAX EXPENSE (CREDIT)        (2,380)             18,158             (5,428)

INTEREST CHARGES                                93,603             119,210             83,672
                                                ------             -------             ------

INCOME BEFORE EXTRAORDINARY ITEM               165,793             102,613            212,157

EXTRAORDINARY LOSS - DISCONTINUANCE OF
  REGULATORY ACCOUNTING FOR GENERATION -
  Net of tax (See Note 2)                      (18,348)            (18,876)              -
                                               -------             -------               ----

NET INCOME                                     147,445              83,737            212,157

PREFERRED STOCK DIVIDEND REQUIREMENTS            1,258               1,266              1,417
                                                 -----               -----              -----

EARNINGS APPLICABLE TO COMMON STOCK           $146,187            $ 82,471           $210,740
                                              ========            ========           ========
</TABLE>
<TABLE>
<CAPTION>
Consolidated Statements of Comprehensive Income
                                                   Year Ended December 31,
                                                   -----------------------
                                            2001                2000                1999
                                            ----                ----                ----

<S>                                      <C>                 <C>                 <C>
NET INCOME                                $147,445            $83,737             $212,157

OTHER COMPREHENSIVE INCOME (LOSS)
  Foreign Currency Exchange Rate Hedge        (196)              -                    -
                                              ----               ----                 ----

COMPREHENSIVE INCOME                      $147,249            $83,737             $212,157
                                          ========            =======             ========
</TABLE>
The common stock of the Company is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
                                                                    December 31,
                                                            -------------------------
                                                            2001                 2000
                                                            ----                 ----
                                                                  (in thousands)
<S>                                                        <C>                   <C>
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                                $3,007,866            $2,764,155
  Transmission                                                 891,283               870,033
  Distribution                                               1,081,122             1,040,940
  General (including mining assets at December 31, 2000)       245,232               707,417
  Construction Work in Progress                                165,073               195,086
                                                               -------               -------
          Total Electric Utility Plant                       5,390,576             5,577,631
  Accumulated Depreciation and Amortization                  2,452,571             2,764,130
                                                             ---------             ---------
          NET ELECTRIC UTILITY PLANT                         2,938,005             2,813,501
                                                             ---------             ---------

OTHER PROPERTY AND INVESTMENTS                                  62,303               109,124
                                                                ------               -------

LONG-TERM ENERGY TRADING CONTRACTS                             263,734               255,938
                                                               -------               -------

CURRENT ASSETS:
  Cash and Cash Equivalents                                      8,848                31,393
  Advances to Affiliates                                          -                   92,486
  Accounts Receivable:
   Customers                                                    84,694               139,732
   Affiliated Companies                                        148,563               126,203
   Miscellaneous                                                20,409                39,046
   Allowance for Uncollectible Accounts                         (1,379)               (1,054)
  Fuel - at average cost                                        84,724                82,291
  Materials and Supplies - at average cost                      88,768                96,053
  Accrued Utility Revenues                                        -                      264
  Energy Trading Contracts                                     472,246             1,608,298
  Prepayments and Other                                         20,865                32,882
                                                                ------                ------
          TOTAL CURRENT ASSETS                                 927,738             2,247,594
                                                               -------             ---------

REGULATORY ASSETS                                              644,625               714,710
                                                               -------               -------

DEFERRED CHARGES                                                79,662               101,690
                                                                ------               -------

                    TOTAL                                   $4,916,067            $6,242,557
                                                            ==========            ==========
</TABLE>

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
                                                             December 31,
                                                       ------------------------
                                                       2001                2000
                                                       ----                ----
                                                            (in thousands)
<S>                                                <C>                   <C>
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized - 40,000,000 Shares
    Outstanding - 27,952,473 Shares                  $321,201              $321,201
  Paid-in Capital                                     462,483               462,483
  Accumulated Other Comprehensive Income (Loss)          (196)                 -
  Retained Earnings                                   401,297               398,086
                                                      -------               -------
    Total Common Shareholder's Equity               1,184,785             1,181,770
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption                16,648                16,648
    Subject to Mandatory Redemption                     8,850                 8,850
  Long-term Debt                                    1,203,841             1,077,987
                                                    ---------             ---------

          TOTAL CAPITALIZATION                      2,414,124             2,285,255
                                                    ---------             ---------

OTHER NONCURRENT LIABILITIES                          130,386               542,017
                                                      -------               -------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                     -                  117,506
  Advances From Affiliates                            300,213                  -
  Accounts Payable - General                          134,418               179,691
  Accounts Payable - Affiliated Companies             176,520               121,360
  Customer Deposits                                     5,452                39,736
  Taxes Accrued                                       126,770               223,101
  Interest Accrued                                     17,679                20,458
  Obligations Under Capital Leases                     16,405                32,716
  Energy Trading Contracts                            456,047             1,652,953
  Other                                                87,070               151,934
                                                       ------               -------

          Total CURRENT LIABILITIES                 1,320,574             2,539,455
                                                    ---------             ---------

DEFERRED INCOME TAXES                                 797,889               621,941
                                                      -------               -------

DEFERRED INVESTMENT TAX CREDITS                        21,925                25,214
                                                       ------                ------

LONG-TERM ENERGY TRADING CONTRACTS                    214,487               205,670
                                                      -------               -------

DEFERRED CREDITS                                       16,682                23,005
                                                       ------                ------

COMMITMENTS AND CONTINGENCIES (Note 8)

                    TOTAL                          $4,916,067            $6,242,557
                                                   ==========            ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
                                                                   Year Ended December 31,
                                                           ---------------------------------------
                                                           2001              2000             1999
                                                           ----              ----             ----
                                                                       (in thousands)

OPERATING ACTIVITIES:
<S>                                                     <C>                 <C>               <C>
  Net Income                                             $ 147,445            $83,737         $ 212,157
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization               252,123            200,350           193,780
    Deferred Income Taxes                                  215,833            (65,956)            3,666
    Deferred Investment Tax Credits                         (3,289)            (3,399)           (3,458)
    Deferred Fuel Costs (net)                                 -               (56,869)          (76,978)
    Extraordinary Loss                                      18,348             18,876              -
    Mark to Market of Energy Trading Contracts             (59,833)            (5,614)           (4,234)
  Change in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                               51,640             51,430           (49,309)
    Fuel, Materials and Supplies                             4,852             46,645           (60,500)
    Accrued Utility Revenues                                   264             45,311            (2,074)
    Accounts Payable                                         9,887             56,069             9,195
  Disputed Tax and Interest Related to COLI                   -               110,494            (6,272)
  Accumulated Provisions - Noncurrent                     (392,026)           145,573            66,573
  Taxes Accrued                                            (96,331)            60,919              (776)
  Customer Deposits                                        (34,284)            31,540            (3,763)
  Change in Other Assets                                    79,831           (439,448)          (67,515)
  Change in Other Liabilities                             (107,704)           359,640           127,288
                                                          --------            -------           -------
            Net Cash Flows From Operating Activities        86,756            639,298           337,780
                                                            ------            -------           -------

INVESTING ACTIVITIES:
  Construction Expenditures                               (344,571)          (254,016)         (193,870)
  Proceeds From Sales of Property and Other                 16,778              6,354             5,900
  Investment in Coal Companies                             (32,115)              -                 -
                                                           -------               ----              ----
            Net Cash Flows Used For
              Investing Activities                        (359,908)          (247,662)         (187,970)
                                                          --------           --------          --------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                               300,000             74,748           222,308
  Change in Advances From Affiliates (net)                 392,699            (92,486)             -
  Retirement of Cumulative Preferred Stock                    -                  (182)           (3,392)
  Retirement of Long-term Debt                            (297,858)           (30,663)         (158,638)
  Change in Short-term Debt (net)                             -              (194,918)           71,913
  Dividends Paid on Common Stock                          (142,976)          (271,813)         (210,813)
  Dividends Paid on Cumulative Preferred Stock              (1,258)            (1,262)           (1,420)
                                                            ------             ------            ------
            Net Cash Flows Used For
              Financing Activities                         250,607           (516,576)          (80,042)
                                                           -------           --------           -------

Net Increase (Decrease) in Cash and Cash Equivalents       (22,545)          (124,940)           69,768
Cash and Cash Equivalents January 1                         31,393            156,333            86,565
                                                            ------            -------            ------
Cash and Cash Equivalents December 31                      $ 8,848            $31,393         $ 156,333
                                                           =======            =======         =========
</TABLE>
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $94,747,000,
$87,120,000 and $78,739,000 and for income taxes was $(22,417,000), $142,710,000
and $94,606,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under
capital leases were $2,380,000, $17,005,000 and $28,561,000 in 2001, 2000 and
1999, respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statement of Retained Earnings
                                          Year Ended December 31,
                                  ---------------------------------------
                                  2001              2000             1999
                                  ----              ----             ----
                                              (in thousands)

Retained Earnings January 1       $398,086          $587,424          $587,500
  Net Income                       147,445            83,737           212,157
                                   -------  --        ------   -       -------
                                   545,531           671,161           799,657
                                   -------  -        -------   -       -------

Deductions:
  Cash Dividends Declared:
    Common Stock                   142,976           271,813           210,813
    Cumulative Preferred Stock:
       4.08%  Series                    58                59                61
       4.20%  Series                    96                96                97
       4.40%  Series                   139               139               142
       4-1/2% Series                   439               442               460
       5.90%  Series                   428               428               472
       6.02%  Series                    66                66               156
       6.35%  Series                    32                32                32
                                        --  ------        --   ------       --
              Total Dividends      144,234           273,075           212,233
                                   -------  -        -------   -       -------

Retained Earnings December 31     $401,297          $398,086          $587,424
                                  ========          ========          ========

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization

                                                                                   December 31,
                                                                          -----------------------------
                                                                              2001             2000
                                                                              ----             ----
                                                                                 (in thousands)
<S>                                                                       <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                               $1,184,785        $1,181,770
                                                                          ----------        ----------

PREFERRED STOCK: $100 par value - authorized shares 3,762,403
                 $25  par value - authorized shares 4,000,000

            Call Price                                            Shares
           December 31,    Par   Number of Shares Redeemed     Outstanding
Series(a)      2001       Value    Year Ended December 31,   December 31, 2001
- ------     ------------   -----  --------------------------- -----------------
                                  2001      2000      1999
                                  ----      ----      ----

Not Subject to Mandatory Redemption:

4.08%          $103        $100    -        -          373       14,595        1,460             1,460
4.20%           103.20      100    -         276      -          22,824        2,282             2,282
4.40%           104         100    -         432       330       31,512        3,151             3,151
4-1/2%          110         100    -       2,181     3,631       97,546        9,755             9,755
                                                                              ------            ------

                                                                              16,648            16,648
                                                                              ------            ------
Subject to Mandatory Redemption:

5.90% (b)         -        $100   -         -       10,000       72,500        7,250             7,250
6.02% (c)         -         100   -         -       20,000       11,000        1,100             1,100
6.35% (c)         -         100   -         -         -           5,000          500               500
                                                                              ------            ------

                                                                               8,850             8,850
                                                                              ------            ------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                         141,544           316,294
Installment Purchase Contracts                                               233,235           233,130
Senior Unsecured Notes                                                       396,962           471,583
Notes Payable to Affiliated Company                                          300,000              -
Notes Payable                                                                   -               30,000
Junior Debentures                                                            132,100           131,980
Other Long-term Debt                                                            -               12,506
Less Portion Due Within One Year                                                -             (117,506)
                                                                          ----------        ----------

  Long-term Debt Excluding Portion Due Within One Year                     1,203,841         1,077,987
                                                                          ----------        ----------

  TOTAL CAPITALIZATION                                                    $2,414,124        $2,285,255
                                                                          ==========        ==========
</TABLE>
(a)  The series subject to mandatory redemption are not callable until after
     2002. The sinking fund provisions of each series subject to mandatory
     redemption have been met by purchase of shares in advance of the due date.
(b)  Commencing in 2004 and continuing through the year 2008, a sinking fund for
     the 5.90% cumulative preferred stock will require the redemption of 22,500
     shares each year and the redemption of the remaining shares outstanding on
     January 1, 2009, in each case at $100 per share. Shares previously redeemed
     may be applied to meet sinking fund requirements.
(c)  Commencing in 2003 and continuing through 2007 cumulative preferred stock
     sinking funds will require the redemption of 20,000 shares each year of the
     6.02% series and 15,000 shares each year of the 6.35% series, in each case
     at $100 per share. All remaining outstanding shares must be redeemed in
     2008. Shares previously redeemed may be applied to meet the sinking fund
     requirements.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt


First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2001       2000
                           ----       ----
                          (in thousands)
% Rate Due
6.75   2003 - April 1    $ 29,850   $ 38,850
6.55   2003 - October 1    27,315     32,135
6.00   2003 - November 1   12,500     25,000
6.15   2003 - December 1   20,000     50,000
8.80   2022 - February 10   5,000     50,000
7.75   2023 - April 1       5,000     40,000
7.375  2023 - October 1    20,250     40,000
7.10   2023 - November 1   12,000     20,000
7.30   2024 - April 1      10,000     21,500
Unamortized Discount         (371)    (1,191)
                         --------   --------
  Total                  $141,544   $316,294
                         ========   ========

         First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.

         Installment purchase contracts have been entered into in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:

                             December 31,
                           2001       2000
                           ----       ----
                            (in thousands)
% Rate Due

Mason County, West
 Virginia:
5.45%  2016 - December 1  $ 50,000  $ 50,000
Marshall County, West
 Virginia:
5.45%  2014 - July 1        50,000    50,000
5.90%  2022 - April 1       35,000    35,000
6.85%  2022 - June 1        50,000    50,000
Ohio Air Quality
 Development
5.15%  2026 - May 1         50,000    50,000
Unamortized Discount        (1,765)   (1,870)
                          --------  --------
  Total                   $233,235  $233,130
                          ========  ========

         Under the terms of the installment purchase contracts, OPCo is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.


Senior unsecured notes outstanding were as follows:
                            December 31,
                        --------------------
                          2001       2000
                          ----       ----
                           (in thousands)
% Rate Due
- ------ ------------------
 (a)   2001 - May 16    $   -      $ 75,000
6.75   2004 - July 1     100,000    100,000
7.00   2004 - July 1      75,000     75,000
6.73   2004 - November 1  48,000     48,000
6.24   2008 - December 4  37,225     37,225
7-3/8  2038 - June 30    140,000    140,000
Unamortized Discount      (3,263)    (3,642)
                        --------   --------
  Total                 $396,962   $471,583
                        ========   ========

(a)      Redeemed on 5/16/01.

Notes payable to parent company were as follows:

                              December 31,
                             2001      2000
                             ----      ----
                             (in thousands)
% Rate Due
4.336% 2003 - May 15       $ 60,000   $ -
6.501% 2006 - May 15        240,000     -
                           --------   ------
  Total                    $300,000   $ -
                           ========   ======

Notes payable outstanding were as follows:

                              December 31,
                             2001      2000
                             ----      ----
                             (in thousands)
% Rate Due
6.20   2001 - January 31   $  -      $ 5,000
6.20   2001 - January 31      -        7,000
6.20   2001 - January 31      -       18,000
                           -------   -------
  Total                    $  -      $30,000
                           =======   =======

Junior debentures outstanding were as follows:
                             December 31,
                            2001      2000
                            ----      ----
                            (in thousands)
% Rate Due
- ------ -----------------
8.16   2025 - September 30 $ 85,000 $ 85,000
7.92   2027 - March 31       50,000   50,000
Unamortized Discount         (2,900)  (3,020)
                           -------- --------
  Total                    $132,100 $131,980
                           ======== ========

         Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of the Company.


<PAGE>

         Finance obligations were entered into by the Company's coal mining
subsidiaries for mining facilities and equipment through sale and leaseback
transactions. In accordance with SFAS 98, the transactions did not qualify as
sales and leasebacks for accounting purposes and therefore are shown as other
long-term debt. The remaining long-term debt obligation was paid off in the
first quarter of 2001.

         At December 31, 2001, future annual long-term debt payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2002                       $     -
2003                          149,665
2004                          223,000
2005                             -
2006                          240,000
Later Years                   599,475
                           ----------
  Total Principal Amount    1,212,140
Unamortized Discount            8,299
                           ----------
    Total                  $1,203,841
                           ==========



<PAGE>




OHIO POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements

The notes to OPCo's financial statements are combined with the notes to
financial statements for AEP and its other subisidiary registrants. Listed below
are the combined notes that apply to OPCo. The combined footnotes begin on page
L-1.

                                                     Combined
                                                     Footnote
                                                     Reference

Significant Accounting Policies                      Note  1

Extraordinary Items and Cumulative Effect            Note  2

Effects of Regulation                                Note  6

Customer Choice and Industry Restructuring           Note  7

Commitments and Contingencies                        Note  8

Acquisitions and Dispositions                        Note  9

Benefit Plans                                        Note 10

Business Segments                                    Note 12

Risk Management, Financial Instruments
  and Derivatives                                    Note 13

Income Taxes                                         Note 14

Supplementary Information                            Note 16

Leases                                               Note 18

Lines of Credit and Sale of Receivables              Note 19

Unaudited Quarterly Financial Information            Note 20

Related Party Transactions                           Note 24




<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of Ohio Power Company:

     We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Ohio Power Company and its
subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, comprehensive income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

     We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

     In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Ohio Power Company and its
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002



<PAGE>


















                       PUBLIC SERVICE COMPANY OF OKLAHOMA
                                AND SUBSIDIARIES

<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Selected Consolidated Financial Data
                                                             Year Ended December 31,
                                     2001              2000              1999                 1998           1997
                                     ----              ----              ----                 ----           ----
                                                                                (in thousands)
INCOME STATEMENTS DATA:
<S>                              <C>               <C>               <C>               <C>               <C>
  Operating Revenues              $2,201,249        $1,430,019         $749,390            $780,159        $712,690
  Operating Expenses               2,104,261         1,333,350          650,677             665,085         630,666
                                   ---------         ---------          -------             -------         -------
  Operating Income                    96,988            96,669           98,713             115,074          82,024
  Nonoperating Income (Loss)              20             8,974              946                 (91)          1,649
  Interest Charges                    39,249            38,980           38,151              38,074          37,218
                                      ------            ------           ------              ------          ------
  Net Income                          57,759            66,663           61,508              76,909          46,455
  Preferred Stock Dividend
    Requirements                         213               212              212                 213             364
  Gain On Reacquired
    Preferred Stock                     -                 -                -                   -              4,211
                                        ----              ----             ----                ----           -----
  Earnings Applicable to
    Common Stock                    $ 57,546          $ 66,451         $ 61,296            $ 76,696        $ 50,302
                                    ========          ========         ========            ========        ========

                                                                    December 31,
                                     2001              2000              1999             1998              1997
                                     ----              ----              ----             ----              ----
                                                                               (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant          $2,695,099        $2,604,670       $2,459,705        $2,391,722        $2,339,908
  Accumulated Depreciation
    and Amortization               1,184,443         1,150,253        1,114,255         1,082,081         1,031,322
                                   ---------         ---------        ---------         ---------         ---------
  Net Electric Utility Plant      $1,510,656        $1,454,417       $1,345,450        $1,309,641        $1,308,586
                                  ==========        ==========       ==========        ==========        ==========

  Total Assets                    $1,917,897        $2,138,333       $1,524,726        $1,470,939        $1,464,562
                                  ==========        ==========       ==========        ==========        ==========

  Common Stock and Paid-in
    Capital                         $337,230          $337,230         $337,230          $337,230          $337,230
  Retained Earnings                  142,994           137,688          139,237           142,941           135,245
                                     -------           -------          -------           -------           -------
  Total Common Shareholder's
    Equity                          $480,224          $474,918         $476,467          $480,171          $472,475
                                    ========          ========         ========          ========          ========

  Cumulative Preferred Stock:
    Not Subject to Mandatory
      Redemption                     $ 5,283           $ 5,283          $ 5,286           $ 5,287           $ 5,287
                                     =======           =======          =======           =======           =======

  Preferred Securities of
    Subsidiary Trust                $ 75,000          $ 75,000         $ 75,000          $ 75,000          $ 75,000
                                    ========          ========         ========          ========          ========

  Long-term Debt (a)                $451,129          $470,822         $384,516          $384,064          $438,703
                                    ========          ========         ========          ========          ========

  Total Capitalization and
    Liabilities                   $1,917,897        $2,138,333       $1,524,726        $1,470,939        $1,464,562
                                  ==========        ==========       ==========        ==========        ==========
</TABLE>
(a) Including portion due within one year.
<PAGE>
PUBLIC SERVICE COMPANY OF OKLAHOMA
Management's Narrative Analysis of Results of Operations

       PSO is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to approximately 502,000 retail
customers in eastern and southwestern Oklahoma. PSO also sells electric power at
wholesale to other utilities, municipalities and rural electric cooperatives.

       Wholesale power marketing and trading activities are conducted on PSO's
behalf by AEP. PSO, along with the other AEP electric operating subsidiaries,
shares in the revenues and costs of AEP's wholesale sales to and forward trades
with other utility systems and power marketers.

Critical Accounting Policies - Revenue Recognition

Regulatory Accounting - As a cost-based rate-regulated electric public utility
company, PSO's consolidated financial statements reflect the actions of
regulators that can result in the recognition of revenues and expenses in
different time periods than enterprises that are not rate regulated. In
accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.

        When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.

Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to PSO. Trading
activities allocated to PSO involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.

Accounting standards applicable to trading activities require that changes in
the fair value of trading contracts be recognized in revenues prior to
settlement and is commonly referred to as mark-to-market (MTM) accounting. Since
PSO is a cost-based rate-regulated entity,whose revenues are based on settled
transaction, unrealized changes in the fair value of physical forward sale and
purchase contracts are deferred as regulatory liabilities (gains) or regulatory
assets (losses).

Mark-to-market accounting represents the change in the unrealized gain or loss
throughout the contract's term. When the contract actually settles, that is, the
energy is actually delivered in a sale or received in a purchase or the parties
agree to forego delivery and receipt and net settle in cash, the unrealized gain
or loss is reversed and the actual realized cash gain or loss is recognized in
the income statement. Therefore, as the contract's market value changes over the
contract's term an unrealized gain or loss is deferred as a regulatory liability
or a regulatory asset. When the contract settles the total gain or loss is
realized in cash and recognized in the income statement. Physical forward
trading sale contracts are included in revenues when the contracts settle.
Physical forward trading purchase contracts are included in purchased power
expense when they settle. Prior to settlement, changes in the fair value of
physical forward sale and purchase contracts are deferred as regulatory
liabilities (gains) or regulatory assets (losses). Unrealized mark-to-market
gains and losses are included in the Balance Sheet as energy trading contract
assets or liabilities as appropriate.

        The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.

       Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing PSO to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.

Results of Operations

         Net income decreased $8.9 million or 13.4% in 2001 due primarily due to
the effect of a gain on the sale of a minority interest in Scientech, Inc.
recorded in year 2000.

Operating Revenues

       The 54% increase in operating revenues for the year resulted from
increased trading volumes of the wholesale electric marketing and trading
business. The increase in revenues is primarily attributable to our sharing in
AEP's power marketing and trading operations. Revenues also increased as a
result of favorable fuel-related revenues associated with the Oklahoma fuel
clause recovery mechanism.

                                           Increase
                                   From Previous Year
                                      Amount      %
(dollars in millions)
- ---------------------
Retail*                               $ 49.1        8
Wholesale Marketing
 and Trading                           675.3      124
Other                                    7.9       41
                                      ------
  Total Marketing and Trading          732.3       63
Energy Delivery*                        16.8        7
Sales to AEP Affiliates                 22.1      151
                                      ------
   Total Revenues                     $771.2       54
                                      ======

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.

         Revenues from retail customers increased primarily as a result of an
increase in fuel-related revenues. Rising prices for natural gas used for
generation and higher purchased power prices accounted for the increase in
fuel-related revenues. The Oklahoma fuel clause recovery mechanism provides for
the accrual of fuel-related revenues until reviewed and approved for billing to
customers by the Oklahoma Corporation Commission. The accrual of additional fuel
and purchased power revenues is offset by increases in fuel and purchased power
expenses. As a result, accrued fuel-related revenues do not impact results of
operations.

         The increase in wholesale electric marketing and trading revenues is
attributable to PSO's sharing in the AEP System's power marketing and trading
operations for a full year. In June 2000 as a result of a merger with CSW, PSO
started sharing in the AEP System's power marketing and trading transactions.



<PAGE>


Operating Expenses Increase

        Operating expenses were $770.9 million more in 2001 than in 2000 largely
as a result of increased fuel and purchased power expenses. Changes in the
components of operating expenses were as follows:

                                           Increase
                                   From Previous Year
                                      Amount      %
(dollars in millions)
- ---------------------

Fuel                                  $ 58.5       15
Marketing and Trading
 Purchases                             669.0      119
Affiliated Purchases                    18.5       30
Other Operation                         18.2       15
Maintenance                              0.3      N.M.
Depreciation and Amortization            3.8        5
Taxes Other Than
 Income Taxes                           (1.2)      (4)
Income Taxes                             3.8       12
                                      ------
     Total                            $770.9       58
                                      ------

N.M. = Not Meaningful

        Fuel expense increased primarily from the recovery of fuel cost due to
regulated recovery mechanisms offset in part by a 4% decrease in generation.


        The increase in purchased power expense was primarily attributable to
our participation in AEP's power marketing and trading activities for a full
year.

        Other operation expenses increased due mainly to a true-up adjustment in
2000 under a FERC-approved Transmission Coordination Agreement and a full year
of our share of incentive compensation for power trading.

        Depreciation expense increased due to investment relating to repowering
Northeast Station Units 1 and 2.

        The increase in income tax expense was primarily due to adjustments
associated with prior year tax returns offset in part by a decrease in pre-tax
book income.

Nonoperating Income

         Nonoperating income decreased primarily from the effect of a gain
recorded in 2000 on the sale of PSO's minority interest in Scientech, Inc.
Scientech provides services, systems and instruments, which describe, regulate,
monitor and enhance the safety and reliability of power plant operations and
their environmental impact.





<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of Income
                                                     Year Ended December 31,
                                            -----------------------------------------
                                            2001               2000              1999
                                            ----               ----              ----
                                                          (in thousands)
<S>                                        <C>                <C>                <C>
OPERATING REVENUES:
  Electricity Marketing and Trading         $1,902,601         $1,170,247         $479,346
  Energy Delivery                              261,877            245,124          256,327
  Sales to AEP Affiliates                       36,771             14,648           13,717
                                                ------             ------           ------

            TOTAL OPERATING REVENUES         2,201,249          1,430,019          749,390
                                             ---------          ---------          -------

OPERATING EXPENSES:
  Fuel                                         461,470            402,933          269,316
  Purchased Power:
    Electricity Marketing and Trading        1,230,694            561,709           40,274
    AEP Affiliates                              79,251             60,788           34,619
  Other Operation                              139,927            121,697          121,896
  Maintenance                                   46,188             45,858           45,809
  Depreciation and Amortization                 80,245             76,418           74,736
  Taxes Other Than Income Taxes                 31,973             28,688           30,520
  Income Taxes                                  34,513             35,259           33,507
                                                ------             ------           ------

            TOTAL OPERATING EXPENSES         2,104,261          1,333,350          650,677
                                             ---------          ---------          -------

OPERATING INCOME                                96,988             96,669           98,713

NONOPERATING INCOME                              2,112              8,807            2,580

NONOPERATING EXPENSES                            1,740              1,139            3,849

NONOPERATING INCOME TAX EXPENSE (CREDIT)           352             (1,306)          (2,215)

INTEREST CHARGES                                39,249             38,980           38,151
                                                ------             ------           ------

NET INCOME                                      57,759             66,663           61,508

PREFERRED STOCK DIVIDEND REQUIREMENTS              213                212              212
                                                   ---                ---              ---

EARNINGS APPLICABLE TO COMMON STOCK           $ 57,546           $ 66,451         $ 61,296
                                              ========           ========         ========
</TABLE>
Consolidated Statements of Retained Earnings
                                              Year Ended December 31,
                                    -----------------------------------------
                                    2001               2000              1999
                                    ----               ----              ----
                                               (in thousands)
BEGINNING OF PERIOD                $137,688            $139,237         $142,941
NET INCOME                           57,759              66,663           61,508
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                     52,240              68,000           65,000
    Preferred Stock                     213                 212              212
                                        ---                 ---              ---

BALANCE AT END OF PERIOD           $142,994            $137,688         $139,237
                                   ========            ========         ========

See Notes to Financial Statements beginning on page L-1.
<PAGE>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Balance Sheets
                                                     December 31,
                                                     ------------
                                               2001                2000
                                               ----                ----
                                                    (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                   $1,034,711            $914,096
  Transmission                                    427,110             396,695
  Distribution                                    972,806             938,053
  General                                         203,572             206,731
  Construction Work in Progress                    56,900             149,095
                                                   ------             -------
          Total Electric Utility Plant          2,695,099           2,604,670
  Accumulated Depreciation and Amortization     1,184,443           1,150,253
                                                ---------           ---------
          NET ELECTRIC UTILITY PLANT            1,510,656           1,454,417
                                                ---------           ---------

OTHER PROPERTY AND INVESTMENTS                     41,020              38,211
                                                   ------              ------

LONG-TERM ENERGY TRADING CONTRACTS                 55,215              52,275
                                                   ------              ------

CURRENT ASSETS:
  Cash and Cash Equivalents                         5,795              11,301
  Accounts Receivable:
   Customers                                       31,144              60,424
   Affiliated Companies                            10,905               3,453
   Allowance for Uncollectible Accounts               (44)               (467)
  Fuel - at LIFO cost                              21,559              28,113
  Materials and Supplies - at average cost         36,785              29,642
  Under-recovered Fuel Costs                         -                 43,267
  Energy Trading Contracts                        162,200             378,911
  Prepayments                                       2,368               1,559
                                                    -----               -----
          TOTAL CURRENT ASSETS                    270,712             556,203
                                                  -------             -------

REGULATORY ASSETS                                  35,004              29,338
                                                   ------              ------

DEFERRED CHARGES                                    5,290               7,889
                                                    -----               -----

                    TOTAL                      $1,917,897          $2,138,333
                                               ==========          ==========

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                                                                    December 31,
                                                             -----------------------
                                                             2001               2000
                                                             ----               ----
                                                                  (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                      <C>                <C>
CAPITALIZATION:
  Common Stock - $15 Par Value:
    Authorized Shares: 11,000,000
    Issued Shares: 10,482,000
    Outstanding Shares: 9,013,000                          $157,230           $157,230
  Paid-in Capital                                           180,000            180,000
  Retained Earnings                                         142,994            137,688
                                                            -------            -------
    Total Common Shareholder's Equity                       480,224            474,918
                                                            -------            -------

Cumulative Preferred Stock Not Subject
  To Mandatory Redemption                                     5,283              5,283
PSO-Obligated, Mandatorily Redeemable Preferred
  Securities of Subsidiary Trust Holding Solely Junior
  Subordinated Debentures of PSO                             75,000             75,000
Long-term Debt                                              345,129            450,822
                                                            -------            -------

          TOTAL CAPITALIZATION                              905,636          1,006,023
                                                            -------          ---------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                        106,000             20,000
  Advances from Affiliates                                  123,087             81,120
  Accounts Payable - General                                 72,759            104,379
  Accounts Payable - Affiliated Companies                    40,857             64,556
  Customer Deposits                                          21,041             19,294
  Over-Recovered Fuel                                         8,720               -
  Taxes Accrued                                              18,150              1,659
  Interest Accrued                                            7,298              8,336
  Energy Trading Contracts                                  167,658            385,809
  Other                                                      12,296             12,137
                                                             ------             ------

          TOTAL CURRENT LIABILITIES                         577,866            697,290
                                                            -------            -------

DEFERRED INCOME TAXES                                       296,877            312,060
                                                            -------            -------

DEFERRED INVESTMENT TAX CREDITS                              33,992             35,783
                                                             ------             ------

REGULATORY LIABILITIES AND DEFERRED CREDITS                  56,203             35,292
                                                             ------             ------

LONG-TERM ENERGY TRADING CONTRACTS                           47,323             51,885
                                                             ------             ------

                    TOTAL                                $1,917,897         $2,138,333
                                                         ==========         ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of Cash Flows
                                                                   Year Ended December 31,
                                                          ----------------------------------------
                                                          2001              2000              1999
                                                          ----              ----              ----
                                                                      (in thousands)
<S>                                                    <C>               <C>                <C>
OPERATING ACTIVITIES:
  Net Income                                             $57,759           $66,663           $61,508
  Adjustments for Noncash Items:
    Depreciation and Amortization                         80,245            76,418            74,736
    Deferred Income Taxes                                (17,751)           25,453            14,521
    Deferred Investment Tax Credits                       (1,791)           (1,791)           (1,791)
  Changes in Certain Assets and Liabilities:
    Accounts Receivable (net)                             21,405           (28,826)           (1,668)
    Fuel, Materials and Supplies                            (589)              677            (8,985)
    Other Property and Investments                        (2,809)            7,994            (2,108)
    Accounts Payable                                     (55,319)           89,330            (8,000)
    Taxes Accrued                                         16,491           (16,821)           (4,615)
    Fuel Recovery                                         51,987           (36,798)          (21,709)
  Transmission Coordination Agreement Settlement            -              (15,063)           15,063
  Changes in Other Assets                                 (9,150)            4,452            10,227
  Changes in Other Liabilities                             9,381            (6,073)          (15,736)
                                                           -----            ------           -------
            Net Cash Flows From Operating Activities     149,859           165,615           111,443
                                                         -------           -------           -------

INVESTING ACTIVITIES:
  Construction Expenditures                             (124,520)         (176,851)         (103,122)
  Other Items                                               (359)             -               (8,659)
                                                            ----              ----            ------
            Net Cash Flows Used For
              Investing Activities                      (124,879)         (176,851)         (111,781)
                                                        --------          --------          --------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                                -              105,625            33,232
  Retirement of Long-term Debt                           (20,000)          (20,000)          (33,700)
  Change in Advances From Affiliates (net)                41,967             1,951            63,277
  Dividends Paid on Common Stock                         (52,240)          (68,000)          (65,000)
  Dividends Paid on Cumulative Preferred Stock              (213)             (212)             (212)
                                                            ----              ----              ----
            Net Cash Flows (used For) From
              Financing Activities                       (30,486)           19,364            (2,403)
                                                         -------            ------            ------

Net Increase (Decrease) in Cash and Cash Equivalents      (5,506)            8,128            (2,741)
Cash and Cash Equivalents January 1                       11,301             3,173             5,914
                                                          ------   ----      -----   ----      -----
Cash and Cash Equivalents December 31                    $ 5,795           $11,301           $ 3,173
                                                         =======           =======           =======
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $38,250,000, $33,732,000
and $37,081,000 and for income taxes was $38,653,000, $25,786,000 and
$23,871,000 in 2001, 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of Capitalization

                                                                                          December 31,
                                                                                 --------------------------
                                                                                    2001              2000
                                                                                    ----              ----
                                                                                       (in thousands)

<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $  480,224        $  474,918
                                                                                 ----------        ----------

PREFERRED STOCK: Cumulative $100 par value - authorized shares 700,000,
redeemable at the option of PSO upon 30 days notice.

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2001            Year Ended December 31,       December 31, 2001
- ------     ------------     ----------------------------     -----------------
                              2001      2000      1999
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4.00%        $105.75           -        25        9                 44,606            4,460             4,460
4.24%         103.19           -        -         -                  8,069              807               807
Premium                                                                                  16                16
                                                                                 ----------        ----------
                                                                                      5,283             5,283
                                                                                 ----------        ----------

TRUST PREFERRED SECURITIES
  PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust
   holding solely Junior Subordinated Debentures of PSO, 8.00%,
   due April 30, 2037                                                                75,000            75,000
                                                                                 ----------        ----------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                297,772           317,465
Installment Purchase Contracts                                                       47,357            47,357
Senior Unsecured Notes                                                              106,000           106,000
Less Portion Due Within One Year                                                   (106,000)          (20,000)
                                                                                 ----------        ----------

Long-term Debt Excluding Portion Due Within One Year                                345,129           450,822
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $  905,636        $1,006,023
                                                                                 ==========        ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.

<PAGE>

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Schedule of Long-term Debt


First mortgage bonds outstanding were as follows:

                                         December 31,
                                      2001        2000
                                        (in thousands)
% Rate Due
5.91 2001 - March 1                $ -           $6,000
6.02 2001 - March 1                  -            5,000
6.02 2001 - March 1                  -            9,000
6.25 2003 - April 1                35,000        35,000
7.25 2003 - July 1                 65,000        65,000
7.38 2004 - December 1             50,000        50,000
6.50 2005 - June 1                 50,000        50,000
7.38 2023 - April 1               100,000       100,000
Unamortized Discount               (2,228)       (2,535)
                               --  ------   --   ------
                                 $297,772      $317,465

         First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.

         Installment purchase contracts have been entered into in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:

                                         December 31,
                                      2001        2000
                                        (in thousands)
% Rate Due
Oklahoma Environmental
 Finance Authority (OEFA):
5.90 2007 - December 1            $ 1,000       $ 1,000

Oklahoma Development
 Finance Authority (ODFA):
4.875  2014 - June 1               33,700        33,700

Red River Authority
  of Texas:
6.00   2020 - June 1               12,660        12,660
Unamortized Discount                   (3)           (3)
                                    -----         -----
  Total                           $47,357       $47,357
                                  =======       =======



         Under the terms of the installment purchase contracts, PSO is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.

Senior unsecured notes outstanding were as follows:

                                         December 31,
                                      2001        2000
                                        (in thousands)
% Rate Due
(a)   2002 - November 21            $106,000    $106,000
                                    ========    ========

(a) A floating interest rate is determined monthly. The rate on December 31,
2001 and 2000 was 2.775% and 7.376%.

     At December 31, 2001, future annual long-term debt payments are as follows:

                                              Amount
                                              ------
                                          (in thousands)

2002                                         $106,000
2003                                          100,000
2004                                           50,000
2005                                           50,000
2006                                             -
Later Years                                   147,360
                                              -------
  Total Principal Amount                      453,360
Unamortized Discount                           (2,231)
                                               ------

    Total                                    $451,129
                                             ========




<PAGE>


PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements

The notes to PSO's financial statements are combined with the notes to financial
statements for AEP and its other subisidiary registrants. Listed below are the
combined notes that apply to PSO. The combined footnotes begin on page L-1.

                                    Combined
                                    Footnote
                                                                  Reference


Significant Accounting Policies                                   Note  1

Merger                                                            Note  3

Rate Matters                                                      Note  5

Effects of Regulation                                             Note  6

Customer Choice and Industry Restructuring                        Note  7

Commitments and Contingencies                                     Note  8

Benefit Plans                                                     Note 10

Business Segments                                                 Note 12

Risk Management, Financial Instruments and Derivatives            Note 13

Income Taxes                                                      Note 14

Leases                                                            Note 18

Lines of Credit and Sale of Receivables                           Note 19

Unaudited Quarterly Financial Information                         Note 20

Trust Preferred Securities                                        Note 21

Jointly Owned Electric Utility Plant                              Note 23

Related Party Transactions                                        Note 24


<PAGE>


INDEPENDENT AUDITORS' REPORT

To the Shareholders and Board of
Directors of Public Service Company of Oklahoma:

       We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Public Service Company of Oklahoma
and subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, retained earnings, and cash flows for the years then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. The consolidated financial statements of the
Company for the year ended December 31, 1999, before the restatement described
in Note 3 to the consolidated financial statements, were audited by other
auditors whose report, dated February 25, 2000, expressed an unqualified opinion
on those statements.

       We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

       In our opinion, such 2001 and 2000 consolidated financial statements
present fairly, in all material respects, the financial position of Public
Service Company of Oklahoma and subsidiaries as of December 31, 2001 and 2000,
and the results of their operations and their cash flows for the years then
ended in conformity with accounting principles generally accepted in the United
States of America.

       We also audited the adjustments described in Note 3 that were applied to
restate the 1999 consolidated financial statements to give retroactive effect to
the conforming change in the method of accounting for vacation pay accruals. In
our opinion, such adjustments are appropriate and have been properly applied.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002




<PAGE>



















                       SOUTHWESTERN ELECTRIC POWER COMPANY
                                AND SUBSIDIARIES

<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
                                                                            Year Ended December 31,
                                             2001               2000              1999             1998                1997
                                             ----               ----              ----             ----                ----
                                                                            (in thousands)
<S>                                       <C>                 <C>               <C>                <C>                 <C>
INCOME STATEMENTS DATA:
  Operating Revenues                       $2,574,448          $1,682,726        $971,527           $952,952            $939,869
  Operating Expenses                        2,428,241           1,554,448         824,465            802,274             800,396
                                            ---------           ---------         -------            -------             -------
  Operating Income                            146,207             128,278         147,062            150,678             139,473
  Nonoperating Income
   (Loss)                                         741               3,851          (1,965)             2,451               4,029
  Interest Charges                             57,581              59,457          58,892             55,135              50,536
                                               ------              ------          ------             ------              ------
  Income Before
   Extraordinary Item                          89,367              72,672          86,205             97,994              92,966
  Extraordinary Loss                             -                   -             (3,011)              -                   -
                                                 ----                ----          ------               ----                ----
  Net Income                                   89,367              72,672          83,194             97,994              92,966
  Preferred Stock Dividend
   Requirements                                   229                 229             229                705               2,467
  Gain (Loss) on
   Reacquired Preferred
   Stock                                         -                   -               -                  (856)              1,819
                                                 ----                ----            ----               ----               -----
  Earnings Applicable to
   Common Stock                              $ 89,138            $ 72,443        $ 82,965           $ 96,433            $ 92,318
                                             ========            ========        ========           ========            ========

                                                                            December 31,
                                             2001               2000              1999               1998               1997
                                             ----               ----              ----               ----               ----
                                                                            (in thousands)
BALANCE SHEETS DATA:
  Electric Utility Plant                   $3,460,764          $3,319,024       $3,231,431         $3,157,911         $3,081,443
  Accumulated Depreciation
   and Amortization                         1,550,618           1,457,005        1,384,242          1,317,057          1,225,865
                                            ---------           ---------        ---------          ---------          ---------
  Net Electric Utility
   Plant                                   $1,910,146          $1,862,019       $1,847,189         $1,840,854         $1,855,578
                                           ==========          ==========       ==========         ==========         ==========
  Total Assets                             $2,496,600          $2,657,956       $2,106,215         $2,081,454         $2,134,618
                                           ==========          ==========       ==========         ==========         ==========

  Common Stock and
   Paid-in Capital                           $380,660            $380,660         $380,660           $380,660           $380,660
  Retained Earnings                           308,915             293,989          283,546            296,581            320,148
                                              -------             -------          -------            -------            -------
  Total Common
   Shareholder's Equity                      $689,575            $674,649         $664,206           $677,241           $700,808
                                             ========            ========         ========           ========           ========

  Preferred Stock                             $ 4,704             $ 4,704          $ 4,706            $ 4,707           $ 30,639
                                              =======             =======          =======            =======           ========

  Trust Preferred
   Securities                                $110,000            $110,000         $110,000           $110,000           $110,000
                                             ========            ========         ========           ========           ========

  Long-term Debt (a)                         $645,283            $645,963         $541,568           $587,673           $589,980
                                             ========            ========         ========           ========           ========

  Total Capitalization and Liabilities
                                           $2,496,600          $2,657,956       $2,106,215         $2,081,454         $2,134,618
                                           ==========          ==========       ==========         ==========         ==========
</TABLE>
(a) Including portion due within one year.
<PAGE>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations

       SWEPCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to approximately 431,000 retail
customers in northeastern Texas, northwestern Louisiana, and western Arkansas.
SWEPCo also sells electric power at wholesale to other utilities, municipalities
and rural electric cooperatives.

       Wholesale power marketing and trading activities are conducted on
SWEPCo's behalf by AEP. SWEPCo, along with the other AEP electric operating
subsidiaries, shares in the revenues and costs of AEP's wholesale sales to and
forward trades with other utility systems and power marketers.

Critical Accounting Policies - Revenue Recognition

Regulatory Accounting - Our financial statements reflect the actions of
regulators since our electricity supply sales in the Louisiana jurisdiction and
our transmission and distribution operations our cost-based rate-regulated. As a
result of the regulators' actions our financial statements can recognize
revenues and expenses in different time periods than enterprises that are not
rate regulated. In accordance with SFAS 71, regulatory assets (deferred
expenses) and regulatory liabilities (future revenue reductions or refunds) are
recorded to reflect the economic effects of regulation by matching expenses with
their recovery through regulated revenues in the same accounting period.

Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.


        When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to SWEPCo. Trading
activities allocated to SWEPCo involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We generally recognize revenues from trading activities based on changes in the
fair value of energy trading contracts.

         Recording the net change in the fair value of trading contracts as
revenues prior to settlement is commonly referred to as mark-to-market (MTM)
accounting. It represents the change in the unrealized gain or loss throughout
the contract's term. When the contract actually settles, that is, the energy is
actually delivered in a sale or received in a purchase or the parties agree to
forego delivery and receipt and net settle in cash, the unrealized gain or loss
is reversed out of revenues and the actual realized cash gain or loss is
recognized in revenues for a sale or in purchased power expense for a purchase.
Therefore, over the trading contract's term an unrealized gain or loss is
recognized as the contract's market value changes. When the contract settles the
total gain or loss is realized in cash but only the difference between the
accumulated unrealized net gains or losses recorded in prior months and the cash
proceeds is recognized. Unrealized mark-to-market gains and losses are included
in the Balance Sheet as energy trading contract assets or liabilities as
appropriate.

        Our trading activities represent physical forward electricity contracts
that are typically settled by entering into offsetting contracts. An example of
our trading activities is when, in January, we enter into a forward sales
contract to deliver electricity in July. At the end of each month until the
contract settles in July, we would record any difference between the contract
price and the market price as an unrealized gain or loss in revenues. In July
when the contract settles, we would realize the gain or loss in cash and reverse
to revenues the previously recorded unrealized gain or loss. Prior to
settlement, the change in the fair value of physical forward sale and purchase
contracts is included in revenues on a net basis. Upon settlement of a forward
trading contract, the amount realized is included in revenues for a sales
contract and realized costs are included in purchased power expense for a
purchase contract with the prior change in unrealized fair value reversed in
revenues.

        Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
revenues from recording additional changes in fair values using mark-to-market
accounting.

        The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.

         Volatility in commodities markets affects the fair values of all of our
open trading and derivative contracts exposing SWEPCo to market risk. See
"Market Risks" section of MD&A for a discussion of the policies and procedures
used to manage exposure to risk from trading activities.

Results of Operations

         Net income increased $16.7 million or 23% for the year resulting from
the favorable impact of our sharing in AEP's power marketing and trading
activities for a full year. The $10.5 million or 13% decrease in net income in
2000 is due to increased operating expenses.



<PAGE>


Operating Revenues

       The significant increase in 2001 operating revenues resulted from
increased trading volumes of the wholesale business and a full year of our
participation in AEP's power marketing and trading operations since the merger
in June 2000.

       Operating revenues significantly increased in 2000 due to the post merger
sharing of AEP's power marketing and trading sales, and offset an unfavorable
revenue adjustment in 1999 as a result of FERC's approval of a transmission
coordination agreement. The transmission coordination agreement provides the
means by which the AEP West electric operating companies plan, operate and
maintain their separate transmission assets as a single system. The agreement
also establishes the method by which these companies allocate transmission
revenues received under open access transmission tariffs.

       The following analyzes the changes in operating revenues:

                    Increase (Decrease)
                    From Previous Year
(dollars in millions)
                     2001           2000
                     ----           ----
               Amount    %    Amount     %

Retail*        $ 14.3    3    $ 29.9     6
Wholesale
 Marketing and
 Trading        822.3  111     622.9   N.M.
Mark to Market   15.5  N.M.     (4.7)  N.M.
Other            35.4  113       8.5    37
               ------         ------
Total Marketing
 and Trading    887.5   70     656.6    106
Energy
 Delivery*      (11.9)  (3)     45.6     15
Sales to AEP
 Affiliates      16.1   26       9.0     17
               ------         ------
  Total
   Revenues    $891.7   53    $711.2     73
               ======         ======

N.M. = Not Meaningful

* Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.


       The significant increase in wholesale revenues in 2001 and 2000 is
attributable to SWEPCo's participation in AEP's power marketing and trading
operations after the merger of CSW and AEP. Revenues also increased in 2000
because of additional fuel and purchased power revenues and a rise in sales
volume caused by warmer summer temperatures. The increase in fuel and purchased
power revenues reflects rising prices for natural gas used for generation and
related higher costs for purchased power. The Texas and Arkansas fuel clause
recovery mechanisms provide for the accrual of fuel-related revenues until
reviewed and approved for billing to customers by the regulator. The accrual of
additional fuel-related revenues is generally offset by increases in fuel and
purchased power expenses. As a result fuel-related revenues do not impact
results of operations. Since SWEPCo became a subsidiary of AEP as a result of
the merger in June 2000, SWEPCo shares in the AEP System's power marketing and
trading transactions with other entities. Trading transactions involve the
purchase and sale of substantial amounts of electricity.

Operating Expenses Increase

       Total operating expenses increased 56% in 2001 and 89% for 2000. These
increases are mainly attributable to our sharing in AEP's power marketing and
trading activities since the merger in June 2000. The changes in the components
of operating expenses were:

                    Increase (Decrease)
                    From Previous Year
(dollars in millions)
                     2001           2000
                     ----           ----
                Amount    %    Amount     %

Fuel            $(41.2)  (8)   $119.2    31
Electricity
 Marketing and
 Trading
 Purchases       840.4  135     593.1   N.M.
Affiliated
 Purchases        27.9  N.M.      5.8    77
Other Operation   14.3    9      17.2    12
Maintenance        (.4) N.M.     10.9    17
Depreciation and
 Amortization     14.9   14      (4.2)   (4)
Taxes Other Than
 Income Taxes      2.0    4      N.M.   N.M.
Income Taxes      15.9   60     (12.0)  (31)
                ------         ------
     Total      $873.8   56    $730.0    89
                ======         ======

N.M. = Not Meaningful



<PAGE>


       Fuel expense decreased in 2001 from lower natural gas prices and a mild
summer resulting in a reduction in generation. Fuel expense increased in 2000
due to an increase in the average unit cost of fuel as a result of an increase
in the spot market price for natural gas and an increase in generation to meet
the rise in demand for electricity.

       The major increases in purchased power expense in 2001 and 2000 were
primarily caused by our sharing in AEP's power marketing and trading activities.

       Due to the acquisition of Dolet Hills mining operation in June 2001,
other operation expense increased for the year. Other operation expense
increased in 2000 due primarily to increased regulatory and consulting expenses.

