THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND
SUBSIDIARIES IS REQUESTED TO BE INCLUDED AS PART OF THE FILING.



                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                                    FORM 10-Q
              [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                For The Quarterly Period Ended SEPTEMBER 30, 2000
              [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                        For The Transition Period from to

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

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

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

  0-346         CENTRAL POWER AND LIGHT COMPANY
                (A Texas Corporation)                              74-0550600
                539 North Carancahua  Street,
                Corpus Christi,  Texas 78401-2802
                Telephone (361) 881-5300

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

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

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

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

  0-343         PUBLIC SERVICE COMPANY OF OKLAHOMA                 73-0410895
                (An Oklahoma Corporation)
                212 East 6th Street, Tulsa, Oklahoma  74119-1212
                Telephone (918) 599-2000

  1-3146        SOUTHWESTERN ELECTRIC POWER COMPANY                72-0323455
                (A Delaware Corporation)
                428 Travis Street, Shreveport, Louisiana  71156-0001
                Telephone (318) 673-3000

0-340           WEST TEXAS UTILITIES  COMPANY
                (A Texas  Corporation)                             75-0646790
                301 Cypress Street,
                Abilene,  Texas 79601-5820  Telephone (915)
                674-7000


<PAGE>




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

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

The number of shares outstanding of American Electric Power Company, Inc. Common
Stock, par value $6.50, at October 31, 2000 was 321,993,409.


<PAGE>
<TABLE>
<CAPTION>



         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

                                    FORM 10-Q

                    For The Quarter Ended September 30, 2000
                                      INDEX

Glossary of Terms                                                   i - iii
Forward-Looking Information                                            iv

                                                                            Page
     Part I.  FINANCIAL INFORMATION
        Items 1 and 2. Financial Statements and Management's Discussion
                         and Analysis of Results of Operations:

                American Electric Power Company, Inc. and Subsidiary Companies:
<S>                                                                          <C>
                  Consolidated Financial Statements. . . . . . . . . . . . . A-1 - A-5
                       Management's Discussion and Analysis of Results of
                        Operations. . . . . . . . . . . . . . . . . . . . .  A-6 - A-8

                AEP Generating Company:
                  Financial Statements . . . . . . . . . . . . . . . . . . . B-1 - B-4
                  Management's  Narrative  Analysis  of  Results  of
                       Operations . . . . . . . . . . . . . . . . . . . . .  B-5 - B-6

                Appalachian Power Company and Subsidiaries:
                  Consolidated Financial Statements. . . . . . . . . . . . . C-1 - C-4
                       Management's Discussion and Analysis of Results of
                        Operations. . . . . . . . . . . . . . . . . . . . . .C-5 - C-7

                Central Power and Light Company and Subsidiaries:
                  Consolidated Financial Statements. . . . . . . . . . . . . D-1 - D-4
                       Management's Discussion and Analysis of Results of
                        Operations. . . . . . . . . . . . . . . . . . . . . .D-5 - D-6

                Columbus Southern Power Company and Subsidiaries:
                  Consolidated Financial Statements. . . . . . . . . . . . . E-1 - E-4
                       Management's Narrative Analysis of Results of
                       Operations . . . . . . . . . . . . . . . . . . . . . .E-5 - E-7

                Indiana Michigan Power Company and Subsidiaries:
                  Consolidated Financial Statements. . . . . . . . . . . . . F-1 - F-4
                       Management's Discussion and Analysis of Results of
                        Operations. . . . . . . . . . . . . . . . . . . . . .F-5 - F-7

                Kentucky Power Company:
                  Financial Statements . . . . . . . . . . . . . . . . . . . G-1 - G-4
                  Management's  Narrative  Analysis  of  Results  of
                       Operations . . . . . . . . . . . . . . . . . . . . . .G-5 - G-6

                Ohio Power Company and Subsidiaries:
                  Consolidated Financial Statements. . . . . . . . . . . . . H-1 - H-4
                       Management's Discussion and Analysis of Results of
                        Operations. . . . . . . . . . . . . . . . . . . . . .H-5 - H-6

                Public Service Company of Oklahoma and Subsidiaries:
                  Financial Statements . . . . . . . . . . . . . . . . . . . I-1 - I-4
                       Management's Discussion and Analysis of Results of
                        Operations. . . . . . . . . . . . . . . . . . . . . .I-5 - I-6

                Southwestern Electric Power Company and Subsidiaries:
                  Consolidated Financial Statements. . . . . . . . . . . . . J-1 - J-4
                       Management's Discussion and Analysis of Results of
                        Operations. . . . . . . . . . . . . . . . . . . . . .J-5 - J-7


<PAGE>



                West Texas Utilities Company:
                  Financial Statements . . . . . . . . . . . . . . . . . . . K-1 - K-4
                  Management's Discussion and Analysis of Results of
                        Operations. . . . . . . . . . . . . . . . . . . . . .K-5 - K-7

                 Footnotes to Financial Statements. . . . . . . . . . . . . .L-1 - L-28

        Item 2.Registrants' Combined Management Discussion and
                       Analysis of Financial Condition and Other Matters. . .M-1 - M-25
        Item 3.Quantitative and Qualitative Disclosures About Market Risk.   N-1 - N-2

     Part II.  OTHER INFORMATION
       Item 1.   Legal Proceedings . . . . . . . . . . . . . . . . . . . . .  O-1
       Item 4.   Submission of Matters to a Vote of Security Holders . . . .  O-1 - O-2
        Item 5.Other Information . . . . . . . . . . . . . . . . . . . . . .  O-2
        Item 6.Exhibits and Reports on Form 8-K. . . . . . . . . . . . . . .  O-2 - O-3
(a)      Exhibits
                              Exhibit 12
                              Exhibit 27
(b)      Reports on Form 8-K

SIGNATURE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  P-1
</TABLE>

            This  combined Form 10-Q is  separately  filed by 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 and West
     Texas  Utilities  Company.  Information  contained  herein  relating to any
     individual  registrant is filed by such registrant on its own behalf.  Each
     registrant makes no representation as to information  relating to the other
     registrants.


<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

<C>                                 <S>
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 domestic electric utility companies.
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.
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.
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 electric utility subsidiary of AEP.
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, 2,100 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 Credit......................... CSW Credit, Inc., an AEP subsidiary which factors accounts receivable and accrued utility
                                    revenues for affiliated domestic electric utility companies.
CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
                                    outside the United States.
                                     i

<PAGE>




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.
Federal EPA........................ United States Environmental Protection Agency.
FERC............................... Federal Energy Regulatory Commission.
FMB................................ First Mortgage Bond.
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.
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................................ Megawatt hour
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 7 of the states in which AEP 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.
PJM................................ Pennsylvania - New Jersey - Maryland regional transmission organization.
<PAGE>

                                          ii
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.
RCRA............................... Resource Conservation and Recovery Act of 1976, as amended.
Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
                                    Indiana owned by AEGCo and I&M.
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.
                                    -------------------
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 .
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.
TNRCC.............................. The Texas Natural Resource Conservation Commission.
Travis District Court.............. State District Court of Travis County, Texas.
TVA ............................... Tennessee Valley Authority.
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.
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>


                                       iii


<PAGE>




     FORWARD-LOOKING INFORMATION

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

     C Electric  load and customer  growth.  C Abnormal  weather  conditions.  C
     Available  sources  and  costs  of  fuels.  C  Availability  of  generating
     capacity.
     C The speed and  degree to which  competition  is  introduced  to our power
     generation business. C The structure and timing of a competitive market and
     its  impact on energy  prices or fixed  rates.  C The  ability  to  recover
     stranded  costs  in  connection  with  possible/proposed   deregulation  of
     generation. C New legislation and government regulations.
     C The ability of AEP to  successfully  control its costs.  C The success of
     new business ventures. C International developments affecting AEP's foreign
     investments. C The economic climate and growth in AEP's service territory.
     C Unforeseen  events  affecting AEP's restart of Cook Plant Unit 1 which is
     on  an  extended  safety  related  shutdown.   C  Inflationary   trends.  C
     Electricity and gas market prices.
     C Interest rates C Other risks and unforeseen events.



























                                       iv


<PAGE>
<TABLE>
<CAPTION>



         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                        CONSOLIDATED STATEMENTS OF INCOME
                     (in millions, except per-share amounts)
                                   (UNAUDITED)

                                                  Three Months Ended Nine Months Ended
                                                September 30,          September 30,
                                            --------------------    ------------------
                                              2000        1999        2000        1999
                                              ----        ----        ----        ----
REVENUES:
<S>                                          <C>         <C>         <C>         <C>
  Domestic Electric Utilities. . . . . . .   $3,232      $2,927      $ 8,124     $7,567
  Worldwide Electric and Gas Operations. .      689         605        2,010      1,846
                                             ------      ------      -------     ------
          TOTAL REVENUES . . . . . . . . .    3,921       3,532       10,134      9,413
                                             ------      ------      -------     ------

EXPENSES:
  Fuel and Purchased Power . . . . . . . .    1,237       1,072        3,043      2,643
  Maintenance and Other Operation. . . . .      758         680        2,164      1,960
  Merger Costs . . . . . . . . . . . . . .       20        -             181       -
  Depreciation and Amortization. . . . . .      275         276          804        776
  Taxes Other Than Income Taxes. . . . . .      173         157          507        504
  Worldwide Electric and Gas Operations. .      578         541        1,797      1,635
                                             ------      ------      -------     ------
          TOTAL EXPENSES . . . . . . . . .    3,041       2,726        8,496      7,518
                                             ------      ------      -------     ------
OPERATING INCOME . . . . . . . . . . . . .      880         806        1,638      1,895
OTHER INCOME, net. . . . . . . . . . . . .       16          12           30         33
                                             ------      ------      -------     ------
INCOME BEFORE INTEREST, PREFERRED
  DIVIDENDS AND INCOME TAXES . . . . . . .      896         818        1,668      1,928

INTEREST AND PREFERRED DIVIDENDS . . . . .      274         249          796        738
                                             ------      ------      -------     ------

INCOME BEFORE INCOME TAXES . . . . . . . .      622         569          872      1,190

INCOME TAXES . . . . . . . . . . . . . . .      219         166          348        403
                                             ------      ------      -------     ------

INCOME BEFORE EXTRAORDINARY ITEMS. . . . .      403         403          524        787

EXTRAORDINARY ITEMS - DISCONTINUANCE OF
  REGULATORY ACCOUNTING FOR GENERATION
  (Note 2) . . . . . . . . . . . . . . . .      (44)         (8)         (35)        (8)
                                             ------      ------      -------     ------

NET INCOME . . . . . . . . . . . . . . . .   $  359      $  395      $   489     $  779
                                             ======      ======      =======     ======

AVERAGE NUMBER OF SHARES OUTSTANDING . . .      322         321          322        320
                                                ===         ===          ===        ===

EARNINGS PER SHARE:
  Before Extraordinary Items . . . . . . .    $1.25       $1.26        $1.63      $2.46
  Extraordinary Loss -
    Discontinuance of Regulatory
    Accounting for Generation. . . . . . .     (.14)       (.03)       (0.11)      (.03)
                                              -----       -----        -----      ----- -
  After Extraordinary Items. . . . . . . .    $1.11       $1.23        $1.52      $2.43
                                              =====       =====        =====      =====

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

See Notes to Financial Statements beginning on page L-1.
</TABLE>


<PAGE>
<TABLE>
<CAPTION>



         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                             September 30,   December 31,
                                                                  2000           1999
                                                             -------------   ------------
                                                                    (in millions)
ASSETS

CURRENT ASSETS:
<S>                                                             <C>            <C>
  Cash and Cash Equivalents. . . . . . . . . . . . . . . .      $   295        $   659
  Accounts Receivable (net). . . . . . . . . . . . . . . .        3,022          2,027
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . .          326            436
  Materials and Supplies . . . . . . . . . . . . . . . . .          480            460
  Accrued Utility Revenues . . . . . . . . . . . . . . . .          373            322
  Energy Trading Contracts . . . . . . . . . . . . . . . .        3,660          1,001
  Prepayments and Other. . . . . . . . . . . . . . . . . .          449            169
                                                                -------        -------

          TOTAL CURRENT ASSETS . . . . . . . . . . . . . .        8,605          5,074
                                                                -------        -------

PROPERTY, PLANT AND EQUIPMENT:
  Electric:
    Production . . . . . . . . . . . . . . . . . . . . . .       15,973         15,869
    Transmission . . . . . . . . . . . . . . . . . . . . .        5,590          5,495
    Distribution . . . . . . . . . . . . . . . . . . . . .       10,664         10,432
  Other (including gas and coal mining assets
    and nuclear fuel). . . . . . . . . . . . . . . . . . .        4,027          4,081
  Construction Work in Progress. . . . . . . . . . . . . .        1,295          1,061
                                                                -------        -------
          Total Property, Plant and Equipment. . . . . . .       37,549         36,938
  Accumulated Depreciation and Amortization. . . . . . . .       15,479         15,073
                                                                -------        -------

          NET PROPERTY, PLANT AND EQUIPMENT. . . . . . . .       22,070         21,865
                                                                -------        -------

REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . .        3,540          3,395
                                                                -------        -------

INVESTMENTS IN POWER AND COMMUNICATIONS PROJECTS . . . . .          879            862
                                                                -------        -------

GOODWILL (net of amortization) . . . . . . . . . . . . . .        1,378          1,531
                                                                -------        -------

OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . .        4,046          2,992
                                                                -------        -------

            TOTAL. . . . . . . . . . . . . . . . . . . . .      $40,518        $35,719
                                                                =======        =======

See Notes to Financial Statements beginning on page L-1.
</TABLE>


<PAGE>
<TABLE>
<CAPTION>

         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                            September 30,    December 31,
                                                                2000             1999
                                                            -------------    ------------
                                                                    (in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
<S>                                                            <C>             <C>
  Accounts Payable . . . . . . . . . . . . . . . . . . . .     $ 1,782         $ 1,280
  Short-term Debt. . . . . . . . . . . . . . . . . . . . .       4,375           3,012
  Long-term Debt Due Within One Year . . . . . . . . . . .         753           1,367
  Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .         598             601
  Interest Accrued . . . . . . . . . . . . . . . . . . . .         232             142
  Obligations Under Capital Leases . . . . . . . . . . . .         128              91
  Energy Trading Contracts . . . . . . . . . . . . . . . .       3,623             964
  Other. . . . . . . . . . . . . . . . . . . . . . . . . .       1,268             609
                                                               -------         -------

          TOTAL CURRENT LIABILITIES. . . . . . . . . . . .      12,759           8,066
                                                               -------         -------

LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . . .      10,071          10,157
                                                               -------         -------

CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
  PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
  SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
  SUBSIDIARIES . . . . . . . . . . . . . . . . . . . . . .         334             335
                                                               -------         -------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . .       5,076           5,150
                                                               -------         -------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . .         537             580
                                                               -------         -------

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . . .         206             213
                                                               -------         -------

DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . . .       1,316             715
                                                               -------         -------

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . .       1,641           1,648
                                                               -------         -------

CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . . . .         161             182
                                                               -------         -------

CONTINGENCIES (Note 12)

COMMON SHAREHOLDERS' EQUITY:
  Common Stock-Par Value $6.50:
                                2000          1999
                                ----          ----
    Shares Authorized . . . .600,000,000   600,000,000
    Shares Issued . . . . . .330,993,401   330,692,317
    (8,999,992 shares held in treasury). . . . . . . . . .       2,151          2,149
  Paid-in Capital. . . . . . . . . . . . . . . . . . . . .       2,915          2,898
  Accumulated Other Comprehensive Income (Loss). . . . . .        (155)            (4)
  Retained Earnings. . . . . . . . . . . . . . . . . . . .       3,506          3,630
                                                               -------        -------

          TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . . .       8,417          8,673
                                                               -------        -------

            TOTAL. . . . . . . . . . . . . . . . . . . . .     $40,518        $35,719
                                                               =======        =======

See Notes to Financial Statements beginning on page L-1.

</TABLE>
<PAGE>
<TABLE>
<CAPTION>


         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                     Nine Months Ended
                                                                       September 30,
                                                                  ---------------------
                                                                     2000         1999
                                                                     ----         ----
                                                                       (in millions)

OPERATING ACTIVITIES:
<S>                                                                <C>          <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . . . .   $   489      $   779
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . . . .       976          976
    Deferred Federal Income Taxes. . . . . . . . . . . . . . . .        40           99
    Deferred Investment Tax Credits. . . . . . . . . . . . . . .       (26)         (26)
    Amortization of Deferred Property Taxes. . . . . . . . . . .       138          138
    Amortization (Deferral) of Cook Plant Restart Costs. . . . .        30          (90)
    Deferred Costs Under Fuel Clause Mechanisms. . . . . . . . .      (276)        (133)
    Extraordinary Loss - Discontinuance of SFAS 71 . . . . . . .        35            8
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . . . .      (927)        (452)
    Fuel, Materials and Supplies . . . . . . . . . . . . . . . .        88         (131)
    Accrued Utility Revenues . . . . . . . . . . . . . . . . . .      (134)        -
    Prepayments and Other. . . . . . . . . . . . . . . . . . . .      (280)         (43)
    Accounts Payable . . . . . . . . . . . . . . . . . . . . . .       445           23
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . .        (3)         (46)
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . .       (15)         (43)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . . . .       (52)         134
                                                                   -------      -------
        Net Cash Flows From Operating Activities . . . . . . . .       528        1,193
                                                                   -------      -------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . . . .    (1,204)      (1,147)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . .       (29)         (26)
                                                                   -------      -------
        Net Cash Flows Used For Investing Activities . . . . . .    (1,233)      (1,173)
                                                                   -------      -------

FINANCING ACTIVITIES:
  Issuance of Common Stock . . . . . . . . . . . . . . . . . . .        12           93
  Issuance of Long-term Debt . . . . . . . . . . . . . . . . . .       948          578
  Change in Short-term Debt (net). . . . . . . . . . . . . . . .     1,406          541
  Retirement of Cumulative Preferred Stock . . . . . . . . . . .       (20)          (5)
  Retirement of Long-term Debt . . . . . . . . . . . . . . . . .    (1,400)        (618)
  Other Financing Activities . . . . . . . . . . . . . . . . . .      -             120
  Dividends Paid on Common Stock . . . . . . . . . . . . . . . .      (612)        (624)
                                                                   -------      -------
        Net Cash Flows From Financing Activities . . . . . . . .       334           85
                                                                   -------      -------

Effect of Exchange Rate Change on Cash . . . . . . . . . . . . .         7           (2)

Net Increase (Decrease) in Cash and Cash Equivalents . . . . . .      (364)         103

Cash and Cash Equivalents at Beginning of Period . . . . . . . .       659          330
                                                                   -------      -------
Cash and Cash Equivalents at End of Period . . . . . . . . . . .   $   295      $   433
                                                                   =======      =======

Supplemental Disclosure:
  Cash paid for  interest net of  capitalized  amounts was $685 million and $633
  million and for income  taxes was $242  million  and $172  million in 2000 and
  1999, respectively. Noncash acquisitions under capital leases were $79 million
  and $67 million in 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>

<PAGE>
<TABLE>
<CAPTION>



         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
             CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
                                   (UNAUDITED)

                                                                   Accumulated
                                          Additional                  Other
                                Common      Paid-in     Retained   Comprehensive
                                 Stock      Capital     Earnings   Income (Loss)  Total
                                -------   -----------   --------   -------------  -------
                                                      (in millions)

<S>                             <C>        <C>          <C>            <C>        <C>
JANUARY 1, 1999                 $2,049     $2,903       $3,507         $  7       $8,466
Conforming Change in
 Accounting Policy                -          -             (14)          -           (14)
Reclassification Adjustment         85        (85)        -              -          -
                                ------     ------       ------         ----       -------
  Adjusted Balance at
   Beginning of Period           2,134      2,818        3,493            7        8,452
Issuance of Common Stock            15         79         -              -            94
Common Stock Dividends            -          -            (624)          -          (624)
Other                             -          -              (1)          -            (1)
                                                                                  ------
                                                                                   7,921
Comprehensive Income:
  Other Comprehensive Income,
  Net of Taxes
    Foreign Currency Translation
     Adjustment                   -          -            -             (30)         (30)
    Unrealized Gains
     on Securities                -          -            -               9            9
   Net Income                     -          -             779           -           779
                                                                                  ------

    Total Comprehensive Income                                                       758
                                ------     ------       ------         ----       ------

SEPTEMBER 30, 1999              $2,149     $2,897       $3,647         $(14)      $8,679
                                ======     ======       ======         ====       ======


JANUARY 1, 2000                 $2,064     $2,983       $3,646         $ (4)      $8,689
Conforming Change in
 Accounting Policy                -          -             (16)          -           (16)
Reclassification Adjustment         85        (85)        -              -          -
                                ------     ------       ------         ----       ----------
  Adjusted Balance at
   Beginning of Period           2,149      2,898        3,630           (4)       8,673
Issuance of Common Stock             2         10         -              -            12
Common Stock Dividends            -          -            (612)          -          (612)
Other                             -             7           (1)          -             6
                                                                                  ------
                                                                                   8,079
Comprehensive Income:
  Other Comprehensive Income,
  Net of Taxes
   Foreign Currency Translation
    Adjustment                    -          -            -             (171)       (171)
   Reclassification Adjustment
    For Loss Included in
     Net Income                   -          -            -               20          20
  Net Income                      -          -             489           -           489
                                                                                  ------

 Total Comprehensive Income                                                          338
                                ------     ------       ------         -----      ------

SEPTEMBER 30, 2000              $2,151     $2,915       $3,506         $(155)     $8,417
                                ======     ======       ======         =====      ======

See Notes to Financial Statements beginning on page L-1.