       Maintenance expense increased in 2000 as a result of costs to restore
service and make repairs following a severe ice storm.

       Depreciation and amortization expense increased in 2001 due primarily to
an increase in excess earnings accruals under the Texas restructuring
legislation and the acquisition of Dolet Hills mining operation.

       The increase in 2001 income tax expense was primarily due to an increase
in pre-tax book income. The decrease in income tax expense attributable to
operations in 2000 was primarily due to a decrease in pre-tax operating income.

Nonoperating Expense

       The decrease in nonoperating expense in 2000 was due to the effect of a
1999 write off of acquisition expenses following CSW's decision not to continue
to pursue the acquisition of Cajun Electric Power Cooperatives non-nuclear
assets.



<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
                                                            Year Ended December 31,
                                                    -----------------------------------------
                                                    2001               2000              1999
                                                    ----               ----              ----
                                                                 (in thousands)
<S>                                            <C>                <C>                 <C>
OPERATING REVENUES:
  Electricity Marketing and Trading             $2,162,207         $1,274,652          $618,040
  Energy Delivery                                  333,004            344,950           299,369
  Sales to AEP Affiliates                           79,237             63,124            54,118
                                                    ------             ------            ------
            TOTAL OPERATING REVENUES             2,574,448          1,682,726           971,527
                                                 ---------          ---------           -------

OPERATING EXPENSES:
  Fuel                                             457,613            498,805           379,597
  Purchased Power:
    Electricity Marketing and Trading            1,463,377            622,970            29,820
    AEP Affiliates                                  41,250             13,338             7,551
  Other Operation                                  173,831            159,459           142,385
  Maintenance                                       74,677             75,123            64,241
  Depreciation and Amortization                    119,543            104,679           108,831
  Taxes Other Than Income Taxes                     55,834             53,830            53,783
  Income Taxes                                      42,116             26,244            38,257
                                                    ------             ------            ------
            TOTAL OPERATING EXPENSES             2,428,241          1,554,448           824,465
                                                 ---------          ---------           -------

OPERATING INCOME                                   146,207            128,278           147,062

NONOPERATING INCOME                                  4,512              5,487             2,550

NONOPERATING EXPENSES                                3,229              3,112             9,341

NONOPERATING INCOME TAX EXPENSE (CREDIT)               542             (1,476)           (4,826)

INTEREST CHARGES                                    57,581             59,457            58,892
                                                    ------             ------            ------

INCOME BEFORE EXTRAORDINARY ITEM                    89,367             72,672            86,205

EXTRAORDINARY LOSS (net of tax of $1,621,000)         -                  -               (3,011)
                                                      ----               ----            ------

NET INCOME                                          89,367             72,672            83,194

PREFERRED STOCK DIVIDEND REQUIREMENTS                  229                229               229
                                                       ---                ---               ---

EARNINGS APPLICABLE TO COMMON STOCK               $ 89,138           $ 72,443          $ 82,965
                                                  ========           ========          ========

Consolidated Statements of Retained Earnings

BALANCE AT BEGINNING OF PERIOD                    $293,989           $283,546          $296,581
NET INCOME                                          89,367             72,672            83,194

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                                    74,212             62,000            96,000
    Preferred Stock                                    229                229               229
                                                       ---                ---               ---

BALANCE AT END OF PERIOD                          $308,915           $293,989          $283,546
                                                  ========           ========          ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.

<PAGE>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
                                                       December 31,
                                                  -----------------------
                                                  2001               2000
                                                  ----               ----
                                                       (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                  $1,429,356          $1,414,527
  Transmission                                   538,749             519,317
  Distribution                                 1,042,523           1,001,237
  General                                        376,016             325,948
  Construction Work in Progress                   74,120              57,995
                                                  ------              ------
          Total Electric Utility Plant         3,460,764           3,319,024
  Accumulated Depreciation and Amortization    1,550,618           1,457,005
                                               ---------           ---------
          NET ELECTRIC UTILITY PLANT           1,910,146           1,862,019
                                               ---------           ---------

OTHER PROPERTY AND INVESTMENTS                    43,000              39,627
                                                  ------              ------

LONG-TERM ENERGY TRADING CONTRACTS                63,372              62,605
                                                  ------              ------

CURRENT ASSETS:
  Cash and Cash Equivalents                        5,415               1,907
  Accounts Receivable:
   Customers                                      42,326              42,310
   Affiliated Companies                           20,573              11,419
   Allowance for Uncollectible Accounts              (89)               (911)
  Fuel Inventory - at average cost                52,212              40,024
  Materials and Supplies - at average cost        32,527              25,137
  Under-recovered Fuel Costs                       2,501              35,469
  Energy Trading Contracts                       186,159             453,781
  Prepayments                                     18,716              16,780
                                                  ------              ------
          TOTAL CURRENT ASSETS                   360,340             625,916
                                                 -------             -------

REGULATORY ASSETS                                 51,989              57,082
                                                  ------              ------

DEFERRED CHARGES                                  67,753              10,707
                                                  ------              ------

                    TOTAL                     $2,496,600          $2,657,956
                                              ==========          ==========

See Notes to Financial Statements beginning on page L-1.

<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                                                                   December 31,
                                                              -----------------------
                                                              2001               2000
                                                              ----               ----
                                                                   (in thousands)
<S>                                                       <C>                <C>
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $18 Par Value:
    Authorized - 7,600,000 Shares
    Outstanding - 7,536,640 Shares                          $135,660           $135,660
  Paid-in Capital                                            245,000            245,000
  Retained Earnings                                          308,915            293,989
                                                             -------            -------
    Total Common Shareholder's Equity                        689,575            674,649
  Preferred Stock                                              4,704              4,704
  SWEPCO-Obligated, Mandatorily Redeemable Preferred
   Securities of Subsidiary Trust Holding Solely Junior
   Subordinated Debentures of SWEPCO                         110,000            110,000
  Long-term Debt                                             494,688            645,368
                                                             -------            -------
          TOTAL CAPITALIZATION                             1,298,967          1,434,721
                                                           ---------          ---------

OTHER NONCURRENT LIABILITIES                                  34,997             11,290
                                                              ------             ------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                         150,595                595
  Advances from Affiliates                                   123,609             16,823
  Accounts Payable - General                                  71,810            107,747
  Accounts Payable - Affiliated Companies                     37,469             36,021
  Customer Deposits                                           19,880             16,433
  Taxes Accrued                                               36,522             11,224
  Interest Accrued                                            13,631             13,198
  Energy Trading Contracts                                   192,318            462,043
  Other                                                       26,166             15,064
                                                              ------             ------
          TOTAL CURRENT LIABILITIES                          672,000            679,148
                                                             -------            -------

DEFERRED INCOME TAXES                                        369,781            399,204
                                                             -------            -------

DEFERRED INVESTMENT TAX CREDITS                               48,714             53,167
                                                              ------             ------

REGULATORY LIABILITIES AND DEFERRED CREDITS                   17,828             18,288
                                                              ------             ------

LONG-TERM ENERGY TRADING CONTRACTS                            54,313             62,138
                                                              ------             ------

COMMITMENTS AND CONTINGENCIES (Note 8)

                    TOTAL                                 $2,496,600         $2,657,956
                                                          ==========         ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
                                                                  Year Ended December 31,
                                                          ----------------------------------------
                                                          2001              2000              1999
                                                          ----              ----              ----
                                                                      (in thousands)

OPERATING ACTIVITIES:
<S>                                                    <C>               <C>               <C>
  Net Income                                             $89,367           $72,672           $83,194
  Adjustments for Noncash Items:
    Depreciation and Amortization                        119,543           104,679           108,831
    Deferred Income Taxes                                (31,396)           14,653           (17,347)
    Deferred Investment Tax Credits                       (4,453)           (4,482)           (4,565)
  Mark-to-Market of Energy Trading Contracts              (3,472)            4,677              -
  Changes in Certain Assets and Liabilities:
    Accounts Receivable (net)                             (9,992)           (1,254)          (11,134)
    Fuel, Materials and Supplies                         (19,578)           22,103           (21,891)
    Accounts Payable                                     (34,489)           43,962           (12,953)
    Taxes Accrued                                         25,298           (13,150)            1,185
    Transmission Coordination Agreement Settlement          -              (24,406)           24,406
    Fuel Recovery                                         32,968           (38,357)           (2,490)
Change in Other Assets                                       856            57,418            24,500
Change in Other Liabilities                                4,958           (36,887)          (15,769)
                                                           -----           -------           -------
            Net Cash Flows From Operating Activities     169,610           201,628           155,967
                                                         -------           -------           -------

INVESTING ACTIVITIES:
  Construction Expenditures                             (111,725)         (120,671)         (111,019)
  Purchase of Dolet Hills Mining Operations              (85,716)             -                 -
  Other                                                     (411)              446            (4,167)
                                                            ----              ----            ------
            Net Cash Flows Used For
              Investing Activities                      (197,852)         (120,225)         (115,186)
                                                        --------          --------          --------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                                -              149,360              -
  Redemption of Preferred Stock                             -                   (1)               (1)
  Retirement of Long-term Debt                              (595)          (45,595)          (46,144)
  Change in Advances From Affiliates (net)               106,786          (124,074)          100,192
  Dividends Paid on Common Stock                         (74,212)          (62,000)          (96,000)
  Dividends Paid on Cumulative Preferred Stock              (229)             (229)             (229)
                                                            ----              ----              ----
            Net Cash Flows From (Used For)
              Financing Activities                        31,750           (82,539)          (42,182)
                                                          ------           -------           -------

Net Increase (Decrease) in Cash and Cash Equivalents       3,508            (1,136)           (1,401)
Cash and Cash Equivalents January 1                        1,907             3,043             4,444
                                                           -----             -----             -----
Cash and Cash Equivalents December 31                    $ 5,415           $ 1,907           $ 3,043
                                                         =======           =======           =======
</TABLE>
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $51,126,000, $51,111,000
and $55,254,000 and for income taxes was $49,901,000, $27,994,000 and
$55,677,000 in 2001, 2000, and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.


<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization

                                                                                          December 31,
                                                                                 -----------------------------
                                                                                     2001             2000
                                                                                     ----             ----
                                                                                        (in thousands)

<S>                                                                             <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $  689,575        $  674,649
                                                                                 ----------        ----------

PREFERRED STOCK: $100 par value - authorized shares 1,860,000

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2001            Year Ended December 31,       December 31, 2001
- ------     ------------     ----------------------------     -----------------
                              2001      2000      1999
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4.28%        $103.90             -         -         -              7,386               739               739
4.65%        $102.75             -         -         1              1,907               190               190
5.00%        $109                -        12         2             37,715             3,771             3,771
Premium                                                                                   4                 4
                                                                                 ----------        ----------

                                                                                      4,704             4,704
                                                                                 ----------        ----------

TRUST PREFERRED SECURITIES
  SWEPCo-obligated, mandatorily redeemable preferred securities of subsidiary
   trust holding solely Junior Subordinated Debentures of SWEPCo, 7.875%,
   due April 30, 2037                                                               110,000           110,000
                                                                                 ----------        ----------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                315,449           315,477
Installment Purchase Contracts                                                      179,834           180,486
Senior Unsecured Notes                                                              150,000           150,000
Less Portion Due Within One Year                                                   (150,595)             (595)
                                                                                 ----------        ----------

  Long-term Debt Excluding Portion Due Within One Year                              494,688           645,368
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $1,298,967        $1,434,721
                                                                                 ==========        ==========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt


First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2001       2000
                           ----       ----
                           (in thousands)
% Rate Due
6-5/8  2003 - February 1 $ 55,000   $ 55,000
7-3/4  2004 - June 1       40,000     40,000
6.20   2006 - November 1    5,650      5,795
6.20   2006 - November 1    1,000      1,000
7.00   2007 - September 1  90,000     90,000
7-1/4  2023 - July 1       45,000     45,000
6-7/8  2025 - October 1    80,000     80,000
Unamortized Discount       (1,201)    (1,318)
                         --------   --------
                         $315,449   $315,477

         First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.

         Installment purchase contracts have been entered into in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:

                             December 31,
                           2001       2000
                           ----       ----
                            (in thousands)
% Rate Due
- ------ -----------------
DeSoto County:

7.60   2019 - January 1  $ 53,500   $ 53,500

Sabine:

6.10   2018 - April 1      81,700     81,700

Titus County:

6.90   2004 - November 1   12,290     12,290
6.00   2008 - January 1    13,070     13,520
8.20   2011 - August 1     17,125     17,125
Unamortized Premium         2,149      2,351
                         --------   --------
                         $179,834   $180,486



         Under the terms of the installment purchase contracts, SWEPCo is
required to pay amounts sufficient to enable the payment of interest on and the
principal (at stated maturities and upon mandatory redemptions) of related
pollution control revenue bonds issued to finance the construction of pollution
control facilities at certain plants.

Senior unsecured notes outstanding were as follows:

                            December 31,
                          2001       2000
                          ----       ----
                           (in thousands)
% Rate Due
- ------ ------------------
 (a)   2002 - March 1   $150,000   $150,000
                        ========   ========

(a) A floating interest rate is determined monthly. The rate on
    December 31, 2001 and 2000 was 2.311% and 6.97%.

At December 31, 2001, future annual long-term debt payments are as follows:

                             Amount
                             ------
                         (in thousands)
2002                        $150,595
2003                          55,595
2004                          52,885
2005                             595
2006                           6,520
Later Years                  378,145
                            --------
  Total Principal Amount     644,335
Unamortized Premium              948
                            --------
    Total                   $645,283
                            ========



<PAGE>



SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements

The notes to SWEPCo's financial statements are combined with the notes to
financial statements for AEP and its other subisidiary registrants. Listed below
are the combined notes that apply to SWEPCo. The combined footnotes begin on
page L-1.

                                                          Combined
                                                          Footnote
                                                          Reference

Significant Accounting Policies                           Note  1

Extraordinary Items and Cumulative Effect                 Note  2

Merger                                                    Note  3

Rate Matters                                              Note  5

Effects of Regulation                                     Note  6

Customer Choice and Industry Restructuring                Note  7

Commitments and Contingencies                             Note  8

Acquistions and Dispositions                              Note  9

Benefit Plans                                             Note 10

Business Segments                                         Note 12

Risk Management, Financial Instruments and Derivatives    Note 13

Income Taxes                                              Note 14

Leases                                                    Note 18

Lines of Credit and Sale of Receivables                   Note 19

Unaudited Quarterly Financial Information                 Note 20

Trust Preferred Securities                                Note 21

Jointly Owned Electric Utility Plant                      Note 23

Related Party Transactions                                Note 24



<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of
Directors of Southwestern Electric Power Company:

       We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Southwestern Electric Power Company
and subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, retained earnings, and cash flows for the years then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. The consolidated financial statements of the
Company for the year ended December 31, 1999, before the restatement described
in Note 3 to the consolidated financial statements, were audited by other
auditors whose report, dated February 25, 2000, expressed an unqualified opinion
on those statements.

       We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

       In our opinion, such 2001 and 2000 consolidated financial statements
present fairly, in all material respects, the financial position of Southwestern
Electric Power Company and subsidiaries as of December 31, 2001 and 2000, and
the results of their operations and their cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States of
America.

       We also audited the adjustments described in Note 3 that were applied to
restate the 1999 consolidated financial statements to give retroactive effect to
the conforming change in the method of accounting for vacation pay accruals. In
our opinion, such adjustments are appropriate and have been properly applied.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002



<PAGE>













                          WEST TEXAS UTILITIES COMPANY

<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
Selected Financial Data
                                                              Year Ended December 31,
                                 2001                2000              1999              1998                 1997
                                 ----                ----              ----              ----                 ----
                                                                   (in thousands)
INCOME STATEMENTS DATA:
<S>                          <C>                 <C>               <C>               <C>                  <C>
  Operating Revenues          $1,064,271           $759,562          $445,709          $424,953             $397,779
  Operating Expenses           1,030,881            707,221           391,910           365,677              353,195
                               ---------            -------           -------           -------              -------
  Operating Income                33,390             52,341            53,799            59,276               44,584
  Nonoperating Income
   (Loss)                          2,195             (1,675)            2,488             2,712                1,463
  Interest Charges                23,275             23,216            24,420            24,263               24,570
                                  ------             ------            ------            ------               ------
  Income Before
   Extraordinary Item             12,310             27,450            31,867            37,725               21,477
  Extraordinary Loss                -                   -              (5,461)             -                    -
                                    ----                ---            ------              ----                 ----
  Net Income                      12,310             27,450            26,406            37,725               21,477
  Preferred Stock
   Dividend Requirements             104                104               104               104                  144
                                     ---                ---               ---               ---                  ---
  Gain on Reacquired
   Preferred Stock                  -                  -                 -                 -                   1,085
                                    ----               ----              ----              ----                -----
  Earnings Applicable to
   Common Stock                 $ 12,206           $ 27,346          $ 26,302          $ 37,621             $ 22,418
                                ========           ========          ========          ========             ========

                                                                     December 31,
                                  2001               2000               1999               1998               1997
                                  ----               ----               ----               ----               ----
                                                                (in thousands)
BALANCE SHEETS DATA:
  Electric Utility Plant      $1,260,872         $1,229,339        $1,182,544          $1,146,582         $1,108,845
  Accumulated
   Depreciation and
   Amortization                  546,162            515,041           495,847             473,503            441,281
                                 -------            -------           -------             -------            -------
  Net Electric Utility
   Plant                        $714,710           $714,298          $686,697            $673,079           $667,564
                                ========           ========          ========            ========           ========

  Total Assets                  $923,420         $1,087,411          $861,205            $819,446           $826,858
                                ========         ==========          ========            ========           ========

  Common Stock and
   Paid-in Capital              $139,450           $139,450          $139,450            $139,450           $139,450
  Retained Earnings              105,970            122,588           113,242             114,940            117,319
                                 -------            -------           -------             -------            -------
  Total Common
   Shareholder's Equity         $245,420           $262,038          $252,692            $254,390           $256,769
                                ========           ========          ========            ========           ========

  Cumulative Preferred Stock:
   Not Subject to
    Mandatory Redemption         $ 2,482            $ 2,482           $ 2,482             $ 2,482            $ 2,483
                                 =======            =======           =======             =======            =======
  Long-term Debt (a)            $255,967           $255,843          $303,686            $303,518           $303,351
                                ========           ========          ========            ========           ========

  Total Capitalization
   And Liabilities              $923,420         $1,087,411          $861,205            $819,446           $826,858
                                ========         ==========          ========            ========           ========
</TABLE>
(a) Including portion due within one year.



<PAGE>
WEST TEXAS UTILITIES COMPANY
Management's Narrative Analysis of Results of Operations

       WTU is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power and provides electric power to
approximately 189,000 retail customers in west and central Texas. WTU also sells
electric power at wholesale to other utilities, municipalities and rural
electric cooperatives.

       Wholesale power marketing and trading activities are conducted on WTU's
behalf by AEP. WTU, along with the other AEP electric operating subsidiaries,
shares in the revenues and costs of AEP's wholesale sales to and forward trades
with other utility systems and power marketers.

Critical Accounting Policies - Revenue Recognition

Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.

         When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.

Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.

Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to WTU. Trading
activities allocated to WTU involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the
fair value of energy trading contracts.

           Recording the net change in the fair value of trading contracts as
revenues prior to settlement is commonly referred to as mark-to-market (MTM)
accounting. It represents the change in the unrealized gain or loss throughout
the contract's term. When the contract actually settles, that is, the energy is
actually delivered in a sale or received in a purchase or the parties agree to
forego delivery and receipt of electricity and net settle in cash, the
unrealized gain or loss is reversed out of revenues and the actual realized cash
gain or loss is recognized in revenues for a sale or in purchased power expense
for a purchase. Therefore, over the trading contract's term an unrealized gain
or loss is recognized as the contract's market value changes. When the contract
settles the total gain or loss is realized in cash but only the difference
between the accumulated unrealized net gains or losses recorded in prior months
and the cash proceeds is recognized. Unrealized mark-to-market gains and losses
are included in the Balance Sheet as energy trading contract assets or
liabilities as appropriate.


<PAGE>


        Our trading activities represent physical forward electricity contracts
that are typically settled by entering into offsetting contracts. An example of
our trading activities is when, in January, we enter into a forward sales
contract to deliver electricity in July. At the end of each month until the
contract settles in July, we would record our share of any difference between
the contract price and the market price as an unrealized gain or loss in
revenues. In July when the contract settles, we would realize our share of the
gain or loss in cash and reverse to revenues the previously recorded unrealized
gain or loss. Prior to settlement, the change in the fair value of physical
forward sale and purchase contracts is included in revenues on a net basis. Upon
settlement of a forward trading contract, the amount realized is included in
revenues for a sales contract and realized costs are included in purchased power
expense for a purchase contract with the prior change in unrealized fair value
reversed in revenues.

        Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match, then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
revenues from recording additional changes in fair values using mark-to-market
accounting.

        The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.

        Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing WTU to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.

Results of Operations

       Income before extraordinary items decreased $15.1 million or 55% during
2001, due mostly to a significant increase in other operation expense. The
significant increase in other operation expense is partially due to the effect
of a 2001 increase in energy delivery's transmission expenses that resulted from
new prices for the Electric Reliability Council of Texas (ERCOT) transmission
grid. Other operation expense also increased due to the effect of a favorable
adjustment made in 2000 related to a FERC-approved Transmission Coordination
Agreement.

Operating Revenues

       Operating revenues increased 40% in 2001, as the result of increased
trading volumes of AEP's wholesale business. This increase in revenues is
attributable to our sharing in AEP's power marketing and trading transactions
since the merger of AEP and CSW in June 2000.

       Changes in the components of operating revenues were as follows:

                         Increase (Decrease)
                         From Previous Year
(dollars in millions)      Amount       %
- ----------------------     ------       -

Retail*                    $ (3.1)     (2)
Wholesale Electric
  Marketing and Trading     301.9      91
Unrealized MTM                6.3     N.M.
Other                         6.8      18
                           ------
  Total Marketing and
   Trading                  311.9      55
Energy Delivery*             (7.2)     (4)
                           ------
    Total Revenues         $304.7      40
                           ======

*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.

       Revenues from retail customers decreased slightly in 2001 due to milder
than normal summer and winter weather.

       The significant increase in wholesale marketing and trading revenues is
attributable to WTU's increased sharing in AEP's power marketing and trading
operations. Since WTU became a subsidiary of AEP as the result of the merger in
June 2000, WTU shares in AEP's power marketing and trading transactions. Trading
involves the sale and purchase of substantial amounts of electricity to and from
non-affiliated parties.


Operating Expenses

       Due mostly to an increase in purchased power expense, operating expenses
were $323.7 million or 46% higher than 2000. Charges in the components of
operating expenses were as follows:

                         Increase (Decrease)
                         From Previous Year
(dollars in millions)      Amount       %
- ----------------------     ------       -

Fuel                       $ (6.0)     (3)
Marketing and
 Trading Purchases          321.6     125
Affiliate Purchases          (1.1)     (2)
Other Operation              18.2      20
Maintenance                   1.1       5
Depreciation and
 Amortization                (4.5)     (8)
Taxes Other Than
 Income Taxes                 3.0      12
Income Taxes                 (8.6)    (58)
                           ------
     Total                 $323.7      46
                           ======

       Fuel expense decreased in 2001 due to a decrease in generation offset in
part by an increase in the average spot market price for natural gas. The
decrease in generation reflects milder than normal summer and winter weather.

       The significant increase in electricity marketing and trading purchases
is the result of our full year of sharing in AEP's power marketing and trading
activities.

       Other operation expense increased from the prior year primarily due to
the effect of two items. First, energy delivery's transmission expenses
increased as a result of new prices for the ERCOT transmission grid. The
increase in other operation expense is also attributable to a favorable
adjustment made in 2000 related to the FERC-approved Transmission Coordination
Agreement.

       An increase in maintenance expense is the result of an overhaul in 2001
of the Oklaunion Power Plant.

       Due to the recordation of increased accruals in 2000 for estimated excess
earnings under the Texas Legislation, depreciation and amortization expense
decreased during 2001.

       The increase in taxes other than income taxes is the result of an
increase in Texas franchise tax assessments and an increase in the Texas PUCT
benefit assessment tax, a new tax in the state of Texas.


       Income taxes decreased in 2001, reflecting a decrease in pre-tax income.

Nonoperating Income

       Nonoperating income increased $2.7 million due to an increase in interest
income earned on under-recovered fuel during 2001.

Nonoperating Expense

       The decrease in nonoperating expenses is mainly due to the effect of a
loss provision that was recorded in 2000 for the termination of merchandise
sales and the cost of phasing out the merchandising sales programs.




<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
Statements of Income
                                                               Year Ended December 31,
                                                     ------------------------------------------
                                                     2001                2000              1999
                                                     ----                ----              ----
                                                                   (in thousands)
OPERATING REVENUES
<S>                                             <C>                 <C>                 <C>
  Electricity Marketing and Trading              $  876,554          $  564,704          $256,033
  Energy Delivery                                   169,036             176,204           174,909
  Sales to AEP Affiliates                            18,681              18,654            14,767
                                                 ----------          ----------            ------
            Total Operating Revenues              1,064,271             759,562           445,709
                                                  ---------             -------           -------

OPERATING EXPENSES:
  Fuel                                              177,140             183,154           123,348
  Purchased Power:
    Electricity Marketing and Trading               578,193             256,578            34,941
    AEP Affiliates                                   56,656              57,773            26,591
  Other Operation                                   111,263              93,078            94,290
  Maintenance                                        22,343              21,241            19,604
  Depreciation and Amortization                      50,705              55,172            50,789
  Taxes Other Than Income Taxes                      28,319              25,321            28,268
  Income Taxes                                        6,262              14,904            14,079
                                                      -----              ------            ------
            TOTAL OPERATING EXPENSES              1,030,881             707,221           391,910
                                                  ---------             -------           -------

OPERATING INCOME                                     33,390              52,341            53,799

NONOPERATING INCOME                                  12,199               9,530            14,515

NONOPERATING EXPENSES                                10,695              12,664            11,169

NONOPERATING INCOME TAX EXPENSE (CREDIT)               (691)             (1,459)              858

INTEREST CHARGES                                     23,275              23,216            24,420
                                                     ------              ------            ------

INCOME BEFORE EXTRAORDINARY ITEMS                    12,310              27,450            31,867

EXTRAORDINARY LOSS (net of tax of $2,941,000)          -                   -               (5,461)
                                                       ----                ----            ------

NET INCOME                                           12,310              27,450            26,406

PREFERRED STOCK DIVIDEND REQUIREMENTS                   104                 104               104
                                                        ---                 ---               ---

EARNINGS APPLICABLE TO COMMON STOCK                $ 12,206            $ 27,346          $ 26,302
                                                   ========            ========          ========

Statements of Retained Earnings

BEGINNING OF PERIOD                                 $122,588           $113,242          $114,940

NET INCOME                                            12,310             27,450            26,406
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                                      28,824             18,000            28,000
    Preferred Stock                                      104                104               104
                                                         ---                ---               ---

BALANCE AT END OF PERIOD                            $105,970           $122,588          $113,242
                                                    ========           ========          ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.
<PAGE>
WEST TEXAS UTILITIES COMPANY
Balance Sheets
                                                       December 31,
                                                 ------------------------
                                                 2001                2000
                                                 ----                ----
                                                     (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
  Production                                   $443,508            $431,793
  Transmission                                  250,023             235,303
  Distribution                                  431,969             416,587
  General                                       112,797             110,832
  Construction Work in Progress                  22,575              34,824
                                                 ------              ------
          Total Electric Utility Plant        1,260,872           1,229,339
  Accumulated Depreciation and Amortization     546,162             515,041
                                                -------             -------
          NET ELECTRIC UTILITY PLANT            714,710             714,298
                                                -------             -------

OTHER PROPERTY AND INVESTMENTS                   24,933              23,154
                                                 ------              ------

LONG-TERM ENERGY TRADING CONTRACTS               21,532              20,804
                                                 ------              ------

CURRENT ASSETS:
  Cash and Cash Equivalents                       2,454               6,941
  Accounts Receivable:
   Customers                                     18,720              36,217
   Affiliated Companies                           8,656              16,095
   Allowance for Uncollectible Accounts            (196)               (288)
  Fuel - at average cost                          8,307              12,174
  Materials and Supplies - at average cost       11,190              10,510
  Under-recovered Fuel Costs                     32,791              68,107
  Energy Trading Contracts                       63,252             150,793
  Prepayments                                       966                 851
                                                    ---                 ---
          TOTAL CURRENT ASSETS                  146,140             301,400
                                                -------             -------

REGULATORY ASSETS                                13,659              24,808
                                                 ------              ------

DEFERRED CHARGES                                  2,446               2,947
                                                  -----               -----

                    TOTAL                      $923,420          $1,087,411
                                               ========          ==========

See Notes to Financial Statements beginning on page L-1.
<PAGE>
WEST TEXAS UTILITIES COMPANY
                                                       December 31,
                                                 -----------------------
                                                 2001               2000
                                                 ----               ----
                                                      (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $25 Par Value:
    Authorized - 7,800,000 Shares
    Outstanding - 5,488,560 Shares            $137,214            $137,214
  Paid-in Capital                                2,236               2,236
  Retained Earnings                            105,970             122,588
                                               -------             -------
    Total Common Shareholder's Equity          245,420             262,038
  Cumulative Preferred Stock
    Not Subject to Mandatory Redemption          2,482               2,482
  Long-term Debt                               220,967             255,843
                                               -------             -------
          TOTAL CAPITALIZATION                 468,869             520,363
                                               -------             -------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year            35,000                -
  Advances from Affiliates                      50,448              58,578
  Accounts Payable - General                    33,782              45,562
  Accounts Payable - Affiliated Companies       11,388              42,212
  Customer Deposits                              4,191               2,659
  Taxes Accrued                                 17,358              18,901
  Interest Accrued                               1,244               3,717
  Energy Trading Contracts                      65,414             153,539
  Other                                         12,001               7,906
                                                ------               -----
          TOTAL CURRENT LIABILITIES            230,826             333,074
                                               -------             -------

DEFERRED INCOME TAXES                          145,049             157,038
                                               -------             -------

DEFERRED INVESTMENT TAX CREDITS                 22,781              24,052
                                                ------              ------

LONG-TERM ENERGY TRADING CONTRACTS              18,455              20,648
                                                ------              ------

REGULATORY LIABILITIES AND DEFERRED CREDITS     37,440              32,236
                                                ------              ------

COMMITMENTS AND CONTINGENCIES (Note 8)

                    TOTAL                     $923,420          $1,087,411
                                              ========          ==========

See Notes to Financial Statements beginning on page L-1.



<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
Statements of Cash Flows
                                                                  Year Ended December 31,
                                                          ---------------------------------------
                                                          2001             2000              1999
                                                          ----             ----              ----
                                                                       (in thousands)
<S>                                                     <C>                <C>               <C>
OPERATING ACTIVITIES:
  Net Income                                            $ 12,310           $27,450           $26,406
  Adjustments for Noncash Items:
    Depreciation and Amortization                         50,705            55,172            50,789
    Deferred Federal Income Taxes                        (11,891)            8,164            12,026
    Deferred Investment Tax Credits                       (1,271)           (1,271)           (1,275)
    Extraordinary Loss - Discontinuance of SFAS 71          -                 -                5,461
    Mark-to-Market of Energy Trading Contracts            (1,818)            1,871              -
  CHANGES IN CERTAIN ASSETS AND LIABILITIES:
      Accounts Receivable (net)                           24,844            (1,445)          (18,890)
      Fuel, Materials and Supplies                         3,187             8,478            (3,785)
      Accounts Payable                                   (42,604)           28,393             7,229
      Taxes Accrued                                       (1,543)            6,443             2,427
      Fuel Recovery                                       35,316           (53,841)          (10,101)
  Transmission Coordination Agreement Settlement            -               15,465           (15,465)
  Change in Other Assets                                  (1,519)            3,361             5,615
  Change in Other Liabilities                              6,644            (3,962)            2,205
                                                           -----            ------             -----
            Net Cash Flows From Operating Activities      72,360            94,278            62,642
                                                          ------            ------            ------

INVESTING ACTIVITIES:
  Construction Expenditures                              (39,662)          (64,477)          (49,443)
  Other                                                     (127)             -               (3,832)
                                                            ----              ----            ------
            Net Cash Used For Investing Activities       (39,789)          (64,477)          (53,275)
                                                         -------           -------           -------

FINANCING ACTIVITIES:
  Retirement of Long-term Debt                              -              (48,000)             -
  Change in Advances From Affiliates (net)                (8,130)           37,170            16,835
  Dividends Paid on Common Stock                         (28,824)          (18,000)          (28,000)
  Dividends Paid on Cumulative Preferred Stock              (104)             (104)             (105)
                                                            ----              ----              ----
            Net Cash Used For Financing Activities       (37,058)          (28,934)          (11,270)
                                                         -------           -------           -------

Net Increase (Decrease) in Cash and Cash Equivalents      (4,487)              867            (1,903)
Cash and Cash Equivalents at Beginning of Period           6,941             6,074             7,977
                                                           -----             -----             -----
Cash and Cash Equivalents at End of Period                $2,454           $ 6,941           $ 6,074
                                                          ======           =======           =======
</TABLE>
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $19,279,000,
$19,088,000 and $17,577,000 and for income taxes was $21,997,000, $(906,000) and
$3,309,000 in 2001, 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.
<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
Statements of Capitalization

                                                                                        December 31,
                                                                                 ---------------------------
                                                                                   2001              2000
                                                                                   ----              ----
                                                                                       (in thousands)

<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $245,420          $262,038
                                                                                 --------          --------

PREFERRED STOCK: $100 par value - authorized shares 810,000

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2001            Year Ended December 31,       December 31, 2001
- ------     ------------     ----------------------------     -----------------
                              2001      2000      1999
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4.40%        $107                 -        1         2             23,672           2,367             2,367
Premium                                                                               115               115
                                                                                 --------          --------
                                                                                    2,482             2,482
                                                                                 --------          --------


LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                              211,657           211,533
Installment Purchase Contracts                                                     44,310            44,310
Less Portion Due Within One Year                                                  (35,000)             -
                                                                                 --------          --------

Long-term Debt Excluding Portion Due Within One Year                              220,967           255,843
                                                                                 --------          --------

  TOTAL CAPITALIZATION                                                           $468,869          $520,363
                                                                                 ========          ========
</TABLE>
See Notes to Financial Statements beginning on page L-1.

<PAGE>


WEST TEXAS UTILITIES COMPANY
Schedule of Long-term Debt

First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2001       2000
                           ----       ----
                            (in thousands)
% Rate Due
7-3/4  2007 - June 1     $ 25,000   $ 25,000
6-7/8  2002 - October 1    35,000     35,000
7      2004 - October 1    40,000     40,000
6-1/8  2004 - February 1   40,000     40,000
6-3/8  2005 - October 1    72,000     72,000
Unamortized Discount         (343)      (467)
                         --------   --------
                         $211,657   $211,533

         First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.

         Installment purchase contracts have been entered into, in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:

                             December 31,
                           2001       2000
                           ----       ----
                            (in thousands)
% Rate Due
Red River Authority
 of Texas:
6      2020 - June 1      $44,310    $44,310
                          =======    =======



         Under the terms of the installment purchase contracts, WTU is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.

         At December 31, 2001, future annual long-term debt payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2002                        $ 35,000
2003                            -
2004                          80,000
2005                          72,000
2006                            -
Later Years                   69,310
                            --------
Principal Amount             256,310
Unamortized Discount            (343)
                            --------
    Total                   $255,967
                            ========





<PAGE>




WEST TEXAS UTILITIES COMPANY
Index to Notes to Financial Statements

The notes to WTU's financial statements are combined with the notes to financial
statements for AEP and its other subisidiary registrants. Listed below are the
combined notes that apply to WTU. The combined footnotes begin on page L-1.

                                    Combined
                                    Footnote
                                   Reference


Significant Accounting Policies                                 Note  1

Extraordinary Items and Cumulative Effect                       Note  2

Merger                                                          Note  3

Rate Matters                                                    Note  5

Effects of Regulation                                           Note  6

Customer Choice and Industry Restructuring                      Note  7

Commitments and Contingencies                                   Note  8

Benefit Plans                                                   Note 10

Business Segments                                               Note 12

Risk Management, Financial Instruments and Derivatives          Note 13

Income Taxes                                                    Note 14

Leases                                                          Note 18

Lines of Credit and Sale of Receivables                         Note 19

Unaudited Quarterly Financial Information                       Note 20

Jointly Owned Electric Utility Plant                            Note 23

Related Party Transactions                                      Note 24



<PAGE>


INDEPENDENT AUDITORS' REPORT


To the Shareholders and Board of
Directors of West Texas Utilities Company:

       We have audited the accompanying balance sheets and statements of
capitalization of West Texas Utilities Company as of December 31, 2001 and 2000,
and the related statements of income, retained earnings, and cash flows for the
years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits. The financial statements of the
Company for the year ended December 31, 1999, before the restatement described
in Note 3 to the financial statements, were audited by other auditors whose
report, dated February 25, 2000, expressed an unqualified opinion on those
statements.

       We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

       In our opinion, such 2001 and 2000 financial statements present fairly,
in all material respects, the financial position of West Texas Utilities Company
as of December 31, 2001 and 2000, and the results of its operations and its cash
flows for the years then ended in conformity with accounting principles
generally accepted in the United States of America.

       We also audited the adjustments described in Note 3 that were applied to
restate the 1999 financial statements to give retroactive effect to the
conforming change in the method of accounting for vacation pay accruals. In our
opinion, such adjustments are appropriate and have been properly applied.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002


<PAGE>
NOTES TO FINANCIAL STATEMENTS

The notes to financial statements that follow are a combined presentation for
AEP and its subsidiary registrants. The following list of footnotes shows the
registrant to which they apply:

 1. Significant Accounting Policies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo,  PSO, SWEPCo, WTU

 2. Extraordinary Items and
     Cumulative Effect              AEP, APCo, CPL, CSPCo, OPCo, SWEPCo, WTU

 3. Merger                          AEP, CPL, I&M, KPCo, PSO, SWEPCo, WTU

 4. Nuclear Plant Restart                   AEP, I&M

 5. Rate Matters                    AEP, APCo, CPL, PSO, SWEPCo, WTU

 6. Effects of Regulation           AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo, PSO, SWEPCo, WTU

 7. Customer Choice and Industry
     Restructuring                  AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO,
                                    SWEPCo, WTU

 8. Commitments and Contingencies   AEP, AEGCo, APCo, CPL, CSPCo, I&M,
                                    KPCo, OPCo, PSO, SWEPCo, WTU

 9. Acquisitions and Dispositions   AEP, OPCo, SWEPCo

10. Benefit Plans                   AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo,
                                    PSO, SWEPCo, WTU

11. Stock-Based Compensation        AEP

12. Business Segments               AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo, PSO, SWEPCo, WTU

13. Risk Management, Financial      AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
     Instruments and Derivatives    OPCo, PSO, SWEPCo, WTU

14. Income Taxes                    AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo, PSO, SWEPCo, WTU

15. Basic and Diluted Earnings
     Per Share                      AEP

16. Supplementary Information       AEP, APCo, CSPCo, I&M, OPCo

17. Power, Distribution and
     Communications Projects        AEP

18. Leases                          AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo, PSO, SWEPCo, WTU

19. Lines of Credit and Sale
     of Receivables                 AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo, PSO, SWEPCo, WTU


<PAGE>


20. Unaudited Quarterly Financial
     Information                    AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo, PSO, SWEPCo, WTU

21. Trust Preferred Securities      AEP, CPL, PSO, SWEPCo

22. Minority Interest in
     Finance Subsidiary             AEP

23. Jointly Owned Electric
     Utility Plant                  CPL, CSPCo, PSO, SWEPCo, WTU

24. Related Party Transactions      AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo, PSO, SWEPCo, WTU



<PAGE>


1. Significant Accounting Policies:

Business Operations - AEP's principal business conducted by its eleven domestic
electric utility operating companies is the generation, transmission and
distribution of electric power. Nine of AEP's eleven domestic electric utility
operating companies, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU, are
SEC registrants. AEGCo is a domestic generating company wholly-owned by AEP that
is an SEC registrant. These companies are subject to regulation by the FERC
under the Federal Power Act and follow the Uniform System of Accounts prescribed
by FERC. They are subject to further regulation with regard to rates and other
matters by state regulatory commissions.

AEP also engages in wholesale marketing and trading of electricity, natural gas
and to a lesser extent coal, oil, natural gas liquids and emission allowances in
the United States and Europe. In addition the Company's domestic operations
includes non-regulated independent power and cogeneration facilities, coal
mining and intra-state midstream natural gas operations in Louisiana and Texas.

International operations include regulated supply and distribution of
electricity and other non-regulated power generation projects in the United
Kingdom, Australia, Mexico, South America and China.

The Company also operates domestic barging, provides energy services worldwide
and furnishes communications related services domestically.

Rate Regulation - AEP is subject to regulation by the SEC under the PUHCA. The
rates charged by the domestic utility subsidiaries are approved by the FERC and
the state utility commissions. The FERC regulates wholesale electricity
operations and transmission rates and the state commissions regulate retail
rates. The prices charged by foreign subsidiaries located in the UK, Australia,
China, Mexico and Brazil are regulated by the authorities of that country and
are generally subject to price controls.


Principles of Consolidation - AEP's consolidated financial statements include
AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated
with their wholly-owned or substantially controlled subsidiaries. The
consolidated financial statements for APCo, CPL, CSPCo, I&M, OPCo, PSO and
SWEPCo include the registrant and its wholly-owned subsidiaries. Significant
intercompany items are eliminated in consolidation. Equity investments not
substantially controlled that are 50% or less owned are accounted for using the
equity method with their equity earnings included in Other Income for AEP and
nonoperating income for the registrant subsidiaries.

Basis of Accounting - As the owner of cost-based rate-regulated electric public
utility companies, AEP Co., Inc.'s consolidated financial statements reflect the
actions of regulators that result in the recognition of revenues and expenses in
different time periods than enterprises that are not rate regulated. In
accordance with SFAS 71, "Accounting for the Effects of Certain Types of
Regulation," regulatory assets (deferred expenses) and regulatory liabilities
(future revenue reductions or refunds) are recorded to reflect the economic
effects of regulation by matching expenses with their recovery through regulated
revenues. Application of SFAS 71 for the generation portion of the business was
discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in
Virginia and West Virginia by APCo in June 2000, in Texas by CPL, WTU, and
SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note
7, "Customer Choice and Industry Restructuring" for additional information.

Use of Estimates - The preparation of these financial statements in conformity
with generally accepted accounting principles necessarily includes the use of
estimates and assumptions by management. Actual results could differ from those
estimates.

Property, Plant and Equipment - Domestic electric utility property, plant and
equipment are stated at original cost of the acquirer. Property, plant and
equipment of the non-regulated domestic operations and other investments are
stated at their fair market value at acquisition plus the original cost of
property acquired or constructed since the acquisition, less disposals.
Additions, major replacements and betterments are added to the plant accounts.
For cost-based rate regulated operations retirements from the plant accounts and
associated removal costs, net of salvage, are deducted from accumulated
depreciation. The costs of labor, materials and overheads incurred to operate
and maintain plant are included in operating expenses.

Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
- - AFUDC is a noncash nonoperating income item that is capitalized and recovered
through depreciation over the service life of domestic regulated electric
utility plant. It represents the estimated cost of borrowed and equity funds
used to finance construction projects. The amounts of AFUDC for 2001, 2000 and
1999 were not significant. Effective with the discontinuance of the application
of SFAS 71 regulatory accounting for domestic generating assets in Arkansas,
Ohio, Texas, Virginia and West Virginia and for other non-regulated operations,
interest is capitalized during construction in accordance with SFAS 34,
"Capitalization of Interest Costs." The amounts of interest capitalized were not
material in 2001, 2000, and 1999.



Depreciation, Depletion and Amortization - Depreciation of property, plant and
equipment is provided on a straight-line basis over the estimated useful lives
of property, other than coal-mining property, and is calculated largely through
the use of composite rates by functional class as follows:

                                          Annual Composite
Functional Class                         Depreciation Rates
of Property                                     Ranges
                                                 2001
Production:
  Steam-Nuclear                             2.5% to  3.4%
  Steam-Fossil-Fired                        2.5% to  4.5%
  Hydroelectric- Conventional
    and Pumped Storage                      1.9% to  3.4%
Transmission                                1.7% to  3.1%
Distribution                                2.7% to  4.2%
Other                                       1.8% to 15.0%

                                          Annual Composite
Functional Class                         Depreciation Rates
of Property                                     Ranges
                                                 2000
Production:
  Steam-Nuclear                             2.8% to  3.4%
  Steam-Fossil-Fired                        2.3% to  4.5%
  Hydroelectric- Conventional
    and Pumped Storage                      1.9% to  3.4%
Transmission                                1.7% to  3.1%
Distribution                                3.3% to  4.2%
Other                                       2.5% to  7.3%

                                          Annual Composite
Functional Class                         Depreciation Rates
of Property                                     Ranges
                                                 1999
Production:
  Steam-Nuclear                             2.8% to  3.4%
  Steam-Fossil-Fired                        3.2% to  5.0%
  Hydroelectric- Conventional
    and Pumped Storage                      1.9% to  3.4%
Transmission                                1.7% to  2.7%
Distribution                                2.8% to  4.2%
Other                                       2.0% to 20.0%


<PAGE>
<TABLE>
<CAPTION>
The following table provides the annual composite depreciation rates generally
used by the AEP registrant subsidiaries for the years 2001, 2000 and 1999 which
were as follows:

                   Nuclear         Steam         Hydro          Transmission            Distribution          General
                   -------         -----         -----          ------------            ------------          -------

<S>                     <C>           <C>           <C>                  <C>                     <C>              <C>
AEGCo                    - %          3.5%           - %                  - %                     - %             2.8%
APCo                     -            3.4           2.9                  2.2                     3.3              3.1
CPL                     2.5           2.5           1.9                  2.3                     3.5              4.0
CSPCo                    -            3.2            -                   2.3                     3.6              3.2
I&M                     3.4           4.5           3.4                  1.9                     4.2              3.8
KPCo                     -            3.8            -                   1.7                     3.5              2.5
OPCo                     -            3.4           2.7                  2.3                     4.0              2.7
PSO                      -            2.7            -                   2.3                     3.4              6.0
SWEPCo                   -            3.4            -                   2.7                     3.6              4.5
WTU                      -            2.8            -                   3.1                     3.3              6.6
</TABLE>

<PAGE>


Depreciation, depletion and amortization of coal-mining assets is provided over
each asset's estimated useful life or the estimated life of the mine, whichever
is shorter, and is calculated using the straight-line method for mining
structures and equipment. The units-of-production method is used to amortize
coal rights and mine development costs based on estimated recoverable tonnages
at a current average rate of $3.46 per ton in 2001, $5.07 per ton in 2000 and
$2.32 per ton in 1999. These costs are included in the cost of coal charged to
fuel expense.

Cash and Cash Equivalents - Cash and cash equivalents include temporary cash
investments with original maturities of three months or less.

Inventory - Except for CPL, PSO and WTU, the regulated domestic utility
companies value fossil fuel inventories using a weighted average cost method.
CPL, PSO and WTU, utilize the LIFO method to value fossil fuel inventories. For
those domestic utilities whose generation is unregulated, inventory of coal and
oil is carried at the lower of cost or market. Coal mine inventories are also
carried at the lower of cost or market. Natural gas inventories are
marked-to-market if held in connection with trading operations. Any non-trading
gas inventory is carried at the lower of cost or market.

Accounts Receivable - AEP Credit Inc. (formerly CSW Credit) factors accounts
receivable for the domestic utility subsidiaries and certain non-affiliated
utilities. On December 31, 2001 AEP Credit, Inc. entered into a sale of
receivables agreement with a group of banks and commercial paper conduits. This
transaction constitutes a sale of receivables in accordance with SFAS 140,
allowing the receivables to be taken off of the companies balances sheet. See
Note 19 for further details.

Foreign Currency Translation - The financial statements of subsidiaries outside
the U.S. which are included in AEP's consolidated financial statements are
measured using the local currency as the functional currency and translated into
U.S. dollars in accordance with SFAS 52 "Foreign Currency Translation". Assets
and liabilities are translated to U.S. dollars at year-end rates of exchange and
revenues and expenses are translated at monthly average exchange rates
throughout the year. Currency translation gain and loss adjustments are recorded
in shareholders' equity as "Accumulated Other Comprehensive Income (Loss)". The
non-cash impact of the changes in exchange rates on cash, resulting from the
translation of items at different exchange rates is shown on AEP's Consolidated
Statement of Cash Flows in "Effect of Exchange Rate Change on Cash." Actual
currency transaction gains and losses are recorded in income.

Deferred Fuel Costs - The cost of fuel consumed is charged to expense when the
fuel is burned. Where applicable under governing state regulatory commission
retail rate orders, fuel cost over or under-recoveries are deferred as
regulatory liabilities or regulatory assets in accordance with SFAS 71. These
deferrals generally are amortized when refunded or billed to customers in later
months with the regulator's review and approval. The amount of deferred fuel
costs under fuel clauses for AEP was $139 million at December 31, 2001 and $407
million at December 31, 2000. See also Note 6 "Effects of Regulation".

We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of
Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for
APCo. Where fuel clauses have been eliminated due to the transition to market
pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective
January 1, 2002) changes in fuel costs impact earnings. In other state
jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have
been frozen or suspended for a period of years, fuel cost changes also impact
earnings currently. This is also true for certain of AEP's Independent Power
Producer generating units that do not have long-term contracts for their fuel
supply. See Note 5, "Rate Matters" and Note 7, "Customer Choice and Industry
Restructuring" for further information about fuel recovery.

Revenue Recognition - We recognize revenues from foreign and domestic
generation, transmission and distribution of electricity, domestic gas pipeline
and storage services, other energy supply related business activities, as well
as domestic barging, telecommunications and related services. The revenues
associated with these activities are recorded when earned as physical
commodities are delivered to contractual meter points or services are provided.
These revenues also include the accrual of earned, but unbilled and/or not yet
metered revenues. Such revenues are based on contract prices or tariffs and
presented on a gross basis consistent with generally accepted accounting
principles and industry practice. Revenue recognition for energy marketing and
trading transactions is further discussed within the Energy Marketing and
Trading Transactions section below. The Company follows EITF 98-10 and marks to
market energy trading activities, which includes the net change in fair value of
open trading contracts in earnings. Mark-to-market gains and losses on open
contracts and net settlements of financial contracts (see below) are included in
revenues on a net basis. The net basis of reporting for open contracts is
permitted by EITF 98-10 and for settled financial contracts is consistent with
industry practice. Settled physical forward trading transactions are reported on
a gross basis, as permitted by EITF 98-10. Management believes that the gross
basis of reporting for settled physical forward trading contracts is a better
indication of the scope and significance of energy trading activities to the
Company.