</TABLE>
<PAGE>


         AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                    THIRD QUARTER 2000 vs. THIRD QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

        Income before  extraordinary items remained constant for the quarter and
decreased by $263 million or 33% for the year-to-date  period due  predominately
to the expensing of costs related to AEP's  recently  completed  merger with CSW
and a write down to market of a CSW  investment  in a company  based in Chile in
the second  quarter  and  increased  costs to restart  the Cook  Nuclear  Plant.
Extraordinary  losses were recorded in both periods as a result of discontinuing
SFAS 71  regulatory  accounting in the Ohio  jurisdiction  in 2000 and Texas and
Arkansas jurisdictions in 1999.
        Excluding  extraordinary  items,  increased  Cook Plant  restart  costs,
merger expenses and the write down of the Chilean investment, comparative income
before extraordinary items for the third quarter and nine months ended September
were  favorable.  This favorable  result was  predominately  due to increases in
wholesale marketing sales and net revenues from trading.
        Income statement line items which changed significantly were:

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

Revenues:
  Domestic Electric Utilities. . . . . .  $305     10     $557      7
  Worldwide Electric and Gas Operations.    84     14      164      9
Fuel and Purchased Power Expense . . . .   165     15      400     15
Maintenance and Other Operation
   Expense . . . . . . . . . . . . . . .    78     11      204     10
Merger Costs . . . . . . . . . . . . . .    20    N.M.     181    N.M.
Worldwide Electric and Gas Operations
   Expense . . . . . . . . . . . . . . .    37      7      162     10
Interest and Preferred Dividends . . . .    25     10       58      8
Income Taxes . . . . . . . . . . . . . .    53     32      (55)   (14)

N.M. = Not Meaningful

        Domestic  revenues  increased  in the  third  quarter  due to  increased
fuel-related  revenues,  reflecting  higher fuel and purchased  power  expenses,
discussed  below,  and increased  wholesale sales to and forward net trades with
other utilities and marketers by the domestic electric utility  business.  These
domestic  wholesale  revenue  increases  were offset by a decline in  industrial
retail sales which reflects the  expiration of a long-term  contract on December
31,  1999.  The  increase in wholesale  sales  resulted  from growing the energy
marketing and trading operations,  favorable wholesale market conditions and the
availability of additional generation due to the return to service of one of the
Cook Nuclear Units in June 2000 and improved generating unit outage management.
        Revenues from worldwide electric and gas operations  increased primarily
due to increased  natural gas and gas liquid product prices.  Volumes of natural
gas remained  consistent  with the prior year,  however,  prices have  increased
significantly rebounding from a depressed gas market during 1999.
        The  increase  in  fuel  and  purchased   power  expense  was  primarily
attributable  to a  significant  increase  in the cost of  natural  gas used for
generation.
        Maintenance and other operation expense increased for the quarter due to
increased usage of and prices for emission allowances, higher ERCOT transmission
charges and  increases in employee  related  expenses.  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  January 1,
2000. The increase in transmission  expenses resulted from higher prices for the
ERCOT transmission  usage. Each year ERCOT establishes new rates to allocate the
cost of the Texas transmission system to Texas electric utilities.  Accruals for
incentive  compensation  caused the increase in employee related  expenses.  The
increase in maintenance and other operation expense for the year-to-date  period
was mainly due to increased expenditures to prepare the Cook Plant nuclear units
for restart  following an extended NRC monitored  outage.  The increase  results
from the  effect  of  deferring  restart  costs in 1999 and an  increase  in the
restart  expenditure level. The Cook Plant began an 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.  Unit 2 returned to service in June
and achieved full power operation on July 5, 2000.  Management expects,  barring
any  unforeseen  events,  that Unit 1 will be restarted in the first  quarter of
2001.
        With the  consummation of the merger with CSW, certain merger costs were
expensed.  The merger costs expensed  included  transaction and transition costs
not allocable to and recoverable  from ratepayers  under  regulatory  commission
approved settlement agreements to share net merger savings.
        Worldwide  electric and gas  operations  expense rose in the quarter due
mainly to a  significant  increase in prices for natural gas used to produce gas
liquid products. For the year-to-date period, the increase in worldwide electric
and gas  operations  expense was due to the increase in natural gas prices and a
second quarter write down to market value of an available-for-sale investment in
a Chilean-based electric company.
        Interest and preferred dividends increased due to an increase in average
outstanding  short-term debt balances and an increase in average short-term debt
interest rates reflecting  increased short-term cash demands and short-term debt
market conditions.
        The third  quarter  increase  in income  taxes  results  from  increased
pre-tax  income and the  favorable  effect of a 1999  foreign  tax  credit.  The
decrease in income taxes in the year-to-date  period is  predominately  due to a
decrease in pre-tax income.


<PAGE>
<TABLE>
<CAPTION>



                                AEP GENERATING COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)

                                            Three Months Ended    Nine Months Ended
                                              September 30,          September 30,
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)

<S>                                        <C>        <C>         <C>         <C>
OPERATING REVENUES . . . . . . . . . . .   $55,658    $57,235     $169,452    $161,674
                                           -------    -------     --------    --------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    25,308     28,556       75,791      68,983
  Rent - Rockport Plant Unit 2 . . . . .    17,071     17,071       51,212      51,212
  Other Operation. . . . . . . . . . . .     1,840      2,447        6,894       7,909
  Maintenance. . . . . . . . . . . . . .     2,042      1,457        7,723       8,208
  Depreciation . . . . . . . . . . . . .     5,558      5,459       16,604      16,382
  Taxes Other Than Federal Income Taxes.     1,164      1,398        3,414       3,890
  Federal Income Tax Expense (Credit). .       466        (74)       1,464         807
                                           -------    -------     --------    --------

          TOTAL OPERATING EXPENSES . . .    53,449     56,314      163,102     157,391
                                           -------    -------     --------    --------

OPERATING INCOME . . . . . . . . . . . .     2,209        921        6,350       4,283

NONOPERATING INCOME. . . . . . . . . . .       869        885        2,638       2,630
                                           -------    -------     --------    --------

INCOME BEFORE INTEREST CHARGES . . . . .     3,078      1,806        8,988       6,913

INTEREST CHARGES . . . . . . . . . . . .     1,106        848        2,918       2,119
                                           -------    -------     --------    --------

NET INCOME . . . . . . . . . . . . . . .   $ 1,972    $   958     $  6,070    $  4,794
                                           =======    =======     ========    ========



                         STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                           Three Months Ended      Nine Months Ended
                                              September 30,           September 30,
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . .    $5,836    $4,460       $3,673      $2,770

NET INCOME . . . . . . . . . . . . . . .     1,972       958        6,070       4,794

CASH DIVIDENDS DECLARED. . . . . . . . .       -       2,073        1,935       4,219
                                            ------    ------       ------      ------

BALANCE AT END OF PERIOD . . . . . . . .    $7,808    $3,345       $7,808      $3,345
                                            ======    ======       ======      ======

The common stock of the Company is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.

</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                             AEP GENERATING COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)


                                                            September 30,  December 31,
                                                                2000           1999
                                                            -------------  ------------
                                                                   (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:

<S>                                                           <C>            <C>
  Production. . . . . . . . . . . . . . . . . . . . . . . .   $635,389       $629,286
  General . . . . . . . . . . . . . . . . . . . . . . . . .      2,587          2,400
  Construction Work in Progress . . . . . . . . . . . . . .      3,463          8,407
                                                              --------       --------

          Total Electric Utility Plant. . . . . . . . . . .    641,439        640,093

  Accumulated Depreciation. . . . . . . . . . . . . . . . .    310,815        295,065
                                                              --------       --------


          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .    330,624        345,028
                                                              --------       --------

CURRENT ASSETS:

  Cash and Cash Equivalents . . . . . . . . . . . . . . . .        189            317
  Accounts Receivable:
    Affiliated Companies. . . . . . . . . . . . . . . . . .     38,442         22,464
    Miscellaneous . . . . . . . . . . . . . . . . . . . . .      2,186          2,643
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . .     17,999         17,505
  Materials and Supplies. . . . . . . . . . . . . . . . . .      4,203          3,966
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .       -               150
                                                              --------       --------


          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     63,019         47,045
                                                              --------       --------


REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .      5,564          5,744
                                                              --------       --------


DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .      1,567            823
                                                              --------       --------




            TOTAL . . . . . . . . . . . . . . . . . . . . .   $400,774       $398,640
                                                              ========       ========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                             AEP GENERATING COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)


                                                            September 30,  December 31,
                                                                 2000          1999
                                                            -------------  ------------
                                                                   (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 . . . . . . . . . . . . . . . . . . . . .     24,369         29,235
  Retained Earnings . . . . . . . . . . . . . . . . . . . .      7,808          3,673
                                                              --------       --------