Energy Marketing and Trading Transactions - AEP engages in wholesale electricity
and natural gas marketing and trading transactions (trading activities). Trading
activities inolve the purchase and sale of energy under forward contracts at
fixed and variable prices and the trading of financial energy contracts which
includes exchange futures and options and over-the-counter options and swaps.
Although trading contracts are generally short-term, there are long-term trading
contracts.

The majority of trading activities represent forward electricity and gas
contracts that are typically settled by entering into offsetting physical
contracts. Forward trading sale contracts are included in AEP's revenues when
the contracts settle. Forward trading purchase contracts are included in AEP's
fuel and purchased energy expenses when they settle. Prior to settlement the
change in fair values of forward sale and purchase contracts are included in
AEP's revenues.

All of the registrant subsidiaries except AEGCo participate in AEP's wholesale
marketing and trading of electricity. APCo, CSPCo, I&M, KPCo and OPCo record
forward electricity trading sale contracts in operating revenues when the
contracts settle for contracts with delivery points in AEP's traditional
marketing area and in nonoperating income for forward electricity trading sale
contracts outside AEP's traditional marketing area. APCo, CSPCo, I&M, KPCo and
OPCo record forward electricity trading purchase contracts in purchased power
expense when the contracts settle for contracts with delivery points in AEP's
traditional marketing area and in nonoperating expense for forward electricity
trading purchase contracts outside AEP's traditional marketing area. CPL, PSO,
SWEPCo and WTU record revenues from forward electricity trading sale contracts
in operating revenues. CPL, PSO, SWEPCo and WTU record purchased power expense
for forward electricity trading purchase contracts when they settle.

APCo, CSPCo and OPCo account for open forward electricity sale and purchase
contracts on a mark-to-market basis and include the mark-to-market change in
operating revenues for open contracts in AEP's traditional marketing area and in
nonoperating income for open contracts beyond AEP's traditional marketing area.

I&M and KPCo account for open forward electricity sale and purchase contracts on
a mark-to-market basis and defer the mark-to-market change as regulatory assets
or liabilities for those open contracts in AEP's traditional marketing area and
include the mark-to-market change in nonoperating income for open contracts
beyond AEP's traditional marketing area.

CPL, PSO, SWEPCo and WTU account for open forward electricity sale and purchase
contracts on a mark-to-market basis. CPL includes the mark-to-market change for
open electricity trading contracts in revenues. PSO defers as regulatory assets
or liabilities the mark-to-market change for open forward electricity trading
contracts that are included in cost of service on a settlement basis for
ratemaking purposes. SWEPCo and WTU include the jurisdictional share of the
mark-to-market change in revenues for open electricity trading contracts for
those jurisdictions that are not subject to SFAS 71 cost based rate regulation
and defer as regulatory assets or liabilities the jurisdictional share of the
mark-to-market change for open contracts that are included in cost of service on
a settlement basis for ratemaking purposes.

Trading purchases and sales through electricity and gas options, futures and
swaps, represent financial transactions with the net proceeds reported in AEP's
revenues at fair value upon entering the contracts.

APCo, CSPCo, I&M, KPCo and OPCo share in AEP's trading sales and purchases
through electricity options, futures and swaps, which represent financial
transactions. Changes in fair values of these financial contracts are reported
net in nonoperating income. When these contracts settle, the net proceeds are
recorded in nonoperating income and the prior unrealized gain or loss in
reversed.

Recording of the net changes in fair value of open trading contracts is commonly
referred to a mark-to-market accounting.

All open contracts from trading activities are marked to market in accordance
with EITF 98-10. Except as noted above, the net mark-to-market (change in fair
value) amount included in results of operations on a net discounted basis. The
fair values of open short-term trading contracts are based on exchange prices
and broker quotes. Open long-term trading contracts are marked to market based
mainly on AEP developed valuation models. The valuation models produce an
extimated fair value for open long-term trading contracts. The short-term and
long-term fair values are present valued and reduced by appropriate reserves for
counterparty credit risks and liquidity risk. The models are derived from
internally assessed market prices with the exception of the NYMEX gas curve,
where we use daily settled prices. Bid/ask price curves are developed for
inclusion in the model based on broker quotes and other available market data.
The curves are within the range between the bid and ask price. The end of the
month liquidity reserve is based on the difference in price between the price
curve and the bid side of the bid ask if we have a long position and the ask
side if we have a short position. This provides for a conservative valuation net
of the reserves. The use of these models to fair value open trading contracts
has inherent risks relating to the underlying assumptions employed by such
models. Independent controls are in place to evaluate the reasonableness of the
price curve models. Significant adverse or favorable effects on future results
of operations and cash flows could occur if market risks, at the time of
settlement, do not correlate with AEP developed price models.

The effect on AEP's Consolidated Statements of Income of marking to market open
electricity trading contracts in AEP's regulated jurisdictions is deferred as
regulatory assets or liabilities since these transactions are included in cost
of service on a settlement basis for ratemaking purposes. Unrealized
mark-to-market gains and losses from trading activities whether deferred or
recognized in revenues are part of Energy Trading and Derivative Contracts
assets or liabilities as appropriate.

Hedging and Related Activities - In order to mitigate the risks of market price
and interest rate fluctuations, AEP's foreign subsidiaries, SEEBOARD and
CitiPower, utilize interest swaps, and currency swaps to hedge such market
fluctuations. Changes in the market value of these swaps are deferred until the
gain or loss is realized on the underlying hedged asset, liability or commodity.
To qualify as a hedge, these transactions must be designated as a hedge and
changes in their fair value must correlate with changes in the price and
interest rate movement of the underlying asset, liability or commodity. This in
effect reduces AEP's exposure to the effects of market fluctuations related to
price and interest rates.

AEP, APCo, CSPCo, I&M, and OPCo enter into contracts to manage the exposure to
unfavorable changes in the cost of debt to be issued. These anticipatory debt
instruments are entered into in order to manage the change in interest rates
between the time a debt offering is initiated and the issuance of the debt
(usually a period of 60 days). Gains or losses from these transactions are
deferred and amortized over the life of the debt issuance with the amortization
included in interest charges. There were no such forward contracts outstanding
at December 31, 2001 or 2000. See Note 13 - "Risk Management, Financial
Instruments and Derivatives" for further discussion of the accounting for risk
management transactions.

Levelization of Nuclear Refueling Outage Costs - In order to match costs with
regulated revenues, incremental operation and maintenance costs associated with
periodic refueling outages at I&M's Cook Plant are deferred and amortized over
the period beginning with the commencement of an outage and ending with the
beginning of the next outage.

Maintenance Costs - Maintenance costs are expensed as incurred except where SFAS
71 requires the recordation of a regulatory asset to match the expensing of
maintenance costs with their recovery in cost based regulated revenues. See
below for an explanation of costs deferred in connection with an extended outage
at I&M's Cook Plant.

Amortization of Cook Plant Deferred Restart Costs - Pursuant to settlement
agreements approved by the IURC and the MPSC to resolve all issues related to an
extended outage of the Cook Plant, I&M deferred $200 million of incremental
operation and maintenance costs during 1999. The deferred amount is being
amortized to expense on a straight-line basis over five years from January 1,
1999 to December 31, 2003. I&M amortized $40 million in 2001, 2000 and 1999
leaving $80 million as an SFAS 71 regulatory asset at December 31, 2001 on the
Consolidated Balance Sheets of AEP and I&M.

Other Income and Other Expenses - Other Income includes equity earnings of
non-consolidated subsidiaries, gains on dispositions of property, interest and
dividends, an allowance for equity funds used during construction (explained
above) and various other non-operating and miscellaneous income. Other Expenses
includes losses on dispositions of property, miscellaneous amortization,
donations and various other non-operating and miscellaneous expenses.

Income Taxes - The AEP System follows the liability method of accounting for
income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the
liability method, deferred income taxes are provided for all temporary
differences between the book cost and tax basis of assets and liabilities which
will result in a future tax consequence. Where the flow-through method of
accounting for temporary differences is reflected in regulated revenues (that
is, deferred taxes are not included in the cost of service for determining
regulated rates for electricity), deferred income taxes are recorded and related
regulatory assets and liabilities are established in accordance with SFAS 71 to
match the regulated revenues and tax expense.

Investment Tax Credits - Investment tax credits have been accounted for under
the flow-through method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral basis.
Investment tax credits that have been deferred are being amortized over the life
of the regulated plant investment.

Excise Taxes - AEP and its subsidiary registrants, as an agent for a state or
local government, collect from customers certain excise taxes levied by the
state or local government upon the customer. These taxes are not recorded as
revenue or expense, but only as a pass-through billing to the customer to be
remitted to the government entity. Excise tax collections and payments related
to taxes imposed upon the customer are not presented in the income statement.

Debt and Preferred Stock - Gains and losses from the reacquisition of debt used
to finance domestic regulated electric utility plant are generally deferred and
amortized over the remaining term of the reacquired debt in accordance with
their rate-making treatment. If debt associated with the regulated business is
refinanced, the reacquisition costs attributable to the portions of the business
that are subject to cost based regulatory accounting under SFAS 71 are generally
deferred and amortized over the term of the replacement debt commensurate with
their recovery in rates. Gains and losses on the reacquisition of debt for
operations not subject to SFAS 71 are reported as a component of net income.

Debt discount or premium and debt issuance expenses are deferred and amortized
over the term of the related debt, with the amortization included in interest
charges.

Where rates are regulated redemption premiums paid to reacquire preferred stock
of the domestic utility subsidiaries are included in paid-in capital and
amortized to retained earnings commensurate with their recovery in rates. The
excess of par value over costs of preferred stock reacquired is credited to
paid-in capital and amortized to retained earnings consistent with the timing of
its inclusion in rates in accordance with SFAS 71.

Goodwill and Intangible Assets - The amount of acquisition cost in excess of the
fair value allocated to tangible and identifiable intangible assets obtained
through an acquisition accounted for as a purchase combination is recorded as
goodwill on AEP's consolidated balance sheet. Goodwill recognized in connection
with purchase combinations acquired after June 30, 2001 was determined in
accordance with SFAS 141 "Business Combinations." (see also Note 9,
"Acquisitions and Dispositions"). For goodwill associated with purchase
combinations before July 1, 2001, amortization is on a straight-line basis
generally over 40 years except for the portion of goodwill associated with gas
trading and marketing activities which is being amortized on a straight-line
basis over 10 years. Accumulated amortization of goodwill was $199 million and
$166 million at December 31, 2001 and 2000, respectively. In accordance with
SFAS 142, "Goodwill and Other Intangible Assets," goodwill acquired after June
30, 2001 is not subject to amortization. The amortization of goodwill which
predates July 1, 2001 ceased on December 31, 2001.

SFAS 142 requires that other intangible assets be separately identified and if
they have finite lives they must be amortized over that life. Other intangible
assets of $441 million net of accumulated amortization of $38 million at
December 31, 2001 are included in other assets and represent retail and
wholesale distribution licenses for CitiPower operating franchises which are
currently being amortized on a straight-line basis over 20 and 40 years,
respectively.

Also SFAS 142 provides that goodwill and other intangible assets with indefinite
lives be tested for impairment annually and not be subjected to amortization.
For AEP's goodwill recognized prior to July 1, 2001 and other intangible assets,
these requirements will apply beginning January 1, 2002. For the year 2001, the
amortization of goodwill reduced AEP's net income by $50 million. AEP is still
evaluating the impact of adopting the impairment tests required by SFAS 142.

Nuclear Trust Funds - Nuclear decommissioning and spent nuclear fuel trust funds
represent funds that regulatory commissions have allowed us to collect through
rates to fund future decommissioning and spent fuel disposal liabilities. By
rules or orders, the state jurisdictional commissions (Indiana, Michigan and
Texas) and the FERC established investment limitations and general risk
management guidelines to protect their ratepayers' funds and to allow those
funds to earn a reasonable return. In general, limitations include:

o        Acceptable investments (rated investment grade or above)
o        Maximum percentage invested in a specific type of investment
o        Prohibition of investment in obligations of the applicable company or
         its affiliates.

Trust funds are maintained for each regulatory jurisdiction and managed by
investment managers, who must comply with the guidelines and rules of the
applicable regulatory authorities. The trust assets are invested in order to
optimize the after-tax earnings of the Trust, giving consideration to liquidity,
risk, diversification, and other prudent investment objectives.

Securities held in trust funds for decommissioning nuclear facilities and for
the disposal of spent nuclear fuel are included in Other Assets at market value
in accordance with SFAS 115, "Accounting for Certain Investments in Debt and
Equity Securities." Securities in the trust funds have been classified as
available-for-sale due to their long-term purpose. In accordance with SFAS 71,
unrealized gains and losses from securities in these trust funds are not
reported in equity but result in adjustments to the liability account for the
nuclear decommissioning trust funds and to regulatory assets or liabilities for
the spent nuclear fuel disposal trust funds in accordance with their treatment
in rates.

Comprehensive Income - Comprehensive income is defined as the change in equity
(net assets) of a business enterprise during a period from transactions and
other events and circumstances from non-owner sources. It includes all changes
in equity during a period except those resulting from investments by owners and
distributions to owners. Comprehensive income has two components, net income and
other comprehensive income. There were no material differences between net
income and comprehensive income for AEGCo, CPL, CSPCo, PSO, SWEPCo and WTU.

Components of Other Comprehensive Income - Other comprehensive income is
included on the balance sheet in the equity section. The following table
provides the components that comprise the balance sheet amount in Accumulated
Other Comprehensive Income for AEP.

                                           December 31,
   Components                        2001     2000     1999
- -----------------------------------------------------------
                                 (millions)
Foreign Currency
 Adjustments                       $(113)    $ (99)    $ 20
Unrealized Losses
 On Securities                        -         -       (20)
Unrealized Gain on
 Hedged Derivatives                   (3)       -        -
Minimum Pension                      (10)       (4)      (4)
                                     ---        --       --
 Liability
                                   $(126)    $(103)    $ (4)
                                   =====     =====     ====


Accumulated Other Comprehensive Income for AEP registrant subsidiaries as of
December 31, 2001, is shown in the following table. Registrant subsidiary
balances for Accumulated Other Comprehensive Income for the two years ended
December 31, 2000 and 1999 were zero.


                                  December 31,
   Components                          2001
- ---------------------------------------------
                                   (thousands)
Foreign Currency Rate Hedge
APCo                                   $ (340)
I&M                                    (3,835)
KPCo                                   (1,903)
OPCo                                     (196)

Segment Reporting - The AEP System has adopted SFAS No. 131, which requires
disclosure of selected financial information by business segment as viewed by
the chief operating decision-maker. See Note 12 "Business Segments" for further
discussion and details regarding segments.

Common Stock Options - AEP follows Accounting Principles Board Opinion 25 to
account for stock options. Compensation expense is not recognized at the date of
grant or when exercised, because the exercise price of stock options awarded
under the stock option plan equals the market price of the underlying stock on
the date of grant.

EPS - AEP's basic earnings per share is determined based upon the weighted
average number of common shares outstanding during the years presented. Diluted
earnings per share for AEP is based upon the weighted average number of common
shares and stock options outstanding during the years presented. Basic and
diluted EPS are the same in 2001, 2000 and 1999.

AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, and WTU are wholly-owned
subsidiaries of AEP and are not required to report EPS.

Reclassification - Certain prior year financial statement items have been
reclassified to conform to current year presentation. Such reclassification had
no impact on previously reported net income. Certain settled forward energy
transactions of the trading operation were reclassified from a net to a gross
basis of presentation in order to better reflect the scope and nature of the AEP
System's energy sales and purchases. All financially net settled trading
transactions, such as swaps, futures, and unexercised options, and all
marked-to-market values on open trading contracts continue to be reported on a
net basis, reflecting the financial nature of these transactions. As applicable,
prior year amounts of realized physical purchases from settled purchase trading
contracts were reclassified from revenues to purchased power expense to present
the prior period on a comparable gross basis.

2. Extraordinary Items and Cumulative Effect:

Extraordinary Items - Extraordinary items were recorded for the discontinuance
of regulatory accounting under SFAS 71 for the generation portion of the
business in the Ohio, Virginia, West Virginia, Texas and Arkansas state
jurisdictions. See Note 7 "Customer Choice and Industry Restructuring" for
descriptions of the restructuring plans and related accounting effects. OPCo and
CSPCo recognized an extraordinary loss for stranded Ohio Public Utility Excise
Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal
credits during the quarter ended June 30, 2001. This loss resulted from
regulatory decisions in connection with Ohio deregulation which stranded the
recovery of the GRT. Effective with the liability affixing on May 1, 2001, CSPCo
and OPCo recorded an extraordinary loss under SFAS 101. Both Ohio companies have
appealed to the Ohio Supreme Court the PUCO order on Ohio restructuring that the
Ohio companies believe failed to provide for recovery for the final year of the
GRT. The Ohio Supreme Court decision is expected in 2002.

In October 2001 CPL reacquired $101 million of pollution control bonds in
advance of their maturity. Since these pollution control bonds were used to
finance generation assets, a loss of $2 million after tax was recorded.

The following table shows the components of the extraordinary items reported on
the consolidated statements of income:

                                  Year Ended
                                 December 31,
                               2001  2000  1999
                               ----  ----  ----
                                 (in millions)
Extraordinary Items:
 Discontinuance of Regulatory
 Accounting for Generation:
  Ohio Jurisdiction (Net of Tax
  of $20 million in 2001 and
  $35 Million in 2000)         $(48) $(44) $  -
  Virginia and West Virginia
   Jurisdictions (Inclusive of
   Tax Benefit of $8 Million)     -     9     -
  Texas and Arkansas
   Jurisdictions (Net of Tax
   of $5 Million)                 -     -    (8)
 Loss on Reacquired Debt
 (Net of Tax of $1 Million
  in 2001 and $3 Million
  in 1999)                        (2)  -     (6)
                                ---- ----  ----

  Extraordinary Items           $(50)$(35) $(14)
                                ==== ====  ====

Cumulative Effect of Accounting Change - The FASB's Derivative Implementation
Group (DIG) issued accounting guidance under SFAS 133 for certain derivative
fuel supply contracts with volumetric optionality and derivative electricity
capacity contracts. This guidance, effective in the third quarter of 2001,
concluded that fuel supply contracts with volumetric optionality cannot qualify
for a normal purchase or sale exclusion from mark-to-market accounting and
provided guidance for determining when electricity capacity contracts can
qualify as a normal purchase or sale.

Predominantly all of AEP's fuel supply contracts for coal and gas and contracts
for electricity capacity, which are recorded on a settlement basis, do not meet
the criteria of a financial derivative instrument or qualify as a normal
purchase or sale. Therefore, AEP's contracts are generally exempt from the DIG
guidance described above. Beginning July 1, 2001, the effective date of the DIG
guidance, certain of AEP's fuel supply contracts with volumetric optionality
that qualify as financial derivative instruments are marked to market with any
gain or loss recognized in the income statement. The effect of initially
adopting the DIG guidance at July 1, 2001, for AEP is a favorable earnings
mark-to-market effect of $18 million, net of tax of $2 million, is reported as a
cumulative effect of an accounting change on the income statement.



<PAGE>


3. Merger:

On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned
subsidiary of AEP. Under the terms of the merger agreement, approximately 127.9
million shares of AEP Common Stock were issued in exchange for all the
outstanding shares of CSW Common Stock based upon an exchange ratio of 0.6 share
of AEP Common Stock for each share of CSW Common Stock. Following the exchange,
former shareholders of AEP owned approximately 61.4 percent of the corporation,
while former CSW shareholders owned approximately 38.6 percent of the
corporation.

The merger was accounted for as a pooling of interests. Accordingly, AEP's
consolidated financial statements give retroactive effect to the merger, with
all periods presented as if AEP and CSW had always been combined. Certain
reclassifications have been made to conform the historical financial statement
presentation of AEP and CSW.

The following table sets forth revenues, extraordinary items and net income
previously reported by AEP and CSW and the combined amounts shown in the
accompanying financial statements for 1999:

                         Year Ended December 31,
                                   1999
                                   ----
                              (in millions)
Revenues:
 AEP                              $19,229
 CSW                                5,516
                                  -------
 AEP After Pooling                $24,745
                                  =======
Extraordinary Items:
 AEP                                 $ -
 CSW                                  (14)
                                     ----
 AEP After Pooling                   $(14)
                                     ====
Net Income:
 AEP                                 $520
 CSW                                  455
 Conforming Adjustment                 (3)
                                     ----
 AEP After Pooling                   $972
                                     ====

The combined financial statements include an adjustment to conform CSW's
accounting for vacation pay accruals with AEP's accounting. The effect of the
conforming adjustment was to reduce net assets by $16 million at December 31,
1999 and reduce net income by $3 million for the year ended December 31, 1999.


The following table shows the vacation accrual conforming adjustment for CSW's
registrant utility subsidiaries:

                              Net Income
                              Reductions
             Net Asset        Year Ended
            Reduction at     December 31,
           December 31, 1999       1999
           -----------------       ----
                       (in millions)
CPL              $5.3              $0.7
PSO               2.8               1.1
SWEPCo            4.5               0.5
WTU               2.6               0.4

In connection with the merger, $21 million ($14 million after tax) and $203
million ($180 million after tax) of non-recoverable merger costs were expensed
in 2001 and 2000. Such cost included transaction and transition costs not
recoverable from ratepayers. Also included in the merger costs were
non-recoverable change in control payments. Merger transaction and transition
costs of $51 million recoverable from ratepayers were deferred pursuant to state
regulator approved settlement agreements through December 31, 2001. The deferred
merger costs are being amortized over five to eight year recovery periods,
depending on the specific terms of the settlement agreements, with the
amortization ($8 million and $4 million for the years 2001 and 2000) included in
depreciation and amortization expense.

The following tables show the deferred merger cost and amortization expense of
the applicable subsidiary registrants:

                              Amortization
            Merger Cost       Expense for the
            Deferral at       Year Ended
           December 31, 2000    December 31, 2000
           -----------------    -----------------
                           (in millions)
CPL              $14.4               $1.3
I&M                6.9                0.7
KPCo               2.5                0.3
PSO                7.9                0.5
SWEPCo             6.1                0.5
WTU                4.2                0.4

                              Amortization
            Merger Cost       Expense for the
            Deferral at       Year Ended
           December 31, 2001    December 31, 2001
           -----------------    -----------------
                           (in millions)
CPL              $11.8               $2.6
I&M                9.1                1.7
KPCo               3.2                0.6
PSO                6.6                1.2
SWEPCo             5.0                1.1
WTU                3.5                0.8



<PAGE>


Merger transition costs are expected to continue to be incurred for several
years after the merger and will be expensed or deferred for amortization as
appropriate. As hereinafter summarized, the state settlement agreements provide
for, among other things, a sharing of net merger savings with certain regulated
customers over periods of up to eight years through rate reductions which began
in the third quarter of 2000.

Summary of key provisions of Merger Rate Agreements:

State/Company              Ratemaking Provisions
- -------------              ---------------------
Texas - CPL, SWEPCo        $221 million rate reduction
 WTU                       over 6 years. No base rate increases for 3 years post
                           merger.
Indiana - I&M              $67 million rate reduction
                           over 8 years.  Extension of
                           base rate freeze until
                           January 1, 2005.  Requires
                           additional annual deposits of
                           $6 million to the nuclear
                           decommissioning  trust  fund  for
                           the years 2001 through 2003.
Michigan                   - I&M Customer billing credits of approximately $14
                           million over 8 years. Extension of base rate freeze
                           until January 1, 2005.
Kentucky                   - KPCo Rate reductions of approximately $28 million
                           over 8 years. No base rate increases for 3 years post
                           merger.
Oklahoma                   - PSO Rate reductions of approximately $28 million
                           over 5 years. No base rate increase before January 1,
                           2003.
Arkansas - SWEPCo          Rate reductions of $6 million
                           over 5 years.
Louisiana                  - SWEPCo Rate reductions of $18 million over 8 years.
                           Base rate cap until June 2005.

If actual merger savings are significantly less than the merger savings rate
reductions required by the merger settlement agreements in the eight-year period
following consummation of the merger, future results of operations, cash flows
and possibly financial condition could be adversely affected.

The current annual dividend rate per share of AEP common stock is $2.40. The
dividends per share reported on the statements of income for 2000 and 1999
represent pro forma amounts and are based on AEP's historical annual dividend
rate of $2.40 per share. If the dividends per share reported for prior periods
were based on the sum of the historical dividends declared by AEP and CSW, the
annual dividend rate would be $2.60 per combined share for the year ended
December 31, 1999.

See Note 8, "Commitments and Contingencies" for information on a recent court
decision concerning the merger.

  4. Nuclear Plant Restart:

  I&M completed the restart of both units of the Cook Plant in 2000. Cook Plant
  is a 2,110 MW two-unit plant owned and operated by I&M under licenses granted
  by the NRC. I&M shut down both units of the Cook Plant in September 1997 due
  to questions regarding the operability of certain safety systems that arose
  during a NRC architect engineer design inspection.

  Settlement agreements in the Indiana and Michigan retail jurisdictions that
  address recovery of Cook Plant related outage costs were approved in 1999. The
  IURC approved a settlement agreement that resolved all matters related to the
  recovery of replacement energy fuel costs and all outage/restart costs and
  related issues during the extended outage of the Cook Plant. The MPSC approved
  a settlement agreement for two open Michigan power supply cost recovery
  reconciliation cases that resolved all issues related to the Cook Plant
  extended outage. The settlement agreements allowed:

o    deferral of $200 million of non-fuel restart-related nuclear operation and
     maintenance expense for amortization over five years ending December 31,
     2003,
o    deferral of certain unrecovered fuel and power supply costs for
     amortization over five years ending December 31, 2003,
o    a freeze in base rates through December 31, 2003 and a fixed fuel recovery
     charge through March 1, 2004 in the Indiana jurisdiction, and
o    a freeze in base rates and fixed power supply costs recovery factors until
     January 1, 2004 for the Michigan jurisdiction.



<PAGE>


The amounts of restart costs charged to other operation and maintenance expenses
were as follows:

                                Year Ended December 31,
                                    2001     2000     1999
                                    ----     ----     ----

Costs Incurred                       $ 1     $297     $ 289
Deferred Pursuant to
 Settlement Agreements                -        -       (200)
Amortization of Deferrals             40       40        40
                                   -  --   --  --   ---  --

Charged to O&M Expense               $41     $337     $ 129
                                     ===     ====     =====

At December 31, 2001 and 2000, deferred restart costs of $80 million and $120
million, respectively, remained in regulatory assets to be amortized through
2003. Also pursuant to the settlement agreements, accrued fuel-related revenues
of $38 million in 2001 and 2000 and $37 million in 1999 were amortized. At
December 31, 2001 and 2000, fuel-related revenues of $75 million and $113
million, respectively, were included in regulatory assets and will be amortized
through December 31, 2003 for both jurisdictions.

The amortization of restart costs and fuel-related revenues deferred under
Indiana and Michigan retail jurisdictional settlement agreements will adversely
affect results of operations through December 31, 2003 when the amortization
period ends. The annual amortization of restart cost and fuel-related revenue
deferrals is $78 million.

5. Rate Matters:

Texas Jurisdictional Fuel Filings - AEP's Texas electric operating companies
experienced significant natural gas price increases in the second half of 2000
and early 2001 which resulted in under-recovery of fuel costs and the need to
seek increases in fuel rates and surcharges to recover these under-recoveries.
During 2001 gas price declines and PUCT-approved fuel rate and fuel surcharge
increases resulted in lower unrecovered fuel balances for SWEPCo and WTU and an
overrecovered balance for CPL at the end of 2001.

Fuel recovery for Texas utilities is a multi-step procedure. When fuel costs
change, utilities file with the PUCT for authority to adjust fuel factors. If a
utility's prior fuel factors result in an over- or under-recovery of fuel, the
utility will also request a surcharge factor to refund or collect that amount.
While fuel factors are intended to recover all fuel-related costs, final
settlement of these accounts are subject to reconciliation and approval by the
PUCT.

Fuel reconciliation proceedings determine whether fuel costs incurred and
collected during the reconciliation period were reasonable and necessary. All
fuel costs incurred since the prior reconciliation date are subject to PUCT
review and approval. If material amounts are determined to be unreasonable and
ordered to be refunded to customers, results of operations and cash flows would
be negatively impacted.

According to Texas Restructuring Legislation, fuel cost in the Texas
jurisdiction after 2001 will no longer be subject to PUCT review and
reconciliation. During 2002 CPL and WTU will file final fuel reconciliations
with the PUCT to reconcile their fuel costs through the period ending December
31, 2001. The ultimate recovery of deferred fuel balances at December 31, 2001
will be decided as part of their 2004 true-up proceedings. If the final
under-recovered fuel balances or any amounts incurred but not yet reconciled are
disallowed, it would have a negative impact on results of operations and cash
flows.

In October 2001 the PUCT delayed the start of customer choice in the SPP area of
Texas. All of SWEPCo's Texas service territory and a small portion of WTU's
service territory are in the SPP. SWEPCo's fuel cost recovery procedures will
continue until competition begins. SWEPCo will continue to set fuel factors and
determine final fuel costs in fuel reconciliation proceedings during the SPP
delay period. The PUCT has ruled that WTU fuel factors in the SPP area will be
based upon the price to beat fuel factors offered by the WTU retail electric
provider in the ERCOT portion of WTU's service territory. The PUCT has initiated
a proceeding to determine the most appropriate method to reconcile fuel costs in
WTU's SPP area.



<PAGE>


The following table lists the status of Texas jurisdictional reconciliation,
fuel cost subject to reconciliation and under(over)-recovered fuel balances:

                                     Fuel cost subject
                                     to reconciliation
              Reconciliation         at December 31, 2001
              completed through


Company

CPL           June 30, 1998          $1.6 billion
SWEPCo        December 31, 1999       314 million
WTU           June 30, 2000           303 million

              Under (Over)
              -recovered fuel
              balances at
Company       December 31, 2001

CPL           $(58) million
SWEPCo           7  million
WTU             34  million

During 2001 CPL, SWEPCo and WTU requested and received approval to increase
their fuel rates. In orders issued in 2001 the PUCT delayed consideration of
fuel surcharges for CPL and WTU to recover their underrecovered fuel until the
2004 true-up proceedings. CPL's net underrecovered position was eliminated
between the order date and year end 2001 as gas prices declined. For SWEPCo the
PUCT deferred $6.8 million of Texas jurisdictional unrecovered fuel for
consideration in a future proceeding.

Under Texas restructuring, newly organized retail electric providers will make
sales to consumers beginning January 1, 2002. These sales will be at fixed rates
during a transition period from 2002 through 2006. However, the fuel cost
component of a retail electric providers' fixed rates will be subject to
prospective adjustment twice a year based upon changes in a natural gas price
index. As part of the preparation for customer choice, CPL, SWEPCo and WTU filed
their proposed fuel factors to be implemented as part of the fixed rates
effective January 1, 2002. Fuel factors approved for CPL's and WTU's retail
electric providers were effective January 1, 2002. Due to the SPP area
competition delay, SWEPCo's proceeding was postponed.

WTU Fuel Filings - In December 2000 WTU filed with the PUCT an application to
reconcile fuel costs. During the reconciliation period of July 1, 1997 through
June 30, 2000, WTU incurred $348 million of Texas jurisdiction eligible fuel and
fuel-related expenses. In February 2002 the PUCT approved WTU's fuel cost for
the reconciliation period except for a disallowance of less than $50,000.

Texas Transmission Rates - On June 28, 2001, the Supreme Court of Texas ruled
that the transmission pricing mechanism created by the PUCT in 1996 was invalid.
The court upheld an appeal filed by unaffiliated Texas utilities that the PUCT
exceeded its statutory authority to set such rates for the period January 1,
1997 through August 31, 1999. Effective September 1, 1999, the legislature
granted this authority to the PUCT. CPL and WTU were not parties to the case.
However, the companies' transmission sales and purchases were priced using the
invalid rates. It is unclear what action the PUCT will take to respond to the
court's ruling. If the PUCT changes rates retroactively, the result could have a
material impact on results of operations and cash flows for CPL and WTU.

FERC Wholesale Fuel Complaints - In May 2000 certain WTU wholesale customers
filed a complaint with FERC alleging that WTU had overcharged them through the
fuel adjustment clause for certain purchased power costs related to 1999
unplanned outages at WTU's Oklaunion generation station. In November 2001
certain WTU wholesale customers filed an additional complaint at FERC asserting
that since 1997 WTU had billed wholesale customers for not only the 1999
Oklaunion outage costs, but also certain additional costs that are not
permissible under the fuel adjustment clause.

In December 2001 FERC issued an order requiring WTU to refund, with interest,
amounts associated with the May 2000 complaint that were previously billed to
wholesale customers. The effects of this order were recorded in 2001 and
management believes that as of December 31, 2001, it has fully provided for that
over billing. In response to the November 2001 complaint, management is working
to determine amounts of additional costs inappropriately billed to wholesale
customers, which could result in refunds, with interest. At this time,
management is unable to predict the negative impact this complaint will have on
future results of operations, cash flow and financial condition.



<PAGE>


FERC Transmission Rates - In November 2001 FERC issued an order requiring CPL,
PSO, SWEPCo and WTU to submit revised open access transmission tariffs, and
calculate and issue refunds for overcharges from January 1, 1997. The order
resulted from a remand by an appeals court of a tariff compliance filing order
issued in November 1998 that had been appealed by certain customers. CPL and WTU
recorded refund provisions of $1.7 million and $0.7 million, respectively,
including interest in 2001 for this order. PSO and SWEPCo recorded $100,000 each
for this order making the AEP total $2.6 million.

West Virginia - On June 2, 2000, the WVPSC approved a Joint Stipulation between
APCo and other parties related to base rates and ENEC recoveries. The Joint
Stipulation allows for recovery of regulatory assets including any
generation-related regulatory assets through the following provisions:
o     Frozen transition rates and a wires charge of 0.5 mills per KWH.
o     The retention, as a regulatory liability, on the books of a net cumulative
      deferred ENEC over-recovery balance of $66 million to be used to offset
      the cost of deregulation when generation is deregulated in WV.
o     The retention of net merger savings prior to December 31, 2004 resulting
      from the merger of AEP and CSW.
o     A 0.5 mills per KWH wires charge for departing customers provided for in
      the WV Restructuring Plan (see Note 7 "Customer Choice and Industry
      Restructuring" for discussion of the WV Restructuring Plan)

Management expects that the approved Joint Stipulation, plus the provisions of
pending restructuring legislation will, if the legislation becomes effective,
provide for the recovery of existing regulatory assets, other stranded costs and
the cost of deregulation in WV.


6. Effects of Regulation:

In accordance with SFAS 71 the consolidated financial statements include
regulatory assets (deferred expenses) and regulatory liabilities (deferred
revenues) recorded in accordance with regulatory actions in order to match
expenses and revenues from cost-based rates in the same accounting period.
Regulatory assets are expected to be recovered in future periods through the
rate-making process and regulatory liabilities are expected to reduce future
cost recoveries. Among other things, application of SFAS 71 requires that the
AEP System's regulated rates be cost-based and the recovery of regulatory assets
be probable. Management has reviewed all the evidence currently available and
concluded that the requirements to apply SFAS 71 continue to be met for all
electric operations in Indiana, Kentucky, Louisiana, Michigan, Oklahoma and
Tennessee.

When the generation portion of the Company's business in Arkansas, Ohio, Texas,
Virginia and WV no longer met the requirements to apply SFAS 71, net regulatory
assets were written off for that portion of the business unless they were
determined to be recoverable as a stranded cost through regulated distribution
rates or wire charges in accordance with SFAS 101 and EITF 97-4. In the Ohio and
WV jurisdictions generation-related regulatory assets that are recoverable
through transition rates have been transferred to the distribution portion of
the business and are being amortized as they are recovered through charges to
regulated distribution customers. As discussed in Note 7, "Customer Choice and
Industry Restructing" the Virginia SCC ordered the generation-related regulatory
assets in the Virginia jurisdiction to remain with the generation portion of the
business. Generation-related regulatory assets in the Virginia jurisdiction are
being amortized concurrent with their recovery through capped rates. In the
Texas jurisdiction generation-related regulatory assets that have been
tentatively approved for recovery through securitization have been classified as
"regulatory assets designated for securitization." (See Note 7 "Customer Choice
and Industry Restructuring" for further details.)



<PAGE>


AEP's recognized regulatory assets and liabilities are comprised of the
following at:

                                              December 31,
                                           2001       2000
                                             (in millions)
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes                  $814       $914
  Transition - Regulatory
   Assets                                    847        963
  Regulatory Assets
   Designated for
   Securitization                            959        953
  Deferred Fuel Costs                        139        407
  Unamortized Loss on
   Reacquired Debt                            99        113
  Cook Plant Restart Costs                    80        120
  DOE Decontamination and
   Decommissioning
   Assessment                                 31         35
  Other                                      193        193
                                             ---        ---
Total Regulatory Assets                   $3,162     $3,698
                                          ======     ======

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                              $491       $528
  Other                                      393        208
                                             ---        ---
Total Regulatory Liabilities                $884       $736
                                            ====       ====




<PAGE>
<TABLE>
<CAPTION>
The recognized regulatory assets and liabilities for the registrant subsidiaries
are of two types: those earning a return and those not earning a return. Items
not earning a return have their recovery period end date indicated. Regulatory
assets and liabilities are comprised of the following items:

                                              AEGCo                           APCo
                                  -----------------------------   ----------------------------
                                                     Recovery                        Recovery
                                   2001      2000     Period       2001       2000     Period
                                   ----      ----    --------      ----       ----    --------
                                                        (in thousands)
<S>                             <C>       <C>        <C>          <C>      <C>       <C>
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes      $(22,725) $(23,996)  Note 1       $189,794 $217,540  Note 1
  Transition - Regulatory
   Assets Virginia                                                  46,981   55,523  Jun. 2007
  Transition - Regulatory
   Assets West Virginia                                            127,998  135,946  Jun. 2011
  Deferred Fuel Costs                                               11,732   14,669
  Unamortized Loss on
   Reacquired Debt                 5,207     5,504   Note 2         10,421   11,676  Note 2
  Deferred Storm Damage                                                  6    1,244  Apr. 2002
  Other                                                             71,890   11,152  Note 3
                                --------- --------                -------- --------
Total Regulatory Assets         $(17,518) $(18,492)               $458,822 $447,750
                                ========= =========               ======== ========

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                   $56,304   $59,718                $ 38,328 $ 43,093
  WV Rate Stabilization                                             75,601   75,601
  Other                                                             61,552    2,614
                                 -------   -------                -------- --------
Total Regulatory Liabilities     $56,304   $59,718                $175,481 $121,308
                                 =======   =======                ======== ========
</TABLE>
Note 1: This amount fluctuates from month to month and has no fixed recovery
        period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
        each registrant and ranges from one to thirty-seven years recovery
        period across all registrants.
Note 3: Other may include items not earning a return and would have various
        recovery periods.

<TABLE>
<CAPTION>
                                              CPL                            CSPCo
                                  -----------------------------   ----------------------------
                                                     Recovery                        Recovery
                                   2001      2000     Period       2001       2000     Period
                                   ----      ----    --------      ----       ----    --------
                                                        (in thousands)
<S>                            <C>        <C>         <C>          <C>      <C>       <C>
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes       $200,496 $  206,930  Note 1       $ 28,361 $ 31,853  Note 1
  Transition - Regulatory
   Assets                                                           223,830  247,852  Dec. 2008
  Excess Earnings                 (62,852)   (39,700)
  Regulatory Assets -
   Designated For Securitization  959,294    953,249
  Deferred Fuel Costs             (57,762)   127,295                   -        -
  Unamortized Loss on
   Reacquired Debt                 11,180     12,773  Note 2          7,010    8,340  Note 2
  DOE Decontamination and
   Decommissioning Assessment       3,170      3,622  Dec. 2004
  Other                            11,961     18,815  Note 3          3,066    3,508  Note 3
                               ---------- ----------               -------- --------
Total Regulatory Assets        $1,065,487 $1,282,984               $262,267 $291,553
                               ========== ==========               ======== ========

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                  $122,893    $128,100                $37,176  $41,234
  Other                                                                  31   11,510
                                --------    --------                -------  -------
Total Regulatory Liabilities    $122,893    $128,100                $37,207  $52,744
                                ========    ========                =======  =======
</TABLE>
Note 1: This amount fluctuates from month to month and has no fixed recovery
        period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
        each registrant and ranges from one to thirty-seven years recovery
        period across all registrants.
Note 3: Other may include items not earning a return and would have various
        recovery periods.


<PAGE>
<TABLE>
<CAPTION>
                                              I&M                             KPCo
                                  -----------------------------   ----------------------------
                                                     Recovery                        Recovery
                                   2001      2000     Period       2001       2000    Period
                                   ----      ----    --------      ----       ----   --------
                                                        (in thousands)
<S>                             <C>       <C>       <C>            <C>      <C>      <C>
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes      $171,605  $229,466  Note 1         $83,027  $85,926  Note 1
  Deferred Fuel Costs             75,002   112,503  Dec. 2003        1,542    -      Feb. 2002
  Unamortized Loss on
   Reacquired Debt                16,255    17,740  Note 2              51      459  Note 2
  Cook Plant Restart Costs        80,000   120,000  Dec. 2003
  DOE Decontamination and
   Decommissioning Assessment     27,784    31,744  Dec. 2008
  Other                           38,281    40,687  Note 3          13,073   12,130  Note 3
                                --------- --------                 -------  -------
Total Regulatory Assets         $408,927  $552,140                 $97,693  $98,515
                                ========= =========                =======  =======

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                  $105,449  $113,773                 $10,405  $11,656
  Other                           52,479     9,930                   6,551    3,172
                                --------  --------                 -------  -------
Total Regulatory Liabilities    $157,928  $123,703                 $16,956  $14,828
                                ========  ========                 =======  =======
</TABLE>
Note 1: This amount fluctuates from month to month and has no fixed recovery
        period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
        each registrant and ranges from one to thirty-seven years recovery
        period across all registrants.
Note 3: Other may include items not earning a return and would have various
        recovery periods.
<TABLE>
<CAPTION>
                                              OPCo                             PSO
                                  -----------------------------   ----------------------------
                                                     Recovery                        Recovery
                                   2001      2000     Period       2001       2000    Period
                                   ----      ----    --------      ----       ----   --------
                                                        (in thousands)
<S>                             <C>       <C>        <C>          <C>       <C>         <C>
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes      $186,740  $180,602   Note 1       $(26,085)  $(28,652)  Note 1
  Transition - Regulatory
   Assets                        442,707   517,851   Dec. 2007
  Deferred Fuel Costs                                               11,732     43,267
  Unamortized Loss on
   Reacquired Debt                 5,502     6,106   Note 2         12,321     13,600   Note 2
  Other                            9,676    10,151   Note 3         11,707     15,738   Note 3
                                --------- --------                --------  ---------
Total Regulatory Assets         $644,625  $714,710                $  9,675  $  43,953
                                ========= ========                ========  =========

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                   $21,925   $25,214                 $33,992    $35,783
  Other                            1,237    10,994                  31,858      2,015
                                 -------   -------                 -------    -------
Total Regulatory Liabilities     $23,162   $36,208                 $65,850    $37,798
                                 =======   =======                 =======    =======
</TABLE>
Note 1: This amount fluctuates from month to month and has no fixed recovery
        period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
        each registrant and ranges from one to thirty-seven years recovery
        period across all registrants.
Note 3: Other may include items not earning a return and would have various
        recovery periods.

<TABLE>
<CAPTION>
                                             SWEPCo                            WTU
                                  -----------------------------   ----------------------------
                                                     Recovery                        Recovery
                                   2001      2000     Period       2001       2000    Period
                                   ----      ----    --------      ----       ----   --------
                                                        (in thousands)
<S>                              <C>       <C>       <C>          <C>      <C>        <C>
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes       $16,553   $14,558   Note 1       $(13,591)$(13,493)  Note 1
  Deferred Fuel Costs              7,384    35,469                  36,872   67,655
  Unamortized Loss on
   Reacquired Debt                19,726    22,626   Note 2          8,198   11,204   Note 2
  Other                           15,711    19,898   Note 3          5,460   13,604   Note 3
                                 -------   -------                -------- --------
Total Regulatory Assets          $59,374   $92,551                $ 36,939 $ 78,970
                                 =======   ========               ======== ========

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                   $48,714   $53,167                 $22,781  $24,052
  Excess Earnings                              500                  17,300   15,100
  Other                           15,454     8,140                   5,700    -
                                 -------   -------                 -------  -------
Total Regulatory Liabilities     $64,168   $61,807                 $45,781  $39,152
                                 =======   =======                 =======  =======
</TABLE>
Note 1: This amount fluctuates from month to month and has no fixed recovery
        period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
        each registrant and ranges from one to thirty-seven years recovery
        period across all registrants.
Note 3: Other may include items not earning a return and would have various
        recovery periods.

<PAGE>


7. Customer Choice and Industry
    Restructuring:

Prior to 2001 customer choice/industry restructuring legislation was passed in
Ohio, Texas, Virginia and Michigan allowing retail customers to select
alternative generation suppliers. Customer choice began on January 1, 2001 in
Ohio and on January 1, 2002 in Michigan, Virginia and in the ERCOT area of
Texas. AEP's subsidiaries operate in both the ERCOT and SPP areas of Texas.

Legislation enacted in Oklahoma, Arkansas and WV to allow retail customers to
choose their electricity supplier is not yet effective. In 2001 Oklahoma delayed
implementation of customer choice indefinitely. Arkansas delayed the start of
customer choice until as late as October 2005. The Arkansas Commission has
recommended further delays of the start date or repeal of the restructuring
legislation. Before West Virginia's choice plan can be effective, tax
legislation must be passed to continue consistent funding for state and local
government. No further legislation has been passed related to restructuring in
Arkansas or West Virginia.

In general, state restructuring legislation provides for a transition from
cost-based rate regulated bundled electric service to unbundled cost-based rates
for transmission and distribution service and market pricing for the supply of
electricity with customer choice of supplier.

Ohio Restructuring - Affecting AEP, CSPCo and OPCo

Customer choice of electricity supplier and restructuring began on January 1,
2001, under the Ohio Act. During 2001 alternative suppliers registered and were
approved by the PUCO as required by the Ohio Act. At January 1, 2002, virtually
all customers continue to receive supply service from CSPCo and OPCo with a
legislatively required residential generation rate reduction of 5%. All
customers continue to be served by CSPCo and OPCo for transmission and
distribution services.


The Ohio Act provides for a five-year transition period to move from cost based
rates to market pricing for electric generation supply services. It granted the
PUCO broad oversight responsibility for promulgation of rules for competitive
retail electric generation service, approval of a transition plan for each
electric utility company and addressed certain major transition issues including
unbundling of rates and the recovery of stranded costs including regulatory
assets and transition costs.

The Ohio Act made several changes in the taxation of electric companies.
Effective January 1, 2001 the assessment percentage for property taxes on all
electric company property other than transmission and distribution was lowered
from 100% to 25%. The assessment percentage applicable to transmission and
distribution property remains at 88%. Also, electric companies were exempted
from the excise tax based on receipts. To make up for these tax reductions
electric distribution companies became subject to a new KWH based excise tax.
Since electric companies no longer paid the gross receipts tax, they became
liable, as of January 1, 2002 for the corporation franchise tax and municipal
income taxes.

In preparation for the January 1, 2001 start of the transition period, CSPCo and
OPCo filed a transition plan in December 1999. After negotiations with
interested parties including the PUCO staff, the PUCO approved a stipulation
agreement for CSPCo's and OPCo's transition plans. The approved plans included,
among other things, recovery of generation-related regulatory assets over seven
years for OPCo and over eight years for CSPCo through frozen transition rates
for the first five years of the recovery period and through a wires charge for
the remaining years. At December 31, 2000, the amount of regulatory assets to be
amortized as recovered was $518 million for OPCo and $248 million for CSPCo.

The stipulation agreement required the PUCO to consider implementation of a
gross receipts tax credit rider as the parties could not reach an agreement.



<PAGE>


As of May 1, 2001, electric distribution companies became subject to an excise
tax based on KWH sold to Ohio customers. The last tax year for which Ohio
electric utilities will pay the excise tax based on gross receipts is May 1,
2001 through April 30, 2002. As required by law, the gross receipts tax is paid
in advance of the tax year for which the utility exercises its privilege to
conduct business. CSPCo and OPCo treat the tax payment as a prepaid expense and
amortized it to expense during the tax year.

Following a hearing on the gross receipts tax issue, the PUCO determined that
there was no duplicate tax overlap period. The PUCO ordered the gross receipts
tax credit rider to be effective May 1, 2001 instead of May 1, 2002 as proposed
by the companies. This order reduced CSPCo's and OPCo's revenues by
approximately $90 million. CSPCo's and OPCo's request for rehearing of the gross
receipts tax issue was also denied by the PUCO. A decision on an appeal of this
issue to the Ohio Supreme Court is pending.

As described in Note 2, the PUCO's denial of the request for recovery of the
final year's gross receipts tax and the tax liability affixing on May 1, 2001
stranded the prepaid asset. As a result, an extraordinary loss was recorded in
2001.

One of the intervenors at the hearings for approval of the settlement agreement
(whose request for rehearing was denied by the PUCO) filed with the Ohio Supreme
Court for review of the settlement agreement. During 2001 that intervenor
withdrew from competing in Ohio. The Court dismissed the intervenor's appeal.

CSPCo's and OPCo's fuel costs were no longer subject to PUCO fuel clause
recovery proceedings beginning January 1, 2001. The elimination of fuel clause
recoveries in Ohio subjects AEP, CSPCo and OPCo to risk of fuel market price
variations and could adversely affect their results of operations and cash
flows.

Virginia Restructuring - Affecting AEP and APCo

In Virginia, choice of electricity supplier for retail customers began on
January 1, 2002 under its restructuring law. A finding by the Virginia SCC that
an effective competitive market exists would be required to end the transition
period.

The restructuring law provides an opportunity for recovery of just and
reasonable net stranded generation costs. The mechanisms in the Virginia law for
net stranded cost recovery are: a capping of rates until as late as July 1,
2007, and the application of a wires charge upon customers who depart the
incumbent utility in favor of an alternative supplier prior to the termination
of the rate cap. Capped rates are the rates in effect at July 1, 1999 if no rate
change request was made by the utility. APCo did not request new rates;
therefore, its current rates are its capped rates. Virginia's restructuring law
does not permit the Virginia SCC to change generation rates during the
transition period except for changes in fuel costs, changes in state gross
receipts taxes, or to address financial distress of the utility.

The Virginia restructuring law also requires filings to be made that outline the
functional separation of generation from transmission and distribution and a
rate unbundling plan. On January 3, 2001, APCo filed its corporate separation
plan and rate unbundling plan with the Virginia SCC. The Virginia SCC approved
settlement agreements that resolved most issues except the assignment of
generation-related regulatory assets among functionally separated generation,
transmission and distribution organizations. The Virginia SCC determined that
generation-related regulatory assets and related amortization expense should be
assigned to APCo's generation function. Presently, capped rates are sufficient
to recover generation-related regulatory assets. Therefore, management
determined that recovery of APCo's generation-related regulatory assets remains
probable. APCo will not collect a wires charge in 2002 per the settlement
agreements. The settlement agreements and related Virginia SCC order addressed
functional separation leaving decisions related to corporate separation for
later consideration. The Virginia SCC order approving the settlement agreements
requires several compliance filings, including a fuel/replacement power cost
report during an extended outage of an affiliate's nuclear plant. Management is
unable to predict the outcome of the Virginia SCC's review of APCo's compliance
filings.



<PAGE>


Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU

On January 1, 2002, customer choice of electricity supplier began in the ERCOT
area of Texas. Customer choice has been delayed in other areas of Texas
including the SPP area. All of SWEPCo's Texas service territory and a small
portion of WTU's service territory are located in the SPP. CPL operates entirely
in the ERCOT area of Texas.

Texas restructuring legislation, among other things:
o        provides for the recovery of regulatory  assets and other  stranded
         costs through  securitization  and  non-bypassable  wires charges;
o        requires reductions in NOx and sulfur dioxide emissions;
o        freezes rates until January 1, 2002;
o        provides for an earnings test for each of the three years of the rate
         freeze period (1999 through 2001) which will reduce stranded cost
         recoveries or if there is no stranded cost provides for a refund or
         their use to fund certain capital expenditures;
o        requires  each  utility  to  structurally  unbundle  into a  retail
         electric  provider,  a  power  generation  company  and a
         transmission and distribution utility;
o        provides for certain limits for ownership and control of generating
         capacity by companies;
o        provides for elimination of the fuel clause reconciliation
         process beginning January 1, 2002; and
o        provides for a 2004 true-up proceeding to determine recovery of
         stranded costs including final fuel recovery balances, net
         regulatory assets, certain environmental costs, accumulated excess
         earnings and other issues.

Under the Texas Legislation, delivery of electricity continues to be the
responsibility of the local electric transmission and distribution utility
company at regulated prices. Each electric utility was required to submit a plan
to structurally unbundle its business activities into a retail electric
provider, a power generation company, and a transmission and distribution
utility. In 2000 CPL, SWEPCo and WTU filed and the PUCT approved business
separation plans. The business separation plans provided for CPL and WTU to
establish separate companies and divide their integrated utility operations and
assets into a power generation company, a transmission and distribution utility
and a retail electric provider. In February 2002 the PUCT approved amendments to
SWEPCo's plan. The amended plan separates SWEPCo's Texas jurisdictional
transmission and distribution assets and operations into two new regulated
transmission and distribution subsidiaries. In addition, a retail electric
provider was established by SWEPCo to provide retail electric service to
SWEPCo's Texas jurisdictional customers. Until competition commences in the SPP,
SWEPCo's assets will not be separated and the SWEPCo retail electric provider
will not commence operation.

Due to the SPP area delay in the start of competition, only CPL's and WTU's
retail electric providers commenced operations on January 1, 2002. Operations
for CPL, SWEPCo and WTU have been functionally separated.

Under the Texas Legislation, electric utilities are allowed to recover stranded
generation costs including generation-related regulatory assets. The stranded
costs can be refinanced through securitization (a financing structure designed
to provide lower financing costs than are available through conventional
financings).

In 1999 CPL filed with the PUCT to securitize $1.27 billion of its retail
generation-related regulatory assets and $47 million in other qualified
restructuring costs. The PUCT authorized the issuance of up to $797 million of
securitization bonds ($949 million of generation-related regulatory assets and
$33 million of qualified refinancing costs offset by $185 million of customer
benefits for accumulated deferred income taxes). Four parties appealed to the
Supreme Court of Texas which upheld the PUCT's securitization order. CPL issued
its securitization bonds in February 2002.

CPL included regulatory assets not approved for securitization in its request
for recovery of $1.1 billion of stranded costs. The $1.1 billion request
included $800 million of STP costs included in property, plant and
equipment-electric on the Consolidated Balance Sheets. These STP costs had
previously been identified as excess cost over market (ECOM) by the PUCT for
regulatory purposes. They are earning a lower return and being amortized on an
accelerated basis for rate-making purposes.

After hearings on the issue of stranded costs, the PUCT ruled in October 2001
that its current estimate of CPL's stranded costs was negative $615 million. CPL
disagrees with the ruling. The ruling indicated that CPL's costs were below
market after securitization of regulatory assets. Management believes CPL has a
positive stranded cost exclusive of securitized regulatory assets. The final
amount of CPL's stranded costs including regulatory assets and ECOM will be
established by the PUCT in the 2004 true-up proceeding. If CPL's total stranded
costs determined in the 2004 true-up are less than the amount of securitized
regulatory assets, the PUCT can implement an offsetting credit to transmission
and distribution rates.

The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would
be made to the amount of regulatory costs authorized by the PUCT to be
securitized. However, the PUCT also ruled that excess earnings for the period
1999-2001 should be refunded through distribution rates to the extent of any
over-mitigation of stranded costs represented by negative ECOM. In 2001 the PUCT
issued an order requiring CPL to reduce distribution rates by $54.8 million plus
accrued interest over a five-year period beginning January 1, 2002 in order to
return estimated excess earnings for 1999, 2000 and 2001. The Texas Legislation
intended that excess earnings reduce stranded costs. Final stranded cost amounts
and the treatment of excess earnings will be determined in the 2004 true-up
proceeding. Currently the PUCT estimates that CPL will have no stranded costs
and has ordered the rate reduction to return excess earnings. Since CPL expensed
excess earnings amounts in 1999, 2000 and 2001, the order has no additional
effect on reported net income but will reduce cash flows for the five year
refund period. The amount to be refunded is recorded as a regulatory liability.

Management believes that CPL will have stranded costs in 2004, and that the
current treatment of excess earnings will be amended at that time. CPL has
appealed the PUCT's estimate of stranded costs and refund of excess earnings to
the Travis County District Court. Unaffiliated parties also appealed the PUCT's
refund order contending the entire $615 million of negative stranded costs
should be refunded presently. Management is unable to predict the outcome of
this litigation. An unfavorable ruling would have a negative impact on results
of operations, cash flows and possibly financial condition.

The Texas Legislation allows for several alternative methods to be used to value
stranded costs in the final 2004 true-up proceeding including the sale or
exchange of generation assets, the issuance of power generation company stock to
the public or the use of an ECOM model. To the extent that the final 2004
true-up proceeding determines that CPL should recover additional stranded costs,
the additional amount recoverable can also be securitized.

The Texas Legislation provides for an earnings test each year of the 1999
through 2001 rate freeze period. For CPL, any earnings in excess of the most
recently approved cost of capital in its last rate case must be applied to
reduce stranded costs. Companies without stranded costs, including SWEPCo and
WTU, must pay any excess earnings to customers, invest them in improvements to
transmission or distribution facilities or invest them to improve air quality at
generating facilities. The Texas Legislation requires PUCT approval of the
annual earnings test calculation.

The PUCT issued a final order for the 1999 earnings test in February 2001 and
adjustments to the accrued 1999 and 2000 excess earnings were recorded in
results of operations in the fourth quarter of 2000. After adjustments the 1999
excess earnings for CPL and WTU were $24 million and $1 million, respectively.
SWEPCo had no excess earnings in 1999. The PUCT issued a final order in
September 2001 for the 2000 excess earnings. CPL's, SWEPCo's and WTU's excess
2000 earnings were $23 million, $1 million and $17 million, respectively. An
estimate of 2001 excess earnings of $8 million for CPL, $2 million for SWEPCo
and none for WTU has been recorded and will be adjusted, if necessary, in 2002
when the PUCT issues its final order regarding 2001 excess earnings.

Due to the companies' disagreement with the PUCT, its staff and the Office of
Public Utility Counsel related to the proper determination of 2000 excess
earnings, the companies filed in district court in October 2001 seeking judicial
review of the PUCT's determination of excess earnings. A decision from the court
is not expected until later in 2002.

Beginning January 1, 2002, fuel costs will not be subject to PUCT fuel
reconciliation proceedings for CPL and WTU's ERCOT customers. Consequently, CPL
and WTU will file a final fuel reconciliation with the PUCT to reconcile their
fuel costs through the period ending December 31, 2001. Due to the delay of
competition for the SPP area, SWEPCo, which operates in the SPP area, continues
to record and request recovery of fuel costs under the Texas fuel reconciliation
proceeding. For WTU's SPP area customers, the PUCT will determine a method to
reconcile their fuel costs beginning in 2002 (see Note 5 "Rate Matters"). Final
unrecovered deferred fuel balances at December 31, 2001 will be included in each
company's 2004 true-up proceeding. If the final fuel balances or any amount
incurred but not yet reconciled are not recovered, they could have a negative
impact on results of operations. The elimination of the fuel clause recoveries
in 2002 in the ERCOT area of Texas will subject AEP and the retail electric
providers of CPL and WTU to greater risks of fuel market price increases and
could adversely affect future results of operations beginning in 2002.

The affiliated retail electric providers of CPL, SWEPCo and WTU are required by
the Texas Legislation to offer residential and small commercial customers (with
a peak usage of less than 1000 KW) a price-to-beat rate until January 1, 2007.
In December 2001 the PUCT approved price-to-beat rates for CPL's and WTU's
retail electric providers. Customers with a peak usage of more than 1000 KW are
subject to market rates. The Texas restructuring legislation provides for the
price to beat to be adjusted up to two times annually to reflect changes in fuel
and purchased energy costs using a natural gas price index.
Due to the delay in the start of competition in the SPP areas of Texas, several
issues are pending before the PUCT. These issues impact SWEPCo's and WTU's Texas
SPP operations. WTU's Texas SPP operations are estimated to be less than 5% of
WTU's total operations.

West Virginia Restructuring - Affecting AEP and APCo

In 2000 the WVPSC issued an order approving an electricity restructuring plan
which the WV Legislature approved by joint resolution. The joint resolution
provides that the WVPSC cannot implement the plan until the legislature makes
tax law changes necessary to preserve the revenues of state and local
governments. Since the WV Legislature has not passed the required tax law
changes, the restructuring plan has not become effective. AEP subsidiaries, APCo
and WPCo, provide electric service in WV.

The WV restructuring plan provides for:
o        deregulation of generation assets
o        separation of the generation, transmission and distribution businesses
o        a transition period with capped and fixed rates for up to 13 years
o        establishment of a rate  stabilization  deferred liability balance of
         $81 million ($76 million by APCo and $5 million by WPCo) by the end of
         year ten of the transition period.

APCo's Joint Stipulation, discussed in Note 5 "Rate Matters" and approved by the
WVPSC in 2000 in connection with a base rate filing, provides additional
mechanisms to recover transition generation-related regulatory assets.

In order for customer choice to become effective in WV, the WV Legislature must
enact tax legislation. Management is unable to predict the timing of the passage
of such legislation.

Arkansas Restructuring - Affecting AEP and SWEPCo

In 1999 Arkansas enacted legislation to restructure its electric utility
industry. Major provisions of the legislation as amended are:
o retailcompetition delayed until as late as October 2005;
o transmission facilities must be operated by an ISO if owned by a company which
  also owns generating facilities;
o rates will be frozen for one to three years;
o market power issues will be addressed by the Arkansas Commission; and
o an annual progress report to the Arkansas General Assembly on the development
  of competition in electric markets and its impact on retail customers is
  required.

Based on recommendations in the annual progress report filed by the Arkansas
Commission, the Arkansas General Assembly passed and the Governor signed
legislation in 2001 changing the start date of electric retail competition to
October 1, 2003, and providing the Arkansas Commission with authority to delay
that date for up to an additional two years.

The Arkansas Commission in December 2001 recommended further delays of the start
date or repeal of the restructuring legislation.

Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas,
Ohio, Texas, Virginia and West Virginia - Affecting AEP, APCo, CPL, CSPCo, OPCo,
SWEPCo and WTU

The enactment of restructuring legislation and the ability to determine
transition rates, wires charges and any resultant gain or loss under
restructuring legislation in Arkansas, Ohio, Texas, Virginia and West Virginia
enabled AEP and certain subsidiaries to discontinue regulatory accounting under
SFAS 71 for the generation portion of their business in those states. Under the
provisions of SFAS 71, regulatory assets and regulatory liabilities are recorded
to reflect the economic effects of regulation by matching expenses with related
regulated revenues.

The discontinuance of the application of SFAS 71 in Arkansas, Ohio, Texas,
Virginia and West Virginia in accordance with the provisions of SFAS 101 and
EITF Issue 97-4 resulted in recognition of extraordinary gains or losses in 2000
and 1999. The discontinuance of SFAS 71 can require the write-off of regulatory
assets and liabilities related to the deregulated operations, unless their
recovery is provided through cost-based regulated rates to be collected in a
portion of operations which continues to be rate regulated. Additionally, a
company must determine if any plant assets are impaired when they discontinue
SFAS 71 accounting. At the time the companies discontinued SFAS 71, the analysis
showed that there was no accounting impairment of generation assets.

Prior to 1999, all of the domestic electric utility subsidiaries' financial
statements reflected the economic effects of regulation under the requirements
of SFAS 71. As a result of deregulation of generation, the application of SFAS
71 for the generation portion of the business in Arkansas, Ohio, Texas, Virginia
and West Virginia was discontinued. Remaining generation-related regulatory
assets will be amortized as they are recovered under terms of transition plans.
Management believes that substantially all generation-related regulatory assets
and stranded costs will be recovered under terms of the transition plans. If
future events including the 2004 true-up proceeding in Texas were to make their
recovery no longer probable, the Company would write-off the portion of such
regulatory assets and stranded costs deemed unrecoverable as a non-cash
extraordinary charge to earnings. If any write-off of regulatory assets or
stranded costs occurred, it could have a material adverse effect on future
results of operations, cash flows and possibly financial condition.

Michigan Restructuring - Affecting AEP and I&M

On June 5, 2000, the Michigan Legislation became law. Its major provisions,
which were effective immediately, applied only to electric utilities with one
million or more retail customers. I&M, AEP's electric operating subsidiary doing
business in Michigan, has less than one million customers in Michigan.
Consequently, I&M was not immediately required to comply with the Michigan
Legislation.

The Michigan Legislation gives the MPSC broad power to issue orders to implement
retail customer choice of electric supplier no later than January 1, 2002
including recovery of regulatory assets and stranded costs. In compliance with
MPSC orders, on June 5, 2001, I&M filed its proposed unbundled rates, open
access tariffs and terms of service. On October 11, 2001, the MPSC approved a
settlement agreement which generally approved I&M's June 5, 2001 filing except
for agreed upon modifications. In accordance with the settlement agreement, I&M
agreed that recovery of implementation costs and regulatory assets would be
determined in future proceedings. The settlement agreement did not modify the
procedure for review of decom-missioning costs recoveries. Customer choice
commenced for I&M's Michigan customers on January 1, 2002. Effective with that
date the rates on I&M's Michigan customers' bills for retail electric service
were unbundled to allow customers the opportunity to evaluate the cost of
generation service for comparison with other offers. I&M's total rates in
Michigan remain unchanged and reflect cost of service. At this time, none of
I&M's customers have elected to change suppliers and no competing suppliers are
active in I&M's Michigan service territory.

Management has concluded that as of December 31, 2001 the requirements to apply
SFAS 71 continue to be met since I&M's rates for generation in Michigan continue
to be cost-based regulated. As a result I&M has not yet dis-continued regulatory
accounting under SFAS 71.

Oklahoma Restructuring - Affecting AEP and PSO

Under Oklahoma restructuring legislation passed in 1997 retail open access and
customer choice was scheduled to begin by July 1, 2002.

In June 2001 the Oklahoma Governor signed into law a bill to delay,
indefinitely, the implementation of the transition to customer choice and market
based pricing under restructuring legislation. Consequently, PSO, the AEP
subsidiary doing business in Oklahoma, will remain rate-regulated until further
legislation passes and continues the application of SFAS 71 regulatory
accounting.

8. Commitments and Contingencies:

Construction and Other Commitments - The AEP System has substantial construction
commitments to support its operations. Aggregate construction expenditures for
2002-2004 for consolidated domestic and foreign operations are estimated to be
$5.4 billion. The following table shows the estimated construction expenditures
of the subsidiary registrants for 2002 - 2004:

                     (in millions)


AEGCo                    $171.9
APCo                      815.5
CPL                       573.1
CSPCo                     408.7
I&M                       556.9
KPCo                      223.3
OPCo                    1,008.0
PSO                       364.9
SWEPCo                    321.4
WTU                       169.6

APCo, AEP's subsidiary which operates in Virginia and West Virginia, has been
seeking regulatory approval to build a new high voltage transmission line for
over a decade. Through December 31, 2001 we had invested approximately $40
million in this effort. If the required regulatory approvals are not obtained
and the line is not constructed, the $40 million investment would be written off
adversely affecting future results of operations and cash flows.

Long-term contracts to acquire fuel for electric generation have been entered
into for various terms, the longest of which extends to the year 2014 for the
AEP System. The expiration date of the longest fuel contract is 2006 for APCo,
2005 for CSPCo, 2014 for I&M, 2004 for KPCo, 2012 for OPCo, 2014 for PSO, 2006
for SWEPCo and 2006 for WTU. The contracts provide for periodic price
adjustments and contain various clauses that would release the subsidiaries from
their obligations under certain force majeure conditions.

The AEP System has contracted to sell approximately 1,300 MW of capacity
domestically on a long-term basis to unaffiliated utilities. Certain of these
contracts totaling 250 MW of capacity are unit power agreements requiring the
delivery of energy only if the unit capacity is available. The power sales
contracts expire from 2002 to 2012.

In connection with a lignite mining contract for its Henry W. Pirkey Power
Plant, SWEPCo has agreed under certain conditions, to assume the obligations of
the mining contractor. The contractor's actual obligation outstanding at
December 31, 2001 was $75 million.

As part of the process to receive a renewal of a Texas Railroad Commission
permit for lignite mining, SWEPCo has agreed to provide guarantees of mine
reclamation in the amount of $85 million. Since SWEPCo uses self-bonding, the
guarantee provides for SWEPCo to commit to use its resources to complete the
reclamation in the event the work is not completed by a third party miner. At
December 31, 2001 the cost to reclaim the mine is estimated to be approximately
$36 million.

AEP, through certain subsidiaries, has entered into agreements with an
unrelated, unconsolidated special purpose entity (SPE) to develop, construct,
finance and lease a power generation facility. The SPE will own the power
generation facility and lease it to an AEP consolidated subsidiary after
construction is completed. The lease will be accounted for as an operating lease
with the payment obligations included in the lease footnote. Payments under the
operating lease are expected to commence in the first quarter of 2004. AEP will
in turn sublease the facility to an unrelated industrial company which will both
use the energy produced by the facility and sell excess energy. Another
affiliate of AEP has agreed to purchase the excess energy from the subleasee for
resale.

The SPE has an aggregate financing commitment from equity and debt participants
(Investors) of $427 million. AEP, in its role as construction agent for the SPE,
is responsible for completing construction by December 31, 2003. In the event
the project is terminated before completion of construction, AEP has the option
to either purchase the project for 100% of project costs or terminate the
project and make a payment to the Lessor for 89.9% of project costs.

The term of the operating lease between the SPE and the AEP subsidiary is five
years with multiple extension options. If all extension options are exercised
the total term of the lease would be 30 years. AEP's lease payments to the SPE
are sufficient to provide a return to the Investors. At the end of the first
five-year lease term or any extension, AEP may renew the lease at fair market
value subject to Investor approval; purchase the facility at its original
construction cost; or sell the facility, on behalf of the SPE, to an independent
third party. If the project is sold and the proceeds from the sale are
insufficient to repay the Investors, AEP may be required to make a payment to
the Lessor of up to 85% of the project's cost. AEP has guaranteed a portion of
the obligations of its subsidiaries to the SPE during the construction and
post-construction periods.

As of December 31, 2001, project costs subject to these agreements totaled $168
million, and total costs for the completed facility are expected to be
approximately $450 million. Since the lease is accounted for as an operating
lease for financial accounting purposes, neither the facility nor the related
obligations are reported on AEP's balance sheets. The lease is a variable rate
obligation indexed to three-month LIBOR. Consequently as market interest rates
increase, the payments under this operating lease will also increase. Annual
payments of approximately $12 million represent future minimum payments under
the first five-year lease term calculated using the indexed LIBOR rate of 2.85%
at December 31, 2001.

OPCo has entered into a purchased power agreement to purchase electricity
produced by an unaffiliated entity's three-unit natural gas fired plant that is
under construction. The first unit is anticipated to be completed in October
2002 and the agreement will terminate 30 years after the third unit begins
operation. Under the terms of the agreement OPCo has the options to run the
plant until December 31, 2005 taking 100% of the power generated. For the
remainder of the 30 year contract term, OPCo will pay the variable costs to
generate the electricity it purchases which could be up to 20% of the plant's
capacity. The estimated fixed payments through December 2005 are $55 million.

Nuclear Plants - Affecting AEP, CPL and I&M

I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by
the NRC. CPL owns 25.2% of the two-unit 2,500 MW STP. STPNOC operates STP on
behalf of the joint owners under licenses granted by the NRC. The operation of a
nuclear facility involves special risks, potential liabilities, and specific
regulatory and safety requirements. Should a nuclear incident occur at any
nuclear power plant facility in the U.S., the resultant liability could be
substantial. By agreement I&M and CPL are partially liable together with all
other electric utility companies that own nuclear generating units for a nuclear
power plant incident at any nuclear plant in the U.S. In the event nuclear
losses or liabilities are underinsured or exceed accumulated funds and recovery
in rates is not possible, results of operations, cash flows and financial
condition would be adversely affected.

Nuclear Incident Liability - Affecting AEP, CPL and I&M

The Price-Anderson Act establishes insurance protection for public liability
arising from a nuclear incident at $9.5 billion and covers any incident at a
licensed reactor in the U.S. Commercially available insurance provides $200
million of coverage. In the event of a nuclear incident at any nuclear plant in
the U.S., the remainder of the liability would be provided by a deferred premium
assessment of $88 million on each licensed reactor in the U.S. payable in annual
installments of $10 million. As a result, I&M could be assessed $176 million per
nuclear incident payable in annual installments of $20 million. CPL could be
assessed $44 million per nuclear incident payable in annual installments of $5
million as its share of a STPNOC assessment. The number of incidents for which
payments could be required is not limited.

Insurance coverage for property damage, decommissioning and decontamination at
the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8
billion each. Cook Plant and STPNOC jointly purchase $1 billion of excess
coverage for property damage, de-commissioning and decontamination. Additional
insurance provides coverage for extra costs resulting from a prolonged
accidental outage. I&M and STPNOC utilize an industry mutual insurer for the
placement of this insurance coverage. Participation in this mutual insurer
requires a contingent financial obligation of up to $36 million for I&M and $3
million for CPL which is assessable if the insurer's financial resources would
be inadequate to pay for losses.
SNF Disposal - Affecting AEP, CPL, and I&M

Federal law provides for government responsibility for permanent SNF disposal
and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per
KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being
collected from customers and remitted to the U.S. Treasury. Fees and related
interest of $220 million for fuel consumed prior to April 7, 1983 at Cook Plant
have been recorded as long-term debt. I&M has not paid the government the Cook
Plant related pre-April 1983 fees due to continued delays and uncertainties
related to the federal disposal program. At December 31, 2001, funds collected
from customers towards payment of the pre-April 1983 fee and related earnings
thereon are in external funds and approximate the liability. CPL is not liable
for any assessments for nuclear fuel consumed prior to April 7, 1983 since the
STP units began operation in 1988 and 1989.

Decommissioning and Low Level Waste Accumulation Disposal - Affecting AEP, CPL
and I&M

Decommissioning costs are accrued over the service lives of the Cook Plant and
STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014
and 2017. After expiration of the licenses, Cook Plant is expected to be
decommissioned through dismantlement. The estimated cost of decommissioning and
low level radioactive waste accumulation disposal costs for Cook Plant ranges
from $783 million to $1,481 million in 2000 nondiscounted dollars. The wide
range is caused by variables in assumptions including the estimated length of
time SNF may need to be stored at the plant site subsequent to ceasing
operations. This, in turn, depends on future developments in the federal
government's SNF disposal program. Continued delays in the federal fuel disposal
program can result in increased decommissioning costs. I&M is re-covering
estimated Cook Plant decommissioning costs in its three rate-making
jurisdictions based on at least the lower end of the range in the most recent
decommissioning study at the time of the last rate proceeding. The amount
recovered in rates for decommissioning the Cook Plant and deposited in the
external fund was $27 million in 2001 and $28 million in 2000 and 1999.

The licenses to operate the two nuclear units at STP expire in 2027 and 2028.
After expiration of the licenses, STP is expected to be decommissioned using the
decontamination method. CPL estimates its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. CPL is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of $8 million per year.

Decommissioning costs recovered from customers are deposited in external trusts.
In 2001 and 2000 I&M deposited in its decommissioning trust an additional $12
million and $6 million, respectively, related to special regulatory commission
approved funding for decommissioning of the Cook Plant. Trust fund earnings
increase the fund assets and the recorded liability and decrease the amount
needed to be recovered from ratepayers. Decommissioning costs including
interest, unrealized gains and losses and expenses of the trust funds are
recorded in other operation expense for Cook Plant. For STP, nuclear
decommissioning costs are recorded in other operation expense, interest income
of the trusts are recorded in nonoperating income and interest expense of the
trust funds are included in interest charges.

On the AEP Consolidated Balance Sheets, nuclear decommissioning trust assets are
included in other assets and a corresponding nuclear decommissioning liability
is included in other noncurrent liabilities. On CPL's balance sheets, the
nuclear decommissioning liability of $99 million is included in electric utility
plant-accumulated depreciation and amortization. At December 31, 2001 and 2000,
the decommissioning liability for Cook Plant and STP combined totals $699
million and $654 million, respectively.

Shareholders' Litigation - Affecting AEP

On December 21, 2001, the U.S. District Court for the Southern District of Ohio
dismissed a class action lawsuit against AEP and four former or present
officers. The class consisted of all persons and entities who purchased or
otherwise acquired AEP common stock between July 25, 1997 and June 25, 1999. The
complaint alleged that the defendants knowingly violated federal securities laws
by disseminating materially false and misleading statements related to the
extended Cook Plant outage.

Municipal Franchise Fee Litigation - Affecting AEP and CPL

In 2001 CPL settled litigation regarding municipal franchise fees in Texas. CPL
paid $11 million to settle the litigation and be released from any further
liability. The City of San Juan, Texas had filed a class action suit in 1996
seeking $300 million in damages.

Texas Base Rate Litigation - Affecting AEP and CPL

In 2001 the Texas Supreme Court denied CPL's request to review a case resulting
from a 1997 PUCT base rate order. The Court also denied CPL's rehearing request.

The primary issues were:
o       the  classification  of $800  million of invested  capital in STP as
        ECOM and  assigning it a lower return on equity than other generation
        property;
o       and an $18 million disallowance of an affiliate service billings.

Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo

In 2001 SWEPCo settled ongoing litigation concerning lignite mining in
Louisiana. Since 1997 SWEPCo has been involved in litigation concerning the
mining of lignite from jointly owned lignite reserves. SWEPCo and CLECO are each
a 50% owner of Dolet Hills Power Station Unit 1 and jointly own lignite reserves
in the Dolet Hills area of northwestern Louisiana. Under terms of a settlement,
SWEPCo purchased an unaffiliated mine operator's interest in the mining
operations and related debt and other obligations for $86 million.

Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M,
and OPCo

Since 1999 AEP, APCo, CSPCo, I&M, and OPCo have been involved in litigation
regarding generating plant emissions under the Clean Air Act. Federal EPA and a
number of states alleged that AEP System companies and eleven unaffiliated
utilities modified certain units at coal fired generating plants in violation of
the Clean Air Act. Federal EPA filed complaints against AEP subsidiaries in U.S.
District Court for the Southern District of Ohio. A separate lawsuit initiated
by certain special interest groups was consolidated with the Federal EPA case.
The alleged modification of the generating units occurred over a 20 year period.

Under the Clean Air Act, if a plant undertakes a major modification that
directly results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution control
technology. This requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed components, or other
repairs needed for the reliable, safe and efficient operation of the plant. The
Clean Air Act authorizes civil penalties of up to $27,500 per day per violation
at each generating unit ($25,000 per day prior to January 30, 1997). In March
2001 the District Court ruled claims for civil penalties based on activities
that occurred more than five years before the filing date of the complaints
cannot be imposed. There is no time limit on claims for injunctive relief.

In February 2001 the government filed a motion requesting a determination that
four projects undertaken on units at Sporn, Cardinal and Clinch River plants do
not constitute "routine maintenance, repair and replacement" as used in the
Clean Air Act. Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and intends to vigorously
pursue its defense.

In January 2002 the U.S. Court of Appeals for the 11th Circuit ruled that TVA
may pursue its court challenge of a Federal EPA administrative order charging
similar violations to those in the complaints against AEP and other utilities.
Management is unable to estimate the loss or range of loss related to the
contingent liability for civil penalties under the Clear Air Act proceedings and
unable to predict the timing of resolution of these matters due to the number of
alleged violations and the significant number of issues yet to be determined by
the Court. In the event the AEP System companies do not prevail, any capital and
operating costs of additional pollution control equipment that may be required
as well as any penalties imposed would adversely affect future results of
operations, cash flows and possibly financial condition unless such costs can be
recovered through regulated rates, and where states are deregulating generation,
unbundled transition period generation rates, stranded cost wires charges and
future market prices for electricity.

In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain
plants jointly owned by CSPCo, reached a tentative agreement with Federal EPA
and other parties to settle litigation regarding generating plant emissions
under the Clean Air Act. Negotiations are continuing between the parties in an
attempt to reach final settlement terms. Cinergy's settlement could impact the
operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 (owned
25.4% and 12.5%, respectively, by CSPCo). Until a final settlement is reached,
CSPCo will be unable to determine the settlement's impact on its jointly owned
facilities and its results of operations and cash flows.

NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and
SWEPCo

Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions
in a number of eastern states, including certain states in which the AEP
System's generating plants are located. The NOx Rule has been upheld on appeal.
The compliance date for the NOx Rule is May 31, 2004.

The NOx Rule required states to submit plans to comply with its provisions. In
2000 Federal EPA ruled that eleven states, including states in which AEGCo's,
APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located, failed
to submit approvable compliance plans. Those states could face stringent
sanctions including limits on construction of new sources of air emissions, loss
of federal highway funding and possible Federal EPA takeover of state air
quality management programs. AEP subsidiaries and other utilities requested that
the D.C. Circuit Court review this ruling.



<PAGE>


In 2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting
petitions filed by certain northeastern states under the Clean Air Act. The rule
imposes emissions reduction requirements comparable to the NOx Rule beginning
May 1, 2003, for most of AEP's coal-fired generating units. Affected utilities
including certain AEP operating companies, petitioned the D.C. Circuit Court to
review the Section 126 Rule.

After review, the D.C. Circuit Court instructed Federal EPA to justify the
methods it used to allocate allowances and project growth for both the NOx Rule
and the Section 126 Rule. AEP subsidiaries and other utilities requested that
the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003
compliance date. On August 24, 2001, the D.C. Circuit Court issued an order
tolling the compliance schedule until Federal EPA responds to the Court's
remand. Federal EPA has announced that it intends to adopt May 31, 2004, as the
compliance date for the Section 126 Rule when it finalizes the NOx budgets for
both rules.

In 2000 the Texas Natural Resource Conservation Commission adopted rules
requiring significant reductions in NOx emissions from utility sources,
including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005
for SWEPCo.

During 2001 selective catalytic reduction (SCR) technology to reduce NOx
emissions on OPCo's Gavin Plant commenced operations. Construction of SCR
technology at certain other AEP generating units continues with completion
scheduled in 2002 through 2006.

Our estimates indicate that compliance with the NOx Rule, the Texas Natural
Resource Conservation Commission rule and the Section 126 Rule could result in
required capital expenditures of approximately $1.6 billion of which
approximately $450 million has been spent through December 31, 2001 for the AEP
System. Estimated compliance costs and amounts spent by registrant subsidiaries
are as follows:


                            Estimated          Amount Spent
                         Compliance Cost
                                         (in millions)
AEGCo                             $125                $ -
APCo                               365                 130
CPL                                 57                   4
CSPCo                              106                   1
I&M                                202                  -
KPCo                               140                  13
OPCo                               606                 277
SWEPCo                              28                  21

Since compliance costs cannot be estimated with certainty, the actual cost to
comply could be significantly different than the preliminary estimates depending
upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless any capital and operating costs of additional pollution
control equipment are recovered from customers, they will have an adverse effect
on results of operations, cash flows and possibly financial condition.

Merger Litigation - On January 18, 2002, the U.S. Court of Appeals for the
District of Columbia ruled that the SEC failed to prove that the June 15, 2000
merger of AEP with CSW meets the requirements of the PUHCA and sent the case
back to the SEC for further review. Specifically, the court told the SEC to
revisit its conclusion that the merger met PUHCA requirements that utilities be
"physically interconnected" and confined to a "single area or region."

In its June 2000 approval of the merger, the SEC agreed with AEP that the
companies' systems are integrated because they have transmission access rights
to a single high-voltage line through Missouri and also met the PUCHA's single
region requirement because it is now technically possible to centrally control
the output of power plants across many states. In its ruling, the appeals court
said that the SEC failed to explain its conclusions that the transmission
integration and single region requirements are satisfied.

Management believes that the merger meets the requirements of the PUHCA and
expects the matter to be resolved favorably.



<PAGE>


Enron Bankruptcy -  Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

At the date of Enron's bankruptcy AEP had open trading contracts and trading
accounts receivables and payables with Enron. In addition, on June 1, 2001, we
purchased Houston Pipe Line from Enron and entered into a lease arrangement with
a subsidiary of Enron for a gas storage facility. At the date of Enron's
bankruptcy various HPL related contingencies and indemnities remained unsettled.
In the fourth quarter of 2001 AEP provided $47 million ($31 million net of tax)
for our estimated loss from the Enron bankruptcy. The amounts for certain
subsidiary registrants were:

                                                     Amounts
                                 Amounts              Net of
Registrant                      Provided               Tax
                                --------  --           ---
                                           (in millions)

APCo                              $5.2                $3.4
CSPCo                              3.2                 2.1
I&M                                3.4                 2.2
KPCo                               1.3                 0.8
OPCo                               4.3                 2.8

The amounts provided were based on an analysis of contracts where AEP and Enron
are counterparties, the offsetting of receivables and payables, the application
of deposits from Enron and management's analysis of the HPL related purchase
contingencies and indemnifications. If there are any adverse unforeseen
developments in the bankruptcy proceedings, our future results of operations,
cash flows and possibly financial condition could be adversely impacted.

Other - AEP and its registrant subsidiaries are involved in a number of other
legal proceedings and claims. While management is unable to predict the ultimate
outcome of these matters, it is not expected that their resolution will have a
material adverse effect on results of operations, cash flows or financial
condition.


9. Acquisitions and Dispositions:

On June 1, 2001, AEP, through a wholly owned subsidiary, purchased Houston Pipe
Line Company and Lodisco LLC for $727 million from Enron. The acquired assets
include 4,200 miles of gas pipeline, a 30-year $274 million prepaid lease of a
gas storage facility and certain gas marketing contracts. The purchase method of
accounting was used to record the acquisition. According to APB Opinion No. 16
"Business Combinations" AEP recorded the assets acquired and liabilities assumed
at their estimated fair values as determined by the Company's management based
on information currently available and on current assumptions as to future
operations. Based on a preliminary purchase price allocation the excess of cost
over fair value of the net assets acquired was approximately $190 million and is
recorded as goodwill. SFAS 142 "Goodwill and Other Intangible Assets" treats
goodwill as a non-amortized, non-wasting asset effective January 1, 2002.
Therefore, goodwill was amortized for only seven months in 2001 on a
straight-line basis over 30 years. The purchase method results in the assets,
liabilities and earnings of the acquired operations being included in AEP's
consolidated financial statements from the purchase date.

SFAS 141 "Business Combinations" apply to all business combinations initiated
and consummated after June 30, 2001.

AEP also purchased the following assets or acquired the following businesses
from July 1, 2001 through December 31, 2001 for an aggregate total of $1,651
million:
o        SWEPCo, an AEP subsidiary, purchased the Dolet Hills mining
         operations including existing mine reclamation liabilities at
         its jointly owned lignite reserves in Louisiana. The purchase resulted
         from a litigation settlement discussed in Note 8, "Commitments and
         Contingencies". Management expects the acquisition to have minimal
         impact on results of operations.
o        Quaker Coal Company as part of a bankruptcy proceeding settlement and
         assumed additional liabilities of approximately $58 million. The
         acquisition includes property, coal reserves, mining operations and
         royalty interests in Colorado, Kentucky, Ohio, Pennsylvania and West
         Virginia. AEP will continue to operate the mines and facilities which
         employ over 800 individuals.
o        MEMCO Barge Line that adds 1,200 hopper barges and 30 towboats to AEP's
         existing barging fleet. MEMCO's 450 employees will continue to operate
         the barge line. MEMCO also adds major barging operations on the
         Mississippi and Ohio rivers to AEP's barging operations on the Ohio and
         Kanawha rivers.
o        4,000 megawatts of UK coal-fired generation that includes Fiddler's
         Ferry, a four-unit, 2,000-megawatt station on the River Mersey in
         northwest England, approximately 200 miles from London and Ferrybridge,
         a four-unit, 2,000-megawatt station on the River Aire in northeast
         England, approximately 200 miles from London and related coal stocks.
o        A 20% equity interest in Caiua, a Brazilian electric operating company
         which is a subsidiary of Vale. See Note 17, "Power, Distribution and
         Communications Projects". The Company converted a total of $66 million
         on an existing loan and accrued interest on that loan into Caiua
         equity.
o        Indian Mesa Wind Project consisting of 160 megawatts of wind generation
         located near Fort Stockton, Texas.
o        Acquired existing contracts and hired 22 key staff from Enron's
         London-based international coal trading group.

         Regarding the 2001 acquisitions management has recorded the assets
acquired and liabilities assumed at their estimated fair values in accordance
with APB Opinion No. 16 and SFAS 141 as appropriate based on currently available
information and on current assumptions as to future operations. Management is in
the process of obtaining independent appraisals regarding certain of these
acquisitions and evaluating others to refine its determination of fair values.
Accordingly the allocation of the purchase prices are subject to revision based
on the final determinations.

Dispositions

In March 2001 CSWE, a subsidiary company, completed the sale of Frontera, a
generating plant that the FERC required to be divested in connection with the
merger of AEP and CSW. The sale proceeds were $265 million and resulted in an
after tax gain of $46 million.

In July 2001 AEP, through a wholly owned subsidiary, sold its 50% interest in a
120-megawatt generating plant located in Mexico. The sale resulted in an after
tax gain of approximately $11 million.

In July 2001 OPCo, an AEP subsidiary, sold coal mines in Ohio and West Virginia
and agreed to purchase approximately 34 million tons of coal from the purchaser
of the mines through 2008. The sale is expected to have a nominal impact on
results of operations and cash flows.

In December 2001 AEP completed the sale of its ownership interests in the
Virginia and West Virginia PCS (personal communications services) Alliances for
stock. AEP recorded a 25% valuation provision on the stock received and is
restricted from selling this stock until after January 1, 2003. In addition, the
number of shares AEP can sell each month is limited in order to prevent large
swings in the stock price. The sales resulted in an after tax gain of
approximately $7 million.

In December 2000 the Company, through a wholly owned subsidiary, committed to
negotiate a sale of its 50% investment in Yorkshire, a U.K. electricity supply
and distribution company. As a result a $43 million impairment writedown ($30
million after tax) was recorded in the fourth quarter of 2000 to reflect the net
loss from the expected sale in the first quarter of 2001. The impairment
writedown is included in Other Income on AEP's Consolidated Statements of
Income. On February 26, 2001 an agreement to sell the Company's 50% interest in
Yorkshire was signed. On April 2, 2001, following the approval of the buyer's
shareholders, the sale was completed without further impact on AEP's
consolidated earnings.

In December 2000, CSW International, a subsidiary company sold its investment in
a Chilean electric company for $67 million. A net loss on the sale of $13
million ($9 million after tax) is included in Other Income, and includes $26
million ($17 million net of tax) of losses from foreign exchange rate changes
that were previously reflected in other comprehensive income. In the second
quarter of 2000 manage-ment determined that the then existing decline in market
value of the shares was other than temporary. As a result the investment was
written down by $33 million ($21 million after tax) in June 2000. The total loss
from both the write down of the Chilean investment to market in the second
quarter and from the sale in the fourth quarter was $46 million ($30 million net
of tax).

10. Benefit Plans:

In the U.S. AEP sponsors two qualified pension plans and two nonqualified
pension plans. Substantially all employees in the U.S., are covered by one or
both of the pension plans. OPEB plans are sponsored by the AEP System to provide
medical and death benefits for retired employees in the U.S.

The foreign pension plans are for employees of SEEBOARD in the U.K. and
CitiPower in Australia. The majority of SEEBOARD's employees joined a pension
plan that is administered for the U.K.'s electricity industry. The assets of
this plan are actuarially valued every three years. SEEBOARD and its
participating employees both contribute to the plan. Subsequent to July 1, 1995,
new employees were no longer able to participate in that plan and two new
pension plans were made available to new employees of SEEBOARD. CitiPower
sponsors a defined benefit pension plan that covers all employees.

The following tables provide a reconciliation of the changes in the plans'
benefit obligations and fair value of assets over the two-year period ending
December 31, 2001, and a statement of the funded status as of December 31 for
both years:

<PAGE>
<TABLE>
<CAPTION>
                                       U.S.                 Foreign                U.S.
                                  Pension Plans          Pension Plans          OPEB Plans
                               ------------------       ----------------    -----------------
                                2001        2000        2001        2000     2001       2000
                                ----        ----        ----        ----     ----       ----
                                                          (in millions)
Reconciliation of benefit
 obligation:
<S>                            <C>         <C>          <C>       <C>       <C>        <C>
Obligation at January 1        $3,161      $2,934       $1,179    $1,176    $1,668     $1,365
Service Cost                       69          60           12        13        30         29
Interest Cost                     232         227           60        64       114        106
Participant Contributions        -           -               4         5         8          7
Plan Amendments                  -            (71)(a)     -         -           17  (b)   (67) (c)
Foreign Currency Translation
 Adjustment                      -           -             (36)      (95)     -          -
Actuarial (Gain) Loss             121         218          (62)       80       192        262
Divestures                       -           -            -         -         (287) (d)  -
Benefit Payments                 (291)       (207)         (58)      (64)      (88)       (85)
Curtailments                     -           -            -         -            1         51 (e)
                               ------      ------       ------    ------    ------     ------
Obligation at December 31      $3,292      $3,161       $1,099    $1,179    $1,655     $1,668
                               ======      ======       ======    ======    ======     ======

Reconciliation of fair value
 of plan assets:
Fair value of plan assets at
 January 1                     $3,911      $3,866       $1,290    $1,405      $704       $668
Actual Return on Plan Assets     (182)        250         (131)       55       (31)         2
Company Contributions            -              2            7      -          118        112
Participant Contributions        -           -               4         5         8          7
Foreign Currency Translation
 Adjustment                      -           -             (40)     (111)       -          -
Benefit Payments                 (291)       (207)         (58)      (64)      (88)       (85)
                               ------      ------       ------    ------      ----       ----
Fair value of plan assets at
 December 31                   $3,438      $3,911       $1,072    $1,290      $711       $704
                               ======      ======       ======    ======      ====       ====

Funded status:
Funded status at December 31     $146       $ 750         $(27)     $111     $(944)     $(964)
Unrecognized Net Transition
 (Asset) Obligation               (15)        (23)          -         -        263        298
Unrecognized Prior-Service Cost   (12)        (12)           9        10        17         -
Unrecognized Actuarial
 (Gain) Loss                       35        (628)          74       (67)      649        448
                                 ----       -----         ----      ----     -----      -----
Prepaid Benefit (Accrued
 Liability)                      $154       $  87         $ 56      $ 54     $ (15)     $(218)
                                 ====       =====         ====      ====     =====      =====
</TABLE>
(a) One of the qualified pension plans converted to the cash balance pension
    formula from a final average pay formula.
(b) Related to the purchase of Houston Pipe Line Company and MEMCO Barge Line.
(c) Change to a service-related formula for retirement health care costs and a
    50% of pay life insurance benefit for retiree life insurance.
(d) Related to the sale of Central Ohio Coal Company, Southern Ohio Coal Company
    and Windsor Coal Company.
(e) Related to the shutdown of Central Ohio Coal Company, Southern Ohio Coal
    Company and Windsor Coal Company.


The following table provides the amounts for prepaid benefit costs and accrued
benefit liability recognized in the consolidated balance sheets as of December
31 of both years. The amounts for additional minimum liability, intangible asset
and accumulated other comprehensive income for 2000 were recorded in 2001 and
the amounts for 2001 will be recorded in 2002.
<TABLE>
<CAPTION>
                                      U.S.                  Foreign                  U.S.
                                  Pension Plan           Pension Plans            OPEB Plans
                               -------------------      ----------------      -------------------
                                2001        2000        2001        2000       2001        2000
                                ----        ----        ----        ----       ----        ----
                                                          (in millions)

<S>                             <C>         <C>         <C>          <C>      <C>         <C>
Prepaid Benefit Costs           $ 205       $ 159       $57          $54      $  1        $   3
Accrued Benefit Liability         (51)        (72)       (1)          -        (16)        (221)
Additional Minimum Liability      (15)        (24)       -            -        N/A          N/A
Intangible Asset                    9          14        -            -        N/A          N/A
Accumulated Other
 Comprehensive Income               6          10        -            -        N/A          N/A
                                -----       -----       ---          ---      ----        ------
Net Asset (Liability)           $ 154       $  87       $56          $54      $(15)       $(218)
                                =====       =====       ===          ===      ====        =====

Other Comprehensive (Income)
 Expense Attributable to
 Change in Additional Pension
 Liability Recognition            $(4)         $4        -            -        N/A         N/A
                                  ===          ==       ===          ===       ===         ====
</TABLE>
N/A = Not Applicable



<PAGE>


Both of the AEP System's nonqualified pension plans had accumulated benefit
obligations in excess of plan assets of $40 million and $26 million at December
31, 2001 and $41 million and $26 million at December 31, 2000. There are no plan
assets in the nonqualified plans.

The AEP System's OPEB plans had accumulated benefit obligations in excess of
plan assets of $944 million and $964 million at December 31, 2001 and 2000,
respectively.

In late December 2001 AEP purchased generation plants in the UK (see Note 9,
"Acquisitions and Dispositions"). The purchase included the pension plan of the
existing generation plant employees. In connection with the acquisition, a $10
million liability for the accumulated benefit obligation in excess of plan
assets was assumed.

The following table provides the components of AEP's net periodic benefit cost
for the plans for fiscal years 2001, 2000 and 1999:
<TABLE>
<CAPTION>
                                        U.S.                 Foreign                  U.S.
                                   Pension Plans           Pension Plans          OPEB Plans
                                --------------------   --------------------   -------------------
                                2001    2000    1999   2001    2000    1999   2001   2000   1999
                                ----    ----    ----   ----    ----    ----   ----   ----   ----
                                                         (in millions)
<S>                             <C>    <C>     <C>     <C>     <C>     <C>    <C>    <C>    <C>
Service cost                    $  69  $  60   $  71   $ 12    $ 13    $ 15   $ 30   $ 29   $ 33
Interest cost                     232    227     211     60      64      59    114    106     90
Expected return on plan assets   (338)  (321)   (299)   (69)    (75)    (71)   (61)   (57)   (49)
Amortization of
 transition (asset) obligation     (8)    (8)     (8)    -      -        -      30     41     43
Amortization of prior-service
 cost                              -      13      12      1       1      -      -      -      -
Amortization of net actuarial
 (gain) loss                      (24)   (39)    (15)    -      -        -      18      4      5
                                 ----  -----   -----   ----    ----    ----   ----   ----   ----
Net periodic benefit cost
 (credit)                         (69)   (68)    (28)     4       3       3    131    123    122
Curtailment loss(a)                -      -      -       -      -        -       1     79     18
                                 ----  -----   -----   ----    ----    ----   ----   ----   ----
Net periodic benefit
 cost (credit) after
 curtailments                    $(69) $ (68)  $ (28)  $  4    $  3    $  3   $132   $202   $140
                                 ====  =====   =====   ====    ====    ====   ====   ====   ====
</TABLE>
(a) Curtailment charges were recognized during 2000 and 1999 for the shutdown of
Central Ohio Coal Company, Southern Ohio Coal Company and Windsor Coal Company.

The following table provides the net periodic benefit cost (credit) for the
plans by the following AEP registrant subsidiaries for fiscal years 2001, 2000
and 1999:
<TABLE>
<CAPTION>
                                           U.S.                           U.S
                                       Pension Plans                   OPEB Plans
                                ----------------------------   --------------------------
                                   2001      2000      1999      2001      2000    1999
                                   ----      ----      ----      ----      ----    ----
                                                       (in thousands)
<S>                             <C>        <C>       <C>       <C>      <C>       <C>
APCo                            $(13,645)  $(14,047) $(3,925)  $22,810  $ 22,139  $19,431
CPL                               (3,411)    (2,986)  (4,270)    8,214     6,656    7,595
CSPCo                            (10,624)   (10,905)  (4,893)   10,328     9,643    8,623
I&M                               (7,805)    (8,565)  (1,259)   15,077    14,155   13,664
KPCo                              (1,922)    (2,075)    (393)    2,438     2,364    2,652
OPCo                             (14,879)   (15,041)  (4,979)   34,444   116,205   52,518
PSO                               (2,480)    (2,196)  (3,129)    6,187     4,277    5,516
SWEPCo                            (3,051)    (2,606)  (3,734)    6,399     4,152    4,913
WTU                               (1,664)    (1,585)  (2,221)    3,729     2,929    3,377
</TABLE>
The weighted-average assumptions as of December 31, used in the measurement of
the Company's benefit obligations are shown in the following tables:
<TABLE>
<CAPTION>
                                 U.S.                    Foreign
                             Pension Plans             Pension Plans               U.S. OPEB Plans
                        -----------------------   -------------------------     ---------------------
                        2001    2000       1999   2001      2000       1999     2001    2000    1999
                        ----    ----       ----   ----      ----       ----     ----    ----    ----
                          %       %          %      %         %          %        %       %       %
<S>                     <C>     <C>        <C>    <C>      <C>      <C>         <C>     <C>     <C>
 Discount rate          7.25    7.50       8.00     5-5.8    5-5.5    5.5-6     7.25    7.50    8.00
 Expected return on
  plan assets           9.00    9.00       9.00   6.1-7.5    6-7.5  6.5-7.5     8.75    8.75    8.75
 Rate of compensation
  increase               3.7     3.2        3.8       4.0  3.5-4.0    4-4.5      N/A     N/A     N/A
</TABLE>
<PAGE>





For OPEB measurement purposes, an 8% annual rate of increase in the per capita
cost of covered health care benefits was assumed for 2002. The rate was assumed
to decrease gradually each year to a rate of 5% through 2005 and remain at that
level thereafter.