          TOTAL CAPITALIZATION AND
                 COMMON SHAREHOLDER'S EQUITY . . . . . . . . . .     33,177         33,908
                                                                   --------       --------

OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . .        421            592
                                                              --------       --------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year. . . . . . . . . . . .     44,806         44,800
  Short-term Debt - Notes Payable . . . . . . . . . . . . .       -            24,700
  Advances from Affiliates. . . . . . . . . . . . . . . . .     31,574           -
  Accounts Payable:
    General . . . . . . . . . . . . . . . . . . . . . . . .      6,576          7,539
    Affiliated Companies. . . . . . . . . . . . . . . . . .      4,783         19,451
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      8,907          4,285
  Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . .     23,427          4,963
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      4,228          4,763
                                                              --------       --------

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .    124,301        110,501
                                                              --------       --------

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . .    123,581        127,759
                                                              --------       --------

REGULATORY LIABILITIES:
  Deferred Investment Tax Credits . . . . . . . . . . . . .     60,603         63,114
  Amounts Due to Customers for Income Taxes . . . . . . . .     24,527         26,266
                                                              --------       --------

          TOTAL REGULATORY LIABILITIES. . . . . . . . . . .     85,130         89,380
                                                              --------       --------

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     34,014         36,500
                                                              --------       --------

DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . .        150           -
                                                              --------       --------

CONTINGENCIES (Note 12)

            TOTAL . . . . . . . . . . . . . . . . . . . . .   $400,774       $398,640
                                                              ========       ========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                             AEP GENERATING COMPANY
                            STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                 Nine Months Ended
                                                                   September 30,
                                                                 2000          1999
                                                                 ----          ----
                                                                   (in thousands)

OPERATING ACTIVITIES:
<S>                                                            <C>           <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .   $  6,070      $  4,794
  Adjustments for Noncash Items:
    Depreciation . . . . . . . . . . . . . . . . . . . . . .     16,604        16,382
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     (4,225)       (3,994)
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (2,511)       (2,516)
    Amortization of Deferred Gain on Sale
      and Leaseback - Rockport Plant Unit 2. . . . . . . . .     (4,178)       (4,178)
    Deferred Property Taxes. . . . . . . . . . . . . . . . .       (807)         (827)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable. . . . . . . . . . . . . . . . . . .    (15,521)          772
    Fuel, Materials and Supplies . . . . . . . . . . . . . .       (731)       (7,886)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    (15,631)        6,890
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .      4,622         2,919
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .     18,464        18,464
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .      1,056        (2,549)
                                                               --------      --------
        Net Cash Flows From Operating Activities . . . . . .      3,212        28,271
                                                               --------      --------

INVESTING ACTIVITIES - Construction Expenditures . . . . . .     (3,413)       (5,671)
                                                               --------      --------

FINANCING ACTIVITIES:
  Return of Capital to Parent Company. . . . . . . . . . . .     (4,866)       (6,000)
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (24,700)      (10,625)
  Change in Advances from Affiliates (net) . . . . . . . . .     31,574          -
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .     (1,935)       (4,219)
                                                               --------      --------
        Net Cash Flows From (Used For) Financing Activities.         73       (20,844)
                                                               --------      --------

Net Increase (Decrease) in Cash and Cash Equivalents . . . .       (128)        1,756
Cash and Cash Equivalents at Beginning of Period . . . . . .        317           232
                                                               --------      --------
Cash and Cash Equivalents at End of Period . . . . . . . . .   $    189      $  1,988
                                                               ========      ========

Supplemental Disclosure:
  Cash  paid  for  interest  net  of  capitalized  amounts  was  $2,671,000  and
  $1,889,000  and for income taxes was  $3,101,000  and  $4,458,000  in 2000 and
  1999, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>



                             AEP GENERATING COMPANY
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                    THIRD QUARTER 2000 vs. THIRD QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

        Operating  revenues are derived  from the sale of Rockport  Plant energy
and capacity to two affiliated  companies and in 1999 one  unaffiliated  utility
pursuant  to FERC  approved  long-term  unit  power  agreements.  The unit power
agreements  provide for  recovery of costs  including  a FERC  approved  rate of
return on common  equity and a return on other  capital  net of  temporary  cash
investments.
        Net income increased $1 million or 106% for the third quarter  primarily
as a result of the effect of expenses incurred in the third quarter of 1999 that
were included in billings to wholesale  customers in the fourth quarter of 1999,
partially  offset by a return of capital that decreased the equity return.  Also
contributing  to  the  $1.3  million  or 27%  increase  in net  income  for  the
year-to-date  period was the effect on billings to  wholesale  customers  of the
placing  in-service of plant  additions.  The transfer of  construction  work in
progress to in-service  plant  increases the billings  because the AFUDC rate is
lower than the equity return billed.
        Income statement line items which changed significantly were:

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

Operating Revenues . . . . . . .     $(1.6)     (3)     $ 7.8       5
Fuel Expense . . . . . . . . . .      (3.2)    (11)       6.8      10
Other Operation Expense. . . . .      (0.6)    (25)      (1.0)    (13)
Maintenance Expense. . . . . . .       0.6      40       (0.5)     (6)
Taxes Other Than Federal
  Income Taxes . . . . . . . . .      (0.2)    (17)      (0.5)    (12)
Federal Income Taxes . . . . . .       0.5     N.M.       0.7      81
Interest Charges . . . . . . . .       0.3      30        0.8      38

N.M. = Not Meaningful

        Operating  revenues  decreased for the quarter as a result of a decrease
in generation  of 14%  reflecting  reduced  availability  of the Rockport  Plant
units.
        The increase in year-to-date  operating revenues resulted primarily from
an  increase  in  recoverable  expenses  as  generation  increased  due  to  the
availability of the Rockport Plant. In 1999 planned  maintenance outages reduced
the  availability of the Rockport Plant units.  Shorter outages in the first and
second  quarters of 2000 allowed the  Rockport  Plant units to generate 22% more
electricity in the first six months of 2000 than in 1999.
        Fuel  expense   decreased   for  the  quarter  and   increased  for  the
year-to-date period resulting from a decrease and an increase,  respectively, in
generation.
        The effect of an  unfavorable  accrual  adjustment  for a FERC operating
assessment  recorded  in 1999 was the primary  reason for the  decrease in other
operation  expense.  Also  contributing  to  the  year-to-date  decrease  was  a
reduction in pension  expense due to favorable  pension fund  performance and an
insurance recovery for damaged rail cars.
        The reduction in the number of outages and the shorter length of planned
outages  accounted for the decrease in maintenance  expense for the year-to-date
period.  The increase in maintenance  expense for the quarter was due to outages
for both units in the current period.
        Taxes other than  federal  income  taxes  declined  due to a decrease in
state income taxes  attributable to the filing of a consolidated tax return with
an affiliate that had reduced taxable income.
        Federal  income taxes  attributable  to  operations  increased due to an
increase in pre-tax income.
        The  increase in interest  charges was due to an increase in the average
outstanding  short-term debt balances and an increase in average  interest rates
on short-term and variable rate debt  reflecting the Company's  short-term  cash
demands and market conditions for short-term interest rates.



<PAGE>
<TABLE>
<CAPTION>



                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                            Three Months Ended         Nine Months Ended
                                              September 30,             September 30,
                                           2000        1999          2000         1999
                                           ----        ----          ----         ----
                                                         (in thousands)

<S>                                      <C>         <C>          <C>          <C>
OPERATING REVENUES . . . . . . . . . . . $475,092    $441,435     $1,360,687   $1,242,903
                                         --------    --------     ----------   ----------
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   88,769     108,701        279,989      331,933
  Purchased Power. . . . . . . . . . . .  128,489      93,041        327,463      204,680
  Other Operation. . . . . . . . . . . .   72,297      59,090        194,504      182,001
  Maintenance. . . . . . . . . . . . . .   29,369      26,240         86,683       93,112
  Depreciation and Amortization. . . . .   42,798      37,700        120,035      111,475
  Taxes Other Than Federal Income Taxes.   30,088      29,201         89,550       89,242
  Federal Income Taxes . . . . . . . . .   17,532      21,153         60,259       49,445
                                         --------    --------     ----------   ----------

          TOTAL OPERATING EXPENSES . . .  409,342     375,126      1,158,483    1,061,888
                                         --------    --------     ----------   ----------
OPERATING INCOME . . . . . . . . . . . .   65,750      66,309        202,204      181,015
NONOPERATING INCOME. . . . . . . . . . .    2,399       1,925          6,607        1,152
                                         --------    --------     ----------   ----------
INCOME BEFORE INTEREST CHARGES . . . . .   68,149      68,234        208,811      182,167
INTEREST CHARGES . . . . . . . . . . . .   32,037      32,573         94,795       96,209
                                         --------    --------     ----------   ----------
INCOME BEFORE EXTRAORDINARY ITEM . . . .   36,112      35,661        114,016       85,958
EXTRAORDINARY GAIN - DISCONTINUANCE OF
 REGULATORY ACCOUNTING FOR GENERATION
 (INCLUSIVE OF TAX BENEFIT
 OF $7,872,000). . . . . . . . . . . . .     -           -             8,938         -
                                         --------    --------     ----------   ----------
NET INCOME . . . . . . . . . . . . . . .   36,112      35,661        122,954       85,958
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      750         667          2,015        2,015
                                         --------    --------     ----------   ----------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 35,362    $ 34,994     $  120,939   $   83,943
                                         ========    ========     ==========   ==========

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                           Three Months Ended        Nine Months Ended
                                             September 30,             September 30,
                                           2000        1999          2000         1999
                                           ----        ----          ----         ----
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $198,126    $167,714     $175,854       $179,461
NET INCOME . . . . . . . . . . . . . . .   36,112      35,661      122,954         85,958
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .   31,653      30,348       94,959         91,044
    Cumulative Preferred Stock . . . . .      375         558        1,425          1,690
  Capital Stock Expense. . . . . . . . .      375         109          589            325
                                         --------    --------     --------       --------

BALANCE AT END OF PERIOD . . . . . . . . $201,835    $172,360     $201,835       $172,360
                                         ========    ========     ========       ========