Assumed health care cost trend rates have a significant effect on the amounts
reported for the OPEB health care plans. A 1% change in assumed health care cost
trend rates would have the following effects:

                              1% Increase     1% Decrease
(in millions)
Effect on total  service
 and interest cost
 components of  net
 periodic postretirement
 health care benefit cost              $ 18           $(15)

Effect on the health care
 Component of the
 Accumulated
 Postretirement
 Benefit obligation                     189            (156)

AEP Savings Plans - The AEP Savings Plans are defined contribution plans offered
to non-UMWA U.S. employees. The cost for contributions to these plans totaled
$55 million in 2001, $37 million in 2000 and $36 million in 1999. Beginning in
2001 AEP's contributions to the plans increased to 4.5% of the initial 6% of
employee pay contributed from the previous 3% of the initial 6% of employee base
pay contributed.

The following table provides the cost for contributions to the savings plans by
the following AEP registrant subsidiaries for fiscal years 2001, 2000 and 1999:

                        2001           2000           1999
                        ----           ----           ----
                                    (in thousands)

APCo                   $7,031         $3,988         $4,091
CPL                     3,046          3,161          3,284
CSPCo                   2,789          1,638          1,679
I&M                     7,833          4,231          3,996
KPCo                    1,016            544            561
OPCo                    6,398          3,713          3,744
PSO                     2,235          2,306          2,435
SWEPCo                  2,776          2,880          2,961
WTU                     1,558          1,708          1,766


Other UMWA Benefits - AEP and OPCo provide UMWA pension, health and welfare
benefits for certain unionized mining employees, retirees, and their survivors
who meet eligibility requirements. The benefits are administered by UMWA
trustees and contributions are made to their trust funds. Contributions are
expensed as paid as part of the cost of active mining operations and were not
material in 2001, 2000 and 1999.

11. Stock-Based Compensation:

AEP has a Long-term Incentive Plan under which a maximum of 15,700,000 shares of
common stock can be issued to key employees. The plan was adopted in 2000.

Under the plan, the exercise price of each option granted equals the market
price of AEP's common stock on the date of grant. These options will vest in
equal increments, annually, over a three-year period with a maximum exercise
term of ten years.

CSW maintained a stock option plan prior to the merger with AEP in 2000.
Effective with the merger, all CSW stock options outstanding were converted into
AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP
stock option. The exercise price for each CSW stock option was adjusted for the
exchange ratio. The provisions of the CSW stock option plan will continue in
effect until all options expire or there are no longer options outstanding.
Under the CSW stock option plan, the option exercise price was equal to the
stock's market price on the date of grant. The grant vested over three years,
one-third on each of the first three anniversary dates of the grant, and expires
10 years after the original grant date. All CSW stock options are fully vested.



<PAGE>


The following table summarizes share activity in the above plans, and the
weighted-average exercise price:



<PAGE>
<TABLE>
<CAPTION>
                               2001                    2000                    1999
                               ----                    ----                    ----
                                   Weighted                Weighted                Weighted
                                   Average                 Average                 Average
                        Options    Exercise     Options    Exercise     Options    Exercise
                    (in thousands) Price    (in thousands) Price    (in thousands) Price
                    -------------- -----    -------------- -----    -------------- ------
<S>                      <C>       <C>           <C>       <C>             <C>     <C>
Outstanding at
 beginning of year       6,610     $36             825     $40             866     $40
  Granted                  645     $45           6,046     $36              -      $ -
  Exercised               (216)    $38             (26)    $36             (22)    $38
  Forfeited               (217)    $37            (235)    $39             (19)    $43
                         -----                    ----                     ---
Outstanding at
 end of year             6,822     $37           6,610     $36             825     $40
                         =====                   =====                     ===

Options Exercisable
 at end of year            395     $43             588     $41             707     $42
                           ===                     ===                     ===
</TABLE>

The weighted-average grant-date fair value of options granted in 2001 and 2000
was $8.01 and $5.50 per share. There were no options granted in 1999. Shares
outstanding under the stock option plan have exercise prices ranging from $35 to
$49 and a weighted-average remaining contractual life of 8.5 years.

If compensation expense for stock options had been determined based on the fair
value at the grant date, net income and earnings per share would have been the
pro forma amounts shown below:

                                   2001     2000     1999
                                   ----     ----     ----
Pro forma net income
(in millions)                      $959     $264     $972

Pro forma earnings per Share:
  Basic                            $2.98    $0.82    $3.03
  Diluted                          $2.97    $0.82    $3.03

The proceeds received from exercised stock options are included in common stock
and paid-in capital.

The pro forma amounts are not representative of the effects on reported net
income for future years.

The fair value of each option award is estimated on the date of grant using the
Black-Scholes option-pricing model with the following weighted average
assumptions used to estimate the fair value of options granted:

                                     2001        2000
Risk Free Interest Rate               4.87%       5.02%
Expected Life                       7 years     7 years
Expected Volatility                  28.40%      24.75%
Expected Dividend Yield               6.05%       6.02%




12. Business Segments:

In fiscal year 2000, AEP reported the following four business segments: Domestic
Electric Utilities; Foreign Energy Delivery; Worldwide Energy Investments; and
Other. With this structure, our regulated domestic utility companies were
considered single, vertically integrated units, and were reported collectively
in the Domestic Electric Utilities segment.

In 2001, we moved toward our goal of functionally and structurally segregating
our businesses. The ensuing realignment of our operations resulted in our
current business segments, Wholesale, Energy Delivery and Other. The business
activities of each of these segments are as follows:

Wholesale
o        Generation of electricity for sale to retail and wholesale customers,
o        Marketing and trading of electricity and gas worldwide.
o        Gas pipeline and storage services and other energy supply related
         business

Energy Delivery
o        Domestic electricity transmission
o        Domestic electricity distribution

Other
o        Foreign electricity generation investments
o        Foreign electricity distribution and supply investments
o        Telecommunication services


<PAGE>


Segment results of operations for the twelve months ended December 31, 2001,
2000 and 1999 are shown below. These amounts include certain estimates and
allocations where necessary.

We have used Earnings before Interest and Income Taxes (EBIT) as a measure of
segment operating performance. The EBIT measure is total operating revenues net
of total operating expenses and other routine income and deductions from income.
It differs from net income in that it does not take into account interest
expense or income taxes. EBIT is believed to be a reasonable gauge of results of
operations. By excluding interest and income taxes, EBIT does not give guidance
regarding the demand of debt service or other interest requirements, or tax
liabilities or taxation rates. The effects of interest expense and taxes on
overall corporate performance can be seen in the consolidated income statement.




<PAGE>
<TABLE>
<CAPTION>

                                        Energy           Reconciling      AEP
Year                         Wholesale  Delivery  Other  Adjustments  Consolidated
- ----                         ---------  --------  -----  -----------  ------------
                                              (in millions)
<S>                            <C>      <C>      <C>        <C>           <C>
2001
  Revenues from:
    External unaffiliated
     customers                 $55,929  $ 3,356  $ 1,972    $  -          $61,257
    Transactions with other
     operating segments          2,708       20    1,155     (3,883)         -
  Segment EBIT                   1,418      986      278       (115)        2,567
  Depreciation, depletion and
    amortization expense           597      632      154       -            1,383
  Total assets                  31,459   12,455    4,541     (1,174)(a)    47,281
  Investments in equity method
    subsidiaries                   242     -         414       -              656
  Gross property additions         640      844      348       -            1,832

(a) Reconciling adjustments for Total Assets:
     Eliminate intercompany balances                         (1,558)
     Corporate assets                                           404
     Other                                                      (20)
                                                            -------
                                                             (1,174)
</TABLE>
<TABLE>
<CAPTION>
2000
  Revenues from:
    External unaffiliated
<S>                           <C>       <C>       <C>       <C>           <C>
     customers                $31,437   $ 3,174   $2,095    $  -          $36,706
    Transactions with other
     operating segments         1,726         2      750     (2,478)         -
  Segment EBIT                  1,006     1,017      358       (322)        2,059
  Depreciation, depletion and
    amortization expense          559       506      188         (3)        1,250
  Total assets                 32,216    14,876    7,124       (866)(b)    53,350
  Investments in equity method
    subsidiaries                  140      -         724       -              864
  Gross property additions        493       961      319       -            1,773

(b) Reconciling adjustments for Total Assets:
     Eliminate intercompany balances                           (955)
     Corporate assets                                            93
     Other                                                       (4)
                                                            -------
                                                               (866)
</TABLE>
<TABLE>
<CAPTION>
1999
  Revenues from:
    External unaffiliated
<S>                           <C>        <C>      <C>      <C>            <C>
     customers                $19,543    $3,068   $2,134   $  -           $24,745
    Transactions with other
     operating segments         1,038      -         573    (1,611)          -
  Segment EBIT                  1,146     1,008      392       (82)         2,464
  Depreciation, depletion and
    amortization expense          565       454      196        (3)         1,212
  Total assets                 18,408    11,224    6,396      (335)(c)     35,693
  Investments in equity method
    subsidiaries                  134      -         755        -             889
  Gross property additions        390       815      475        -           1,680

(c) Reconciling adjustments for Total Assets:
     Eliminate intercompany balances                           (345)
     Other                                                       10
                                                            -------
                                                               (335)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>

Geographically our business is transacted primarily in the United States and the
United Kingdom with other holdings in a small number of other counties. Results
of operations by geographic area are as follows:

Geographic Areas                                       Revenues
- ----------------         ---------------------------------------------------------------------
                                               United                                  AEP
                         United States        Kingdom        Other Foreign        Consolidated
                         ---------------------------------------------------------------------
                                                    (in millions)
<S>                        <C>                 <C>                <C>               <C>
2001                       $53,650             $7,201             $406              $61,257
2000                        34,300              2,011              395               36,706
1999                        22,694              1,705              346               24,745
</TABLE>
<TABLE>
<CAPTION>
                                                     Long-Lived Assets
                         ---------------------------------------------------------------------
                                               United                                  AEP
                         United States        Kingdom        Other Foreign        Consolidated
                         ---------------------------------------------------------------------
                                                    (in millions)

<S>                        <C>                 <C>                <C>               <C>
2001                       $21,726             $2,158             $659              $24,543
2000                        20,463              1,220              710               22,393
1999                        19,958              1,124              783               21,865
</TABLE>

Of the registrant operating company subsidiaries, all of the registrant
subsidiaries except AEGCo have two business segments. The segment results for
each of these subsidiaries are reported in the table below. AEGCo has one
segment, a wholesale generation business. AEGCo's results of operations are
reported in AEGCo's financial statements.


<PAGE>
<TABLE>
<CAPTION>
                                                Twelve Months Ended                            Twelve Months Ended
                                                 December 31, 2001                              December 31, 2000
                                                 -----------------                              -----------------
                                  Revenues                                          Revenues
                                  From                                              From
                                  External          Segment                         External     Segment
                                  Customers         EBIT       Total Assets         Customers    EBIT          Total Assets
                                  ---------         ----                            ---------    ----
                                                   (in thousands)                                   (in thousands)
<S>                                  <C>            <C>          <C>                 <C>            <C>            <C>
        Wholesale Segment
        APCo                         $6,404,394     $164,844     $2,855,337          $4,512,390     $ 154,525      $3,708,252
        CPL                           2,848,545      303,926      2,977,504           1,870,689       273,650       3,182,192
        CSPCo                         3,816,644      232,372      1,987,756           2,767,569       235,860       2,488,513
        I&M                           4,489,215      117,396      3,318,919           3,231,065     (146,297)       4,003,805
        KPCo                          1,528,212        4,935        585,847           1,055,521        22,379         766,605
        OPCo                          5,709,689      240,128      3,156,115           4,524,513       289,084       4,007,722
        PSO                           1,939,372       52,086        907,165           1,184,895        54,072       1,011,432
        SWEPCo                        2,241,444       82,409      1,223,334           1,337,776        27,055       1,302,398
        WTU                             895,235        7,930        396,147             583,358        13,910         466,499

        Energy Delivery Segment
        APCo                           $595,036     $213,733     $2,252,601            $574,918      $191,560      $2,925,472
        CPL                             473,182      109,587      2,138,482             478,814       136,069       2,285,492
        CSPCo                           483,219      130,503      1,118,112             398,046        81,896       1,399,789
        I&M                             314,410      111,206      1,498,089             311,019       126,241       1,807,233
        KPCo                            131,183       54,033        567,396             121,346        49,770         742,459
        OPCo                            552,713      118,261      1,759,952             467,587       138,418       2,234,835
        PSO                             261,877       79,787      1,010,732             245,124        85,524       1,126,901
        SWEPCo                          333,004      107,197      1,273,266             344,950       129,842       1,355,558
        WTU                             169,036       33,226        527,273             176,204        50,201         620,912

        Registrant Subsidiaries
        Company Total
        APCo                         $6,999,430      $378,577    $5,107,938          $5,087,308      $346,085     $6,633,724
        CPL                           3,321,727       413,513     5,115,986           2,349,503       409,719      5,467,684
        CSPCo                         4,299,863       362,875     3,105,868           3,165,615       317,756      3,888,302
        I&M                           4,803,625       228,602     4,817,008           3,542,084      (20,056)      5,811,038
        KPCo                          1,659,395        58,968     1,153,243           1,176,867        72,149      1,509,064
        OPCo                          6,262,402       358,389     4,916,067           4,992,100       427,502      6,242,557
        PSO                           2,201,249       131,873     1,917,897           1,430,019       139,596      2,138,333
        SWEPCo                        2,574,448       189,606     2,496,600           1,682,726       156,897      2,657,956
        WTU                           1,064,271        41,156       923,420             759,562        64,111      1,087,411
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                                       Twelve Months Ended December 31, 1999
                                  Revenues From External Customers             Segment EBIT           Total Assets
                                                                 (in thousands)
<S>                                          <C>                                 <C>                    <C>
        Wholesale Segment
        APCo                                 $3,404,987                          $116,907               $2,434,110
        CPL                                   1,032,808                           267,165                2,821,449
        CSPCo                                 2,242,459                           214,312                1,798,394
        I&M                                   2,609,307                           (18,055)               3,153,344
        KPCo                                    789,008                            18,569                  501,212
        OPCo                                  3,763,711                           278,415                3,002,768
        PSO                                     493,063                            56,521                  721,195
        SWEPCo                                  672,158                            95,385                1,032,045
        WTU                                     270,800                            25,008                  369,457

        Energy Delivery Segment
        APCo                                   $565,660                          $208,460               $1,920,290
        CPL                                     449,667                           133,172                2,026,401
        CSPCo                                   389,280                            93,962                1,011,596
        I&M                                     310,880                           142,973                1,423,352
        KPCo                                    129,113                            51,556                  485,426
        OPCo                                    460,182                           149,906                1,674,441
        PSO                                     256,327                            74,430                  803,531
        SWEPCo                                  299,369                            83,143                1,074,170
        WTU                                     174,909                            46,216                  491,748

        Registrant Subsidiaries
        Company Total
        APCo                                 $3,970,647                           $325,367              $4,354,400
        CPL                                   1,482,475                            400,337               4,847,850
        CSPCo                                 2,631,739                            308,274               2,809,990
        I&M                                   2,920,187                            124,918               4,576,696
        KPCo                                    918,121                             70,125                 986,638
        OPCo                                  4,196,893                            428,321               4,677,209
        PSO                                     749,390                            130,951               1,524,726
        SWEPCo                                  971,527                            178,528               2,106,215
        WTU                                     445,709                             71,224                 861,205

</TABLE>
<PAGE>


13.  Risk Management, Financial
       Instruments and Derivatives:

Risk Management

We are subject to market risks in our day to day operations. Our risk policies
have been reviewed with the Board of Directors, approved by a Risk Management
Committee and administered by Chief Risk Officer. The Risk Management Committee
establishes risk limits, approves risk policies, assigns responsibilities
regarding the oversight and management of risk and monitors risk levels. This
committee receives daily, weekly, and monthly reports regarding compliance with
policies, limits and procedures. The committee meets monthly and consists of the
Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior
financial and operating managers.

The risks and related strategies that management can employ are:

Risk                  Description        Strategy
Price Risk            Volatility in      Trading and
                       commodity prices   hedging
Interest Rate Risk    Changes in
                       Interest rates    Hedging
Foreign Exchange      Fluctuations in
 Risk                  foreign currency
                       rates             Hedging
Credit Risk           Non-performance
                       on contracts      Guarantees,
                       with              Collateral
                       counterparties

We employ physical forward purchase and sale contracts, exchange futures and
options, over-the-counter options, swaps, and other derivative contracts to
offset price risk where appropriate. However, we engage in trading of
electricity, gas and to a lesser degree coal, oil, natural gas liquids, and
emission allowances and as a result the Company is subject to price risk. This
risk is managed by the management of the trading operations, the Company's Chief
Risk Officer and the Risk Management Committee. If the risk from trading
activities exceeds certain pre-determined limits, the positions are modified or
hedged to reduce the risk to the limits unless specifically approved by the Risk
Management Committee. Although we do not hedge all commodity price exposure,
manage-ment makes informed risk taking decisions supported by the above
described risk management controls.

AEP is exposed to risk from changes in the market prices of coal and natural gas
used to generate electricity where generation is no longer regulated or where
existing fuel clauses are suspended or frozen. The protection afforded by fuel
clause recovery mechanisms has either been eliminated by the implementation of
customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of
Texas (effective January 1, 2002) or frozen by settlement agreements in Indiana,
Michigan and West Virginia. To the extent all fuel supply for the generating
units in these states are not under fixed price long-term contracts, AEP is
subject to market price risk. AEP continues to be protected against market price
changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky,
Virginia and the SPP area of Texas.

We employ fair value hedges, cash flow hedges and swaps to mitigate changes in
interest rates or fair values on short and long-term debt when management deems
it necessary. We do not hedge all interest rate risk.

We employ cash flow forward hedge contracts to lock-in prices on transactions
denominated in foreign currencies where deemed necessary. International
subsidiaries use currency swaps to hedge exchange rate fluctuations in debt
transactions denominated in foreign currencies. We do not hedge all foreign
currency exposure.

Our open trading contracts, including structured transactions, are
marked-to-market daily using the price model and price curve(s) corresponding to
the instrument. Forwards, futures and swaps are generally valued by subtracting
the contract price from the market price and then multiplying the difference by
the contract volume and adjusting for net present value and other impacts.
Significant estimates in valuing such contracts include forward price curves,
volumes, seasonality, weather, and other factors.

Forwards and swaps (which are a series of forwards) are valued based on forward
price curves which represent a series of projected prices at which transactions
can be executed in the market. The forward price curve includes the market's
expectations for prices of a delivered commodity at that future date. The
forward price curve is developed from the market bid price, which is the highest
price which traders are willing to pay for a contract, and the ask or offer
price, which is the lowest price traders are willing to receive for selling a
contract.

Options contracts, consisting primarily of options on forwards and spread
options, are valued using models, which are variations on Black-Scholes option
models. The market-related inputs are the interest rate curve, the underlying
commodity forward price curve, and the implied volatility curve. Option prices
or volatilities may be quoted in the market. Significant estimates in valuing
these contracts include forward price curves, volumes, and other volatilities.

Futures and futures options traded on futures exchanges (primarily oil and gas
on Nymex) are valued at the exchange price.

Market prices utilized in valuing all forward contracts, OTC options, swaps and
structured transactions represent mid-market price, which is the average of the
bid and ask prices. These bids and offers come from brokers, on-line exchanges
such as the Intercontinental Exchange, and directly from other counterparties.
These prices exist for delivery periods and locations being traded or quoted and
vary by period, location and commodity. For periods and locations that are not
liquid and for which external information is not readily available, management
uses the best information available to develop bid and ask prices and forward
curves.

Electricity and gas markets in particular have primary trading hubs or delivery
points/regions and less liquid secondary delivery points. In North American
natural gas markets, the primary delivery points are generally traded from Henry
Hub, Louisiana. The less liquid gas or power trading points may trade as a
spread (based on transportation costs, constraints, etc.) from the nearest
liquid trading hub. Also, some commodities trade more often and therefore are
more liquid than others. For example, peak electricity is a more liquid product
than off-peak electricity. Henry Hub gas trades in monthly blocks for up to 36
months and after that only trades in seasonal or calendar blocks. In the near
term, forward price curves for gas have a seasonal shape. They are based on
market quotes beyond that.

For all these factors, the curve used for valuation is the mid-point. At times
bids or offers may not be available due to market events, volatility,
constraints, long-dated part of the curve, etc. When this occurs, the Company
uses its best judgment to estimate the curve values until actual values are
available again. The value used will be based on various factors such as last
trade price, recent price trend, product spreads, location spreads (including
transportation costs), cross commodity spreads (e.g., heat rate conversion of
gas to power), time spreads, cost of carry (e.g., cost of gas storage), marginal
production cost, cost of new entrant capacity, and alternative fuel costs. Also,
an energy commodity contract's price volatility generally increases as it
approaches the delivery month. Spot price volatility (e.g., daily or hourly
prices) can cause contract values to change substantially as open positions
settle against spot prices. When a portion of a curve has been estimated for a
period of time and market changes occur, assumptions are updated to align the
company's curve to the market.

The fair values determined are reduced by reserves to adjust for credit risk and
liquidity risk. Credit risk is based on credit ratings of counterparties and
represents the risk that the counterparty to the contract will fail to perform
or fail to pay amounts due AEP. Liquidity risk represents the risk that
imperfections in the market will cause the price to be less than or more than
what the price should be based purely on supply and demand. The liquidity
reserve essentially reserves half of the difference between bids and offers for
each open position, such that the wider the bid-offer spread (indicating lower
liquidity), the greater the reserve.

We also mark to market derivatives that are not trading contracts in accordance
with generally accepted accounting principles. There may be unique models for
these transactions, but the curves the company inputs into the models are the
same forward curves, which are described above.

We have developed independent controls to evaluate the reasonableness of our
valuation models and curves. However, there are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. Therefore, there could be a significant favorable or adverse effect
on future results of operations and cash flows if market prices at settlement
differ from the price models and curves.

AEP limits credit risk by extending unsecured credit to entities based on
internal ratings. AEP uses Moody's Investor Service, Standard and Poor's and
qualitative and quantitative data to independently assess the financial health
of counterparties on an ongoing basis. This data, in conjunction with the
ratings information, is used to determine appropriate risk parameters. AEP also
requires cash deposits, letters of credit and parental/affiliate guarantees as
security from certain below investment grade counterparties in our normal course
of business.

We trade electricity and gas contracts with numerous counterparties. Since our
open energy trading contracts are valued based on changes in market prices of
the related commodities, our exposures change daily. We believe that our credit
and market exposures with any one counterparty is not material to financial
condition at December 31, 2001. At December 31, 2001 less than 5% of the
counterparties were below investment grade as expressed in terms of Net Mark to
Market Assets. Net Mark to Market Assets represents the aggregate difference
(either positive or negative) between the forward market price for the remaining
term of the contract and the contractual price. The following table approximates
counterparty credit quality and exposure for AEP.



                    Futures,
                    Forward and
Counterparty        Swap
 Credit Quality:    Contracts      Options    Total
Year Ending December 31, 2001
                               (in millions)
AAA/Exchanges            $147        $ -        $147
AA                        140           4        144
A                         304           7        311
BBB                       932          34        966
Below   Investment
 Grade                     56          23         79
                           --          --         --
  Total                $1,579         $68     $1,647
                       ======         ===     ======

The counterparty credit quality and exposure for the registrant subsidiaries is
generally consistent with that of AEP.

We enter into transactions for electricity and natural gas as part of wholesale
trading operations. Electric and gas transactions are executed over-the-counter
with counterparties or through brokers. Gas transactions are also executed
through brokerage accounts with brokers who are registered with the Commodity
Futures Trading Commission. Brokers and counterparties require cash or cash
related instruments to be deposited on these transactions as margin against open
positions. The combined margin deposits at December 31, 2001 and 2000 was $55
million and $95 million. These magin accounts are restricted and therefore are
not included in cash and cash equivalents on the Balance Sheet. AEP and its
subsidiaries can be subject to further margin requirements should related
commodity prices change.

The margin deposits at December 31, 2001 for the registrants were:

                   (in thousands)

APCo                       $2,832
CPL                           299
CSP                         1,736
I&M                         1,879
KPCo                          698
OPCo                        2,862
PSO                           247
SWEPCo                        299
WTU                            99



<PAGE>


Financial Derivatives and Hedging

In the first quarter of 2001, AEP adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS 137 and SFAS 138. SFAS
133 requires that entities recognize all derivatives including fair value hedges
as either assets or liabilities and measure such derivatives at fair value.
Changes in the fair value of derivatives are included in earnings unless
designated as a cash flow hedge. This practice is commonly referred to as
mark-to-market accounting. Changes in the fair value of derivatives that are
designated as effective cash flow hedges are included in other comprehensive
income. AEP recorded a favorable transition adjustment to accumu-lated other
comprehensive income of $27 million at January 1, 2001 in connection with the
adoption of SFAS 133. Derivatives included in the transition adjustment are
interest rate swaps, foreign currency swaps and commodity swaps, options and
futures.


Most of the derivatives identified in the trans-ition adjustment were designated
as cash flow hedges and relate to foreign operations.

The amounts of net revenue margins (sales less purchases) in 2001, 2000, and
1999 for trading activities were:

                    2001        2000        1999
                    ----        ----        ----

                              (in millions)

Net Revenue
 Margin             $609        $435        $91


The amounts of revenues recorded in 2001, 2000 and 1999 for the registrant
subsidiaries were:
                      2001         2000        1999
                      ----         ----        ----
                               (in thousands)

APCo              $78,521      $72,649        $28,970
CPL                15,711        3,385           -
CSPCo              51,765       48,142         14,800
I&M                36,089       58,909         16,147
KPCo               12,466       23,417          5,563
OPCo               65,118       73,474         24,389
PSO                (2,483)       9,268           -
SWEPCo              7,897        6,404           -
WTU                (1,491)       1,821           -






<PAGE>




The fair value of open trading contracts that are marked-to-market are based on
management's best estimates using over-the-counter quotations and exchange
prices for short-term open trading contracts, and Company developed price curves
for open long-term trading contracts. The fair values of trading contracts at
December 31 are:

                                           2001                  2000
                                  ------------------     --------------------
                                           Fair                  Fair
                                           Value                 Value
                                           -----                 -----
                                       (in millions)        (in millions)
             Trading Assets

  Electric
               Futures and
                Options-NYMEX             $   11                $ -
               Physicals                   3,588                 8,791
               Options - OTC                 182                   215
               Swaps                         117                   164
                                          ------                ------
             Total Trading Assets         $3,898                $9,170
                                          ======                ======

  Gas
               Futures and
                Options-NYMEX             $  143                $ -
               Physicals                     238                   454
               Options - OTC                 978                 1,266
               Swaps                       5,646                 6,185
                                          ------                ------
             Total Trading Assets         $7,005                $7,905
                                          ======                ======

  Trading Liabilities

  Electric
               Futures and
                Options-NYMEX             $  -                 $  -
               Physicals                   (3,382)              (8,852)
               Options - OTC                 (101)                (133)
               Swaps                         (126)                (144)
                                          -------              -------
             Total Trading Liabilities    $(3,609)             $(9,129)
                                          =======              =======

  Gas
               Futures and
                Options-
                NYMEX                     $   (92)             $   (81)
               Physicals                      (80)                (419)
               Options - OTC               (1,076)                (934)
               Swaps                       (5,598)              (6,449)
                                          -------              -------
             Total Trading Liabilities    $(6,846)             $(7,883)
                                          =======              =======

                                           2001                  2000
                                  ------------------     --------------------
                                           Fair                  Fair
                                           Value                 Value
                                           -----                 -----
                                       (in thousands)        (in thousands)
             APCo
             Trading Assets

             Electric
               Futures and
                Options-NYMEX (net)     $   -                 $     -
               Physicals                 801,306               2,234,522
               Options - OTC              46,649                  59,814
               Swaps                      34,578                  51,470

             Trading Liabilities

             Electric
               Futures and
                Options-NYMEX (net)    $    -                 $      -
               Physicals                (748,016)              (2,258,596)
               Options - OTC             (21,895)                 (35,955)
               Swaps                     (36,921)                 (44,855)

             KPCo
             Trading Assets

             Electric
               Futures and
                Options-NYMEX (net)     $   -                 $   -
               Physicals                 197,545               530,828
               Options - OTC              11,503                14,207
               Swaps                       8,529                12,227



<PAGE>


             Trading Liabilities

             Electric
               Futures and
                Options-NYMEX (net)   $    -                   $    -
               Physicals               (190,389)                (536,512)
               Options - OTC             (5,372)                  (8,521)
               Swaps                     (9,106)                 (10,656)


                                           2001                  2000
                                  ------------------     --------------------
                                           Fair                  Fair
                                           Value                 Value
                                           -----                 -----
                                       (in thousands)        (in thousands)

             I&M
             Trading Assets

             Electric
               Futures and
                Options-NYMEX (net)     $   -                   $     -
               Physicals                 560,393                 1,349,950
               Options - OTC              31,397                    36,139
               Swaps                      22,950                    31,095

             Trading Liabilities

             Electric
               Futures and
                Options-NYMEX (net)      $    -                $      -
               Physicals                  (513,026)             (1,371,793)
               Options - OTC               (15,864)                (25,807)
               Swaps                       (24,505)                (27,099)


             OPCo
             Trading Assets

             Electric
               Futures and
                Options-NYMEX (net)       $   -                $     -
               Physicals                   668,142              1,776,259
               Options - OTC                38,108                 46,731
               Swaps                        29,730                 41,788

             Trading Liabilities

             Electric
               Futures and
                Options-NYMEX (net)      $    -               $      -
               Physicals                  (619,756)            (1,792,417)
               Options - OTC               (18,227)               (29,350)
               Swaps                       (32,551)               (37,398)


             CSPCo
             Trading Assets

             Electric
               Futures and
                Options-NYMEX (net)      $   -                 $     -
               Physicals                  491,290               1,192,203
               Options - OTC               28,612                  31,918
               Swaps                       21,211                  27,461

             Trading Liabilities

             Electric
               Futures and
                Options-NYMEX (net)     $    -                 $      -
               Physicals                 (456,613)              (1,204,948)
               Options - OTC              (13,403)                 (19,220)
               Swaps                      (22,648)                 (23,932)



<PAGE>



                                           2001                  2000
                                  ------------------     --------------------
                                           Fair                  Fair
                                           Value                 Value
                                           -----                 -----
                                       (in thousands)        (in thousands)
             CPL
             Trading Assets

             Electric
               Physicals                 $285,481              $ 542,626

             Trading Liabilities

             Electric
               Physicals                 (281,624)              (550,817)


             PSO
             Trading Assets

             Electric
               Physicals                  217,415                431,186


             Trading Liabilities

             Electric
               Physicals                 (214,981)              (437,694)


             SWEPCo
             Trading Assets

             Electric
               Physicals                  249,531                516,385

             Trading Liabilities

             Electric
               Physicals                 (246,631)              (524,180)


             WTU
             Trading Assets

             Electric
               Physicals                   84,784                171,597


             Trading Liabilities

             Electric
               Physicals                  (83,869)              (174,187)





<PAGE>


The FASB's Derivatives Implementation Group (DIG) Issued guidance, effective in
the third quarter of 2001, regarding the imple-mentation of SFAS 133 for certain
fuel supply contracts with volume optionality and electricity capacity
contracts. The guidance concluded that fuel supply contracts with volumetric
optionality cannot qualify for a normal purchase or sale exclusion from
mark-to-market accounting and provided guidance for determining when electricity
capacity con-racts can qualify as normal purchases or sales.

Predominantly all of AEP's contracts for coal, gas and electricity, which are
recorded on a settlement basis, do not meet the criteria of a financial
derivative instrument and qualify as normal purchases or sales. As a result they
are exempt from the DIG guidance described above and have not been
marked-to-market. Beginning July 1, 2001, the effective date of the DIG
guidance, certain of AEP's fuel supply contracts with volumetric optionality
that qualify as financial derivative instruments are marked to market with any
gain or loss recognized in the income statement. The effect of initially
adopting the DIG guidance at July 1, 2001, a favorable earnings mark-to-market
effect of $18 million, net of tax, is reported as a cumulative effect of an
accounting change on the income statement.


Cash flows from both derivative instruments and trading activities are included
in net cash flows from operating activities.

Certain derivatives may be designated for accounting purposes as a hedge of
either the fair value of an asset, liability or firm commitment, or a hedge of
the variability of cash flows related to a variable-priced asset, liability,
commitment or forecasted trans-action. To qualify for hedge accounting, the
relationship between the hedging instrument and the hedged item must be
documented to include the risk management objective and strategy for use of the
hedge instrument. At the inception of the hedge and on an ongoing basis, the
effectiveness of the hedge is assessed as to whether the hedge is highly
effective in offsetting changes in fair value or cash flows of the item being
hedged. Changes in the fair value that result from ineffectiveness of a hedge
under SFAS 133 are recognized currently in earnings through mark-to-market
accounting. Changes in the fair value of effective cash flow hedges are reported
in accumulated other comprehensive income if documented at inception. Gains and
losses from cash flow hedges in other comprehensive income are reclassified to
earnings in the accounting periods in which the variability of cash flows of the
hedged items affect earnings.

Cash flow hedges included in Accumulated Other Comprehensive income on the
Balance Sheet at December 31, 2001 are:

                   Hedging Assets    Hedging Liabilities    Other Comprehensive
                                                         Income (Loss) After Tax
                                                         -----------------------
                                           (in millions)
 Electric                     $16              $ (6)                    $  4
 Interest Rate                 -                (21)                     (12)
 Foreign Currency              -                 -                         5
                                                                        ----
                                                                        $ (3)

The following table represents the activity in Other Comprehensive Income
related to the effect of adopting SFAS 133 for derivative contracts that qualify
as cash flow hedges at December 31, 2001:

                                                     (in millions)
AEP consolidated
  Transition Adjustment, January 1, 2001                  $ 27
  Changes in fair value                                     (1)
  Reclasses from OCI to net income                         (29)
                                                           ---
Accumulated OCI derivative loss, December 31, 2001        $ (3)
                                                          ====




<PAGE>


                                                       (in thousands)
APCo
  Transition Adjustment, January 1, 2001                      $-
  Effective portion of changes in fair value                 (340)
  Reclasses from OCI to net income                             -
                                                               --
Accumulated OCI derivative gain, December 31, 2001          $(340)
                                                            =====

KPCo
  Transition Adjustment, January 1, 2001                    $(557)
  Effective portion of changes in fair value               (2,348)
  Reclasses from OCI to net income                          1,002
                                                            -----
Accumulated OCI derivative gain, December 31, 2001        $(1,903)
                                                          =======

I&M
  Transition Adjustment, January 1, 2001                    $(317)
  Effective portion of changes in fair value               (5,368)
  Reclasses from OCI to net income                          1,850
                                                            -----
Accumulated OCI derivative gain, December 31, 2001        $(3,835)
                                                          =======

OPCo
  Transition Adjustment, January 1, 2001                      $-
  Effective portion of changes in fair value                 (196)
  Reclasses from OCI to net income                             -
                                                               --
Accumulated OCI derivative gain, December 31, 2001          $(196)
                                                            =====


Approximately $15 million of net losses from cash flow hedges in accumulated
other comprehensive income at December 31, 2001 are expected to be reclassified
to net income in the next twelve months as the items being hedged settle. The
actual amounts reclassified from accumulated other comprehensive income to net
income can differ as a result of market price changes. The maximum term for
which the exposure to the variability of future cash flows is being hedged is 5
years.

We have derivatives under SFAS 133 that do not employ hedge accounting and are
not energy trading. The derivative's mark to market value at December 31, 2001
was a $22.7 million asset and a $13.1 million liability.


FINANCIAL INSTRUMENTS

Market Valuation of Non-Derivative Financial Instrument

The book values of cash and cash equivalents, accounts receivable, short-term
debt and accounts payable approximate fair value because of the short-term
maturity of these instruments. The book value of the pre-April 1983 spent
nuclear fuel disposal liability approximates the best estimate of its fair
value.

The fair values of long-term debt and preferred stock subject to mandatory
redemption are based on quoted market prices for the same or similar issues and
the current dividend or interest rates offered for instruments with similar
maturities. These instruments are not marked-to-market. The estimates presented
are not necessarily indicative of the amounts that we could realize in a current
market exchange. The book values and fair values of significant financial
instruments for AEP and its registrant subsidiaries December 31, 2001 and 2000
are summarized in the following tables.






<PAGE>




                                     2001                      2000
                            Book Value  Fair Value    Book Value  Fair Value
                            ----------  ----------    ----------  ----------
                                (in millions)            (in millions)

 AEP Consolidated
 Long-term Debt             $12,053     $12,002       $10,754     $10,812
 Preferred Stock                 95          93           100          98
 Trust Preferred Securities     321         320           334         326

                                (in thousands)           (in thousands)
 AEGCo

 Long-term Debt             $45,000     $45,268       $45,000     $45,000

 APCo

 Long-term Debt          $1,556,559  $1,439,531    $1,605,818  $1,601,313
 Preferred Stock             10,860      10,860        10,860      10,725

 CPL

 Long-term Debt          $1,253,768  $1,278,644    $1,454,559  $1,463,690
 Trust Preferred Securities 136,250     135,760       148,500     147,431

 CSPCo

 Long-term Debt            $791,848    $802,194      $899,615    $908,620
 Preferred Stock             10,000      10,100        15,000      14,892

 I&M

 Long-term Debt          $1,652,082  $1,672,392    $1,388,939  $1,377,230
 Preferred Stock             64,945      62,795        64,945      63,941

 KPCo

 Long-term Debt            $346,093    $350,233      $330,880    $335,408

 OPCo
 Long-term Debt          $1,203,841  $1,227,880    $1,195,493  $1,176,367
 Preferred Stock              8,850       8,837         8,850       8,780

 PSO
 Long-term Debt            $451,129    $462,903      $470,822    $476,964
 Trust Preferred Securities  75,000      74,730        75,000      72,180

 SWEPCo
 Long-term Debt            $645,283    $656,998      $645,963    $651,586
 Trust Preferred Securities 110,000     109,780       110,000     106,700

 WTU

 Long-term Debt            $255,967    $266,846      $255,843    $261,315



<PAGE>



Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The
trust investments which are classified as held for sale for decommissioning and
SNF disposal, reported in other assets, are recorded at market value in
accordance with SFAS 115. At December 31, 2001 and 2000 the fair values of the
trust investments were $933 million and $873 million, respectively, and had a
cost basis of $839 million and $768 million, respectively. The change in market
value in 2001, 2000, and 1999 was a net unrealized holding loss of $11 million,
and net unrealized holding gain of $6 million, and $18 million, respectively.


14. Income Taxes:

The details of AEP's consolidated income taxes as reported are as follows:

                   Year Ended December 31,
               ------------------------------
                 2001       2000       1999
                 ----       ----       ----
                        (in millions)
Federal:
 Current         $406       $ 766      $308
 Deferred          60        (237)      129
                 ----       -----      ----
     Total        466         529       437
                 ----       -----      ----
State:
 Current           61          50        25
 Deferred          35          (9)      -
                 ----       -----     -----
     Total         96          41        25
                 ----       -----      ----
International:
 Current            1           6         3
 Deferred           6          21        17
                 ----       -----      -----
     Total          7          27        20
                 ----       -----      -----

Total Income Tax
  as Reported    $569       $ 597      $482
                 ====       =====      ====
<TABLE>
<CAPTION>
The details of the registrant subsidiaries income taxes as reported are as
follows:

                                           AEGCo      APCo      CPL       CSPCo      I&M
Year Ended December 31, 2001                             (in thousands)

<S>                                      <C>       <C>       <C>        <C>       <C>
Charged (Credited) to Operating
 Expenses (net):
  Current                                $ 9,126   $ 71,623  $190,671   $ 88,013  $ 107,286
  Deferred                                (6,224)    27,198   (72,568)    14,923    (45,785)
  Deferred Investment Tax Credits           -        (3,237)   (5,207)    (3,899)    (7,377)
                                         -------   --------  --------   --------  ---------
    Total                                  2,902     95,584   112,896     99,037     54,124
                                         -------   --------  --------   --------  ---------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                    (56)   (19,165)     (398)   (13,803)   (10,590)
  Deferred                                  -        21,832      -        17,885     16,580
  Deferred Investment Tax Credits         (3,414)    (1,528)     -          (159)      (947)
                                         -------   --------  --------   --------  ---------
    Total                                 (3,470)     1,139      (398)     3,923      5,043
                                         -------   --------  --------   --------  ---------

Total Income Tax as Reported             $  (568)  $ 96,723  $112,498   $102,960  $  59,167
                                         =======   ========  ========   ========  =========

                                          KPCo      OPCo      PSO       SWEPCo     WTU
Year Ended December 31, 2001                             (in thousands)

Charged (Credited) to Operating
 Expenses (net):
  Current                                $ 7,726   $(62,298) $ 53,030   $ 77,965  $ 19,424
  Deferred                                 2,812    166,166   (16,726)   (31,396)  (11,891)
  Deferred Investment Tax Credits         (1,180)    (2,495)   (1,791)    (4,453)   (1,271)
                                         -------   --------  --------   --------  --------
    Total                                  9,358    101,373    34,513     42,116     6,262
                                         -------   --------  --------   --------   -------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                 (2,725)   (21,600)      352        542      (691)
  Deferred                                 3,481     20,014      -          -         -
  Deferred Investment Tax Credits            (72)      (794)     -          -         -
                                         -------   --------  --------   --------   -------
    Total                                    684     (2,380)      352        542      (691)
                                         -------   --------  --------   --------   -------

Total Income Tax as Reported             $10,042   $ 98,993  $ 34,865   $ 42,658   $ 5,571
                                         =======   ========  ========   ========   =======

                                         AEGCo      APCo      CPL       CSPCo      I&M
Year Ended December 31, 2000                             (in thousands)

Charged (Credited) to Operating
 Expenses (net):
  Current                                $ 8,746   $129,165  $ 89,403   $120,494  $ 134,796
  Deferred                                (5,842)     3,838    16,263     (7,746)  (126,748)
  Deferred Investment Tax Credits           -        (2,947)   (5,207)    (3,379)    (7,524)
                                         -------   --------  --------   --------  ---------
    Total                                  2,904    130,056   100,459    109,369        524
                                         -------   --------  --------   --------  ---------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                    (44)       327    (5,073)     3,777      2,950
  Deferred                                  -         4,764      -         3,683      1,569
  Deferred Investment Tax Credits         (3,396)    (1,968)     -          (103)      (330)
                                         -------   --------   -------   --------  ---------
    Total                                 (3,440)     3,123    (5,073)     7,357      4,189
                                         -------   --------   -------   --------  ---------

Total Income Tax as Reported             $  (536)  $133,179   $95,386   $116,726  $   4,713
                                         =======   ========   =======   ========  =========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                          KPCo      OPCo      PSO       SWEPCo     WTU
Year Ended December 31, 2000                             (in thousands)
<S>                                      <C>       <C>       <C>         <C>       <C>
Charged (Credited) to Operating
 Expenses (net):
  Current                                $17,878   $259,608  $11,597     $16,073   $ 6,774
  Deferred                                 2,521    (70,263)  25,453      14,653     9,401
  Deferred Investment Tax Credits         (1,187)    (1,824)  (1,791)     (4,482)   (1,271)
                                         -------   --------  -------     -------   -------
    Total                                 19,212    187,521   35,259      26,244    14,904
                                         -------   --------  -------     -------   -------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                    (50)    15,426   (1,306)     (1,476)     (222)
  Deferred                                 1,244      4,307     -           -       (1,237)
  Deferred Investment Tax Credits            (65)    (1,575)    -           -         -
                                         -------    -------  -------     -------   --------
    Total                                  1,129     18,158   (1,306)     (1,476)   (1,459)
                                         -------    -------  -------     -------   -------

Total Income Tax as Reported             $20,341   $205,679  $33,953     $24,768   $13,445
                                         =======   ========  =======     =======   =======
</TABLE>
<TABLE>
<CAPTION>

                                           AEGCo     APCo       CPL       CSPCo      I&M
Year Ended December 31, 1999                             (in thousands)
<S>                                      <C>       <C>       <C>         <C>       <C>
Charged (Credited) to Operating
 Expenses (net):
  Current                                $ 7,713   $69,522   $ 89,112    $79,410   $(67,368)
  Deferred                                (5,282)    8,981     19,620      9,737     85,345
  Deferred Investment Tax Credits           -       (2,659)    (5,207)    (3,432)    (7,547)
                                         -------   -------   --------    -------   --------
    Total                                  2,431    75,844    103,525     85,715     10,430
                                         -------   -------   --------    -------   --------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                   (146)   (1,548)    (5,604)    (3,122)     1,529
  Deferred                                  -        4,052        318        744        382
  Deferred Investment Tax Credits         (3,448)   (2,313)      -          (562)      (605)
                                         -------   -------   --------    -------   --------
    Total                                 (3,594)      191     (5,286)    (2,940)     1,306
                                         -------   -------   --------    -------   --------
Total Income Taxes as Reported           $(1,163)  $76,035   $ 98,239    $82,775   $ 11,736
                                         =======   =======   ========    =======   ========
</TABLE>
<TABLE>
<CAPTION>

                                            KPCo      OPCo       PSO      SWEPCo     WTU
Year Ended December 31, 1999                               (in thousands)
<S>                                       <C>       <C>        <C>       <C>        <C>
Charged (Credited) to Operating
 Expenses (net):
  Current                                 $14,897   $135,540   $20,777   $ 60,169   $ 3,328
  Deferred                                  2,239      4,205    14,521    (17,347)   12,026
  Deferred Investment Tax Credits          (1,193)    (1,825)   (1,791)    (4,565)   (1,275)
                                          -------   --------   -------   --------   -------
    Total                                  15,943    137,920    33,507     38,257    14,079
                                          -------   --------   -------   --------   -------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                    (424)    (3,256)   (2,215)    (4,826)      858
  Deferred                                    357       (539)     -          -         -
  Deferred Investment Tax Credits             (99)    (1,633)     -          -         -
                                          -------   --------   -------   --------   -------
    Total                                    (166)    (5,428)   (2,215)    (4,826)      858
                                          -------   --------   -------   --------   -------
Total Income Taxes as Reported            $15,777   $132,492   $31,292   $ 33,431   $14,937
                                          =======   ========   =======   ========   =======
</TABLE>
The following is a reconciliation for AEP Consolidated of the difference between
the amount of federal income taxes computed by multiplying book income before
federal income taxes by the statutory tax rate, and the amount of income taxes
reported.