The common stock of the Company is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                         September 30,    December 31,
                                                              2000            1999
                                                         -------------    ------------
                                                                 (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                        <C>             <C>
  Production . . . . . . . . . . . . . . . . . . . . .     $2,042,497      $2,014,968
  Transmission . . . . . . . . . . . . . . . . . . . .      1,173,720       1,151,377
  Distribution . . . . . . . . . . . . . . . . . . . .      1,793,783       1,741,685
  General. . . . . . . . . . . . . . . . . . . . . . .        248,938         247,798
  Construction Work in Progress. . . . . . . . . . . .        100,553         107,123
                                                           ----------      ----------
          Total Electric Utility Plant . . . . . . . .      5,359,491       5,262,951
  Accumulated Depreciation and Amortization. . . . . .      2,163,483       2,079,490
                                                           ----------      ----------

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      3,196,008       3,183,461
                                                           ----------      ----------



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        251,775         160,546
                                                           ----------      ----------



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .          7,167          64,828
  Advances to Affiliates . . . . . . . . . . . . . . .          8,626            -
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .        192,113         109,525
    Affiliated Companies . . . . . . . . . . . . . . .         42,175          37,827
    Miscellaneous. . . . . . . . . . . . . . . . . . .         21,216           9,154
    Allowance for Uncollectible Accounts . . . . . . .         (2,181)         (2,609)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         43,046          58,161
  Materials and Supplies . . . . . . . . . . . . . . .         63,113          56,917
  Accrued Utility Revenues . . . . . . . . . . . . . .         40,470          53,418
  Energy Trading Contracts . . . . . . . . . . . . . .        420,386         143,777
  Prepayments. . . . . . . . . . . . . . . . . . . . .          6,257           7,713
                                                           ----------      ----------

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        842,388         538,711
                                                           ----------      ----------


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        441,601         436,894
                                                           ----------      ----------


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         24,817          34,788
                                                           ----------      ----------

            TOTAL. . . . . . . . . . . . . . . . . . .     $4,756,589      $4,354,400
                                                           ==========      ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>

<PAGE>
<TABLE>
<CAPTION>



                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                       September 30,    December 31,
                                                            2000            1999
                                                       -------------    ------------
                                                               (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                      <C>             <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  30,000,000 Shares
    Outstanding - 13,499,500 Shares. . . . . . . . . .   $  260,458      $  260,458
  Paid-in Capital. . . . . . . . . . . . . . . . . . .      715,066         714,259
  Retained Earnings. . . . . . . . . . . . . . . . . .      201,835         175,854
                                                         ----------      ----------
          Total Common Shareholder's Equity. . . . . .    1,177,359       1,150,571
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .       17,818          18,491
    Subject to Mandatory Redemption. . . . . . . . . .       10,860          20,310
  Long-term Debt . . . . . . . . . . . . . . . . . . .    1,435,496       1,539,302
                                                         ----------      ----------

          TOTAL CAPITALIZATION . . . . . . . . . . . .    2,641,533       2,728,674
                                                         ----------      ----------

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .      117,150         132,130
                                                         ----------      ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .      175,005         126,005
  Short-term Debt. . . . . . . . . . . . . . . . . . .      100,025         123,480
  Accounts Payable - General . . . . . . . . . . . . .      116,545          59,150
  Accounts Payable - Affiliated Companies. . . . . . .       86,635          42,459
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .       63,122          49,038
  Customer Deposits. . . . . . . . . . . . . . . . . .       12,607          12,898
  Interest Accrued . . . . . . . . . . . . . . . . . .       35,424          19,079
  Energy Trading Contracts . . . . . . . . . . . . . .      411,887         140,279
  Other. . . . . . . . . . . . . . . . . . . . . . . .       64,177          71,044
                                                         ----------      ----------

          TOTAL CURRENT LIABILITIES. . . . . . . . . .    1,065,427         643,432
                                                         ----------      ----------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .      679,784         671,917
                                                         ----------      ----------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       44,562          57,259
                                                         ----------      ----------

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .      208,133         120,988
                                                         ----------      ----------

CONTINGENCIES (Note 12)

            TOTAL. . . . . . . . . . . . . . . . . . .   $4,756,589      $4,354,400
                                                         ==========      ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>

<PAGE>
<TABLE>
<CAPTION>



                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                 Nine Months Ended
                                                                    September 30,
                                                                 2000           1999
                                                                 ----           ----
                                                                    (in thousands)
OPERATING ACTIVITIES:
<S>                                                           <C>             <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 122,954       $ 85,958
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    120,119        112,264
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     14,059         10,947
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (3,446)        (3,516)
    Provision for Rate Refunds . . . . . . . . . . . . . . .     (4,818)         5,139
    Deferred Power Supply Costs (net). . . . . . . . . . . .    (80,232)        27,715
    Amortization of Deferred Property Taxes. . . . . . . . .     13,051         13,302
    Extraordinary Gain - Discontinuance of SFAS No. 71 . . .     (8,938)          -
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    (99,426)        21,766
    Fuel, Materials and Supplies . . . . . . . . . . . . . .      8,919         (8,377)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     12,948          5,409
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    101,571        (27,582)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .     14,084         (1,775)
    Interest Accrued . . . . . . . . . . . . . . . . . . . .     16,345         10,255
    Revenue Refunds Accrued. . . . . . . . . . . . . . . . .       -           (95,267)
  Payment of Disputed Tax and Interest Related to COLI . . .       -            (4,124)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     42,216        (31,362)
                                                              ---------      ---------
        Net Cash Flows From Operating Activities . . . . . .    269,406        120,752
                                                              ---------      ---------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (132,290)      (134,645)
  Proceeds from Sale of Property . . . . . . . . . . . . . .        160            274
                                                              ---------      ---------
        Net Cash Flows Used For Investing Activities . . . .   (132,130)      (134,371)
                                                              ---------      ---------

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company. . . . . . . . .       -            25,000
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .     74,788        148,751
  Change in Short-term Debt (net). . . . . . . . . . . . . .    (23,455)        42,980
  Change in Advances to Affiliates (net) . . . . . . . . . .     (8,626)          -
  Retirement of Cumulative Preferred Stock . . . . . . . . .     (9,905)          (587)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (131,202)       (86,687)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (94,959)       (91,044)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (1,578)        (1,699)
                                                              ---------      ---------
        Net Cash Flows From (Used For) Financing Activities.   (194,937)        36,714
                                                              ---------      ---------

Net Increase (Decrease) in Cash and Cash Equivalents . . . .    (57,661)        23,095
Cash and Cash Equivalents at Beginning of Period . . . . . .     64,828          7,755
                                                              ---------      ---------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $   7,167      $  30,850
                                                              =========      =========

Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $75,938,000  and
  $83,069,000  and for income taxes was  $30,503,000 and $33,996,000 in 2000 and
  1999, respectively. Noncash acquisitions under capital leases were $11,312,000
  and $12,132,000 in 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>



                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
                    THIRD QUARTER 2000 vs. THIRD QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

        Income before extraordinary items increased slightly for the quarter and
increased  by $28  million or 33% for the  year-to-date  period  largely  due to
increased  operating  income. An extraordinary  gain from the  discontinuance of
SFAS 71 regulatory  accounting of $9 million after tax was recorded in June 2000
(See Note 9 - Industry Restructuring).
        Income statement line items which changed significantly were:
                                         Increase (Decrease)
                                 Third Quarter        Year-to-Date
                                (in millions)  %   (in millions)   %

Operating Revenues . . . . . . .    $ 34       8       $118        9
Fuel Expense . . . . . . . . . .     (20)    (18)       (52)     (16)
Purchased Power Expense. . . . .      35      38        123       60
Other Operation Expense. . . . .      13      22         13        7
Maintenance Expense. . . . . . .       3      12         (6)      (7)
Depreciation and Amortization. .       5      14          9        8
Federal Income Taxes . . . . . .      (4)    (17)        11       22
Extraordinary Gain . . . . . . .      -       -           9      N.M.

N.M. = Not Meaningful
The increase in operating revenues and purchased power expense resulted from the
Company's share of increased wholesale electricity transactions by the AEP Power
Pool.  The Company as a member of the AEP Power Pool 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. The Company's share of the AEP Power Pool's
wholesale sales are recorded as operating  revenues and purchased power expense.
Forward  trading  sales  and  purchases  within  the  AEP  System's  traditional
marketing area (within two transmission  systems of the AEP System) are recorded
on a net basis in operating revenues.  Wholesale Power Pool sales increased as a
result of growing  the AEP Power  marketing  and  trading  operation,  favorable
wholesale  market  conditions  and  increased  availability  of AEP  Power  Pool
generation  for  wholesale  sales.  The  increase  in AEP Power Pool  generation
availability was due to an affiliate's nuclear out of service unit going on line
in June 2000, a major industrial  customer's decision not to continue purchasing
its power from an affiliate, and improved generating unit outage management.


        Fuel expense decreased due to the combined effect of the  discontinuance
of deferred accounting for over or under recovery of fuel cost effective January
1, 2000 as a result of the  discontinuance of cost based rate making in WV and a
decrease in the average cost of fuel consumed.
        The increase in other operation  expense was due to increased  marketing
and trading costs including increased accruals for incentive compensation and an
increase  in  transmission  equalization  payments.  Under  the AEP East  Region
Transmission  Agreement,  the  Company  shares  the  costs  associated  with the
ownership of the extra-high voltage  transmission  system and certain facilities
at lower voltages based upon each company's MLR and  investment.  An increase in
the  Company's  MLR  was  the  main  reason  for the  increase  in  transmission
equalization charges.
        The increase in  maintenance  expense in the third quarter is due to the
effect of performing  generating plant boiler plant  maintenance  repairs to the
Amos Plant in 2000.  The  decrease in  maintenance  expense in the  year-to-date
period  is  due  to  the  effect  of  performing  more  extensive  boiler  plant
maintenance  repairs  during 1999 than in 2000 and the effect of  recording  two
years of storm damage amortization in 1999 pursuant to a Virginia SCC order.
        Depreciation and amortization  expense increased due to the amortization
beginning in July 2000 of a new transition  regulatory asset established in June
2000 for the net  generation-related  regulatory assets related to the Company's
Virginia  and  West  Virginia   jurisdictions   that  were  transferred  to  the
distribution  portion of the business and are currently being recovered  through
regulated  rates  (see  Note  9  for  further   discussion  of  the  effects  of
restructuring). Additional investments in distribution plant also contributed to
the increase in depreciation and amortization expense.
        The decrease in federal  income taxes for the quarter was  primarily due
to  changes  in  certain  book/tax  timing   differences   accounted  for  on  a
flow-through  basis for  rate-making  and  financial  reporting  purposes  and a
decrease in pre-tax  operating  income.  For the  year-to-date  period,  federal
income taxes attributable to operations  increased  primarily due to an increase
in pre-tax operating income.
        The  extraordinary  gain recorded in the second  quarter of 2000 was the
result of the  discontinuance  of SFAS 71,  for the  generation  portion  of the
Company's business in Virginia and West Virginia.  Based on management's  belief
that all net  regulatory  assets  related  to the  Virginia  and  West  Virginia
generation  business will be recovered,  the  Company's  generation-related  net
regulatory assets were transferred to the regulated  distribution portion of the
business  and are being  amortized  as they are  recovered  through  rates.  The
Company  performed an accounting  impairment  analysis of its generation  assets
under SFAS 121 and concluded  there was no  accounting  impairment of generation
assets.


<PAGE>
<TABLE>
<CAPTION>

                     CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                          Three Months Ended       Nine Months Ended
                                             September 30,            September 30,
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)

<S>                                        <C>        <C>        <C>        <C>
OPERATING REVENUES . . . . . . . . . . .   $601,369   $495,653   $1,355,608 $1,161,714
                                           --------   --------   ---------- ----------
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    181,827    138,020      412,065    312,333
  Purchased Power. . . . . . . . . . . .     75,398     24,229      130,754     53,624
  Other Operation. . . . . . . . . . . .    101,116     69,288      230,725    198,180
  Maintenance. . . . . . . . . . . . . .     12,780     13,615       44,676     48,797
  Depreciation and Amortization. . . . .     41,970     68,160      137,055    154,531
  Taxes Other Than Federal Income Taxes.     19,717     14,899       57,173     61,194
  Federal Income Taxes . . . . . . . . .     47,908     39,943       88,140     79,784
                                           --------   --------   ---------- ----------
          TOTAL OPERATING EXPENSES . . .    480,716    368,154    1,100,588    908,443
                                           --------   --------   ---------- ----------

OPERATING INCOME . . . . . . . . . . . .    120,653    127,499      255,020    253,271

NONOPERATING INCOME. . . . . . . . . . .        818      2,080        3,180      4,227
                                           --------   --------   ---------- ----------

INCOME BEFORE INTEREST CHARGES . . . . .    121,471    129,579      258,200    257,498

INTEREST CHARGES . . . . . . . . . . . .     31,497     25,590       92,534     85,463
                                           --------   --------   ---------- ----------

NET INCOME . . . . . . . . . . . . . . .     89,974    103,989      165,666    172,035

PREFERRED STOCK DIVIDEND REQUIREMENTS. .         60      1,979          181      5,527
                                           --------   --------   ---------- ----------

EARNINGS APPLICABLE TO COMMON STOCK. . .   $ 89,914   $102,010   $  165,485 $  166,508
                                           ========   ========   ========== ==========

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                          Three Months Ended        Nine Months Ended
                                              September 30,           September 30,
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD
  AS PREVIOUSLY REPORTED . . . . . . .    $756,465  $730,419      $764,225    $739,031
CONFORMING CHANGE IN ACCOUNTING POLICY        -       (5,535)       (5,331)     (4,644)
                                          --------  --------      --------    --------
ADJUSTED BALANCE AT BEGINNING OF
  PERIOD . . . . . . . . . . . . . . . .   756,465   724,884       758,894     734,387
NET INCOME . . . . . . . . . . . . . . .    89,974   103,989       165,666     172,035

DEDUCTIONS:
  Cash Dividends Declared:
        Common Stock . . . . . . . . . .    39,000    37,000       117,000     111,000
        Preferred Stock. . . . . . . . .        60     1,979           181       5,527
  Other. . . . . . . . . . . . . . . . .         1        (2)            1          (1)
                                          --------  --------      --------    --------

BALANCE AT END OF PERIOD . . . . . . . .  $807,378  $789,896      $807,378    $789,896
                                          ========  ========      ========    ========

The Company is a wholly owned subsidiary of AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                            September 30,  December 31,
                                                                 2000          1999
                                                            -------------  -----------
                                                                   (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                          <C>            <C>
  Production. . . . . . . . . . . . . . . . . . . . . . . .  $3,174,186     $3,152,319
  Transmission. . . . . . . . . . . . . . . . . . . . . . .     582,395        566,629
  Distribution. . . . . . . . . . . . . . . . . . . . . . .   1,205,873      1,157,091
  General . . . . . . . . . . . . . . . . . . . . . . . . .     236,292        307,378
  Construction Work in Progress . . . . . . . . . . . . . .     106,495        101,550
  Nuclear Fuel. . . . . . . . . . . . . . . . . . . . . . .     229,094        226,927
                                                             ----------     ----------

          Total Electric Utility Plant. . . . . . . . . . .   5,534,335      5,511,894

  Accumulated Depreciation. . . . . . . . . . . . . . . . .   2,277,409      2,263,925
                                                             ----------     ----------

          Net Electric Utility Plant. . . . . . . . . . . .   3,256,926      3,247,969
                                                             ----------     ----------

OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . .      58,377         41,433
                                                             ----------     ----------

CURRENT ASSETS:
  Cash and Cash Equivalents . . . . . . . . . . . . . . . .       6,244          7,995
  Special Deposits for Reacquisition of Long-term Debt. . .        -            50,000
  Accounts Receivable:
    General . . . . . . . . . . . . . . . . . . . . . . . .      61,370         49,228
    Affiliated Companies. . . . . . . . . . . . . . . . . .      33,800         15,254
  Materials and Supplies. . . . . . . . . . . . . . . . . .      56,469         58,196
  Fuel Inventory. . . . . . . . . . . . . . . . . . . . . .      22,333         26,434
  Under-recovered Fuel Costs. . . . . . . . . . . . . . . .     120,157         30,911
  Energy Trading Contracts. . . . . . . . . . . . . . . . .      38,032           -
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .       8,060          3,188
                                                             ----------     ----------

          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     346,465        241,206
                                                             ----------     ----------

REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .     224,888        240,059
                                                             ----------     ----------

REGULATORY ASSETS DESIGNATED FOR SECURITIZATION . . . . . .     953,249        953,249
                                                             ----------     ----------

NUCLEAR DECOMMISSIONING TRUST . . . . . . . . . . . . . . .      94,180         86,122
                                                             ----------     ----------

DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .      26,981         37,812
                                                             ----------     ----------

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $4,961,066     $4,847,850
                                                             ==========     ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                           September 30,   December 31,
                                                                2000           1999
                                                           -------------   ----------------
                                                                   (in thousands)

CAPITALIZATION AND LIABILITIES
<S>                                                          <C>            <C>
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 . . . . . . . . . . . . . . . . . . . .     807,378        758,894
                                                             ----------     ----------
          TOTAL COMMON SHAREHOLDER'S EQUITY . . . . . . . .   1,381,266      1,332,782

PREFERRED STOCK . . . . . . . . . . . . . . . . . . . . . .       5,967          5,967
CPL-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED
 SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR
 SUBORDINATED DEBENTURES OF CPL . . . . . . . . . . . . . .     148,500        150,000
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . .   1,454,556      1,304,541
                                                             ----------     ----------

          TOTAL CAPITALIZATION. . . . . . . . . . . . . . .   2,990,289      2,793,290
                                                             ----------     ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year. . . . . . . . . . . .        -           150,000
  Advances from Affiliates. . . . . . . . . . . . . . . . .     198,322        322,158
  Accounts Payable - General. . . . . . . . . . . . . . . .     187,356         88,702
  Accounts Payable - Affiliated Companies . . . . . . . . .      17,229         35,344
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      71,268         41,121
  Interest Accrued. . . . . . . . . . . . . . . . . . . . .      26,046         14,723
  Energy Trading Contracts. . . . . . . . . . . . . . . . .      39,809           -
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      34,916         25,349
                                                             ----------     ----------

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .     574,946        677,397
                                                             ----------     ----------

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .   1,241,981      1,234,175
                                                             ----------     ----------

DEFERRED INVESTMENT TAX CREDITS . . . . . . . . . . . . . .     129,401        133,306
                                                             ----------     ----------

DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . .      24,449          9,682
                                                             ----------     ----------

CONTINGENCIES (Note 12)

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $4,961,066     $4,847,850
                                                             ==========     ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                Nine Months Ended
                                                                  September 30,
                                                               2000           1999
                                                               ----           ----
                                                                  (in thousands)

OPERATING ACTIVITIES:
<S>                                                          <C>           <C>
 Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $165,666      $ 172,035
  Adjustments For Non-Cash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .  137,055        169,023
    Deferred Federal Income Taxes. . . . . . . . . . . . . .   14,529         (2,835)
    Deferred Investment Tax Credits. . . . . . . . . . . . .   (3,905)        (3,905)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .  (30,689)        (9,563)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .    5,829         (1,166)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .   80,539         (7,738)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .   30,147         27,935
    Fuel Recovery. . . . . . . . . . . . . . . . . . . . . .  (89,246)       (31,811)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .   18,428        (21,931)
                                                             --------       --------
        Net Cash Flows From Operating Activities . . . . . .  328,353        290,044
                                                             --------       --------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . . (137,053)      (138,506)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .     -             5,810
                                                             --------       ---------
        Net Cash Flows Used For Investing Activities . . . . (137,053)      (132,696)
                                                             --------       --------

FINANCING ACTIVITIES:
  Retirement of Long-term Debt . . . . . . . . . . . . . . . (151,440)      (125,000)
  Redemption of Preferred Stock. . . . . . . . . . . . . . .     -                (1)
  Special Deposit for Reacquisition of Long-term Debt. . . .   50,000           -
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .  149,413           -
  Changes in Advances from Affiliates. . . . . . . . . . . . (123,836)        91,394
  Dividends Paid on Common Stock . . . . . . . . . . . . . . (117,000)      (111,000)
  Dividends Paid on Preferred Stock. . . . . . . . . . . . .     (188)        (5,476)
                                                             --------       --------
        Net Cash Flows Used For Financing Activities . . . . (193,051)      (150,083)
                                                             --------       --------