                                                  Year Ended December 31,
                                             ---------------------------------
                                                2001       2000        1999
                                                ----       ----        ----
                                                       (in millions)
Net Income                                    $  971        $267      $  972
Extraordinary Items
 (net of income tax $20 million in 2001,
 $44 million in 2000 and $8 million in 1999)      50          35          14
Cumulative Effect of Accounting Change
 (net of income tax $2 million in 2001)          (18)         -           -
Preferred Stock Dividends                         10          11          19
                                              ------        ----      ------
Income Before Preferred Stock Dividends
  of Subsidiaries                              1,013         313       1,005
Income Taxes                                     569         597         482
                                              ------        ----      ------
Pre-Tax Income                                $1,582        $910      $1,487
                                              ======        ====      ======


Income Tax on Pre-Tax Income
  at Statutory Rate (35%)                       $554        $319        $520
Increase (Decrease) in Income Tax
  Resulting from the Following Items:
   Depreciation                                   48          77          71
   Corporate Owned Life Insurance                  4         247           2
   Investment Tax Credits (net)                  (37)        (36)        (38)
   Tax Effects of Foreign Operations             (27)        (29)        (54)
   Merger Transaction Costs                       -           49          -
   State Income Taxes                             62          26          16
   Other                                         (35)        (56)        (35)
                                                ----        ----        ----
Total Income Taxes as Reported                  $569        $597        $482
                                                ====        ====        ====
Effective Income Tax Rate                       36.0%       65.5%       32.5%
                                                ====        ====        ====
Shown below is a reconciliation for each AEP registrant subsidiary of the
difference between the amount of federal income taxes computed by multiplying
book income before federal income taxes by the statutory rate, and the amount of
income taxes reported.
<TABLE>
<CAPTION>
                                             AEGCo    APCo      CPL      CSPCo       I&M
Year Ended December 31, 2001                              (in thousands)
<S>                                         <C>     <C>       <C>       <C>         <C>
Net Income (Loss)                           $7,875  $161,818  $182,278  $161,876    $ 75,788
Extraordinary (Gains) Loss                    -         -        2,509    30,024        -
Income Tax Benefit                            -         -         -         -           -
Income Taxes                                  (568)   96,723   112,498   102,960      59,167
                                            ------  --------  --------  --------    --------
Pre-Tax Income (Loss)                       $7,307  $258,541  $297,285  $294,860    $134,955
                                            ======  ========  ========  ========    ========

Income Tax on Pre-Tax Income (Loss)
 at Statutory Rate (35%)                   $ 2,557  $ 90,490  $104,050  $103,201    $ 47,234
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                 230     2,977     8,477     2,757      21,224
  Corporate Owned Life Insurance              -          450      -          544        (148)
  Nuclear Fuel Disposal Costs                 -         -         -         -         (3,292)
  Allowance for Funds Used
    During  Construction                    (1,078)     -         -         -         (1,606)
  Rockport Plant Unit 2 Investment
    Tax Credit                                 374      -         -         -           -
  Removal Costs                               -         -         -         -           -
  Investment Tax Credits (net)              (3,414)   (4,765)   (5,207)   (4,058)     (8,324)
  State Income Taxes                         1,050     9,613     9,652     5,727       6,137
  Other                                       (287)   (2,042)   (4,474)   (5,211)     (2,058)
                                           -------  --------  --------  --------    --------
Total Income Taxes as Reported             $  (568) $ 96,723  $112,498  $102,960    $ 59,167
                                           =======  ========  ========  ========    ========

Effective Income Tax Rate                     N.M.     37.4%     37.9%     34.9%       43.8%
                                              ====     ====      ====      ====        ====
</TABLE>
<TABLE>
<CAPTION>

                                           KPCo      OPCo       PSO      SWEPCo     WTU
Year Ended December 31, 2001                               (in thousands)
<S>                                       <C>       <C>        <C>       <C>        <C>
Net Income                                $21,565   $147,445   $ 57,759  $ 89,367   $12,310
Extraordinary Loss                           -        18,348       -         -         -
Income Tax Benefit                           -          -          -         -         -
Income Taxes                               10,042     98,993     34,865    42,658     5,571
                                          -------   --------   --------  --------   -------
Pre-Tax Income                            $31,607   $264,786   $ 92,624  $132,025   $17,881
                                          =======   ========   ========  ========   =======

Income Tax on Pre-Tax Income
 at Statutory Rate (35%)                  $11,062   $ 92,675    $32,418  $ 46,209   $ 6,259
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                              1,581      7,972       -         -        1,463
  Corporate Owned Life Insurance              334      1,852       -         -         -
  Nuclear Fuel Disposal Costs                -          -          -         -         -
  Allowance for Funds Used
    During Construction                      -          -          -         -         -
  Rockport Plant Unit 2 Investment
    Tax Credit                               -          -          -         -         -
  Removal Costs                              (420)      -          -         -         -
  Investment Tax Credits (net)             (1,252)    (3,289)    (1,791)   (4,453)   (1,271)
  State Income Taxes                          318      9,752      5,137     5,451     1,283
  Other                                    (1,581)    (9,969)      (899)   (4,549)   (2,163)
                                          -------   --------    -------  --------   -------
Total Income Taxes as Reported            $10,042   $ 98,993    $34,865  $ 42,658   $ 5,571
                                          =======   ========    =======  ========   =======

Effective Income Tax Rate                    31.8%      37.4%      37.6%     32.3%     31.2%
                                             ====       ====       ====      ====      ====
</TABLE>
<TABLE>
<CAPTION>

                                            AEGCo      APCo      CPL      CSPCo       I&M
Year Ended December 31, 2000                              (in thousands)
<S>                                         <C>     <C>       <C>       <C>        <C>
Net Income (Loss)                           $7,984  $ 73,844  $189,567  $ 94,966   $(132,032)
Extraordinary (Gains) Loss                            (1,066)             39,384
Income Tax Benefit                            -       (7,872)     -      (14,148)       -
Income Taxes                                  (536)  133,179    95,386   116,726       4,713
                                            ------  --------  --------  --------   ---------
Pre-Tax Income (Loss)                       $7,448  $198,085  $284,953  $236,928   $(127,319)
                                            ======  ========  ========  ========   =========

Income Tax on Pre-Tax Income (Loss)
 at Statutory Rate (35%)                   $ 2,607  $ 69,330   $99,733  $ 82,925    $(44,561)
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                 452     7,606     7,556    10,529      20,378
  Corporate Owned Life Insurance              -       54,824      -       29,259      42,587
  Nuclear Fuel Disposal Costs                 -         -         -         -         (3,957)
  Allowance for Funds Used
    During  Construction                    (1,070)     -         -         -         (2,211)
  Rockport Plant Unit 2 Investment
    Tax Credit                                 374      -         -         -           -
  Removal Costs                               -       (1,197)     -         -           -
  Investment Tax Credits (net)              (3,396)   (4,915)   (5,207)   (3,482)     (7,854)
  State Income Taxes                           784     9,950     2,296        89       6,004
  Other                                       (287)   (2,419)   (8,992)   (2,594)     (5,673)
                                           -------  --------   -------  --------    --------
Total Income Taxes as Reported             $  (536) $133,179   $95,386  $116,726    $  4,713
                                           =======  ========   =======  ========    ========

Effective Income Tax Rate                     N.M.     67.2%     33.5%     49.3%       N.M.
                                              ====     ====      ====      ====        ====
</TABLE>
<TABLE>
<CAPTION>
                                           KPCo      OPCo       PSO      SWEPCo     WTU
Year Ended December 31, 2000                               (in thousands)
<S>                                       <C>       <C>        <C>        <C>       <C>
Net Income                                $20,763   $ 83,737   $ 66,663   $72,672   $27,450
Extraordinary Loss                                    40,157
Income Tax Benefit                           -       (21,281)      -         -         -
Income Taxes                               20,342    205,679     33,953    24,768    13,445
                                          -------   --------   --------   -------   -------
Pre-Tax Income                            $41,105   $308,292   $100,616   $97,440   $40,895
                                          =======   ========   ========   =======   =======

Income Tax on Pre-Tax Income
 at Statutory Rate (35%)                  $14,387   $107,903    $35,216  $ 34,104   $14,313
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                              1,827     27,577       -         -        1,204
  Corporate Owned Life Insurance            5,149     84,453       -         -         -
  Nuclear Fuel Disposal Costs                -          -          -         -         -
  Allowance for Funds Used
    During Construction                      -          -          -         -         -
  Rockport Plant Unit 2 Investment
    Tax Credit                               -          -          -         -         -
  Removal Costs                              (420)      -          -         -         -
  Investment Tax Credits (net)             (1,252)    (3,398)    (1,791)   (4,482)   (1,271)
  State Income Taxes                        1,597     (1,988)     3,037     1,650      -
  Other                                      (946)    (8,868)    (2,509)   (6,504)     (801)
                                          -------   --------    -------  --------   -------
Total Income Taxes as Reported            $20,342   $205,679    $33,953  $ 24,768   $13,445
                                          =======   ========    =======  ========   =======

Effective Income Tax Rate                    49.5%      66.8%      33.8%     25.4%     32.9%
                                             ====       ====       ====      ====      ====
</TABLE>
<TABLE>
<CAPTION>
                                            AEGCo      APCo       CPL       CSPCo     I&M
Year Ended December 31, 1999                                 (in thousands)
<S>                                         <C>       <C>        <C>        <C>        <C>
Net Income                                  $ 6,195   $120,492   $182,201   $150,270   $32,776
Extraordinary Loss                                                  8,488
Income Tax Benefit                             -          -        (2,971)      -         -
Income Taxes                                 (1,163)    76,035     98,239     82,775    11,736
                                            -------   --------   --------   --------   -------
Pre-Tax Income                              $ 5,032   $196,527   $285,957   $233,045   $44,512
                                            =======   ========   ========   ========   =======
Income Tax on Pre-Tax
 Income at Statutory Rate (35%)             $ 1,762   $ 68,785   $100,085    $ 81,566  $15,580
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                  446     12,593      7,981       8,846   19,966
  Corporate Owned Life Insurance               -          -          -           -         594
  Nuclear Fuel Disposal Costs                  -          -          -           -      (3,347)
  Allowance for Funds Used
   During Construction                       (1,069)      -          -           -      (2,174)
  Rockport Plant Unit 2
   Investment Tax Credit                        374       -          -           -        -
  Removal Costs                                -        (3,220)      -           -        -
  Investment Tax Credits (net)               (3,448)    (4,972)    (5,207)     (3,994)  (8,152)
  State Income Taxes                            467      3,305      6,965          58   (4,635)
Other                                           305       (456)   (11,585)     (3,701)  (6,096)
                                            -------   --------   --------    --------  -------
Total Income Taxes as Reported              $(1,163)  $ 76,035   $ 98,239    $ 82,775  $11,736
                                            =======   ========   ========    ========  =======

Effective Income Tax Rate                      N.M.       38.7%      34.4%       35.6%    26.4%
                                               ====       ====       ====        ====     ====
</TABLE>
<TABLE>
<CAPTION>

                                           KPCo      OPCo       PSO       SWEPCo     WTU
Year Ended December 31, 1999                               (in thousands)
<S>                                       <C>       <C>         <C>        <C>       <C>
Net Income                                $25,430   $212,157    $61,508    $83,194   $26,406
Extraordinary Loss                                                           4,632     8,402
Income Tax Benefit                           -           -         -        (1,621)   (2,941)
Income Taxes                               15,777    132,492     31,292     33,431    14,937
                                          -------   --------    -------   --------   -------
Pre-Tax Income                            $41,207   $344,649    $92,800   $119,636   $46,804
                                          =======   ========    =======   ========   =======
Income Tax on Pre-Tax Income
 at Statutory Rate (35%)                  $14,423   $120,628   $ 32,480   $ 41,873   $16,382
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                              1,843     17,517       -          -        1,120
  Corporate Owned Life Insurance             -           198       -          -         -
  Removal Costs                              (420)      -          -          -         -
  Investment Tax Credits (net)             (1,292)    (3,458)    (1,791)    (4,565)   (1,275)
  State Income Taxes                        1,809      1,090      3,054      2,924      -
Other                                        (586)    (3,483)    (2,451)    (6,801)   (1,290)
                                          -------   --------   --------   --------   -------
Total Income Taxes as Reported            $15,777   $132,492   $ 31,292   $ 33,431   $14,937
                                          =======   ========   ========   ========   =======

Effective Income Tax Rate                    38.3%      38.5%      33.8%      28.0%     32.0%
                                             ====       ====       ====       ====      ====
</TABLE>
<PAGE>


The following tables show the elements of the net deferred tax liability and the
significant temporary differences for AEP Consolidated and each registrant
subsidiary:

                                                           December 31,
                                                   --------------------------
                                                      2001            2000
                                                      ----            ----
                                                          (in millions)
Deferred Tax Assets                                 $ 1,248         $ 1,248
Deferred Tax Liabilities                             (6,071)         (6,123)
                                                    -------         -------
  Net Deferred Tax Liabilities                      $(4,823)        $(4,875)
                                                    =======         =======

Property Related Temporary Differences              $(3,963)        $(3,935)
Amounts Due From Customers For Future
  Federal Income Taxes                                 (245)           (252)
Deferred State Income Taxes                            (160)           (251)
Transition Regulatory Assets                           (268)           (163)
Regulatory Assets Designated for Securitization        (332)           (332)
All Other (net)                                         145              58
                                                    -------         -------
  Net Deferred Tax Liabilities                      $(4,823)        $(4,875)
                                                    =======         =======
<TABLE>
<CAPTION>
                                          AEGCo       APCo         CPL        CSPCo      I&M
December 31, 2001                                            (in thousands)
<S>                                     <C>         <C>        <C>          <C>        <C>
Deferred Tax Assets                     $  75,856   $ 162,334  $   130,863  $  74,767  $ 332,225
Deferred Tax Liabilities                 (103,831)   (865,909)  (1,294,658)  (518,489)  (732,756)
                                        ---------   ---------  -----------  ---------  ---------
  Net Deferred Tax Liabilities          $ (27,975)  $(703,575) $(1,163,795) $(443,722) $(400,531)
                                        =========   =========  ===========  =========  =========

Property Related Temporary Differences  $ (70,581)  $(530,298) $  (808,922) $(323,139) $(306,151)
Amounts Due From Customers For
  Future Federal Income Taxes               9,292     (55,206)     (70,174)    (9,839)   (46,756)
Deferred State Income Taxes                (3,822)    (56,747)        -        (8,968)   (38,015)
Translation Regulatory Assets                -        (34,783)        -       (78,298)      -
Net Deferred Gain on Sale and
  Leaseback-Rockport Plant Unit 2          40,816        -            -          -        27,157
Accrued Nuclear Decommissioning Expense      -           -            -          -        43,707
Deferred Fuel and Purchased Power            -           -            -          -       (26,270)
Deferred Cook Plant Restart Costs            -           -            -          -       (28,000)
Nuclear Fuel                                 -           -            -          -       (16,062)
Regulatory Assets Designated
  for Securitization                         -           -        (332,198)      -          -
All Other (net)                            (3,680)    (26,541)      47,499    (23,478)   (10,141)
                                        ---------   ---------  -----------  ---------  ---------
  Net Deferred Tax Liabilities          $ (27,975)  $(703,575) $(1,163,795) $(443,722) $(400,531)
                                        =========   =========  ===========  =========  =========
</TABLE>
<TABLE>
<CAPTION>

                                           KPCo        OPCo       PSO       SWEPCo        WTU
December 31, 2001                                           (in thousands)
<S>                                     <C>        <C>        <C>        <C>           <C>
Deferred Tax Assets                     $  30,927  $ 135,938  $  59,421  $   56,189    $  22,888
Deferred Tax Liabilities                 (199,231)  (933,827)  (356,298)   (425,970)    (167,937)
                                        ---------  ---------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $(168,304) $(797,889) $(296,877)  $(369,781)   $(145,049)
                                        =========  =========  =========   =========    =========

Property Related Temporary Differences  $(118,147) $(595,974) $(320,900)  $(362,884)   $(149,309)
Amounts Due From Customers For
  Future Federal Income Taxes             (20,215)   (61,130)    10,199      (6,441)       4,757
Deferred State Income Taxes               (25,267)   (18,440)      -           -            -
Translation Regulatory Assets                -      (154,947)      -           -            -
Deferred Fuel and Purchased Power            -        20,323       -           -            -
Provision for Mine Shutdown Costs            -        18,365       -           -            -
All Other (net)                            (4,675)    (6,086)    13,824        (456)        (497)
                                        ---------  ---------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $(168,304) $(797,889) $(296,877)  $(369,781)   $(145,049)
                                        =========  =========  =========   =========    =========
</TABLE>
<TABLE>
<CAPTION>
                                          AEGCo       APCo         CPL        CSPCo      I&M
December 31, 2000                                            (in thousands)
<S>                                     <C>         <C>        <C>          <C>        <C>
Deferred Tax Assets                     $  81,480   $ 178,487  $    67,184  $  88,198  $ 342,900
Deferred Tax Liabilities                 (114,408)   (860,961)  (1,309,981)  (510,957)  (830,845)
                                        ---------   ---------  -----------  ---------  ---------
  Net Deferred Tax Liabilities          $ (32,928)  $(682,474) $(1,242,797) $(422,759) $(487,945)
                                        =========   =========  ===========  =========  =========

Property Related Temporary Differences  $ (78,113)  $(510,950) $  (773,454) $(343,045) $(324,198)
Amounts Due From Customers For
  Future Federal Income Taxes              10,317     (55,085)     (72,426)   (11,142)   (55,218)
Deferred State Income Taxes                (5,478)    (86,351)        -          -       (69,982)
Translation Regulatory Asset                 -        (40,554)        -       (68,817)      -
Net Deferred Gain on Sale and
  Leaseback-Rockport Plant Unit 2          42,766        -            -          -        28,454
Accrued Nuclear Decommissioning Expense      -           -            -          -        34,702
Deferred Fuel and Purchased Power            -           -            -          -       (39,395)
Deferred Cook Plant Restart Costs            -           -            -          -       (42,000)
Nuclear Fuel                                 -           -            -          -       (28,319)
Regulatory Assets Designated
  for Securitization                         -           -        (332,198)      -          -
All Other (net)                            (2,420)     10,466      (64,719)       245      8,011
                                        ---------   ---------  -----------  ---------  ---------
  Net Deferred Tax Liabilities          $ (32,928)  $(682,474) $(1,242,797) $(422,759) $(487,945)
                                        =========   =========  ===========  =========  =========
</TABLE>
<TABLE>
<CAPTION>

                                           KPCo        OPCo       PSO       SWEPCo        WTU
December 31, 2000                                           (in thousands)
<S>                                     <C>        <C>        <C>        <C>           <C>
Deferred Tax Assets                     $  32,807  $ 330,878  $  60,010  $   47,615    $  16,604
Deferred Tax Liabilities                 (198,742)  (952,819)  (372,070)   (446,819)    (173,642)
                                        ---------  ---------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $(165,935) $(621,941) $(312,060)  $(399,204)   $(157,038)
                                        =========  =========  =========   =========    =========

Property Related Temporary Differences  $(116,109) $(586,039) $(313,248)  $(375,427)   $(150,264)
Amounts Due From Customers For
  Future Federal Income Taxes             (19,680)   (57,759)    11,082      (6,015)       4,723
Deferred State Income Taxes               (29,695)   (14,282)   (36,487)       -            -
Translation Regulatory Asset                 -       (53,149)      -           -            -
Deferred Fuel and Purchased Power            -      (116,224)      -           -            -
Provision for Mine Shutdown Costs            -        63,995       -           -            -
Postretirement Benefits                      -        93,306       -           -            -
All Other (net)                              (451)    48,211     26,593     (17,762)     (11,497)
                                        ---------  ---------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $(165,935) $(621,941) $(312,060)  $(399,204)   $(157,038)
                                        =========  =========  =========   =========    =========
</TABLE>
We have settled with the IRS all issues from the audits of our consolidated
federal income tax returns for the years prior to 1991. We have received Revenue
Agent's Reports from the IRS for the years 1991 through 1996, and have filed
protests contesting certain proposed adjustments. Returns for the years 1997
through 2000 are presently being audited by the IRS. Management is not aware of
any issues for open tax years that upon final resolution are expected to have a
material adverse effect on results of operations.

COLI Litigation - On February 20, 2001, the U.S. District Court for the Southern
District of Ohio ruled against AEP in its suit against the United States over
deductibility of interest claimed by AEP in its consolidated federal income tax
returns related to its COLI program. AEP had filed suit to resolve the IRS'
assertion that interest deductions for AEP's COLI program should not be allowed.
In 1998 and 1999 the Company paid the disputed taxes and interest attributable
to COLI interest deductions for taxable years 1991-98 to avoid the potential
assessment by the IRS of additional interest on the contested tax. The payments
were included in other assets pending the resolution of this matter. As a result
of the U.S. District Court's decision to deny the COLI interest deductions, net
income was reduced by $319 million in 2000. The Company has filed an appeal of
the U.S. District Court's decision with the U.S. Court of Appeals for the 6th
Circuit.

The earnings reductions for affected registrant subsidiaries are as follows:

                     (in millions)
APCo                      $ 82
CSPCo                       41
I&M                         66
KPCo                         8
OPCo                       118

The Company has not recognized a deferred tax liability for temporary
differences related to investments in certain subsidiaries located outside of
the United States because such differences are deemed to be essentially
permanent in duration. If the investments were sold, the temporary differences
may become taxable resulting in a tax liability of approximately $66 million.

The Company joins in the filing of a consolidated federal income tax return with
its affiliated companies in the AEP System. The allocation of the AEP System's
current consolidated federal income tax to the System companies is in accordance
with SEC rules under the 1935 Act. These rules permit the allocation of the
benefit of current tax losses to the System companies giving rise to them in
determing their current tax expense. The tax loss of the System parent company,
AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the
exception of the loss of the parent company, the method of allocation
approximates a separate return result for each company in the consolidated
group.



<PAGE>


15.  Basic and Diluted Earnings Per Share:

The calculation of basic and diluted earnings per share is based on the amounts
of income and weighted average shares shown in the table below.

                        2001     2000    1999
                        ----     ----    ----
                       (in millions - except
                         per share amounts)
Income:
- ------
Income before
 Extraordinary Item and
 Cumulative Effect      $1,003   $302    $986

Extraordinary Losses
 (net of tax)              (50)   (35)    (14)
Cumulative Effect of
 Accounting Change
 (net of tax)               18     -       -
                        ------   ----     ----

Net Income              $  971   $267     $972
                        ======   ====     ====

Weighted Average Shares:
 Average common
  Shares outstanding       322    322      321
 Assumed conversion of
  stock options
  (see Note 11)              1     -        -
                           ---    ---      ---
 Diluted average comon
  shares outstanding       323    322      321
                           ===    ===      ===

Basic and Diluted
 Earnings Per Share:
 Income before
  Extraordinary item
  and cumulative effect  $3.11 $ 0.94   $ 3.07
 Extraordinary losses
  (net of tax)           (0.16) (0.11)   (0.04)
 Cumulative effect
  of accounting change
  (net of tax)            0.06    -       -
                         ----- ------  ------
                         $3.01 $ 0.83  $ 3.03

The assumed conversion of stock options does not affect income for purposes of
calculating diluted earnings per share. Basic and diluted EPS are the same in
2001, 2000 and 1999 since the effect on weighted average shares outstanding is
little or nil.

16.  Supplementary Information:
<TABLE>
<CAPTION>
                                                          Year Ended December 31,
                                                          -----------------------
                                                     2001           2000         1999
                                                     ----           ----         ----
                                                               (in millions)
<S>                                                      <C>          <C>          <C>
AEP Consolidated Purchased Power -
 Ohio Valley Electric Corporation
  (44.2% owned by AEP System)                            $127          $86          $64

Cash was paid for:
  Interest (net of capitalized amounts)                  $972         $842         $979
  Income Taxes                                           $569         $449         $270

Noncash Investing and Financing Activities:
 Acquisitions under Capital Leases                        $17         $118          $80
Assumption of Liabilities Related to Acquisitions        $171           -            -

Exchange of Communication Investment for Common Stock      $5           -            -
</TABLE>
<PAGE>


The amounts of power purchased by the registrant subsidiaries from Ohio Valley
Electric Corporation, which is 44.2% owned by the AEP System, for the years
ended December 31, 2001, 2000, and 1999 were:

                              APCo         CSPCo         I&M         OPCo
                              ----         -----         ---         ----
                                             (in thousands)
Year Ended December 31, 2001   $45,542      $12,626      $20,723      $47,757
Year Ended December 31, 2000    30,998        8,706       15,204       31,134
Year Ended December 31, 1999    21,774        6,006       10,227       25,623


17. Power, Distribution and
      Communications Projects:

Power Projects

AEP owns interests of 50% or less in domestic unregulated power plants with a
capacity of 1,483 MW located in Colorado, Florida and Texas. In addition to the
domestic projects, AEP has equity interests in international power plants
totaling 1,788 MW. AEP has other projects in various stages of development.

Investments in power projects that are 50% or less owned are accounted for by
the equity method and reported in investments in power, distribution and
communications projects on the balance sheet. At December 31, 2001, six domestic
and four international power projects are accounted for under the equity method.
The six domestic projects are combined cycle gas turbines that provide steam to
a host commercial customer and are considered Qualifying Facilities (QF) under
the Public Utilities Regulatory Policies Act of 1978. The four international
power plants are classified as Foreign Utility Companies (FUCO) under the Energy
Policies Act of 1992. All of the power projects accounted for under the equity
method have unrelated third-party partners.

All of the above power projects have project-level financing, which is
non-recourse to AEP. AEP or AEP subsidiaries have guaranteed $30 million of
domestic partnership obligations for performance under power purchase agreements
and for debt service reserves in lieu of cash deposits. AEP has guaranteed $94
million of additional equity for two projects.


Distribution Projects

We own a 44% equity interest in Vale, a Brazilian electric operating company
which was purchased for a total of $149 million. On December 1, 2001 we
converted a $66 million note receivable and accrued interest into a 20% equity
interest in Caiua (Brazilian electric operating company), a subsidiary of Vale.
Vale and Caiua have experienced losses from operations and our investment has
been affected by the devaluation of the Brazilian Real. The cumulative equity
share of operating and foreign currency translation losses through December 31,
2001 is approximately $46 million and $54 million, respectively, net of tax. The
cumulative equity share of operating and foreign currency translation losses
through December 31, 2000 is approximately $33 million and $49 million,
respectively, net of tax. Both investments are covered by a put option, which,
if exercised, requires our partners in Vale to purchase our Vale and Caiua
shares at a minimum price equal to the U.S. dollar equivalent of the original
purchase price. As a result, management has concluded that the investment
carrying amount should not be reduced below the put option value unless it is
deemed to be an other than temporary impairment and our partners in Vale are
deemed unable to fulfill their responsibilities under the put option. Management
has evaluated through an independent third-party, the ability of its Vale
partners to fulfill their responsibilities under the put option agreement and
has concluded that our partners should be able to fulfill their
responsibilities.

Management believes that the decline in the value of its investment in Vale in
US dollars is not other than temporary. As a result and pursuant to the put
option agreement, these losses have not been applied to reduce the carrying
values of the Vale and Caiua investments. As a result we will not recognize any
future earnings from Vale and Caiua until the operating losses are recovered.
Should the impairment of our investment become other than temporary due to our
partners in Vale becoming unable to fulfill their responsibilities, it would
have an adverse effect on future results of operations.

Management will continue to monitor both the status of the losses and of its
partners ability to fulfill its obligations under the put.

Communication Projects

AEP provides telecommunication services to businesses and telecommunication
companies through a broadband fiber optic network. AEP's investment in the
network include fiber optic cable, electronic equipment and colocation
facilities that house the equipment. The investments are both owned and leased
with a majority of the leased investments being indefeasible rights of use
(IRUs) for fiber optic cable for periods ranging from 20 to 30 years.
Telecommunication revenue is accounted for using the accrual method of
accounting as service is rendered over the contractual term. Lease obligations
related to these investment are included in the lease payment amounts disclosed
in the lease note.

AEP has a 46.25% ownership interest in a joint venture, AFN networks, LLC (AFN),
which is engaged in the operation and construction of a fiber optic network. AFN
both owns and leases fiber optic cable and electronic equipment with the
majority of leases being IRUs of fiber optic cable for periods ranging from 20
to 25 years. AEP accounts for AFN under the equity method of accounting and has
recorded its pro rata share of the losses during the start up phase. AEP has a
credit agreement with AFN that enables AFN to borrow up to $91.5 million at
market interest rates to finance their construction and operations. The amount
available to AFN at December 31, 2001 is $61 million.


AEP has a 50% ownership interest in a joint venture, American Fiber Touch, LLC
(AFT), that is constructing a fiber optic line from Missouri to Illinois. AEP
accounts for AFT under the equity method of accounting and has recorded its pro
rata share of the losses of AFT during the start up phase. AEP has recently
decided to withdraw from this venture and fully provided for the expected loss
in exiting the joint venture in December 2001.

18. Leases:

Leases of property, plant and equipment are for periods up to 35 years and
require payments of related property taxes, maintenance and operating costs. The
majority of the leases have purchase or renewal options and will be renewed or
replaced by other leases.

Lease rentals for both operating and capital leases are generally charged to
operating expenses in accordance with rate-making treatment for regulated
operations. Capital leases for non-regulated property are accounted for as if
the assets were owned and financed. The components of rental costs are as
follows:



<PAGE>
<TABLE>
<CAPTION>
                                   AEP     AEGCo     APCo     CPL      CSPCo     I&M      KPCo
Year Ended December 31, 2001                            (in thousands)
<S>                             <C>       <C>      <C>       <C>      <C>      <C>       <C>
Lease Payments on
 Operating Leases               $296,000  $76,262  $ 6,142   $5,948   $ 7,063  $104,574  $1,191
Amortization of Capital Leases    85,000      281   12,099     -        7,206    17,933   2,740
Interest on Capital Leases        22,000       55    3,789     -        2,396     4,424     808
                                --------  -------  -------   ------   -------  --------  ------
 Total Lease Rental Costs       $403,000  $76,598  $22,030   $5,948   $16,665  $126,931  $4,739
                                ========  =======  =======   ======   =======  ========  ======

                                   OPCo     PSO     SWEPCo    WTU
Year Ended December 31, 2001                (in thousands)
Lease Payments on
 Operating Leases                $63,913   $4,010   $2,277   $1,534
Amortization of Capital Leases    14,443     -        -        -
Interest on Capital Leases         5,818     -        -        -
                                 -------   ------   ------   ------
 Total Lease Rental Costs        $84,174   $4,010   $2,277   $1,534
                                 =======   ======   ======   ======
</TABLE>
<TABLE>
<CAPTION>
                                   AEP     AEGCo     APCo     CPL      CSPCo      I&M     KPCo
Year Ended December 31, 2000                            (in thousands)
<S>                             <C>       <C>      <C>      <C>       <C>      <C>       <C>
Lease Payments on
 Operating Leases               $237,000  $73,858  $ 7,128  $  -      $ 7,683  $ 81,446  $1,978
Amortization of Capital Leases   121,000      281   13,900     -        7,776    26,341   3,931
Interest on Capital Leases        38,000       55    3,930     -        2,690    10,908   1,054
                                --------  -------  -------  -------   -------  --------  ------
 Total Lease Rental Costs       $396,000  $74,194  $24,958  $  -      $18,149  $118,695  $6,963
                                ========  =======  =======  =======   =======  ========  ======

                                   OPCo     PSO     SWEPCo    WTU
Year Ended December 31, 2000                (in thousands)
Lease Payments on
 Operating Leases                $51,981   $ -      $ -      $ -
Amortization of Capital Leases    37,280     -        -        -
Interest on Capital Leases         9,584     -        -        -
                                 -------   ------   ------   ------
 Total Lease Rental Costs        $98,845   $ -      $ -      $ -
                                 =======   ======   ======   ======
</TABLE>
<TABLE>
<CAPTION>
                                   AEP     AEGCo     APCo     CPL      CSPCo     I&M     KPCo
Year Ended December 31, 1999                            (in thousands)
Lease Payments on
<S>                             <C>       <C>       <C>      <C>      <C>      <C>      <C>
 Operating Leases               $247,000  $74,269   $ 5,647  $ -      $ 5,687  $ 81,611 $   199
Amortization of Capital Leases    97,000      364    13,749    -        7,427    11,320   4,299
Interest on Capital Leases        35,000       64     4,267    -        2,720     9,338   1,162
                                --------  -------   -------  ------   -------  --------  ------
 Total Lease Rental Costs       $379,000  $74,697   $23,663  $ -      $15,834  $102,269  $5,660
                                ========  =======   =======  ======   =======  ========  ======

                                   OPCo     PSO     SWEPCo    WTU
Year Ended December 31, 1999                (in thousands)
Lease Payments on
 Operating Leases               $ 60,026   $ -      $ -      $ -
Amortization of Capital Leases    35,622     -        -        -
Interest on Capital Leases         9,552     -        -        -
                                --------   ------   ------   ------
 Total Lease Rental Costs       $105,200   $ -      $ -      $ -
                                ========   ======   ======   ======
</TABLE>
<TABLE>
<CAPTION>
Property, plant and equipment under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:

                                  AEP     AEGCo      APCo    CSPCo      I&M       KPCo    OPCo
Year Ended December 31, 2001                             (in thousands)
<S>                             <C>       <C>      <C>      <C>       <C>       <C>     <C>
Property, Plant and Equipment
 Under Capital Leases
 Production                     $ 40,000  $1,983   $ 2,712  $ 6,380   $  4,826  $ 1,138 $ 22,477
 Distribution                    177,000                                14,593
 Other:
  Mining Assets and Other        722,000     129    82,292  $54,999     86,267   17,658  114,944
                                --------  ------   -------  -------   --------  ------- --------
   Total Property, Plant
    and Equipment                939,000   2,112    85,004   61,379    105,686   18,796  137,421
 Accumulated Amortization        256,000   1,801    38,745   26,044     43,768    9,213   57,429
                                --------  ------   -------  -------   --------  ------- --------
  Net Property, Plant and
   Equipment Under
   Capital Leases               $683,000  $  311   $46,259  $35,335   $ 61,918  $ 9,583 $ 79,992
                                ========  ======   =======  =======   ========  ======= ========

Obligations Under Capital Leases:
  Noncurrent Liability          $356,000  $   76   $33,928  $27,052   $ 51,093  $ 6,742 $ 64,261
  Liability Due Within One Year   95,000     235    12,357    7,835     10,840    2,841   16,405
                                --------  ------   -------  -------   --------  ------- --------
      Total Obligations Under
       Capital Leases           $451,000  $  311   $46,285  $34,887   $ 61,933  $ 9,583 $ 80,666
                                ========  ======   =======  =======   ========  ======= ========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                  AEP     AEGCo      APCo    CSPCo      I&M       KPCo    OPCo
Year Ended December 31, 2000                             (in thousands)
<S>                             <C>       <C>      <C>      <C>       <C>       <C>     <C>
Property, Plant and Equipment
 Under Capital Leases
 Production                     $ 42,000  $2,017   $ 6,276  $     2   $  7,023  $ 1,730 $ 24,709
 Distribution                    151,000                                14,595
 Other:
  Nuclear Fuel
  (net of amortization)           90,000                                89,872
  Mining Assets and Other        619,000     177    93,437  $68,352     97,383   22,072  200,308
                                --------  ------   -------  -------   --------  ------- --------
   Total Property, Plant
    and Equipment                902,000   2,194    99,713   68,354    208,873   23,802  225,017
 Accumulated Amortization        288,000   1,603    36,553   25,422     45,700    9,618  108,436
                                --------  ------   -------  -------   --------  ------- --------
  Net Property, Plant and
   Equipment Under
   Capital Leases               $614,000  $  591   $63,160  $42,932   $163,173  $14,184 $116,581
                                ========  ======   =======  =======   ========  ======= ========

Obligations Under Capital Leases:
  Noncurrent Liability          $419,000  $  358   $50,350  $35,199   $ 62,325  $11,091 $ 83,866
  Liability Due Within One Year  195,000     233    12,810    7,733    100,848    3,093   32,715
                                --------  ------   -------  -------   --------  ------- --------
      Total Obligations Under
       Capital Leases           $614,000  $  591   $63,160  $42,932   $163,173  $14,184 $116,581
                                ========  ======   =======  =======   ========  ======= ========
</TABLE>
Properties under operating leases and related obligations are not included in
the Consolidated Balance Sheets.

CPL, PSO, SWEPCo and WTU do not lease property, plant and equipment under
capital leases.
<TABLE>
<CAPTION>
Future minimum lease payments consisted of the following at December 31, 2001:

                                   AEP    AEGCo    APCo     CSPCo     I&M        KPCo      OPCo
Capital                                                (in thousands)
- -------
<C>                             <C>       <C>    <C>       <C>      <C>       <C>        <C>
2002                            $ 96,000  $217   $13,718   $ 8,932  $11,759   $ 3,093    $ 18,516
2003                              81,000   132    11,625     7,284   10,028     2,441      17,521
2004                              63,000    20     9,371     6,111    7,947     1,824      14,701
2005                              49,000     6     6,440     5,248    6,282     1,449      11,520
2006                              42,000     1     4,690     3,903    5,335       891      10,305
Later Years                      397,000    -      7,613    11,400   17,882     1,548      28,948
                                --------  ----   -------   -------  -------   -------    --------
Total Future Minimum
 Lease Payments                  728,000   376    53,457    42,878   59,233    11,246     101,511
Less Estimated Interest Element  277,000    65     7,172     7,991   (2,700)    1,663      20,845
                                --------  ----   -------   -------  -------   -------    --------
Estimated Present Value of
  Future Minimum Lease Payments $451,000  $311   $46,285   $34,887  $61,933   $ 9,583    $ 80,666
                                ========  ====   =======   =======  =======   =======    ========
</TABLE>
<TABLE>
<CAPTION>
                                AEP        AEGCo      APCo     CPL     CSPCo      I&M       KPCo
                                                         (in thousands)
<C>                          <C>        <C>         <C>      <C>      <C>      <C>         <C>
Noncancellable Operating Leases
2002                         $  286,000 $   73,854  $ 3,193  $ 5,948  $ 2,104  $   82,627  $  717
2003                            271,000     73,854    3,108    5,948    1,991      79,923     691
2004                            255,000     73,854    2,402    5,948    1,623      77,104     571
2005                            245,000     73,854    2,155    5,948    1,308      75,736     544
2006                            243,000     73,854    1,887    5,948    1,279      75,595     398
Later Years                   2,671,000  1,181,664    4,563     -       3,198   1,186,678   1,842
                             ---------- ----------  -------  -------  -------  ----------  ------
Total Future Minimum
 Lease Payments              $3,971,000 $1,550,934  $17,308  $29,740  $11,503  $1,577,663  $4,763
                             ========== ==========  =======  =======  =======  ==========  ======
</TABLE>

                                  OPCo       PSO     SWEPCo     WTU
                                            (in thousands)
Noncancellable Operating Leases
2002                           $ 62,945     $4,010  $ 2,277   $1,534
2003                             62,914      4,010    2,277    1,534
2004                             63,323      4,010    2,277    1,534
2005                             62,836      4,010    2,277    1,534
2006                             63,242      4,010    2,277    1,534
Later Years                     244,069       -        -        -
                               --------     ------  -------   ------
Total Future Minimum
 Lease Payments                $559,329     $20,050 $11,385   $7,670
                               ========     ======= =======   ======



<PAGE>


Operating leases include lease agreements with special purpose entities related
to Rockport Plant Unit 2 and the Gavin Plant's flue gas desulfurization system
(Gavin Scrubbers). The Rockport Plant lease resulted from a sale and leaseback
transaction in 1989. The gain from the sale was deferred and is being amortized
over the term of the lease which expires in 2022. The Gavin Scrubber lease
expires in 2009. AEP has no ownership interest in the special purpose entities
and does not guarantee their debt. The special purpose entities are not
consolidated in AEP's financial statements in accordance with applicable
accounting standards. As a result, neither the leased plant and equipment nor
the debt of the special purpose entities is included on AEP's balance sheet. The
future lease payment obligations to the special purpose entities are included in
the above table of future minimum lease payments under noncancellable operating
leases.

19.  Lines of Credit and Sale of Receivables:

The AEP System uses short-term debt, primarily commercial paper, to meet
fluctuations in working capital requirements and other interim capital needs.
AEP has established a money pool to coordinate short-term borrowings for certain
subsidiaries, including AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo
and WTU and also incurs borrowings outside the money pool for other
subsidiaries. As of December 31, 2001, AEP had revolving credit facilities
totaling $3.5 billion to support its commercial paper program. At December 31,
2001, AEP had $3.2 billion outstanding in short-term borrowings of which $2.9
billion was under these credit facilities. The maximum amount of such short-term
borrowings outstanding during the year, which had a weighted average interest
rate for the year of 4.95%, was $3.3 billion during March 2001.


The registrant subsidiaries incurred interest expense for amounts borrowed from
the AEP money pool as follows:

                        Year Ended December 31,
                       -------------------------
                       2001      2000       1999
                       ----      ----       ----
                            (in millions)
AEGCo                   0.8        -          -
APCo                    9.8        -          -
CPL                    11.4      16.9       14.1
CSPCo                   5.0       1.4         -
I&M                    13.1       0.8         -
KPCo                    2.3        -          -
OPCo                   14.6       9.2         -
PSO                     6.3       7.5        2.0
SWEPCo                  3.4       4.2        4.7
WTU                     3.1       2.7        0.6

Interest income earned from amounts advanced to the AEP money pool by the
registrant subsidiaries were:

                        Year Ended December 31,
                       -------------------------
                       2001      2000       1999
                       ----      ----       ----
                            (in millions)
APCo                    1.7        -          -
CPL                     0.1        -          -
CSPCo                   0.8       1.1         -
I&M                     1.6       9.0         -
KPCo                    0.1       1.8         -
OPCo                    8.6       3.4         -
SWEPCo                  0.1        -         0.1
WTU                      -         -         0.2

Outstanding short-term debt for AEP Consolidated consisted of:

                                 December 31,
                               2001        2000
                               ----        ----
                                 (in millions)
Balance Outstanding:
  Notes Payable               $  207      $  193
  Commercial paper             2,948       4,140
                              ------      ------
    Total                     $3,155      $4,333
                              ======      ======

AEP Credit, which does not participate in the money pool, issued commercial
paper on a stand-alone basis up to May 30, 2001. AEP Credit provides low-cost
financing for utilities, including both AEP's electric utility operating
companies and non-affiliates, through factoring receivables which arise
primarily from the sale and delivery of electricity in the ordinary course of
business. In January 2002 AEP Credit stopped purchasing accounts receivable from
non-affiliated electric utility companies.

On May 30, 2001, AEP Credit stopped issuing commercial paper and allowed its $2
billion unsecured revolving credit facility to mature. Funding needs were
replaced on May 30, 2001 by a $1.5 billion variable funding note. The variable
funding note was, in turn, replaced on December 31, 2001 when AEP Credit entered
into a sale of receivables agreement with a group of banks and commercial paper
conduits.

Under the sale of receivables agreement, AEP Credit sells an interest in the
receivables it acquired from its clients to the commercial paper conduits and
banks and receives cash. This transaction constitutes a sale of receivables in
accordance with SFAS 140 allowing the receivables to be taken off of AEP
Credit's balance sheet. AEP has no ownership interest in the commercial paper
conduits and does not consolidate these entities in accordance with GAAP. We
continue to service the receivables. At December 31, 2001, the banks had a $1.2
billion commitment under the sale of receivables agreement to purchase
receivables from AEP Credit of which $1 billion was outstanding. Of the $1
billion of receivables sold, $485 million respresented non-affiliate
receivables. The commitment available under the sale of receivables agreement
declines to $1.1 billion on January 31, 2002 and to $900 million on February 28,
2002, where it remains until the expiration of the commitment on May 30, 2002.
AEP Credit maintains a retained interest in the receivables sold and this
interest is pledged as collateral for the collection of the receivables sold.
The fair value of the retained interest is based on book value due to the
short-term nature of the accounts receivable less an allowance for anticipated
uncollectible accounts.








<PAGE>



At year ended December 31, 2001, AEP Credit had:

                                    $ Millions
Accounts Receivable Sold               1,045
Accounts Receivable
 Retained Interest Less
  Uncollectible Accounts
  and Pledged as Collateral              143
Deferred Revenue from
 Servicing Accounts
 Receivable                                5
Loss on Sale of Accounts
 Receivable                                8
Initial Variable
 Discount Rate                          2.28%

Retained Interest if 10%
 Adverse change in
 Uncollectible Accounts                  142

Retained Interest if 20%
 Adverse change in
 Uncollectible Accounts                  140



Historical loss and delinquency amount for the Customer Accounts Receivable
managed portfolio for the year ended December 31, 2001.

                                                                   Face Value
                                                              December 31, 2001
                                                                   $ Millions

Customer Accounts Receivable Retained                                  $  626
Miscellaneous Accounts Receivable Retained                              1,365
Allowance for Uncollectible Accounts Retained                            (109)
                                                                       ------
         Total Net Balance Sheet Accounts Receivable                    1,882

Customer Accounts Receivable Securitized (Affiliate)                      560
Customer Accounts Receivable Securitized (Non-Affiliate)                  485
                                                                       ------
         Total Accounts Receivable managed                             $2,927
                                                                       ======

Net Uncollectible Accounts Written off for the Year Ended
  December 31, 2001                                                        87
                                                                           --



<PAGE>


Customer Accounts receivable retained and securitized for the domestic electric
operating companies are managed by AEP Credit as a pool between affiliate and
non-affiliate accounts receivable. Miscellaneous Account Receivable have been
fully retained and not securitized.

Delinquent Customer Accounts Receivable over 60 days old at December 31, 2001:

                               (in millions)
Affiliated                            $ 92
Non-Affiliated                          17
                                      ----
Total                                 $109
                                      ====

Under the factoring arrangement the registrant subsidiaries (excluding AEGCo)
sell without recourse certain of their customer accounts receivable and accrued
utility revenue balances to AEP Credit and are charged a fee based on AEP Credit
financing costs, uncollectible accounts experience for each company's
receivables and administrative costs. The costs of factoring customer accounts
receivable is reported as an operating expense. At December 31, 2001 the amount
of factored accounts receivable and accrued utility revenues for each registrant
subsidiary was as follows:

Company        (in millions)
- -------
APCo                       $ 61
CPL                          89
CSPCo                       106
I&M                          95
KPCo                         26
OPCo                        100
PSO                          43
SWEPCo                       47
WTU                          23


The fees paid by the registrant subsidiaries to AEP Credit for factoring
customer accounts receivable were:

                               Year Ended December 31,
                             -------------------------
                         2001          2000         1999
                         ----          ----         ----
                                    (in millions)

APCo                    $ 5.2           $-           $-
CPL                      14.7          15.7         14.7
CSPCo                    15.2          10.8           -
I&M                       8.5           6.8           -
KPCo                      2.7           1.9           -
OPCo                     12.8           8.4           -
PSO                       9.6           8.3          6.5
SWEPCo                    7.4           9.2          9.3
WTU                       3.8           4.0          3.5




<PAGE>


20.  Unaudited Quarterly Financial Information:

The unaudited quarterly financial information for AEP Consolidated follows:

                                    2001 Quarterly Periods Ended
                       -------------------------------------------------------
                        March 31        June 30       Sept. 30       Dec. 31
                       ----------     ----------     ----------     ----------
(In Millions - Except
Per Share Amounts)
- -----------------------
Operating Revenues      $14,165         $14,528        $18,385        $14,179
Operating Income            601             672            862            260
Income Before
 Extraordinary Items
 and Cumulative Effect      266             280            403             54
Net Income                  266             232            421             52
Earnings per Share Before
 Extraordinary Items
 And Cumulative Effect*    0.83            0.87           1.25           0.17
Earnings per Share**       0.83            0.72           1.31           0.16

                                    2000 Quarterly Periods Ended
                       -------------------------------------------------------
                        March 31        June 30       Sept. 30       Dec. 31
                       ----------     ----------     ----------     ----------
(In Millions - Except
Per Share Amounts)
- -----------------------

Operating Revenues       $6,117          $8,137        $11,608       $10,844
Operating Income            428             308            873           395
Income (Loss) Before
 Extraordinary Items
 and Cumulative Effect      140             (18)           403          (223)
Net Income (Loss)           140              (9)           359          (223)
Earnings (Loss) per Share
 Before Extraordinary Items
 and Cumulative Effect     0.43           (0.06)          1.25         (0.68)
Earnings (Loss) per Share  0.43           (0.03)          1.11         (0.68)

*  Amounts for 2001 do not add to $3.11 earnings per share before extraordinary
   items and cumulative effect due to rounding.
** Amounts for 2001 do not add to $3.01 earnings per share due to rounding.

The unaudited quarterly financial information for each AEP registrant subsidiary
follows:
<TABLE>
<CAPTION>
     Quarterly Periods
     Ended                                AEGCo      APCo         CPL        CSPCo       I&M
     -----------------                    -----      ----         ---        -----       ---
                                                            (in thousands)
<S>                                      <C>      <C>           <C>       <C>         <C>
     2001
     March 31
      Operating Revenues                 $60,507  $1,974,127    $603,412  $1,125,573  $1,291,538
      Operating Income                     1,807      88,152      64,152      51,932      52,698
      Income (Loss) Before
        Extraordinary Items                1,980      61,787      35,031      37,671      32,363
      Net Income (Loss)                    1,980      61,787      35,031      37,671      32,363

     June 30
      Operating Revenues                 $52,217  $1,849,304    $648,499  $1,109,095  $1,259,874
      Operating Income                     1,882      59,362      82,351      62,894      47,340
      Income (Loss) Before
        Extraordinary Items                2,063      36,419      52,518      47,418      27,374
      Net Income (Loss)                    2,063      36,419      52,518      21,011      27,374

     September 30
      Operating Revenues                 $57,417  $2,017,159  $1,235,941  $1,297,704  $1,402,178
      Operating Income                     1,615      60,381     112,598      76,920      44,509
      Income Before Extraordinary Items    2,051      30,317      83,702      65,318      25,064
      Net Income                           2,051      30,317      83,702      65,318      25,064

     December 31
      Operating Revenues                 $57,407  $1,158,840    $833,875    $767,491    $850,035
      Operating Income                     1,673      67,091      36,630      60,431      15,158
      Income (Loss) Before
        Extraordinary Items                1,781      33,295      13,536      41,493      (9,013)
      Net Income (Loss)                    1,781      33,295      11,027      37,876      (9,013)
</TABLE>
<TABLE>
<CAPTION>
     Quarterly Periods
     Ended                                 KPCo      OPCo          PSO        SWEPCo       WTU
     -----------------                     ----      ----          ---        ------       ---
                                                              (in thousands)
<S>                                     <C>       <C>           <C>         <C>         <C>
     2001
     March 31
      Operating Revenues                $459,157  $1,699,665    $356,139    $425,689    $195,006
      Operating Income                    12,604      64,756       8,340      33,986       5,392
      Income Before Extraordinary Items    7,075      53,397      (1,560)     19,869         891
      Net Income                           7,075      53,397      (1,560)     19,869         891

     June 30
      Operating Revenues                $439,131  $1,627,177    $398,194    $434,795    $192,839
      Operating Income                     8,364      47,067      21,942      32,649      12,428
      Income Before Extraordinary Items    2,742      32,094      11,921      17,784       6,133
      Net Income                           2,742      10,579      11,921      17,784       6,133

     September 30
      Operating Revenues                $485,820  $1,819,792    $910,428  $1,028,742    $429,623
      Operating Income                    12,587      69,668      59,914      60,194      17,745
      Income Before Extraordinary Items    5,312      51,378      51,069      46,357      14,067
      Net Income                           5,312      51,378      51,069      46,357      14,067

     December 31
      Operating Revenues                $275,287  $1,115,768    $536,488    $685,222    $246,803
      Operating Income                    14,123      59,219       6,793      19,378      (2,175)
      Income (Loss) Before
        Extraordinary Items                6,436      28,924      (3,670)      5,357      (8,781)
      Net Income (Loss)                    6,436      32,091      (3,670)      5,357      (8,781)
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
     Quarterly Periods
     Ended                                  AEGCo      APCo       CPL      CSPCo        I&M
     -----------------                      -----      ----       ---      -----        ---
                                                            (in thousands)
<S>                                        <C>      <C>         <C>       <C>         <C>
     2000
     March 31
      Operating Revenues                   $56,866  $1,021,678  $316,328  $633,305    $708,150
      Operating Income                       2,395      78,246    38,650    44,124     (15,251)
      Income Before Extraordinary Items      2,445      47,664     8,139    27,471     (36,553)
      Net Income                             2,445      47,664     8,139    27,471     (36,553)

     June 30
      Operating Revenues                   $56,928  $1,460,774  $437,911  $928,332  $1,011,706
      Operating Income                       1,746      58,208    95,717    50,798     (18,599)
      Income Before Extraordinary Items      1,653      30,240    67,553    35,335     (39,181)
      Net Income                             1,653      39,178    67,553    35,335     (39,181)

     September 30
      Operating Revenues                   $55,658  $1,538,340  $795,794  $960,837  $1,060,654
      Operating Income                       2,209      65,750   120,653    83,562      36,056
      Income Before Extraordinary Items      1,972      36,112    89,974    65,542      15,190
      Net Income                             1,972      36,112    89,974    40,306      15,190

     December 31
      Operating Revenues                   $59,064  $1,066,516  $799,470  $643,141  $  761,574
      Operating Income                       2,074      (1,050)   52,078    17,393     (36,908)
      Income (Loss) Before
        Extraordinary Items                  1,914     (49,110)   23,901    (8,146)    (71,488)
      Net Income (Loss)                      1,914     (49,110)   23,901    (8,146)    (71,488)
</TABLE>
<TABLE>
<CAPTION>
     Quarterly Periods
     Ended                                  KPCo        OPCo       PSO     SWEPCo       WTU
     -----------------                      ----        ----       ---     ------       ---
                                                             (in thousands)
<S>                                       <C>       <C>         <C>       <C>         <C>
     2000
     March 31
      Operating Revenues                  $231,454  $1,047,837  $161,329  $207,756    $ 93,335
      Operating Income                      15,557      65,113    10,860    22,731       9,781
      Income Before Extraordinary Items      8,052      46,216     1,165     7,663       3,833
      Net Income                             8,052      46,216     1,165     7,663       3,833

     June 30
      Operating Revenues                  $342,660  $1,436,330  $209,172  $272,409    $130,742
      Operating Income                       9,456      79,968    24,502    33,296      16,938
      Income Before Extraordinary Items      2,449      58,233    14,700    18,786       8,070
      Net Income                             2,449      58,233    14,700    18,786       8,070

     September 30
      Operating Revenues                  $359,296  $1,484,663  $555,236  $573,891    $249,330
      Operating Income                      13,790      96,652    56,437    61,312      16,565
      Income Before Extraordinary Items      6,761      77,061    54,329    47,537      10,670
      Net Income                             6,761      58,185    54,329    47,537      10,670

     December 31
      Operating Revenues                  $243,457  $1,023,270  $504,282  $628,670    $286,155
      Operating Income                      10,935     (14,906)    4,870    10,939       9,057
      Income (Loss) Before
        Extraordinary Items                  3,501     (78,897)   (3,531)   (1,314)      4,877
      Net Income (Loss)                      3,501     (78,897)   (3,531)   (1,314)      4,877
</TABLE>

<PAGE>

Earnings for the fourth quarter 2001 increased $275 million from the prior year
primarily due to the effect of charges recorded in 2000 from a ruling by the IRS
disallowing interest deductions from AEP's COLI program and a write down for the
proposed sale of Yorkshire. Fourth quarter 2001 earnings were also favorably
impacted by the return to service in December 2000 of Unit 1 of the Cook Plant
after an extended outage and the receipt of a contract cancellation fee from a
non-affiliated factoring client of AEP Credit.