Net Increase (Decrease) in Cash and Cash Equivalents . . . .   (1,751)         7,265
Cash and Cash Equivalents at Beginning of Period . . . . . .    7,995          5,195
                                                             --------       --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $  6,244       $ 12,460
                                                             ========       ========

Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $81,211,000  and
  $75,012,000  and for income taxes was  $48,141,000 and $50,798,000 in 2000 and
  1999, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>



                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                    THIRD QUARTER 2000 vs. THIRD QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

         CPL's net income  for the third  quarter  was $14  million or 13% lower
than the comparable period in 1999 and year-to-date net income was $6 million or
4% lower  largely  as a result of  increased  operating  expenses  and  interest
charges.
        Income statement line items which changed significantly were:

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

Operating Revenues . . . . . . .     $106       21      $194       17
Fuel Expense . . . . . . . . . .       44       32       100       32
Purchased Power Expense. . . . .       51      211        77      144
Other Operation Expense. . . . .       32       46        33       16
Depreciation Expense . . . . . .      (26)     (38)      (17)     (11)
Taxes Other Than Federal
  Income Taxes . . . . . . . . .        5       32        (4)      (7)
Federal Income Taxes . . . . . .        8       20         8       10
Interest Expense . . . . . . . .        6       23         7        8
Preferred Stock Dividends. . . .       (2)     (97)       (5)     (97)

         The  increase in  operating  revenues  was the result of a rise in fuel
related  revenue,  reflecting  higher fuel and  purchased  power  expenses,  and
increased wholesale sales to neighboring  utilities and marketers resulting from
the introduction of AEP's power trading and marketing  operation.  The increased
fuel related revenue is generally offset by increases in fuel related expenses.
         A rise in the  average  price per unit of fuel,  resulting  mainly from
higher  spot  market  natural gas  prices,  accounted  for the  increase in fuel
expense.
         The significant  increase in purchased power expense resulted primarily
from an increase in the cost per KWH  purchased.  The increase was primarily due
to the rise in spot market  natural gas prices,  an increase in the  quantity of
energy  purchased  to  meet  the  rise in  demand,  and  increased  cogeneration
purchases.


<PAGE>



         Other operation  expenses  increased in the third quarter primarily due
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  expenses  increased for the
first nine months due to higher administrative expenses resulting from increased
consulting  expense  for  a  sales  tax  audit,  insurance  expense,  regulatory
restructing  expenses,  and an allocation of  administrative  costs from the AEP
power trading and marketing operation.
         Depreciation and amortization  expenses decreased due to a reduction in
excess  earnings  under the Texas  Legislation.  Under  the  legislation  excess
earnings are expensed to the extent they reduce stranded cost.
         The increase for the third  quarter in taxes other than federal  income
taxes was mainly  attributable to a favorable  accrual  adjustment to ad valorem
tax expense recorded in 1999. The decline for the  year-to-date  period in taxes
other than  federal  income  taxes can be  attributed  to a  reduction  in state
franchise taxes.
         Federal income tax expense attributable to utility operations increased
as a result of a favorable  accrual  adjustment  recorded in  September  1999 in
conjunction  with the  filing  of the  1998 tax  return  and the  effect  of tax
adjustments  in 1999 for  securitization  of regulatory  assets  retroactive  to
January 1, 1999.
         The increase in interest expense for the quarter was due to an increase
in long-term debt  outstanding.  For the  year-to-date  period interest  expense
increased due to increases in long-term and short-term debt outstanding.
         Preferred  stock  dividends  decreased as a result of the redemption of
preferred stock in the fourth quarter of 1999.


<PAGE>
<TABLE>
<CAPTION>



                 COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                         Three Months Ended          Nine Months Ended
                                            September 30,               September 30,
                                           2000         1999         2000         1999
                                           ----         ----         ----         ----
                                                         (in thousands)

<S>                                      <C>          <C>        <C>            <C>
OPERATING REVENUES . . . . . . . . . . . $386,583     $368,946   $1,015,803     $949,432
                                         --------     --------   ----------     --------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   50,452       44,416      139,781      139,416
  Purchased Power. . . . . . . . . . . .   86,184       90,272      253,880      204,718
  Other Operation. . . . . . . . . . . .   57,940       46,829      153,561      139,312
  Maintenance. . . . . . . . . . . . . .   18,991       16,693       51,915       49,013
  Depreciation . . . . . . . . . . . . .   25,091       23,723       74,531       70,429
  Taxes Other Than Federal Income Taxes.   31,079       31,558       93,640       92,687
  Federal Income Taxes . . . . . . . . .   33,284       31,977       70,011       69,859
                                         --------     --------    ---------     --------
          TOTAL OPERATING EXPENSES . . .  303,021      285,468      837,319      765,434
                                         --------     --------    ---------     --------

OPERATING INCOME . . . . . . . . . . . .   83,562       83,478      178,484      183,998
NONOPERATING INCOME (LOSS) . . . . . . .     (683)      (1,076)       3,498       (1,193)
                                         --------     --------    ---------      -------
INCOME BEFORE INTEREST CHARGES . . . . .   82,879       82,402      181,982      182,805
INTEREST CHARGES . . . . . . . . . . . .   17,337       18,683       53,634       57,109
                                         --------     --------    ---------     --------
INCOME BEFORE EXTRAORDINARY ITEM . . . .   65,542       63,719      128,348      125,696

EXTRAORDINARY LOSS:
  DISCONTINUANCE OF REGULATORY
  ACCOUNTING FOR GENERATION
  (INCLUSIVE OF TAX BENEFIT
  OF $14,148,000). . . . . . . . . . . .  (25,236)        -         (25,236)        -
                                         --------     --------    ---------     --------
NET INCOME . . . . . . . . . . . . . . .   40,306       63,719      103,112      125,696
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      416          533        1,481        1,598
                                         --------     --------    ---------     --------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 39,890     $ 63,186    $ 101,631     $124,098
                                         ========     ========    =========     ========


                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                          Three Months Ended        Nine Months Ended
                                             September 30,             September 30,
                                           2000         1999         2000         1999
                                           ----         ----         ----         ----
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $261,024     $203,354    $246,584      $186,441
NET INCOME . . . . . . . . . . . . . . .   40,306       63,719     103,112       125,696
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .  169,650       21,999     216,950        65,997
    Cumulative Preferred Stock . . . . .      263          437       1,138         1,312
  Capital Stock Expense. . . . . . . . .      250           95         441           286
                                         --------     --------    --------      --------

BALANCE AT END OF PERIOD . . . . . . . . $131,167     $244,542    $131,167      $244,542
                                         ========     ========    ========      ========

The common  stock of the Company is wholly  owned by AEP. See Notes to Financial
Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                         September 30,    December 31,
                                                              2000            1999
                                                         -------------    -------------
                                                                 (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                        <C>             <C>
  Production . . . . . . . . . . . . . . . . . . . . .     $1,554,958      $1,544,858
  Transmission . . . . . . . . . . . . . . . . . . . .        357,866         350,826
  Distribution . . . . . . . . . . . . . . . . . . . .      1,085,802       1,032,550
  General. . . . . . . . . . . . . . . . . . . . . . .        146,036         141,137
  Construction Work in Progress. . . . . . . . . . . .         83,340          82,248
                                                           ----------      ----------
          Total Electric Utility Plant . . . . . . . .      3,228,002       3,151,619

  Accumulated Depreciation . . . . . . . . . . . . . .      1,275,674       1,210,994
                                                           ----------      ----------

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      1,952,328       1,940,625
                                                           ----------      ----------


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        144,551         101,286
                                                           ----------      ----------


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         11,192           5,107
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         57,768          77,418
    Affiliated Companies . . . . . . . . . . . . . . .         35,218          28,453
    Miscellaneous. . . . . . . . . . . . . . . . . . .         15,875           8,887
    Allowance for Uncollectible Accounts . . . . . . .           (659)         (3,045)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         17,958          21,484
  Materials and Supplies . . . . . . . . . . . . . . .         44,815          41,696
  Accrued Utility Revenues . . . . . . . . . . . . . .          8,037          48,117
  Energy Trading Contracts . . . . . . . . . . . . . .        224,291          90,103
  Prepayments and Other. . . . . . . . . . . . . . . .         41,469          37,969
                                                           ----------      ----------

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        455,964         356,189
                                                           ----------      ----------


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        298,235         339,103
                                                           ----------      ----------


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         25,455          72,787
                                                           ----------      ----------



            TOTAL. . . . . . . . . . . . . . . . . . .     $2,876,533      $2,809,990
                                                           ==========      ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                        September 30,    December 31,
                                                             2000            1999
                                                        -------------    ------------
                                                                (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                       <C>              <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  24,000,000 Shares
    Outstanding - 16,410,426 Shares. . . . . . . . . .    $   41,026       $   41,026
  Paid-in Capital. . . . . . . . . . . . . . . . . . .       573,314          572,873
  Retained Earnings. . . . . . . . . . . . . . . . . .       131,167          246,584
                                                          ----------       ----------
          Total Common Shareholder's Equity. . . . . .       745,507          860,483
  Cumulative Preferred Stock - Subject to
    Mandatory Redemption . . . . . . . . . . . . . . .        15,000           25,000
  Long-term Debt . . . . . . . . . . . . . . . . . . .       899,486          924,545
                                                          ----------       ----------

          TOTAL CAPITALIZATION . . . . . . . . . . . .     1,659,993        1,810,028
                                                          ----------       ----------

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        44,603           43,056
                                                          ----------       ----------

CURRENT LIABILITIES:
  Short-term Debt. . . . . . . . . . . . . . . . . . .          -              45,500
  Advances from Affiliates . . . . . . . . . . . . . .        43,970             -
  Accounts Payable - General . . . . . . . . . . . . .        65,169           28,279
  Accounts Payable - Affiliated Companies. . . . . . .       103,592           52,776
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .       107,598          143,477
  Interest Accrued . . . . . . . . . . . . . . . . . .        24,441           13,936
  Energy Trading Contracts . . . . . . . . . . . . . .       219,757           87,911
  Other. . . . . . . . . . . . . . . . . . . . . . . .        58,189           34,375
                                                          ----------       ----------