21.  Trust Preferred Securities:

The following Trust Preferred Securities issued by the wholly-owned statutory
business trusts of CPL, PSO and SWEPCo were outstanding at December 31, 2001 and
December 31, 2000. They are classified on the balance sheets as Certain
Subsidiaries Obligated, Mandatorily Redeemable Preferred Securities of
Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such
Subsidiaries. The Junior Subordinated Debentures mature on April 30, 2037. CPL
reacquired 490,000 and 60,000 trust preferred units during 2001 and 2000,
respectively.
<TABLE>
<CAPTION>
                                                Units issued/
                                                Outstanding                                    Description of
                                                At 12/31/01                                    Underlying
                                                -----------
Business Trust           Security                                Amount at December 31,        Debentures of Registrant
- --------------           --------                                ----------------------        ------------------------
                                                                      2001           2000
                                                                        (in millions)
<S>                      <C>                    <C>                  <C>            <C>        <C>
CPL Capital I            8.00%, Series A         5,450,000            $136           $149      CPL, $141 million,
                                                                                               8.00%, Series A

PSO Capital I            8.00%, Series A         3,000,000              75             75      PSO, $77 million,
                                                                                               8.00%, Series A

SWEPCo Capital I         7.875%, Series A        4,400,000             110            110      SWEPCO, $113 million,
                                                ----------             ---            ---
                                                12,850,000            $321           $334      7.875%, Series A
                                                ==========            ====           ====
</TABLE>

Each of the business trusts is treated as a subsidiary of its parent company.
The only assets of the business trusts are the subordinated debentures issued by
their parent company as specified above. In addition to the obligations under
their subordinated debentures, each of the parent companies has also agreed to a
security obligation which represents a full and unconditional guarantee of its
capital trust obligation.

22.  Minority Interest in Finance Subsidiary:

In August 2001, AEP formed Caddis Partners, LLC (Caddis), a consolidated
subsidiary, and sold a non-controlling preferred member interest in Caddis to an
unconsolidated special purpose entity (Steelhead) for $750 million. Under the
provisions of the Caddis formation agreements, the preferred member interest
receives quarterly a preferred return equal to an adjusted floating reference
rate (4.413% at December 31, 2001). The $750 million received replaces interim
funding used to acquire Houston Pipe Line Company in June 2001.

The preferred interest is supported by natural gas pipeline assets and $321.4
million of preferred stock issued by an AEP subsidiary to the AEP affiliate
which has the managing member interest in Caddis. Such preferred stock is
convertible into common stock of AEP upon the occurrence of certain events. AEP
can elect not to have the transaction supported by such preferred stock if the
preferred interest were reduced by $225 million. In addition, Caddis has the
right to redeem the preferred member interest at any time.

The initial period of the preferred interest is through August 2006. At the end
of the initial period, Caddis will either reset the preferred rate, re-market
the preferred member interests to new investors, redeem the preferred member
interests, in whole or in part including accrued return, or liquidate in
accordance with the provisions of applicable agreements.

Steelhead has the right to terminate the transaction and liquidate Caddis upon
the occurrence of certain events including a default in the payment of the
preferred return. Steelhead's rights include: forcing a liquidation of Caddis
and acting as the liquidator, and requiring the conversion of the $321.4 million
of AEP subsidiary preferred stock into AEP common stock. If the preferred member
interest exercised its rights to liquidate under these conditions, then AEP
would evaluate whether to refinance at that time or relinquish the assets that
support the preferred member interest. Liquidation of the preferred interest or
of Caddis could impact AEP's liquidity.

Caddis and the AEP subsidiary which acts as its managing member are each a
limited liability company, with a separate existence and identity from its
members, and the assets of each are separate and legally distinct from AEP. The
results of operations, cash flows and financial position of Caddis and such
managing member are consolidated with AEP for financial reporting purposes. The
preferred member interest and payments of the preferred return are reported on
AEP's income statement and balance sheet as Minority Interest in Finance
Subsidiary.

23.  Jointly Owned Electric Utility Plant:

CPL, CSPCo, PSO, SWEPCo and WTU have generating units that are jointly owned
with unaffiliated companies. Each of the participating companies is obligated to
pay its share of the costs of any such jointly owned facilities in the same
proportion as its ownership interest. Each AEP registrant subsidiary's
proportionate share of the operating costs associated with such facilities is
included in its statements of income and the investments are reflected in its
balance sheets under utility plant as follows:
<TABLE>
<CAPTION>
                                                            Company's Share
                                                               December 31,
                                                     2001                        2000
                                          --------------------------  ---------------------------
                                 Percent     Utility    Construction     Utility   Construction
                                   of         Plant         Work          Plant         Work
                                Ownership  in Service   in Progress    in Service   in Progress
                                --------- ------------ -------------  ------------ ------------
                                                   (in thousands)            (in thousands)
<S>                                   <C>      <C>            <C>         <C>           <C>
CPL:
  Oklaunion Generating Station
  (Unit No. 1)                         7.8     $   37,728     $   318     $   37,236    $   395
  South Texas Project Generating
   Station (Units No. 1 and 2)        25.2      2,360,452      41,571      2,373,575     19,292
                                               ----------     -------     ----------    -------
                                               $2,398,180     $41,889     $2,410,811    $19,687
                                               ==========     =======     ==========    ========

CSP:
  W.C. Beckjord Generating Station
   (Unit No. 6)                       12.5     $   14,292     $   884     $   14,108    $   178
  Conesville Generating Station
   (Unit No. 4)                       43.5         81,697         494         80,103        261
  J.M. Stuart Generating Station      26.0        193,760      27,758        191,875     10,086
  Wm. H. Zimmer Generating Station    25.4        704,951       2,634        706,549      5,265
  Transmission                         (a)         61,476          91         61,820        451
                                               ----------     -------     ----------    -------
                                               $1,056,176     $31,861     $1,054,455    $16,241
                                               ==========     =======     ==========    =======

PSO:
  Oklaunion Generating Station
   (Unit No. 1)                       15.6     $   82,646     $   634     $   81,185    $   817
                                               ==========     =======     ==========    ========

SWEPCo:
  Dolet Hills Generating Station
   (Unit No. 1)                       40.2     $  234,747     $   675     $  231,442    $ 1,984
  Flint Creek Generating Station
   (Unit No. 1)                       50.0         83,953         213         82,899        852
  Pirkey Generating Station
   (Unit No. 1)                       85.9        439,430      10,577        437,069        435
                                               ----------     -------     ----------    -------
                                               $  758,130     $11,465     $  751,410    $ 3,271
                                               ==========     =======     ==========    ========

WTU:
  Oklaunion Generating Station
   (Unit No. 1)                       54.7     $  279,419     $ 1,651     $  277,624    $ 3,295
                                               ==========     =======     ==========    =======
</TABLE>
(a)      Varying percentages of ownership.



<PAGE>




The accumulated depreciation with respect to each AEP registrant subsidiary's
share of jointly owned facilities is shown below:

                        December 31,
                        2001             2000
                        ----             ----
                            (in thousands)
CPL                      $863,130         $834,722
CSPCo                     410,756          389,558
PSO                        35,653           33,669
SWEPCo                    392,728          367,558
WTU                       100,430           98,045

24.  Related Party Transactions

AEP System Power Pool

APCo, CSPCo, I&M, KPCo 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 their 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, KPCo and OPCo have been
parties to the AEP System Interim Allowance Agreement which provides, among
other things, for the transfer of SO2 Allowances associated with transactions
under the Interconnection Agreement. As part of AEP's restructuring settlement
agreement filed with FERC, CSPCo and OPCo would no longer be parties to the
Interconnection agreement and certain other modifications to its terms would
also be made.

Power marketing and trading transactions (trading activities) are conducted by
the AEP Power Pool and shared among the parties under the Interconnection
Agreement. Trading activities involve the purchase and sale of electricity under
physical forward contracts at fixed and variable prices and the trading of
electricity contracts including exchange traded futures and options and
over-the-counter options and swaps. The majority of these transactions represent
physical forward contracts in the AEP System's traditional marketing area and
are typically settled by entering into offsetting contracts. The regulated
physical forward contracts are recorded on a gross basis in the month when the
contract settles.

In addition, the AEP Power Pool enters into transactions for the purchase and
sale of electricity options, futures and swaps, and for the forward purchase and
sale of electricity outside of the AEP System's traditional marketing area.

CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Restated and
Amended Operating Agreement originally dated as of January 1, 1997 (CSW
Operating Agreement). The CSW Operating Agreement requires the operating
companies of the west zone to maintain specified annual planning reserve margins
and requires the subsidiaries that have capacity in excess of the required
margins to make such capacity available for sale to other AEP subsidiaries as
capacity commitments. The CSW Operating Agreement also delegates to AEP Service
Corporation the authority to coordinate the acquisition, disposition, planning,
design and construction of generating units and to supervise the operation and
maintenance of a central control center. The CSW Operating Agreement has been
accepted for filing and allowed to become effective by FERC.

AEP's System Integration Agreement provides for the integration and coordination
of AEP's east and west zone operating subsidiaries, joint dispatch of generation
within the AEP System, and the distribution, between the two operating zones, of
costs and benefits associated with the System's generating plants. It is
designed to function as an umbrella agreement in addition to the AEP
Interconnection Agreement and the CSW Operating Agreement, each of which will
continue to control the distribution of costs and benefits within each zone.



<PAGE>

<TABLE>
<CAPTION>
The following table shows the revenues derived from sales to the Pools and
direct sales to affiliates for years ended December 31, 2001, 2000 and 1999:

                                          APCo    CSPCo     I&M     KPCo    OPCo    AEGCo
Related Party Revenues                                (in thousands)
<S>                                     <C>      <C>     <C>      <C>     <C>      <C>
2001     Sales to East System Pool      $ 91,977 $44,185 $239,277 $34,735 $431,637 $   -
         Sales to West System Pool        24,892  13,971   15,596   6,117   19,797     -
         Direct Sales To East Affiliates  54,777    -        -       -      55,450  227,338
         Direct Sales To West Affiliates  (3,133) (1,705)  (1,905)   (744)  (2,590)    -
         Other                             2,772  11,060    2,071   2,258    7,072     -
                                        -------- ------- -------- ------- -------- --------
            Total Revenues              $171,285 $67,511 $255,039 $42,366 $511,366 $227,338
                                        ======== ======= ======== ======= ======== ========

2000     Sales to East System Pool      $ 81,013 $36,884 $200,474 $36,554 $502,140 $   -
         Sales to West System Pool         7,697   4,095    4,614   1,829    6,356     -
         Direct Sales To East Affiliates  59,106    -        -       -      66,487  227,983
         Direct Sales To West Affiliates   4,092   2,262    2,510     972    3,421     -
         Other                             2,770   6,124    2,710   2,466    4,043     -
                                        -------- ------- -------- ------- -------- --------
            Total Revenues              $154,678 $49,365 $210,308 $41,821 $582,447 $227,983
                                        ======== ======= ======== ======= ======== ========

1999     Sales to East System Pool      $ 41,869 $15,136  $50,624 $43,157 $337,699 $   -
         Direct Sales To East Affiliates  57,201    -        -       -      50,968  152,559
         Other                             1,162   4,582      345   1,145      825     -
                                        -------- ------- -------- ------- -------- --------
            Total Revenues              $100,232 $19,718  $50,969 $44,302 $389,492 $152,559
                                        ======== =======  ======= ======= ======== ========
</TABLE>
                                         CPL      PSO     SWEPCo   WTU
Related Party Revenues                            (in thousands)

2001     Sales to East System Pool       $  -    $     4  $  -    $  -
         Sales to West System Pool        19,865   3,317    8,073     322
         Direct Sales To East Affiliates   3,697   2,833    3,238   1,228
         Direct Sales To West Affiliates  12,617  30,668   67,930   9,350
         Other                             5,583     (51)      (3)  7,781
                                         ------- -------  ------- -------
            Total Revenues               $41,762 $36,771  $79,238 $18,681
                                         ======= =======  ======= =======

2000     Sales to East System Pool       $  -    $  -     $  -    $  -
         Sales to West System Pool        23,421   7,323    5,546     194
         Direct Sales To East Affiliates  (3,348) (1,990)  (3,008) (1,116)
         Direct Sales To West Affiliates  12,516  21,995   62,178   7,645
         Other                             5,163 (12,680)  (1,592) 11,931
                                         ------- -------  ------- -------
            Total Revenues               $37,752 $14,648  $63,124 $18,654
                                         ======= =======  ======= =======

1999     Sales to West System Pool       $ 6,124 $ 3,097  $ 4,527 $   401
         Direct Sales To West Affiliates   7,470   7,968   49,542   2,576
         Other                            14,177   2,652       48  11,790
                                         ------- -------  ------- -------
             Total Revenues              $27,771 $13,717  $54,117 $14,767
                                         ======= =======  ======= =======

<TABLE>
<CAPTION>
The following table shows the purchased power expense incurred from purchases
from the Pools and affiliates for the years ended December 31, 2001, 2000, and
1999:

                                                APCo     CSPCo    I&M      KPCo     OPCo
Related Party Purchases                                      (in thousands)

<S>                                            <C>      <C>      <C>      <C>       <C>
2001     Purchases from East System Pool       $346,582 $292,034 $ 79,030 $ 61,816  $62,350
         Purchases from West System Pool            296      165      185       72      235
         Direct Purchases from East Affiliates     -        -     159,022   68,316     -
         Direct Purchases from West Affiliates     -        -        -        -        -
                                               -------- -------- -------- --------  -------
             Total Purchases                   $346,878 $292,199 $238,237 $130,204  $62,585
                                               ======== ======== ======== ========  =======

2000     Purchases from East System Pool       $355,305 $287,482 $106,644 $ 58,150  $50,339
         Purchases from West System Pool            455      260      285      108      390
         Direct Purchases from East Affiliates     -        -     158,537   69,446     -
         Direct Purchases from West Affiliates       14        8        9        3       12
                                               -------- -------- -------- --------  -------
             Total Purchases                   $355,774 $287,750 $265,475 $127,707  $50,741
                                               ======== ======== ======== ========  =======

1999     Purchases from East System Pool       $130,991 $199,574 $112,350  $19,502 $ 20,864
         Direct Purchases from East Affiliates     -        -      88,022   64,498     -
                                               -------- -------- --------  ------- ---------
             Total Purchases                   $130,991 $199,574 $200,372  $84,000 $ 20,864
                                               ======== ======== ========  ======= ========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
                                                CPL      PSO     SWEPCo    WTU
Related Party Purchases                                  (in thousands)

<S>                                             <C>      <C>      <C>     <C>
2001     Purchases from East System Pool        $  -     $ 1,327  $  -    $     4
         Purchases from West System Pool            415    5,877    3,810  11,689
         Direct Purchases from East Affiliates   12,657   37,445   27,744   4,614
         Direct Purchases from West Affiliates   45,569   34,603    9,696  40,349
                                                -------  -------  ------- -------
             Total Purchases                    $58,641  $79,252  $41,250 $56,656
                                                =======  =======  ======= =======

2000     Purchases from East System Pool        $  -     $20,100  $  -    $  -
         Purchases from West System Pool          1,696    5,386    4,379  18,444
         Direct Purchases from East Affiliates      251    2,117      695      71
         Direct Purchases from West Affiliates   30,644   33,185    8,264  39,258
                                                -------  -------  ------- -------
             Total Purchases                    $32,591  $60,788  $13,338 $57,773
                                                =======  =======  ======= =======

1999     Purchases from West System Pool        $   895  $ 6,992   $1,295 $ 7,266
         Direct Purchases from West Affiliates   15,778   27,627    6,256  19,325
                                                -------  -------   ------ -------
             Total Purchases                    $16,673  $34,619   $7,551 $26,591
                                                =======  =======   ====== =======
</TABLE>
The above summarized related party revenues and expenses are reported in their
entirely, without elimination, and are presented as operating revenues
affiliated and purchased power affiliated on the income statement of each AEP
Power Pool member. Since all of the above pool members are included in AEP's
consolidated results, the above summarized related party transactions are
eliminated in total in AEP's consolidated revenues and expenses.

<PAGE>


AEP System Transmission Pool

APCo, CSPCo, I&M, KPCo 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."

The following table shows the net (credits) or charges allocated among the
parties to the Transmission Agreement during the years ended December 31, 1998,
1999 and 2000:

            1999         2000          2001
            ----         ----          ----
                    (in thousands)

APCo     $ (8,300)    $ (3,400)    $ (3,100)
CSPCo      39,000       38,300       40,200
I&M       (43,900)     (43,800)     (41,300)
KPCo      (4,300)      (6,000)      (4,600)
OPCo       17,500       14,900        8,800

CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Transmission
Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA
established a coordinating committee, which is charged with the responsibility
of overseeing the coordinated planning of the transmission facilities of the
west zone operating subsidiaries, including the performance of transmission
planning studies, the interaction of such subsidiaries with independent system
operators (ISO) and other regional bodies interested in transmission planning
and compliance with the terms of the Open Access Transmission Tariff (OATT)
filed with the FERC and the rules of the FERC relating to such tariff.

Under the TCA, the west zone operating subsidiaries have delegated to AEP
Service Corporation the responsibility of monitoring the reliability of their
transmission systems and administering the OATT on their behalf. The TCA also
provides for the allocation among the west zone operating subsidiaries of
revenues collected for transmission and ancillary services provided under the
OATT.



AEP's System Transmission Integration Agreement provides for the integration and
coordination of the planning, operation and maintenance of the transmission
facilities of AEP's east and west zone operating subsidiaries. Like the System
Integration Agreement, the System Transmission Integration Agreement functions
as an umbrella agreement in addition to the AEP Transmission Agreement and the
Transmission Coordination Agreement. The System Transmission Integration
Agreement contains two service schedules that govern:

o        The allocation of transmission costs and revenues.
o        The allocation of third-party transmission costs and revenues and
         System dispatch costs.

The Transmission Integration Agreement anticipates that additional service
schedules may be added as circumstances warrant.

Unit Power Agreements and Other

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 expiration of the lease term of Unit 2 of the Rockport Plant
unless extended in specified circumstances.

Pursuant to an assignment between I&M and KPCo, and a unit power agreement
between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy
associated therewith) available to AEGCo from both units of the Rockport Plant.
KPCo 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 KPCo unit power agreement expires
on December 31, 2004.

APCo and OPCo, jointly own two power plants. The costs of operating these
facilities are apportioned between the owners based on ownership interests. Each
company's share of these costs is included in the appropriate expense accounts
on each company's consolidated statements of income. Each company's investment
in these plants is included in electric utility plant on its consolidated
balance sheets.

I&M provides barging services to AEGCo, APCo and OPCo. I&M records revenues from
barging services as nonoperating income. AEGCo, APCo and OPCo record costs paid
to I&M for barging services as fuel expense. The amount of affiliated revenues
and affiliated expenses were:


                    Year Ended December 31,
                     2001     2000     1999
                     ----     ----     ----
Company                   (in millions)

I&M - revenues      $30.2    $23.5    $28.1
AEGCo - expense       8.5      8.8      8.5
APCo - expense       11.5      7.8     10.5
OPCo - expense       10.2      6.9      9.1

American Electric Power Service Corporation (AEPSC) provides certain managerial
and professional services to AEP System companies. The costs of the services are
billed to its affiliated companies by AEPSC on a direct-charge basis, whenever
possible, and on reasonable bases of proration for shared services. The billings
for services are made at cost and include no compensation for the use of equity
capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are
capitalized or expensed depending on the nature of the services rendered. AEPSC
and its billings are subject to the regulation of the SEC under the 1935 Act.

<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS


        The following is a combined presentation of management's discussion and
analysis of financial condition, contingencies and other matters for AEP and
certain of its registrant subsidiaries. Management's discussion and analysis of
results of operations for AEP and each of its subsidiary registrants is
presented with their financial statements earlier in this document. The
following is a list of sections of management's discussion and analysis of
financial condition, contingencies and other matters and the registrant to which
they apply:

Financial Condition         AEP, APCo, CPL,
                            I&M, OPCo, SWEPCo

Market Risks                AEP, AEGCo, APCo,
                            CPL, CSPCo, I&M,
                            KPCo, OPCo, PSO,
                            SWEPCo, WTU

Industry Restructuring      AEP, APCo, CPL,
                            CSPCo, I&M, OPCo,
                            PSO, SWEPCo, WTU

Litigation                  AEP, AEGCo, APCo,
                            CPL, CSPCo, I&M,
                            KPCo, OPCo, PSO,
                            SWEPCo, WTU

Environmental Concerns
 and Issues                 AEP, APCo, CPL,
                            CSPCo, I&M, OPCo,
                            SWEPCo

Other Matters               AEP, AEGCo, APCo,
                            CPL, CSPCo, I&M,
                            KPCo, OPCo, PSO,
                            SWEPCo, WTU

Financial Condition - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo

        We measure our financial condition by the strength of the balance sheet
and the liquidity provided by cash flows and earnings.

        Balance sheet capitalization ratios and cash flow ratios are principal
determinants of our credit quality.


        Year-end ratings of AEP's subsidiaries' first mortgage bonds are listed
in the following table:

Company                      Moody's    S&P      Fitch

APCo                         A3         A        A-
CPL                          A3         A-       A
CSPCo                        A3         A-       A
I&M                          Baa1       A-       BBB+
KPCo                         Baa1       A-       BBB+
OPCo                         A3         A-       A-
PSO                          A1         A        A+
SWEPCO                       A1         A        A+
WTU                          A2         A-       A


         The ratings at the end of the year for senior unsecured debt are listed
in the following table:

Company                      Moody's    S&P      Fitch

AEP                          Baa1       BBB+     BBB+
AEP Resources*               Baa1       BBB+     BBB+
APCo                         Baa1       BBB+     BBB+
CPL                          Baa1       BBB+     A-
CSPCo                        A3         BBB+     A-
I&M                          Baa2       BBB+     BBB
KPCo                         Baa2       BBB+     BBB
OPCo                         A3         BBB+     BBB+
PSO                          A2         BBB+     A
SWEPCO                       A2         BBB+     A

o The  rating  is for a series of  senior  notes  issued
  with a Support Agreement from AEP.

        The ratings are presently stable. AEP's commercial paper program has
short-term ratings of A2 and P2 by Moody's and Standard and Poor's,
respectively.

        AEP's common equity to total capitalization declined to 33% in 2001 from
34% in 2000. Total capitalization includes long-term debt due within one year,
minority interests and short-term debt. Preferred stock at 1% remained
unchanged. Long-term debt increased from 47% to 50% while short-term debt
decreased from 18% to 13% and minority interest in finance subsidiary increased
to 3%. In 2001 and 2000, AEP did not issue any shares of common stock to meet
the requirements of the Dividend Reinvestment and Direct Stock Purchase Plan and
the Employee Savings Plan.



<PAGE>


        We plan to strengthen the balance sheet in 2002 by issuing AEP common
stock and mandatory convertible preferred stock and using the proceeds from
asset sales to reduce debt. The issuance of common stock has the potential to
dilute future earnings per share but will enhance the equity to capitalization
ratio.

        Rating agencies have become more focused in their evaluation of credit
quality as a result of the Enron bankruptcy. They are focusing especially on the
composition of the balance sheet (off-balance sheet leases, debt and special
purpose financing structures), the cash liquidity profile and the impact of
credit quality downgrades on financing transactions. We have worked closely with
the agencies to provide them with all the information they need, but we are
unable to predict what actions, if any, they may take regarding our current
ratings.

        During 2001 AEP's cash flow from operations was $2.9 billion, including
$971 million from net income and $1.5 billion from depreciation, amortization
and deferred taxes. Capital expenditures including acquisitions were $4 billion
and dividends on common stock were $773 million. Cash from operations less
dividends on common stock financed 52% of capital expenditures.

During 2001, the proceeds of AEP's $1.25 billion global notes issuance and
proceeds from the sale of a UK distribution company and two generating plants
provided cash to purchase assets, fund construction, retire debt and pay
dividends. Major construction expenditures include amounts for a wind generating
facility and emission control technology on several coal-fired generating units
(see discussion in Note 8). Asset purchases include HPL, coal mines, a barge
line, a wind generating facility and two coal-fired generating plants in the UK.
These acquisitions accounted for the increase in total debt in 2001. During the
third quarter of 2001, permanent financing was completed for the acquisition of
HPL by the issuance of a minority interest which provided $735 million net of
expenses (See Note 22 for discussion of the terms). HPL's permanent financing
increased funds available for other corporate purposes. Long-term financings for
the other acquisitions will be announced as arranged. Long-term funding
arrangements for specific assets are often complex and typically not completed
until after the acquisition.

        Earnings for 2001 resulted in a dividend payout ratio of 80%, a
considerable improvement over the 289% payout ratio in 2000. The abnormally high
ratio in 2000 was the result of the adverse impact on 2000 earnings from the
Cook Plant extended outage and related restart expenditures, merger costs and
the write-off related to COLI and non-regulated subsidiaries. We expect
continued improvement of the payout ratio as a result of earnings growth in
2002.

        Cash from operations and short-term borrowings provide working capital
and meet other short-term cash needs. We generally use short-term borrowings to
fund property acquisitions and construction until long-term funding mechanisms
are arranged. Some acquisitions of existing business entities include the
assumption of their outstanding debt and certain liabilities. Sources of
long-term funding include issuance of AEP common stock, minority interest or
long-term debt and sale-leaseback or leasing arrange-ments. The domestic
electric subsidiaries generally issue short-term debt to provide for interim
financing of capital expenditures that exceed internally generated funds and
periodically reduce their outstanding short-term debt through issuances of
long-term debt and additional capital contributions from their parent company.
We operate a money pool and sell accounts receivables to provide liquidity for
the domestic electric subsidiaries. Short-term borrowings in the U.S. are
supported by two revolving credit agreements. At December 31, 2001,
approximately $554 million remained available for short-term borrowings in the
US.

        Subsidiaries that trade energy commodities in Europe have a separate
multicurrency revolving loan and letters of credit agreement allowing them to
borrow up to 150 million Euros of which 42 million Euros were available on
December 31, 2001. In February 2002 they also originated a temporary second line
of 50 million Euros for three months which is expected to be replaced with a 150
million Euro line, providing for a total of 300 million Euros. SEEBOARD, Nanyang
and Citipower which operate in the UK, China and Australia, respectively, each
have independent financing arrangements which provide for borrowing in the local
currency. SEEBOARD has a 320 million pound revolving credit agreement it uses
for short-term funding purposes. At December 31, 2001, SEEBOARD had 117 million
pounds available.

        Our revolving credit agreements include covenants that require us to
maintain specified financial ratios and describe non-performance of certain
actions as events of default. At December 31, 2001 we complied with the
covenants of these agreements. In general, a default in excess of $50 million
under one agreement is considered a default under the other agreements. In the
case of a default on payments under these agreements, all amounts outstanding
would be immediately payable.



<PAGE>


        The contractual obligations of AEP include amounts reported on the
balance sheet and other obligations disclosed in our footnotes. The following
table summarizes AEP's contractual cash obligations at December 31, 2001:
<TABLE>
<CAPTION>
                                                                    Payments Due by Period
                                                                        (in millions)
Contractual Cash Obligations             Less Than 1 year      2-3 years    4-5 years      After 5 years    Total
- ----------------------------             ----------------      ---------    ---------      -------------    -----
<S>                                               <C>             <C>            <C>             <C>          <C>
Long-term Debt                                    $2,300          $2,988         $2,559          $ 4,246      $12,093
Short-term Debt                                    3,155            -              -                -           3,155
Trust Preferred Securities                          -               -              -                 321          321
Minority Interest In Finance
 Subsidiary (a)                                     -               -               750             -             750
Preferred Stock Subject to
 Mandatory Redemption                               -                 24              4               67           95
Capital Lease Obligations                             96             144             91              397          728
Unconditional Purchase
 Obligations (b)                                     317           1,658          1,299            3,559        6,833
Noncancellable Operating Leases                      286             526            488            2,671        3,971
Other Long-term Obligations (c)                       31              30           -                -              61
                                                      --              --           ----             ----           --
  Total Contractual
   Cash Obligations                               $6,185          $5,370         $5,191          $11,261      $28,007
                                                  ======          ======         ======          =======      =======
</TABLE>
(a)  The initial period of the preferred interest is through August 2006. At the
     end of the initial period, the preferred rate may be reset, the preferred
     member interests may be re-marketed to new investors, the preferred member
     interests may be redeemed, in whole or in part including accrued return, or
     the preferred member interest may be liquidated.
(b)  Represents contractual obligations to purchase coal and natural gas as fuel
     for electric generation along with related transportation of the fuel.
(c)  Represents contractual obligations to loan funds to a joint venture
     accounted for under the equity method.

      For the subsidiary registrants, please see each registrant's schedules of
capitalization and long-term debt included with each registrants' financial
statements in sections B through J for the timing of debt payment obligations
and the lease footnote (Note 18) in section L for the timing of rent payments.

      Special purpose entities have been employed for some of the contractual
cash obligations reported in the above table. The lease of Rockport Plant Unit 2
and the Gavin Plant's flue gas desulfurization system (Gavin Scrubbers), the
permanent financing of HPL and the sale of accounts receivable use special
purpose entities. Neither AEP nor any AEP related parties has an ownership
interest in the special purpose entities. AEP does not guarantee the debt of
these entities. These special purpose entities are not consolidated in AEP's
financial statements in accordance with generally accepted accounting
principles. As a result, neither the assets nor the debt of the special purpose
entities is included on AEP's balance sheet. The future cash obligations payable
to the special purpose entities are included in the above table

      In addition to the amounts disclosed in the contractual cash obligations
table above, AEP and certain subsidiaries make commitments in the normal course
of business. These commitments include standby letters of credit, guarantees for
the payment of obligation performance bonds, and other commitments. AEP's
commitments outstanding at December 31, 2001 under these agreements are
summarized in the table below:
<TABLE>
<CAPTION>
                                                    Amount of Commitment Expiration Per Period
                                                                     (in millions)
Other Commercial Commitments             Less Than 1 year      2-3 years    4-5 years      After 5 years    Total
- ----------------------------             ----------------      ---------    ---------      -------------    -----
<S>                                           <C>                 <C>        <C>               <C>          <C>
Standby Letters of Credit                     $  101              $ 53         -               $36          $  190
Guarantees                                       815               161         -                15             991
Construction of Generating and
 Transmission Facilities for
 Third Parties (a)                               168               540         -                -              708
Other Commercial
 Commitments (b)                                   6                45         40               24             115
                                              ------              ----        ---              ---          ------
Total Commercial Commitments                  $1,090              $799        $40              $75          $2,004
                                              ======              ====        ===              ===          ======
</TABLE>
(a) As construction agent for third party owners of power plants and
transmission facilities, the Company has committed by contract terms to complete
construction by dates specified in the contracts. Should the Company default on
these obligations, financial payments could be up to 100% of contract value
(amount shown in table) or other remedies required by contract terms.
(b) Represents estimated future payments for power to be generated at facilities
under construction.

<PAGE>

         With the exceptions of SWEPCo's guarantanee of an unaffiliated mine
operator's obligations (payable upon their default) of $111 million at December
31, 2001, and OPCo's obligations under a power purchase agreement of $6 million
in 2002 and $16 million each year in 2003 through 2005, the obligations in the
above table are commitments of AEP and its non-registrant subsidiaries.

         AEP, through certain subsidiaries, has entered into agreements with an
unrelated, unconsolidated special purpose entity (SPE) to develop, construct,
finance and lease a power generation facility. The SPE will own the power
generation facility and lease it to an AEP consolidated subsidiary after
construction is completed. The lease will be accounted for as an operating lease
with the payment obligations included in the lease footnote. Payments under the
operating lease are expected to commence in the first quarter of 2004. AEP will
in turn sublease the facility to an unrelated industrial company which will both
use the energy produced by the facility and sell excess energy. Another
affiliate of AEP has agreed to purchase the excess energy from the subleasee for
resale.

         The SPE has an aggregate financing commitment from equity and debt
participants (Investors) of $427 million. AEP, in its role as construction agent
for the SPE, is responsible for completing construction by December 31, 2003. In
the event the project is terminated before completion of construction, AEP has
the option to either purchase the project for 100% of project costs or terminate
the project and make a payment to the Lessor for 89.9% of project costs.

         The term of the operating lease between the SPE and the AEP subsidiary
is five years with multiple extension options. If all extension options are
exercised the total term of the lease would be 30 years. AEP's lease payments to
the SPE are sufficient to provide a return to the Investors. At the end of the
first five-year lease term or any extension, AEP may renew the lease at fair
market value subject to Investor approval; purchase the facility at its original
construction cost; or sell the facility, on behalf of the SPE, to an independent
third party. If the project is sold and the proceeds from the sale are
insufficient to repay the Investors, AEP may be required to make a payment to
the Lessor of up to 85% of the project's cost. AEP has guaranteed a portion of
the obligations of its subsidiaries to the SPE during the construction and
post-construction periods.

           As of December 31, 2001, project costs subject to these agreements
totaled $168 million, and total costs for the completed facility are expected to
be approximately $450 million. Since the lease is accounted for as an operating
lease for financial accounting purposes, neither the facility nor the related
obligations are reported on AEP's balance sheets. The lease is a variable rate
obligation indexed to three-month LIBOR. Consequently as market interest rates
increase, the payments under this operating lease will also increase. Annual
payments of approximately $12 million represent future minimum payments under
the first five-year lease term calculated using the indexed LIBOR rate of 2.85%
at December 31, 2001.

        The lease payments and the guarantee of construction commitments are
included in the Other Commercial Commitments table above.

        OPCo has entered into a purchased power agreement to purchase
electricity pro-duced by an unaffiliated entity's three-unit natural gas fired
plant that is under construction. The first unit is anticipated to be completed
in October 2002 and the agree-ment will terminate 30 years after the third unit
begins operation. Under the terms of the agreement OPCo has the option to run
the plant until December 31, 2005 taking 100% of the power generated. For the
remainder of the 30 year contract term, OPCo will pay the variable costs to
generate the electricity it pur-chases which could be up to 20% of the plant's
capacity. The estimated fixed pay-ments through December 2005 are $55 million
and are included in the Other Commercial Commitments table shown above.



<PAGE>


Minority Interest in Finance Subsidiary

         In August 2001, AEP formed Caddis Partners, LLC (Caddis), a
consolidated subsidiary, and sold a non-controlling pre-ferred member interest
in Caddis to an unconsolidated special purpose entity (Steelhead) for $750
million. Under the provisions of the Caddis formation agree-ments, the preferred
member interest receives quarterly a preferred return equal to an adjusted
floating reference rate (4.413% at December 31, 2001). The $750 million received
replaced interim funding used to acquire Houston Pipe Line Company in June 2001.

         The preferred interest is supported by natural gas pipeline assets and
$321.4 million of preferred stock issued by an AEP subsidiary to the AEP
affiliate which has the managing member interest in Caddis. Such preferred stock
is convertible into common stock of AEP upon the occurrence of certain events.
AEP can elect not to have the transaction supported by such preferred stock if
the preferred interest were reduced by $225 million. In addition, Caddis has the
right to redeem the preferred member interest at any time.

         The initial period of the preferred interest is through August 2006. At
the end of the initial period, Caddis will either reset the preferred rate,
re-market the preferred member interests to new investors, redeem the preferred
member interests, in whole or in part including accrued return, or liquidate in
accordance with the provisions of applicable agreements.

         The credit agreement between Caddis and the AEP subsidiary that acts as
its managing member contains covenants that restrict incremental liens and
indebtedness, asset sales, investments, acquisitions, and distributions.
Financial covenants impose minimum financial ratios. At December 31, 2001, we
satisfied all of the financial ratio requirements. In general, a default in
excess of $50 million under another agreement is considered a default under this
agreement.


         Steelhead has the right to terminate the transaction and liquidate
Caddis upon the occurrence of certain events including a default in the payment
of the preferred return. Steelhead's rights include: forcing a liquidation of
Caddis and acting as the liquidator, and requiring the conversion of the $321.4
million of AEP subsidiary preferred stock into AEP common stock. If the
preferred member interest exercised its rights to liquidate under these
conditions, then AEP would evaluate whether to refinance at that time or
relinquish the assets that support the preferred member interest. Liquidation of
the preferred interest or of Caddis could impact AEP's liquidity.

         Caddis and the AEP subsidiary which acts as its managing member are
each a limited liability company, with a separate existence and identity from
its members, and the assets of each are separate and legally distinct from AEP.
The results of operations, cash flows and financial position of Caddis and such
managing member are consolidated with AEP for financial reporting purposes. The
preferred member interest and payments of the preferred return are reported on
AEP's income statement and balance sheet as Minority Interest in Finance
Subsidiary.

         Expenditures for domestic electric utility construction are estimated
to be $4.6 billion for the next three years. Approximately 100% of those
construction expenditures are expected to be financed by internally generated
funds.

         Construction expenditures for the registrant subsidiaries for the next
three years excluding AFUDC are:

                              Construction
          Projected           Expenditures
          Construction        Financed with
          Expenditures        Internal Funds
         (in millions)

APCo         $  815.5               92%
CPL             573.1               80%
I&M             556.9               ALL
OPCo          1,008.0               68%
SWEPCo          321.4               92%

        In 1998 SEEBOARD's 80% owned subsidiary, SEEBOARD Powerlink, signed a
30-year contract for $1.6 billion to operate, maintain, finance and renew the
high-voltage power distribution network of the London Underground transportation
system. SEEBOARD Powerlink will be responsible for distributing high voltage
electricity to supply 270 London Underground stations and 250 miles of the rail
system's track. SEEBOARD's partners in Powerlink are an international electrical
engineering group and an international cable and construction group.

Financing Activity

        AEP issued $1.25 billion of global notes in May 2001 (with intermediate
maturities). The proceeds were loaned to regulated and non-regulated
subsidiaries.


        In 2001 CSPCo and OPCo, AEP's Ohio subsidiaries, reacquired $295.5
million and $175.6 million, respectively, of first mortgage bonds in preparation
for corporate separation.

        AEP Credit purchases, without recourse, the accounts receivable of most
of the domestic utility operating companies and certain non-affiliated electric
utility companies. AEP Credit's financing for the purchase of receivables
changed during 2001. Starting December 31, 2001, AEP Credit entered into a sale
of receivables agreement. The agreement allows AEP Credit to sell certain
receivables and receive cash meeting the requirements of SFAS 140 for the
receivables to be removed from the balance sheet. The agreement expires in May
2002 and is expected to be renewed. At December 31, 2001, AEP Credit had $1.0
billion sold under this agreement of which $485 million are non-affiliated
receivables. In January 2002, AEP Credit stopped purchasing accounts receivables
from non-affiliated electric utility companies.

        In February 2002 CPL issued $797 million of securitization notes that
were approved by the PUCT as part of Texas restructuring to help decrease rates
and recover regulatory assets. The proceeds were used to reduce CPL's debt and
equity.

        In 2002 AEP plans to continue restructuring its debt for corporate
separation assuming receipt of all necessary regulatory approvals. Corporate
separation will require the transfer of assets between legal entities. With
corporate separation, a newly created holding company for the unregulated
business is expected to issue all debt needed to fund the wholesale business and
unregulated generating companies. The size and maturity lengths of the original
offering is presently being determined.

        The regulated holding company is expected to issue the debt needed by
the wires companies in Ohio and Texas. The regulated integrated utility
companies will continue their current debt structure until the regulatory
commissions approve changes. At that time, the regulated holding company may
also issue the debt for the regulated companies' funding needs.

        We have requested credit ratings for the holding companies consistent
with our existing credit quality, but we cannot predict what the outcome will
be.

        AEP uses a money pool to meet the short-term borrowings for certain of
its subsidiaries, primarily the domestic electric utility operations. Following
corporate separation, management will evaluate the advantages of establishing a
money pool for the unregulated business subsidiaries. The current money pool
which was approved by the appropriate regulatory authorities will continue to
service the regulated business subsidiaries. Presently, AEP also funds the
short-term debt requirements of other subsidiaries that are not included in the
money pool. As of December 31, 2001, AEP had credit facilities totaling $3.5
billion to support its commercial paper program. At December 31, 2001, AEP had
$2.9 billion outstanding in short-term borrowing subject to these credit
facilities.

Market Risks - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and WTU

        As a major power producer and trader of wholesale electricity and
natural gas, we have certain market risks inherent in our business activities.
These risks include com-modity price risk, interest rate risk, foreign exchange
risk and credit risk. They represent the risk of loss that may impact us due to
changes in the underlying market prices or rates.

        Policies and procedures are established to identify, assess, and manage
market risk exposures in our day to day operations. Our risk policies have been
reviewed with the Board of Directors, approved by a Risk Management Committee
and administered by a Chief Risk Officer. The Risk Management Committee
establishes risk limits, approves risk policies, assigns responsibilities
regarding the oversight and management of risk and monitors risk levels. This
committee receives daily, weekly, and monthly reports regarding compliance with
policies, limits and procedures. The committee meets monthly and consists of the
Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior
financial and operating managers.

        We use a risk measurement model which calculates Value at Risk (VaR) to
measure our commodity price risk. The VaR is based on the variance - covariance
method using historical prices to estimate volatilities and correlations and
assuming a 95% confidence level and a one-day holding period. Based on this VaR
analysis, at December 31, 2001 a near term typical change in commodity prices is
not expected to have a material effect on our results of operations, cash flows
or financial condition. The following table shows the high, average, and low
market risk as measured by VaR at:

                      December 31,
                   2001             2000
                   ----             ----
          High Average Low   High Average Low
                       (in millions)

AEP        $28    $14   $5    $32    $10   $1

APCo         4      1    -      6      2    -
CPL          3      1    -      4      1    -
CSPCo        2      1    -      3      1    -
I&M          3      1    -      4      1    -
KPCo         1      -    -      1      -    -
OPCo         3      1    -      5      2    -
PSO          2      1    -      3      1    -
SWEPCo       3      1    -      4      1    -
WTU          1      1    -      1      -    -

        We also utilize a VaR model to measure interest rate market risk
exposure. The interest rate VaR model is based on a Monte Carlo simulation with
a 95% confidence level and a one year holding period. The volatilities and
correlations were based on three years of weekly prices. The risk of potential
loss in fair value attributable to AEP's exposure to interest rates, primarily
related to long-term debt with fixed interest rates, was $673 million at
December 31, 2001 and $998 million at December 31, 2000. However, since we would
not expect to liquidate our entire debt portfolio in a one year holding period,
a near term change in interest rates should not materially affect results of
operations or consolidated financial position.

        The following table shows the potential loss in fair value as measured
by VaR allocated to the AEP registrant subsidiaries based upon debt outstanding:

VaR for Registrant Subsidiaries:
                                     December 31,
                              2001              2000
                                    (in millions)
Company
AEGCo                           $5                $4
APCo                           100               149
CPL                             80               135
CSPCo                           60                84
I&M                             86               129
KPCo                            16                31
OPCo                            59               112
PSO                             17                44
SWEPCo                          36                60
WTU                             20                24

          AEGCo is not exposed to risk from changes in interest rates on
short-term and long-term borrowings used to finance operations since financing
costs are recovered through the unit power agreements.

          AEP is exposed to risk from changes in the market prices of coal and
natural gas used to generate electricity where generation is no longer regulated
or where existing fuel clauses are suspended or frozen. The protection afforded
by fuel clause recovery mechanisms has either been eliminated by the
implementation of customer choice in Ohio (effective January 1, 2001 for CSPCo
and OPCo) and in the ERCOT area of Texas (effective January 1, 2002 for CPL and
WTU) or frozen by settlement agreements in Indiana, Michigan and West Virginia.
To the extent the fuel supply of the generating units in these states is not
under fixed price long-term contracts AEP is subject to market price risk. AEP
continues to be protected against market price changes by active fuel clauses in
Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.



<PAGE>


      We employ physical forward purchase and sale contracts, exchange futures
and options, over-the-counter options, swaps, and other derivative contracts to
offset price risk where appropriate. However, we engage in trading of
electricity, gas and to a lesser degree coal, oil, natural gas liquids, and
emission allowances and as a result the Company is subject to price risk. The
amount of risk taken by the traders is controlled by the management of the
trading operations and the Company's Chief Risk Officer and his staff. When the
risk from trading activities exceeds certain pre-determined limits, the
positions are modified or hedged to reduce the risk to the limits unless
specifically approved by the Risk Management Committee.

        We employ fair value hedges, cash flow hedges and swaps to mitigate
changes in interest rates or fair values on short and long-term debt when
management deems it necessary. We do not hedge all interest rate risk.

        We employ cash flow forward hedge contracts to lock-in prices on
transactions denominated in foreign currencies where deemed necessary.
International subsidiaries use currency swaps to hedge exchange rate
fluctuations in debt denominated in foreign currencies. We do not hedge all
foreign currency exposure.

        AEP limits credit risk by extending unsecured credit to entities based
on internal ratings. In addition, AEP uses Moody's Investor Service, Standard
and Poor's and qualitative and quantitative data to independently assess the
financial health of counterparties on an ongoing basis. This data, in
conjunction with the ratings information, is used to determine appropriate risk
parameters. AEP also requires cash deposits, letters of credit and
parental/affiliate guarantees as security from certain below investment grade
counterparties in our normal course of business.

        We trade electricity and gas contracts with numerous counterparties.
Since our open energy trading contracts are valued based on changes in market
prices of the related commodities, our exposures change daily. We believe that
our credit and market exposures with any one counterparty is not material to
financial condition at December 31, 2001. At December 31, 2001 less than 5% of
the counterparties were below investment grade as expressed in terms of Net Mark
to Market Assets. Net Mark to Market Assets represents the aggregate difference
(either positive or negative) between the forward market price for the remaining
term of the contract and the contractual price. The following table approximates
counterparty credit quality and exposure for AEP.

                    Futures,
                    Forward and
                    Swap
Counterparty        Contracts    Options   Total
 Credit Quality:
December 31, 2001
                            (in millions)
AAA/Exchanges         $ 147         $-       $ 147
AA                      140           4        144
A                       304           7        311
BBB                     932          34        966
Below   Investment
Grade                                23
                    -------      --- --
                         56                     79
                                                --

  Total               $1,579        $68     $1,647
                      ======        ===     ======

             The counterparty credit quality and exposure for the registrant
subsidiaries is generally consistent with that of AEP.

             We enter into transactions for electricity and natural gas as part
of wholesale trading operations. Electric and gas transactions are executed over
the counter with counterparties or through brokers. Gas transactions are also
executed through brokerage accounts with brokers who are registered with the
Commodity Futures Trading Commission. Brokers and counterparties require cash or
cash related instruments to be deposited on these transactions as margin against
open positions. The combined margin deposits at December 31, 2001 and 2000 was
$55 million and $95 million. These margin accounts are restricted and therefore
are not included in cash and cash equivalents on the Balance Sheet. We can be
subject to further margin requirements should related commodity prices change.

           We recognize the net change in the fair value of all open trading
contracts, a practice commonly called mark-to-market accounting, in accordance
with generally accepted accounting principles and include the net change in
mark-to-market amounts on a net discounted basis in revenues. Unrealized
mark-to-market revenues totaled $257 million in 2001. The fair values of open
short-term trading contracts are based on exchange prices and broker quotes. The
fair value of open long-term trading contracts are based mainly on Company
developed valuation models. The valuation models produce an estimated fair value
for open long-term trading contracts. This fair value is present valued and
reduced by appropriate reserves for counterparty credit risks and liquidity
risk. The models are derived from internally assessed market prices with the
exception of the NYMEX gas curve, where we use daily settled prices. Forward
price curves are developed for inclusion in the model based on broker quotes and
other available market data. The curves are within the range between the bid and
ask prices. The end of the month liquidity reserve is based on the difference in
price between the price curve and the bid price of the bid ask prices if we have
a long position and the ask side if we have a short position. This provides for
a conservative valuation net of the reserves.

           The use of these models to fair value open trading contracts has
inherent risks relating to the underlying assumptions employed by such models.
Independent controls are in place to evaluate the reasonableness of the price
curve models. Significant adverse or favorable effects on future results of
operations and cash flows could occur if market risks, at the time of
settlement, do not correlate with the Company developed price models.

           The effect on the Consolidated Statements of Income of marking to
market open electricity trading contracts in the Company's regulated
jurisdictions is deferred as regulatory assets or liabilities since these
transactions are included in cost of service on a settlement basis for
ratemaking purposes. Unrealized mark-to-market gains and losses from trading are
reported as assets or liabilities.


             The following table shows net revenues (revenues less fuel and
purchased energy expense) and their relationship to the mark-to-market revenues
(the change in fair value of open trading contracts).

                                  December 31,
                            ------------------
                        2001       2000        1999
                        ----       ----        ----

                               (in millions)
Revenues
 (including
 mark- to-
 market
 adjustment)          $61,257    $36,706    $24,745
Fuel and
 Purchased
 Energy
 Expense               52,753     28,718     17,244
                      -------    -------    -------
Net Revenues          $ 8,504    $ 7,988    $ 7,501
                      =======    =======    =======
Mark-to-Market
 Revenues                $257       $170        $23
                         ====       ====        ===
Percentage of
 Net Revenues
 Represented by
 Mark-to-Market            3%         2%         -%
                           ==         ==         ==


<PAGE>


        The following tables analyze the changes in fair values of trading
assets and liabilities. The first table "Net Fair Value of Energy Trading
Contracts" shows how the net fair value of energy trading contracts was derived
from the amounts included in the balance sheet line item "energy trading and
derivative contracts." The next table "Energy Trading Contracts" disaggregates
realized and unrealized changes in fair value; identifies changes in fair value
as a result of changes in valuation methodologies; and reconciles the net fair
value of energy trading contracts at the beginning of the year of $63 million to
the end of the year of $448 million. Contracts realized/settled during the
period include both sales and purchase contracts. The third table "Energy
Trading Contract Maturities" shows exposures to changes in fair values and
realization periods over time for each method used to determine fair value.

Net Fair Value of Energy Trading Contracts
                                                  December 31,
                                              -------------------
                                               2001          2000
                                               ----          ----
                                                (in millions)
Energy Trading Contracts:
    Current Asset                          $ 8,536      $ 15,495
    Long-term Asset                          2,367         1,552
    Current Liability                       (8,279)      (15,671)
    Long-term Liability                     (2,176)       (1,313)
                                           -------      --------
Net Fair Value of Energy Trading Contracts $   448      $     63
                                           =======      ========

The net fair value of energy trading contracts includes $257 million at December
31, 2001 and $170 million at December 31, 2000 of unrealized mark-to-market
gains that are recognized in the income statement. Also included in the above
net fair value of energy trading contracts are option premiums that are deferred
until the related contracts settle and the portion of changes in fair values of
electricity trading contracts that are deferred for ratemaking purposes.
<TABLE>
<CAPTION>
Energy Trading Contracts AEP Consolidated
(in millions)
                                                                                         Total
<S>                                                                                    <C>         <C>
Net Fair Value of Energy Trading Contracts at December 31, 2000                        $  63

Gain from Contracts realized/settled during period                                      (352)       (a)

Fair Value of new open contracts when entered into during period                          73        (b)

Adjustments for Contracts entered into and settled during period                         310        (a)

Net option premium payments                                                               24

Change in fair value due to Valuation Methodology changes                                 (1)       (c)

Changes in market value of contracts                                                     331        (d)
                                                                                       -----

Net Fair Value of Energy Trading Contracts at December 31, 2001                        $ 448        (e)
                                                                                       =====
</TABLE>
(a)       Gains from Contracts Realized or Otherwise Settled During the Period"
          include realized gains from energy trading contracts that settled
          during 2001 that were entered into prior to 2001, as well as during
          2001. "Adjustment for Contracts Entered into and Settled During the
          Period" discloses the realized gains from settled energy trading
          contracts that were both entered into and closed within 2001 that are
          included in the total gains of $352 million, but not included in the
          ending balance of open contracts.
(b)       The "Fair Value of New Open Contracts When Entered Into during period"
          represents the fair value of long-term contracts entered into with
          customers during 2001. The fair value is calculated as of the
          execution of the contract. Most of the fair value comes from longer
          term fixed price contracts with customers that seek to limit their
          risk against fluctuating energy prices. The contract prices are valued
          against market curves representative of the delivery location.
(c)       The Company changed its methodology for calculating and reporting load
          based transactions. The previous methodology estimated a baseload
          volume based on historical takes and sold a call option for potential
          load increases from the baseload. The current methodology uses a
          modified version of a straddle load follow model to estimate the
          baseload volume and call option volume. This methodogy change more
          accurately estimates the load volume forecast. The dollar impact on
          existing deals was a decrease of in fair value of $1.2 million.
(d)       "Change in market Value of Contracts" represents the fair value change
          in the trading portfolio due to market fluctuations during the current
          period. Market fluctuations are attributable to various factors such
          as supply/demand, weather, storage, etc.
(e)       The net change in the fair value of energy trading contracts for 2001
          that resulted in an increase of $385 million ($448 million less $63
          million) represents the balance sheet change. The net mark-to-market
          gain on energy trading contracts of $257 million represents the impact
          on earnings. The difference is related primarily to regulatory
          deferrals of certain mark-to-market gains that were recorded as
          regulatory liabilities and not reflected in the income statement for
          those companies that operate in regulated jurisdictions, and deferrals
          of option premiums included in the above analysis, which do not have a
          mark-to-market income statement impact.


<PAGE>


Energy Trading Contracts
(in thousand)
                                               APCo        CPL           CSPCo
Net Fair Value of Energy Trading
 Contracts at December 31, 2000             $  7,447     $(8,191)     $  3,769

Loss/(Gain) from Contracts
 Realized/settled during period              (12,478)      4,221       (11,522)

Fair Value of new open Contracts
 when entered into during period              13,441       9,635         8,245

Adjustments for Contracts Entered
 into and settled during period               40,755       2,602        24,998

Net option premium payments                    1,072        -              658

Change in fair value due to Valuation
 Methodology changes                            (220)       (158)         (135)

Changes in market value of Contracts          25,684      (4,252)       22,436
                                            --------     -------      --------

Net Fair Value of Energy Trading
 Contracts at December 31, 2001             $ 75,701     $ 3,857      $ 48,449
                                            ========     =======      ========

Energy Trading Contracts
(in thousands)
                                             I&M          KPCo         OPCo
Net Fair Value of Energy Trading
 Contracts at December 31, 2000           $ (6,845)    $ 1,678      $  5,613

Loss/(Gain) from Contracts
 Realized/settled during period            (10,982)     (3,298)      (10,861)

Fair Value of new open Contracts
 when entered into During period             8,921       3,315        11,213

Adjustments for Contracts Entered
 into and settled During period             27,049      10,051        34,001

Net option premium payments                    712         264           894

Change in fair value due to Valuation
 Methodology changes                          (146)        (54)         (183)

Changes in market value of Contracts        42,636         773        24,769
                                           -------     -------      --------

Net Fair Value of Energy Trading
 Contracts at December 31, 2001           $ 61,345     $12,729      $ 65,446
                                          ========     =======      ========

Energy Trading Contracts
(in thousands)
                                            PSO        SWEPCo         WTU
Net Fair Value of Energy Trading
 Contracts at December 31, 2000          $(6,508)     $(7,795)     $(2,590)

Loss/(Gain) from Contracts
 Realized/settled during period            2,483        2,938        5,881

Fair Value of new open Contracts
 when entered into During period           7,338        8,422        2,861

Adjustments for Contracts Entered
 into and settled during period            1,981        2,274          773

Net option premium payments                 -            -            -

Change in fair value due to Valuation
 Methodology changes                        (120)        (138)         (46)

Changes in market value of Contracts      (2,740)      (2,801)      (5,964)
                                         -------      -------      -------

Net Fair Value of Energy Trading
 Contracts at December 31, 2001          $ 2,434      $ 2,900      $   915
                                         =======      =======      =======
<PAGE>
<TABLE>
<CAPTION>
Energy Trading Contract Maturities
                                                            Fair Value of Contracts at December 31,2001
                                               ------------------------------------------------------------
                                                                                 Maturities
                                               ------------------------------------------------------------
                                                                               (in millions)
AEP Consolidated                               Less than                                In Excess       Total Fair
Source of Fair Value                           1 year        1-3 years     4-5 years    Of 5 years      Value
- --------------------                           ------        ---------     ---------    ----------      -----
<S>                                            <C>           <C>           <C>          <C>             <C>
Prices actively quoted (a)                     $ 46          $  8          $ -          $ -             $ 54

Prices provided by other external
 Sources (b)                                    152            33            -            -              185

Prices based on models and other
 Valuation methods (c)                           13           133           35           28              209
                                               ----          ----          ---          ---             ----

Total                                          $211          $174          $35          $28             $448
                                               ====          ====          ===          ===             ====
</TABLE>
<TABLE>
<CAPTION>
Energy Trading Contract Maturities
                                                            Fair Value of Contracts at December 31,2001
                                               --------------------------------------------------------------
                                                                                 Maturities
                                               --------------------------------------------------------------
                                                                               (in thousands)
                                               Less than                                In Excess       Total Fair
Source of Fair Value                           1 year        1-3 years     4-5 years    Of 5 years      Value
- --------------------                           ------        ---------     ---------    ----------      -----
<S>                                            <C>            <C>                                       <C>
APCo
Other External Sources                         13,366         9,588         -            -              22,954
Models/Other Valuation                          3,215        34,318        8,413        6,801           52,747
                                               ------        ------        -----        -----           ------
  Total                                        16,581        43,906        8,413        6,801           75,701
                                               ======        ======        =====        =====           ======

CPL
Other External Sources                         (5,245)       1,681          -            -              (3,564)
Models/Other Valuation                         (1,262)       6,016         1,475        1,192            7,421
                                               -------       -----         -----        -----           ------
  Total                                        (6,507)       7,697         1,475        1,192            3,857
                                               =======       =====         =====        =====           ======

CSP
Other External Sources                          9,867         5,872            -         -              15,739
Models/Other Valuation                          2,373        21,018        5,153        4,166           32,710
                                               ------        ------        -----        -----           ------
  Total                                        12,240        26,890        5,153        4,166           48,449
                                               ======        ======        =====        =====           ======

KEPCo
Other External Sources                         (1,475)        2,361         -            -                 886
Models/Other Valuation                           (355)        8,451        2,072        1,675           11,843
                                               -------       ------        -----        -----           ------
  Total                                        (1,830)       10,812        2,072        1,675           12,729
                                               =======       ======        =====        =====           ======

I&M
Other External Sources                         17,237         6,481         -            -              23,718
Models/Other Valuation                          4,146        23,197        5,687        4,597           37,627
                                               ------        ------        -----        -----           ------
  Total                                        21,383        29,678        5,687        4,597           61,345
                                               ======        ======        =====        =====           ======

OPCo
Other External Sources                         13,058         7,987         -            -              21,045
Models/Other Valuation                          3,141        28,587        7,008        5,665           44,401
                                               ------        ------        -----        -----           ------
  Total                                        16,199        36,574        7,008        5,665           65,446
                                               ======        ======        =====        =====           ======

PSO
Other External Sources                         (4,400)       1,280          -            -              (3,120)
Models/Other Valuation                         (1,058)       4,581         1,123        908              5,554
                                               -------       -----         -----        ---             ------
  Total                                        (5,458)       5,861         1,123        908              2,434
                                               =======       =====         =====        ===             ======

SWEPCo
Other External Sources                         (4,965)       1,469          -            -              (3,496)
Models/Other Valuation                         (1,194)       5,259         1,289        1,042            6,396
                                               -------       -----         -----        -----           ------
  Total                                        (6,159)       6,728         1,289        1,042            2,900
                                               =======       =====         =====        =====           ======

WTU
Other External Sources                         (1,743)         499          -            -              (1,244)
Models/Other Valuation                           (419)       1,786         438          354              2,159
                                               -------       -----         ---          ---             ------
  Total                                        (2,162)       2,285         438          354                915
                                               =======       =====         ===          ===             ======
</TABLE>
(a)      "Prices Actively Quoted" represents the Company's exchange traded
         futures positions in natural gas.
(b)      "Prices Provided by Other External Sources" represents the Company's
         positions in natural gas, power, and coal at points where
         over-the-counter broker quotes are available.  Prices for these
         various commodities can generally be obtained on the
         over-the-counter market through 2003. Some prices from external
         sources are quoted as strips (one bid/ask for Nov-Mar, Apr-Oct, etc).
         Such transactions have also been included in this category.
(c)      "Prices Based on Models and Other Valuation Methods" contain the
         following: the value of the Company's adjustments for liquidity and
         counterparty credit exposure, the value of contracts not quoted by an
         exchange or an over-the-counter broker, the value of transactions for
         which an internally developed price curve was developed as a result of
         the long dated nature of certain transactions, and the value of certain
         structured transactions.




<PAGE>


        We have investments in debt and equity securities which are held in
nuclear trust funds. The trust investments and their fair value are discussed in
Note 13, "Risk Management, Financial Instruments and Derivatives." Financial
instruments in these trust funds have not been included in the market risk
calculation for interest rates as these instruments are marked-to-market and
changes in market value of these instruments are reflected in a corresponding
decommissioning liability. Any differences between the trust fund assets and the
ultimate liability are expected to be recovered through regulated rates from our
regulated customers.

        Inflation affects our cost of replacing utility plant and the cost of
operating and maintaining plant. The rate-making process limits recovery to the
historical cost of assets, resulting in economic losses when the effects of
inflation are not recovered from customers on a timely basis. However, economic
gains that result from the repayment of long-term debt with inflated dollars
partly offset such losses.

Industry Restructuring

         In 2000 California's deregulated electricity market suffered problems
including high energy prices mainly due to short energy supplies and financial
difficulties for retail distribution companies. This energy crisis has
highlighted the importance of risk management and has contributed to certain
state regulatory and legislative actions which have delayed the start of
customer choice and the transition to competitive, market based pricing for
retail electricity supply in some of the states in which AEP operates. Seven of
the eleven state retail jurisdictions in which the AEP domestic electric utility
companies operate have enacted restructuring legislation. In general, the
legislation provides for a transition from cost-based regulation of bundled
electric service to customer choice and market pricing for the supply of
electricity. As legislative and regulatory proceedings evolved, six AEP electric
operating companies (APCo, CPL, CSPCo, OPCo, SWEPCo and WTU) doing business in
five of the seven states that have passed restructuring legislation have
discontinued the application of SFAS 71 regulatory accounting for the generation
business. The seven states in various stages of restructuring to transition
power generation and supply to market based pricing are Arkansas, Michigan,
Ohio, Oklahoma, Texas, Virginia, and West Virginia. AEP has not discontinued its
regulatory accounting for its subsidiaries doing business in Michigan and
Oklahoma pending the effective implementation of the legislation. Restructuring
legislation, the status of the transition plans and the status of the electric
utility companies' accounting to comply with the changes in each of AEP's seven
state regulatory jurisdictions affected by restructuring legislation is
presented in the Note 7 of the Notes to Financial Statements.

RTO Formation

        FERC Order No. 2000 and many of the settlement agreements with the FERC
and state regulatory commissions to approve the AEP-CSW Merger have provisions
for the transfer of functional control of our transmission system to an RTO.
Certain AEP subsidiaries are participating in the formation of the Alliance RTO.
Other subsidiaries are a member of ERCOT or SPP.

        In 2001 the Alliance companies and MISO entered into a settlement
addressing transmission pricing and other "seam" issues between the two RTOs.
The FERC subsequently expressed its opinion that four large RTO regions serving
the continental US would best support competition and reliability of electric
service. Certain state regulatory commissions have taken exception to the FERC's
RTO actions. Louisiana's commission ordered utilities it regulates, including
SWEPCo, to show the advantage of large RTOs to their customers.

        On December 19, 2001 the FERC approved the proposal of the Midwest ISO
for a regional transmission organization and told the Alliance companies, which
had submitted a separate RTO proposal, to explore joining the Midwest ISO
organization. The FERC's order is intended to facilitate the establishment of a
single RTO in the Midwest and to support the establishment of viable, for-profit
transmission companies under an RTO umbrella and concluded that the RTO proposed
by Alliance companies lacks sufficient scope to exist as a stand-alone RTO and
thus directed the Alliance companies to explore how their business plan can be
accommodated within the Midwest ISO.

        Management is unable to predict the outcome of these transmission
regulatory actions and proceedings or their impact on the timing and operation
of RTOs, AEP's transmission operations or future results of operations and cash
flows.

Litigation

         AEP is involved in various litigation. The details of significant
litigation contin-gencies are disclosed in Note 8 and summarized below.

COLI - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

        A decision by U.S. District Court for the Southern District of Ohio in
February 2001 that denied AEP's deduction of interest claimed on AEP's
consolidated federal income tax returns related to its COLI program resulted in
a $319 million reduction in net income for 2000. AEP had filed suit to resolve
the IRS' assertion that interest deductions for AEP's COLI program should not be
allowed. In 1998 and 1999 AEP and the impacted subsidiaries paid the disputed
taxes and interest attributable to COLI interest deductions for taxable years
1991-98 for APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the
potential assessment by the IRS of additional interest on the contested tax. The
payments were included in other assets on AEP's balance sheet and other property
and investments on the subsidiaries' balance sheets pending the resolution of
this matter. AEP has appealed the Court's decision.

The earnings reductions for affected registrant subsidiaries are as follows:

                                (in millions)
APCo                                $ 82
CSPCo                                 41
I&M                                   66
KPCo                                   8
OPCo                                 118

Shareholders' Litigation - Affecting AEP

        On December 21, 2001, the U.S. District Court for the Southern District
of Ohio dismissed a class action lawsuit against AEP and four former or present
officers. The complaint alleged violation of federal securities laws by
disseminating materially false and misleading statements related to the extended
Cook Plant outage.

FERC Wholesale Fuel Complaints - Affecting AEP and WTU

        In November 2001 certain WTU wholesale customers filed a complaint with
FERC alleging that WTU has overcharged them since 1997 through the fuel
adjustment clause. The customers allege inappropriate costs related to purchased
power were included in the fuel adjustment clause. Management is working to
compute if any overcharges occurred and is unable to predict their impact on
results of operations, cash flow and financial condition.

Municipal Franchise Fee Litigation - Affecting AEP and CPL

        In 2001 CPL paid $11 million to settle class action litigation regarding
municipal franchise fees in Texas. The City of San Juan, Texas had filed a class
action lawsuit in 1996 seeking $300 million in damages.

Texas Base Rate Litigation - Affecting AEP and CPL

        In 2001 the Texas Supreme Court denied CPL's request for the court to
review a 1997 PUCT base rate order. Subsequently the Court also denied CPL's
rehearing request.

The primary issues CPL requested the Court to review were:
o       the  classification  of $800  million of invested  capital in STP as
        ECOM and  assigning it a lower return on equity than other
        generation property;
o       and an $18 million disallowance of affiliated service billings.



<PAGE>


Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo

         In 2001 SWEPCo settled litigation concerning lignite mining in
Louisiana. Since 1997 SWEPCo has been involved in litigation concerning the
mining of lignite from jointly owned lignite reserves. SWEPCo and CLECO, an
unaffiliated utility, are each a 50% owner of the Dolet Hills Power Station Unit
1 and jointly own lignite reserves in the Dolet Hills area of northwestern
Louisiana. Under terms of a settlement, SWEPCo purchased an unaffiliated mine
operator's interest in the mining operations and related debt and other
obligations for $86 million.

Merger Litigation - Affecting AEP and all Subsidiary Registrants

        In January 2002, a federal court ruled that the SEC failed to prove that
the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and
sent the case back to the SEC for further review. Management believes that the
merger meets the requirements of the PUHCA and expects the matter to be resolved
favorably.

Other  - Affecting AEP and all Subsidiary Registrants

        AEP and its registrant subsidiaries are involved in a number of other
legal proceedings and claims. While management is unable to predict the outcome
of such litigation, it is not expected that the ultimate resolution of these
matters will have a material adverse effect on the results of operations, cash
flows or financial condition.

Environmental Concerns and Issues

        The U.S. continues to debate an array of environmental issues affecting
the electric utility industry including new emission limitations recommended by
the Bush Administration in February 2002. Most of the policies are aimed at
reducing air emissions citing alleged impacts of such emissions on public
health, sensitive ecosystems or the global climate.

        AEP and its subsidiaries' policy on the environment continues to be the
development and application of long-term economically feasible measures to
improve air and water quality, limit emissions and protect the health of
employees, customers, neighbors and others impacted by their operations. In
support of this policy, AEP and its subsidiaries continue to invest in research
through groups like the Electric Power Research Institute and directly through
demonstration projects for new technology for the capture and storage of carbon
dioxide, mercury, NOx and other emissions. The AEP System intends to continue in
a leadership role to protect and preserve the environment while providing vital
energy commodities and services to customers at fair prices.

        AEP and its subsidiaries have a proven record of efficiently producing
and delivering electricity and gas while minimizing the impact on the
environment. AEP and its subsidiaries have spent billions of dollars to equip
their facilities with the latest cost effective clean air and water technologies
and to research new technologies. We are proud of our award winning efforts to
reclaim our mining properties.

        The introduction of multi-pollutant control legislation is being
discussed by members of Congress and the Bush Administration. The legislation
being considered may regulate carbon dioxide, NOx, sulfur dioxide, mercury and
other emissions from electric generating plants. Management will continue to
support solutions which are based on sound science, economics and demonstrated
control technologies. Management is unable to predict the timing or magnitude of
additional pollution control laws or regulations. If additional control
technology is required on facilities owned by the electric utility companies and
their costs were not recoverable from ratepayers or through market based prices
or volumes of product sold, they could adversely affect future results of
operations and cash flows. The following discussions explains existing control
efforts, litigation and other pending matters related to environmental issues
for AEP companies.
<PAGE>
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M
and OPCo

        Since 1999 AEP, APCo, CSPCo, I&M and OPCo have been involved in
litigation regarding generating plant emissions under the Clean Air Act. Federal
EPA, a number of states and certain special interest grups alleged that APCo,
CSPCo, I&M and OPCo modified certain generating units over a 20 year period in
violation of the Clean Air Act.

         Under the Clean Air Act, if a plant undertakes a major modification
that directly results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution control
technology. This requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed components, or other
repairs needed for the reliable, safe and efficient operation of the plant. We
believe our maintenance, repair and replacement activities were in conformity
with the Clean Air Act and intend to vigorously pursue our defense.

        The Clean Air Act authorizes civil penalties of up to $27,500 per day
per violation at each generating unit ($25,000 per day prior to January 30,
1997). In March 2001 the District Court ruled that claims for civil penalties
based on activities that occurred more than five years before the filing date of
the complaints cannot be imposed. There is no time limit on claims for
injunctive relief.

        Management is unable to estimate a loss or predict the timing of the
resolution of these matters due to the number of alleged violations and the
significant number of issues yet to be determined by the Court. If we do not
prevail, any capital and operating costs of additional pollution control
equipment that may be required as well as any penalties imposed would adversely
affect future results of operations, cash flows and possibly financial
condition.

        An unaffiliated utility which operates certain plants jointly owned by
CSPCo reached a tentative agreement to settle litigation regarding generating
plant emissions under the Clean Air Act. Negotiations are continuing and a
settlement could impact the operation of Zimmer Plant and W.C. Beckjord
Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until
a final settlement is reached, CSPCo will be unable to determine the
settlement's impact on its jointly owned facilities and its future results of
operations and cash flows.

NOx Reduction - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo

        Federal EPA issued a NOx rule (the Nox Rule) and granted petitions filed
by certain northeastern states (the Section 126 Rule) requiring substantial
reductions in NOx emissions in a number of eastern states, including certain
states in which the AEP System's generating plants are located.

        Federal EPA ruled that eleven states, including certain states in which
AEP's generating units are located, failed to submit approvable plans to comply
with the NOx Rule. This ruling means that those states could face stringent
sanctions including limits on construction of new sources of air emissions, loss
of federal highway funding and possible Federal EPA takeover of state air
quality management programs. A request for the D.C. Circuit Court to review this
ruling is pending. The compliance date for the NOx Rule is May 31, 2004.

        The D.C. Circuit Court instructed Federal EPA to justify methods used to
allocate allowances and project growth for both the NOx Rule and the Section 126
Rule. In response to AEP and other utilities request for the D.C. Circuit Court
to suspend the May 2003 compliance date of the Section 126 Rule, the D.C.
Circuit Court issued an order tolling the compliance schedule until Federal EPA
responds to the Court's remand.

        In April 2000 the Texas Natural Resource Conservation Commission adopted
rules requiring significant reductions in NOx emissions from utility sources,
including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005
for SWEPCo.

        In 2001 selective catalytic reduction (SCR) technology to reduce NOx
emissions on OPCo's Gavin Plant commenced operation. Construction of SCR
technology at certain other generating units continues with completion scheduled
in 2002 through 2006.
<PAGE>

        Our estimates indicate that compliance with the NOx Rule, the Texas
Natural Resource Conservation Commission rule and the Section 126 Rule could
result in required capital expenditures of approximately $1.6 billion of which
approximately $450 million has been spent for the AEP System.

        The following table shows the estimated compliance cost and amounts
spent for certain of AEP's registrant subsidiaries.

                 Estimated     Amounts
             Compliance Costs   Spent
             ----------------  -------
                     (in millions)
Company

APCo                $365        $130
CPL                   57           4
I&M                  202          -
OPCo                 606         277
SWEPCo                28          21

        Since compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the estimates depending
upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless any capital and operating costs of additional pollution
control equipment are recovered from customers, they will have an adverse effect
on future results of operations, cash flows and possibly financial condition.

Superfund - Affecting AEP, APCo, CPL, CSPCo, I&M, OPCo and SWEPCo

        By-products from the generation of electricity include materials such as
ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion
by-products, which constitute the overwhelming percentage of these materials,
are typically disposed of or treated in captive disposal facilities or are
beneficially utilized. In addition, our generating plants and transmission and
distribution facilities have used asbestos, PCBs and other hazardous and
non-hazardous materials. We are currently incurring costs to safely dispose of
these substances. Additional costs could be incurred to comply with new laws and
regulations if enacted.

        Superfund addresses clean-up of hazardous substances at disposal sites
and authorized Federal EPA to administer the clean-up programs. As of year-end
2001, subsidiaries of AEP have been named by the Federal EPA as a PRP for five
sites. APCo, CSPCo, and OPCo each have one PRP site and I&M has two PRP sites.
There are four additional sites for which AEP, APCo, CSPCo, I&M, OPCo and SWEPCo
have received information requests which could lead to PRP designation. CPL,
OPCo and SWEPCo have also been named a PRP at two sites under state law. Our
liability has been resolved for a number of sites with no significant effect on
results of operations. In those instances where AEP or its subsidiaries have
been named a PRP or defendant, their disposal or recycling activities were in
accordance with the then-applicable laws and regulations. Unfortunately,
Superfund does not recognize compliance as a defense, but imposes strict
liability on parties who fall within its broad statutory categories.

        While the potential liability for each Superfund site must be evaluated
separately, several general statements can be made regarding AEP's and its
subsidiaries' potential future liability. Disposal of materials at a particular
site is often unsubstantiated and the quantity of materials deposited at a site
was small and often nonhazardous. Although liability is joint and several,
typically many parties are named as PRPs for each site and several of the
parties are financially sound enterprises. Therefore, our present estimates do
not anticipate material cleanup costs for identified sites for which we have
been declared PRPs. If significant cleanup costs are attributed to AEP or its
subsidiaries in the future under Superfund, results of operations, cash flows
and possibly financial condition would be adversely affected unless the costs
can be recovered from customers.

Global Climate Change - Affecting AEP and all Registrant Subsidiaries

        At the Third Conference of the Parties to the United Nations Framework
Convention on Climate Change held in Kyoto, Japan in December 1997 more than 160
countries, including the U.S., negotiated a treaty requiring legally-binding
reductions in emissions of greenhouse gases, chiefly carbon dioxide, which many
scientists believe are contributing to global climate change. Although the U.S.
signed the Kyoto Protocol on November 12, 1998, the treaty was not submitted to
the Senate for its advice and consent by President Clinton. In March 2001
President Bush announced his opposition to the treaty and its U.S. ratification.
At the Seventh Conference of the Parties in November 2001, the parties finalized
the rules, procedures and guidelines required to facilitate ratification of the
protocol. The protocol is expected to become effective by 2003. U.S.
representatives attended the Seventh Conference but they did not take any
positions on issues being negotiated or attempt to block the approval of any
issue. AEP does not support the Kyoto Protocol but intends to work with the Bush
Administration and U.S. Congress to develop responsible public policy on this
issue. Management expects due to President Bush's opposition to legislation
mandating greenhouse gas emissions controls, any policies developed and
implemented in the near future are likely to encourage voluntary measures to
reduce, avoid or sequester such emissions.

        The acquisition of 4,000 MW of coal-fired generation in the United
Kingdom in December 2001 exposes these assets to potential carbon dioxide
emission control obligations since the U.K. is expected to be a party to the
Kyoto Protocol.

Costs for Spent Nuclear Fuel and Decommissioning - Affecting AEP, CPL and I&M

        I&M, as the owner of the Cook Plant, and CPL, as a partial owner of STP,
have a significant future financial commitment to safely dispose of SNF and
decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site disposal of SNF
and high-level radioactive waste. By law CPL and I&M participate in the DOE's
SNF disposal program which is described in Note 8 of the Notes to Financial
Statements. Since 1983 I&M has collected $288 million from customers for the
disposal of nuclear fuel consumed at the Cook Plant. $116 million of these funds
have been deposited in external trust funds to provide for the future disposal
of SNF and $172 million has been remitted to the DOE. CPL has collected and
remitted to the DOE, $49 million for the future disposal of SNF since STP began
operation in the late 1980s. Under the provisions of the Nuclear Waste Policy
Act, collections from customers are to provide the DOE with money to build a
permanent repository for spent fuel. However, in 1996, the DOE notified the
companies that it would be unable to begin accepting SNF by the January 1998
deadline required by law. To date DOE has failed to comply with the requirements
of the Nuclear Waste Policy Act.

        As a result of DOE's failure to make sufficient progress toward a
permanent repository or otherwise assume responsibility for SNF, AEP on behalf
of I&M and STPNOC on behalf of CPL and the other STP owners, along with a number
of unaffiliated utilities and states, filed suit in the D.C. Circuit Court
requesting, among other things, that the D.C. Circuit Court order DOE to meet
its obligations under the law. The D.C. Circuit Court ordered the parties to
proceed with contractual remedies but declined to order DOE to begin accepting
SNF for disposal. DOE estimates its planned site for the nuclear waste will not
be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S.
Court of Federal Claims seeking damages in excess of $150 million due to the
DOE's partial material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by
other utilities. In August 2000, in an appeal of related cases involving other
unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held
that the delays clause of the standard contract between utilities and the DOE
did not apply to DOE's complete failure to perform its contract obligations, and
that the utilities' suits against DOE may continue in court. AEP's and I&M's
suit has been stayed pending further action by the U.S. Court of Federal Claims.
As long as the delay in the availability of a government approved storage
repository for SNF continues, the cost of both temporary and permanent storage
and the cost of decommissioning will continue to increase.

        In January 2001, I&M and STPNOC, on behalf of STP's joint owners, joined
a lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related
to DOE's nuclear waste fund cost recovery settlement with PECO Energy
Corporation. The settlement allows PECO to skip two payments to the DOE for
disposal of SNF due to the lack of progress towards development of a permanent
repository for SNF. The companies believe the settlement is unlawful as the
settlement would force other utilities to make up any shortfall in DOE's SNF
disposal funds.

        The cost to decommission nuclear plants is affected by both NRC
regulations and the delayed SNF disposal program. Studies completed in 2000
estimate the cost to decommission the Cook Plant ranges from $783 million to
$1,481 million in 2000 non-discounted dollars. External trust funds have been
established with amounts collected from customers to decommission the plant. At
December 31, 2001, the total decom-missioning trust fund balance for Cook Plant
was $598 million which includes earnings on the trust investments. Studies
completed in 1999 for STP estimate CPL's share of decommissioning cost to be
$289 million in 1999 non-discounted dollars. Amounts collected from customers to
decommission STP have been placed in an external trust. At December 31, 2001,
the total decommission-ing trust fund for CPL's share of STP was $99 million
which includes earnings on the trust investments. Estimates from the
decommissioning studies could continue to escalate due to the uncertainty in the
SNF disposal program and the length of time that SNF may need to be stored at
the plant site. We will work with regulators and customers to recover the
remaining estimated costs of decommissioning Cook Plant and STP. However, AEP's,
CPL's and I&M's future results of operations, cash flows and possibly their
financial conditions would be adversely affected if the cost of SNF disposal and
decommissioning continues to increase and cannot be recovered.

        AEP and its subsidiaries are exposed to other environmental concerns
which are not considered to be material or potentially material at this time.
Should they become significant or should any new concerns be uncovered that are
material they could have a material adverse effect on results of operations and
possibly financial condition. AEP performs environmental reviews and audits on a
regular basis for the purpose of identifying, evaluating and addressing
environmental concerns and issues.

        APCo, AEP's subsidiary which operates in Virginia and West Virginia, has
been seeking regulatory approval to build a new high voltage transmission line
for over a decade. Through December 31, 2001 we have invested approximately $40
million in this effort. If the required regulatory approvals are not obtained
and the line is not constructed, the $40 million investment would be written off
adversely affecting AEP's and APCo's future results of operations and cash
flows.

OTHER MATTERS

Enron Bankruptcy - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

        At the date of Enron's bankruptcy AEP had open trading contracts and
trading accounts receivables and payables with Enron. In addition, on June 1,
2001, we purchased Houston Pipe Line from Enron and entered into a lease
arrangement with a subsidiary of Enron for a gas storage facility. At the date
of Enron's bankruptcy various HPL related contingencies and indemnities remained
unsettled. In the fourth quarter of 2001 AEP provided $47 million ($31 million
net of tax) for our estimated losses from the Enron bankruptcy.

        The amounts for certain subsidiary registrants were:

                                              Amounts
                            Amounts            Net of
Registrant                 Provided             Tax
                           --------  --         ---
                                  (in millions)

APCo                         $5.2               3.4
CSPCo                         3.2               2.1
I&M                           3.4               2.2
KPCo                          1.3               0.8
OPCo                          4.3               2.8


        The amounts provided were based on an analysis of contracts where AEP
and Enron are counterparties, the offsetting of receivables and payables, the
application of deposits from Enron and management's analysis of the HPL related
purchase contingencies and indemnifications. If there are any adverse unforeseen
developments in the bankruptcy proceedings, our future results of operations,
cash flows and possibly financial condition could be adversely impacted.

International Investments - Affecting AEP

        We own a 44% equity interest in Vale, a Brazilian electric operating
company which was purchased for a total of $149 million. On December 1, 2001 we
converted a $66 million note receivable and accrued interest into a 20% equity
interest in Caiua (Brazilian electric operating company), a subsidiary of Vale.
Vale and Caiua have experienced losses from operations and our investment has
been affected by the devaluation of the Brazilian Real. The cumulative equity
share of operating and foreign currency translation losses through December 31,
2001 is approximately $46 million and $54 million, respectively net of tax. The
cumulative equity share of operating and foreign currency translation losses
through December 31, 2000 is approximately $33 million and $49 million,
respectively net of tax. Both investments are covered by a put option, which, if
exercised, requires our partners in Vale to purchase our Vale and Caiua shares
at a minimum price equal to the U.S. dollar equivalent of the original purchase
price. As a result, management has concluded that the investment carrying amount
should not be reduced below the put option value unless it is deemed to be an
other than temporary impairment and our partners in Vale are deemed unable to
fulfill their responsibilities under the put option. Management has evaluated
through an independent third-party, the ability of its Vale partners to fulfill
their responsibilities under the put option agreement and has concluded that our
partners should be able to fulfill their responsibilities.

        Management believes that the decline in the value of its investment in
Vale in US dollars is not other than temporary. As a result and pursuant to the
put option agreement, these losses have not been applied to reduce the carrying
values of the Vale and Caiua investments. As a result we will not recognize any
future earnings from Vale and Caiua until the operating losses are recovered.
Should the impairment of our investment become other than temporary due to our
partners in Vale becoming unable to fulfill their responsibilities, it would
have an adverse effect on future results of operations.

        Management will continue to monitor both the status of the losses and
the ability of its partners to fulfill their obligations under the put.

Investments Limitations - Affecting AEP

        Our investment, including guarantees of debt, in certain types of
activities is limited by PUHCA. SEC authorization under PUHCA limits us to
issuing and selling securities in an amount up to 100% of our average quarterly
consolidated retained earnings balance for investment in EWGs and FUCOs. At
December 31, 2001, AEP's investment in EWGs and FUCOs was $2.9 billion,
including guarantees of debt, compared to AEP's limit of $3.3 billion.

        SEC rules under PUHCA permit AEP to invest up to 15% of consolidated
capitalization (such amount was $3.6 billion at December 31, 2001) in
energy-related companies, including marketing and/or trading of electricity, gas
and other energy commodities. Our gas trading business and our interest in
domestic cogeneration projects are reported as investments under this rule and
at December 31, 2001, such investment was $2.2 billion.

New Accounting Standards - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo and WTU

        The FASB recently issued SFAS 141, "Business Combinations" and SFAS 142,
"Goodwill And Other Intangible Assets." SFAS 141 requires that the purchase
method of accounting be used to account for all business combinations entered
into after June 30, 2001. SFAS 142 requires that goodwill amortization cease and
that goodwill and other intangible assets with indefinite lives be tested for
impairment upon SFAS 142 implementation and annually thereafter. We must
implement these new standards in the first quarter of 2002. Amortization of
goodwill and other intangible assets with indefinite lives will cease with our
implementation of SFAS 142 beginning January 1, 2002. The amortization of
goodwill reduced AEP's net income by $50 million for the twelve months ended
December 31, 2001. The registrant subsidiaries did not have any goodwill at
December 31, 2001. We are currently in the process of fair valuing our reporting
units with goodwill in order to determined potential goodwill impairment. As
such we have not yet determined the impact on first quarter 2002 results of
operations of adopting the provision of these standards.

        SFAS 143, "Accounting for Asset Retirement Obligations," will become
effective for us beginning January 1, 2003. SFAS 143 established accounting and
reporting for legal obligations associated with the retirement of tangible
long-lived assets and the related asset retirement costs. We are currently in
the process of evaluating the provisions of the standard and determining its
impact on future results of operations and financial condition. To the extent
AEP or it registrant subsidiaries are regulated entities, we anticipate that the
cumulative effect of this accounting change on future results of operations will
be significantly offset by a regulatory asset representing the right to recover
legal asset retirement obligations (ARO) relative to regulated long lived assets
included in rate base. The impact on future results of operations from the
implementation of this new standard on non-regulated long lived assets has not
yet been determined. We anticipate that the considerable effort to identify all
long lived assets with legal ARO and to determine the required discounted legal
ARO will take the remainder of 2002.


        In August 2001 the FASB issued SFAS 144, "Accounting for the Impairment
or Disposal of Long-lived Assets" which sets forth the accounting to recognize
and measure an impairment loss. This standard replaces the previous standard,
SFAS 121, "Accounting for the Long-lived Assets and for Long-lived Assets to be
Disposed Of." SFAS 144 will apply to us beginning January 1, 2002. We do not
expect that the imple-mentation of SFAS 144 will materially affect results of
operations or financial condition.

        The FASB recently revised its prior guidance related to SFAS 133,
"Accounting for Deriviative Instruments and Hedging Activities" with regard to
certain power option and forward contracts. The revised guidance states that
power contracts, including both forward and option contracts, that include
certain qualitative characteristics are considered capacity contracts, and
qualify for the normal purchases and normal sales exception from being marked to
market even if they are subject to being booked out, or scheduled to be booked
out. As normal purchases and sales these open energy contracts are not marked to
market. Rather they are accounted for on a settlement basis. Most of AEP's power
contracts that are not marked to market as trading transactions do not qualify
as derivatives and thus are not subject to the revised guidance. The few
contracts that are derivatives qualified for the exception under the previous
guidance and will continue to qualify under the new guidance.


<PAGE>




Common Stock and Dividend Information

The quarterly high and low sales prices for AEP common stock and the cash
dividends paid per share are shown in the following table:

Quarter Ended                            High          Low          Dividend

March 2001                               $48.10       $39.25        $0.60
June 2001                                 51.20        45.10         0.60
September 2001                            48.90        41.50         0.60
December 2001                             46.95        39.70         0.60

March 2000                                34.94        25.94         0.60
June 2000                                 38.50        29.44         0.60
September 2000                            40.00        29.94         0.60
December 2000                             48.94        36.19         0.60

AEP common stock is traded principally on the New York Stock Exchange. At
December 31, 2001, AEP had approximately 150,000 shareholders of record.




<PAGE>



























INVESTOR INQUIRIES
Investors should direct inquiries to Investor Relations using the toll free
number, 1-800-237-2667 or by writing to: Bette Jo Rozsa Managing Director of
Investor Relations American Electric Power Service Corporation 28th Floor 1
Riverside Plaza Columbus, OH 43215-2373

FORM 10-K ANNUAL REPORT
The Annual Report (Form 10-K) to the Securities  and Exchange  Commission  will
       be available in April 2001 at no cost to  shareholders.
Please address requests for copies to:
Geoffrey C. Dean
Director of Financial Reporting
American Electric Power Service Corporation
26th Floor
1 Riverside Plaza
Columbus, OH  43215-2373

TRANSFER AGENT AND REGISTRAR OF CUMULATIVE PREFERRED STOCK
Equiserve, First Chicago Division
P.O. Box 2500
Jersey City, NJ  07303-2500
Phone number: 1-800-328-6955



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-21
<SEQUENCE>12
<FILENAME>x21.txt
<TEXT>
<PAGE>
<TABLE>
                                                                      EXHIBIT 21
                                 Subsidiaries of
                      American Electric Power Company, Inc.
                             As of December 31, 2001

    The voting stock of each company shown indented is owned by the company
immediately above which is not indented to the same degree. Subsidiaries not
indented are directly owned by American Electric Power Company, Inc.

<CAPTION>
                                                                   Percentage
                                                                   of Voting
                                                                   Securities
                                                 Location of        Owned By
     Name of Company                            Incorporation   Immediate Parent
<S>                                              <C>                 <C>

American Electric Power Company, Inc.             New York
American Electric Power Service Corporation       New York            100.0
AEP C&I Company, LLC                              Delaware            100.0
AEP Coal, Inc.                                    Nevada              100.0
AEP Communications, Inc.                          Ohio                100.0
AEP Energy Services, Inc.                         Ohio                100.0
AEP Generating Company                            Ohio                100.0
AEP Indian Mesa LP, LLC                           Delaware            100.0
AEP Investments, Inc.                             Ohio                100.0
Mutual Energy L.L.C.                              Delaware            100.0
AEP Power Marketing, Inc.                         Ohio                100.0
AEP T&D Services, LLC                             Delaware            100.0
AEP Pro Serv, Inc.                                Ohio                100.0
AEP Retail Energy LLC                             Delaware            100.0
AEP Texas POLR, LLC                               Delaware            100.0
AEP Resources, Inc.                               Ohio                100.0
Appalachian Power Company                         Virginia             98.7 (a)
  Cedar Coal Co.                                  West Virginia       100.0
  Central Appalachian Coal Company                West Virginia       100.0
  Central Coal Company                            West Virginia        50.0 (b)
  Southern Appalachian Coal Company               West Virginia       100.0
  West Virginia Power Company                     West Virginia       100.0
Columbus Southern Power Company                   Ohio                100.0
  Colomet, Inc.                                   Ohio                100.0
  Conesville Coal Preparation Company             Ohio                100.0
  Simco Inc.                                      Ohio                100.0
  Ohio Valley Electric Corporation                Ohio                  4.3 (e)
    Indiana-Kentucky Electric Corporation         Indiana             100.0
Franklin Real Estate Company                      Pennsylvania        100.0
Indiana Michigan Power Company                    Indiana             100.0
  Blackhawk Coal Company                          Utah                100.0
  Price River Coal Company, Inc.                  Indiana             100.0
Kentucky Power Company                            Kentucky            100.0
Kingsport Power Company                           Virginia            100.0
Ohio Power Company                                Ohio                 99.2 (c)
  Cardinal Operating Company                      Ohio                 50.0 (d)
  Central Coal Company                            West Virginia        50.0 (b)
Ohio Valley Electric Corporation                  Ohio                 39.9 (e)
  Indiana-Kentucky Electric Corporation           Indiana             100.0
Wheeling Power Company                            West Virginia       100.0
Central and South West Corporation                Delaware            100.0
  Central Power and Light Company                 Texas               100.0
    CPL Capital I                                 Delaware            100.0
    CPL Transition Funding LLC (DE)               Delaware            100.0
  Public Service Company of Oklahoma              Oklahoma            100.0
    Ash Creek Mining Company                      Oklahoma            100.0
    PSO Capital I                                 Delaware            100.0
  Southwestern Electric Power Company             Delaware            100.0
    The Arklahoma Corporation                     Arkansas             47.6
    SWEPCo Capital I                              Delaware            100.0
    Southwestern Arkansas Utilities Corporation   Arkansas            100.0
    Dolet Hills Lignite Company, LLC              Delaware            100.0
  West Texas Utilities Company                    Texas               100.0


NOTES:
a.   13,499,500 shares of Common Stock, all owned by parent,  have one vote each
     and 177,905 shares of Preferred  Stock,  all owned by the public,  have one
     vote each.
b.   Owned 50% by Appalachian Power Company and 50% by Ohio Power Company.
c.   27,952,473 shares of Common Stock, all owned by parent,  have one vote each
     and 238,977 shares of Preferred  Stock,  all owned by the public,  have one
     vote each.
d.   Ohio  Power  Company  owns 50% of the  stock;  the  other 50% is owned by a
     corporation not affiliated with American Electric Power Company, Inc.
e.   American  Electric Power Company,  Inc. and Columbus Southern Power Company
     own 39.9% and 4.3% of the stock,  respectively,  and the remaining 55.8% is
     owned by unaffiliated companies.
</TABLE>



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23
<SEQUENCE>13
<FILENAME>x23a.txt
<DESCRIPTION>(A) CONSENT OF DELOITTE & TOUCHE LLP
<TEXT>

<PAGE>

                                                                   Exhibit 23(a)

INDEPENDENT AUDITORS' CONSENT


We consent to the  incorporation  by reference in  Registration  Statement  Nos.
333-46360,  333-39402,  333-66048  and  333-62278  of  American  Electric  Power
Company,  Inc.  on Form  S-8,  Post-Effective  Amendment  No. 1 to  Registration
Statement No.  333-50109 of American  Electric Power Company,  Inc. on Form S-8,
Post-Effective  Amendment  No.  3 to  Registration  Statement  No.  33-01052  of
American Electric Power Company,  Inc. on Form S-8, Post Effective Amendment No.
3 to  Registration  Statement No.  33-01734 of American  Electric Power Company,
Inc. on Form S-3 and Registration  Statement No. 333-58540 of American  Electric
Power  Company,  Inc. on Form S-3,  of our  reports  dated  February  22,  2002,
appearing in and incorporated by reference in this Annual Report on Form 10-K of
American Electric Power Company, Inc. for the year ended December 31, 2001.


/s/ Deloitte & Touche LLP

Deloitte & Touche LLP
Columbus, Ohio
March 28, 2002




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23
<SEQUENCE>14
<FILENAME>x23b.txt
<DESCRIPTION>(B) CONSENT OF ARTHUR ANDERSEN LLP
<TEXT>
<PAGE>

                                                                   Exhibit 23(b)

CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS


As independent public accountants, we hereby consent to the incorporation of our
report dated February 25, 2000 on Central and South West  Corporation,  included
and  incorporated  by  reference in this Form 10-K,  into the American  Electric
Power Company,  Inc.  registration  statements on Form S-8 (File Nos.  33-01052,
333-39402, 333-50109, 333-46360, 333-66048 and 333-62278) and Form S-3 (File No.
33-01734 and 333-58540).


/s/ Arthur Andersen LLP

Dallas, Texas
March 28, 2002


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23
<SEQUENCE>15
<FILENAME>x23c.txt
<DESCRIPTION>(C) CONSENT OF KPMG AUDIT PLC
<TEXT>

<PAGE>

                                                                   EXHIBIT 23(c)

The Board of Directors
CSW UK Holdings

We consent to the incorporation of our report dated 17 January 2000 with respect
to the consolidated  balance sheet of CSW UK Holdings as of 31 December 1999 and
the related consolidated statements of earnings and cash flows for the year then
ended (not separately presented herein), which report appears in the 2001 Annual
Report of American Electric Power Company, Inc. and is incorporated by reference
in Form 10-K of American  Electric  Power  Company,  Inc.  for the year ended 31
December 2001.

/s/ KPMG Audit Plc

KPMG Audit Plc                                                London, England
Chartered Accountants                                         28  March 2002
Registered Auditor


</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-24
<SEQUENCE>16
<FILENAME>x24.txt
<TEXT>

<PAGE>

                                                                      Exhibit 24
                                POWER OF ATTORNEY

                      AMERICAN ELECTRIC POWER COMPANY, INC.
              Annual Report on Form 10-K for the Fiscal Year Ended
                                December 31, 2001


     The undersigned  directors of AMERICAN ELECTRIC POWER COMPANY,  INC., a New
York  corporation  (the  "Company"),  do hereby  constitute  and appoint E. LINN
DRAPER,  JR.,  ARMANDO  A.  PENA and  SUSAN  TOMASKY,  and  each of them,  their
attorneys-in-fact  and agents,  to execute for them, and in their names,  and in
any and all of their capacities,  the Annual Report of the Company on Form 10-K,
pursuant to Section 13 of the  Securities  Exchange Act of 1934,  for the fiscal
year ended December 31, 2001, and any and all  amendments  thereto,  and to file
the same, with all exhibits thereto and other documents in connection therewith,
with   the   Securities   and   Exchange   Commission,    granting   unto   said
attorneys-in-fact  and agents,  and each of them, full power and authority to do
and perform  every act and thing  required or necessary to be done,  as fully to
all intents and purposes as the undersigned might or could do in person,  hereby
ratifying and confirming all that said  attorneys-in-fact  and agents, or any of
them, may lawfully do or cause to be done by virtue hereof.

     IN WITNESS  WHEREOF,  the undersigned  have signed these presents this 25th
day of February, 2002.


   /s/ E. R. Brooks                          /s/ Leonard J. Kujawa


   /s/ Donald M. Carlton                     /s/ James L. Powell


   /s/ John P. DesBarres                     /s/ Richard L. Sandor


   /s/ E. Linn Draper, Jr.                   /s/ Thomas V. Shockley, III


   /s/ Robert W. Fri                         /s/ Donald G. Smith


   /s/ William R. Howell                     /s/ Linda Gillespie Stuntz


   /s/ Lester A. Hudson, Jr.                 /s/ Kathryn D. Sullivan


</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
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