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       622,716          406,254
                                                          ----------       ----------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       433,575          447,607
                                                          ----------       ----------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .        42,175           44,716
                                                          ----------       ----------

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .        73,471           58,329
                                                          ----------       ----------

CONTINGENCIES (Note 12)

            TOTAL. . . . . . . . . . . . . . . . . . .    $2,876,533       $2,809,990
                                                          ==========       ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                Nine Months Ended
                                                                   September 30,
                                                               2000            1999
                                                               ----            ----
                                                                  (in thousands)
OPERATING ACTIVITIES:
<S>                                                          <C>            <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 103,112      $ 125,696
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization . . . . . . . .    74,945         70,727
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     7,945          7,854
    Deferred Investment Tax Credits. . . . . . . . . . . . .    (2,541)        (2,605)
    Deferred Fuel Costs (net). . . . . . . . . . . . . . . .       890          3,765
    Amortization of Deferred Property Taxes. . . . . . . . .    50,130         51,680
    Extraordinary Loss - Discontinuance of SFAS No. 71 . . .    25,236           -
  Changes in Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .     3,511         (5,666)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .       407         (6,277)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .    40,080         (5,076)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    87,706          4,894
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .   (35,879)       (42,534)
    Interest Accrued . . . . . . . . . . . . . . . . . . . .    10,505          8,784
   Other (net) . . . . . . . . . . . . . . . . . . . . . . .   (14,766)        (7,143)
                                                             ---------      ---------
        Net Cash Flows From Operating Activities . . . . . .   351,281        204,099
                                                             ---------      ---------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (91,122)       (75,933)
  Proceeds from Sale of Property and Other . . . . . . . . .       992            495
                                                             ---------      ---------
        Net Cash Flows Used For Investing Activities . . . .   (90,130)       (75,438)
                                                             ---------      ---------

FINANCING ACTIVITIES:
  Change in Money Pool . . . . . . . . . . . . . . . . . . .    43,970           -
  Change in Short-term Debt (net). . . . . . . . . . . . . .   (45,500)       (24,300)
  Retirement of Cumulative Preferred Stock . . . . . . . . .   (10,000)          -
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (25,274)       (35,523)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .  (216,950)       (65,997)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .    (1,312)        (1,312)
                                                             ---------      ---------
        Net Cash Flows Used For Financing Activities . . . .  (255,066)      (127,132)
                                                             ---------      ---------

Net Increase in Cash and Cash Equivalents. . . . . . . . . .     6,085          1,529
Cash and Cash Equivalents at Beginning of Period . . . . . .     5,107          7,206
                                                             ---------      ---------
Cash and Cash Equivalents at End of Period . . . . . . . . . $  11,192      $   8,735
                                                             =========      =========

Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $40,411,000  and
  $45,659,000  and for income taxes was  $42,007,000 and $41,866,000 in 2000 and
  1999, respectively.  Noncash acquisitions under capital leases were $4,043,000
  and $5,573,000 in 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>



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

                    THIRD QUARTER 2000 vs. THIRD QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

     Income before  extraordinary  items increased by $1.8 million or 3% for the
quarter and $2.7  million or 2% for the  year-to-date  period due  primarily  to
increased  wholesale power marketing and trading  activities.  An  extraordinary
loss  related to the  discontinuance  of SFAS 71  regulatory  accounting  of $25
million after tax was recorded in September 2000 in connection with the approval
of a plan to transition the company's  generation  business from cost based rate
regulation  to  customer   choice   market   pricing  (See  Note  9  -  Industry
Restructuring).
        Income statement line items which changed significantly were:

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

Operating Revenues. . . . .    $18        5         $66        7
Fuel Expense. . . . . . . .      6       14          -        -
Purchased Power Expense . .     (4)      (5)         49       24
Other Operation Expense . .     11       24          14       10
Maintenance Expense . . . .      2       14           3        6
Nonoperating Income . . . .     -       N.M.          5      N.M.
Interest Charges. . . . . .     (1)      (7)         (3)      (6)
Extraordinary Loss. . . . .    (25)     N.M.        (25)     N.M.

N.M. = Not Meaningful

        The increases in operating  revenues and purchased power expense are due
to a  significant  increase  in AEP Power Pool  transactions.  The  Company as a
member of the AEP Power Pool shares in the  revenues  and costs of the AEP Power
Pool's  wholesale  marketing  sales to and  forward  trades  with other  utility
systems  and  power  marketers.  The  Company's  share of the AEP  Power  Pool's
wholesale sales are recorded as operating  revenues and purchased power expense.
Forward trading sales and purchases within the AEP System traditional  marketing
area (within two  transmission  systems of the AEP System) are recorded on a net
basis in  operating  revenues.  As a  result  of a major  industrial  customer's
decision in January  2000 not to continue  purchasing  power from an  affiliate,
additional  power was  available to the AEP Power Pool for sale on the wholesale
market accounting in part for the increase in the Company's wholesale Power Pool
revenues and for the  increase in  year-to-date  purchased  power  expense.  The
increase in AEP Power Pool  wholesale  sales also  resulted  from growing  AEP's
power marketing and trading operation, favorable wholesale market conditions and
increased  availability  of generation.  AEP generating  unit  availability  was
increased  due to the  return  to  service  of  one  of an  affiliate's  nuclear
generating units and improved generating unit outage management.  The decline in
higher cost purchased power expense in the third quarter  reflects a decrease in
purchases from unaffiliated entities as that power was supplied by the AEP Power
Pool.  With the  return to  service  in June 2000 of one of an  affiliate's  two
nuclear  generating  units that  affiliate  supplied more power to the AEP Power
Pool at a lower cost reducing the need to acquire  higher cost power on the open
market.
        Fuel  expense  increased  in the third  quarter  due to an  increase  in
generation  reflecting an increase in availability of certain Company generating
units and favorable demand for wholesale energy.
        The  increase  in other  operation  expense was due to  increased  power
generation  costs.  The increase in generation  costs is due to higher  emission
allowance  consumption,  increased emission allowance cost,  increased costs for
power trading reflecting the growth of the power marketing and trading operation
including incentive compensation.
        Additional  generating  unit boiler repairs and  maintenance of overhead
transmission  and  distribution  lines accounted for the increase in maintenance
expense.
        The increase in nonoperating  income in the year-to-date  period was due
to an  increase  in net gains from  non-regulated  AEP Power Pool power  trading
transactions  outside of the AEP System's  traditional  marketing  area. The AEP
Power Pool enters into power trading  transactions  for the purchase and sale of
electricity and for options,  futures and swaps.  The Company's share of the AEP
Power  Pool's  gains and losses from forward  electricity  trading  transactions
outside  of the AEP  System  traditional  marketing  area  and  for  speculative
financial  transactions  (options,  futures,  swaps) is included in nonoperating
income. The increase in nonoperating income is also attributable to the reversal
in the first quarter of 2000 of a remaining  provision  for potential  liability
for clean-up of possible  environmental  contamination from underground  storage
tanks at a Company  facility  after the state of Ohio  reviewed  the  matter and
determined that no further corrective action would be required.
        The  decline in interest  charges  was due to a decrease in  outstanding
long-term debt balances.


        An extraordinary loss was recorded in the third quarter of 2000 when the
Company  discontinued  the application of SFAS 71 regulatory  accounting for the
generation  portion of its business  due to the approval in September  2000 of a
stipulation  agreement by the PUCO  providing  for a transition  from cost based
rate regulation for the Company's  generation business to customer choice market
pricing.


<PAGE>
<TABLE>
<CAPTION>




                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                          Three Months Ended          Nine Months Ended
                                             September 30,              September 30,
                                           2000        1999           2000         1999
                                           ----        ----           ----         ----
                                                         (in thousands)

<S>                                      <C>         <C>           <C>         <C>
OPERATING REVENUES . . . . . . . . . . . $423,217    $411,248      $1,129,475  $1,081,914
                                         --------    --------      ----------  ----------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .   56,338      51,908         148,042     135,831
  Purchased Power. . . . . . . . . . . .   73,168      93,683         254,496     223,508
  Other Operation. . . . . . . . . . . .  139,375     139,997         424,254     346,830
  Maintenance. . . . . . . . . . . . . .   53,596      43,526         164,821      99,349
  Depreciation and Amortization. . . . .   38,951      37,626         115,661     112,106
  Taxes Other Than Federal Income Taxes.   17,156      12,356          51,152      48,641
  Federal Income Tax Expense (Credit). .    8,577       6,067         (31,157)     23,760
                                         --------    --------      ----------  ----------
          TOTAL OPERATING EXPENSES . . .  387,161     385,163       1,127,269     990,025
                                         --------    --------      ----------  ----------
OPERATING INCOME . . . . . . . . . . . .   36,056      26,085           2,206      91,889
NONOPERATING INCOME. . . . . . . . . . .    1,344       2,407           4,546       5,698
                                         --------    --------      ----------  ----------
INCOME BEFORE INTEREST CHARGES . . . . .   37,400      28,492           6,752      97,587
INTEREST CHARGES . . . . . . . . . . . .   22,210      20,408          67,296      59,688
                                         --------    --------      ----------  ----------
NET INCOME (LOSS). . . . . . . . . . . .   15,190       8,084         (60,544)     37,899
PREFERRED STOCK DIVIDEND REQUIREMENTS. .    1,156       1,218           3,469       3,647
                                         --------    --------      ----------  ----------
EARNINGS (LOSS) APPLICABLE TO
  COMMON STOCK . . . . . . . . . . . . . $ 14,034    $  6,866      $  (64,013) $   34,252
                                         ========    ========      ==========  ==========



                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                          Three Months Ended          Nine Months Ended
                                             September 30,               September 30,
                                           2000        1999           2000        1999
                                           ----        ----           ----        ----
                                                         (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . $ 60,930    $223,212       $166,389    $253,154
NET INCOME (LOSS). . . . . . . . . . . .   15,190       8,084        (60,544)     37,899
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .     -         28,664         26,290      85,992
    Cumulative Preferred Stock . . . . .     -          1,182          3,368       3,546
  Capital Stock Expense. . . . . . . . .       34          65            101         130
                                         --------    --------       --------    --------

BALANCE AT END OF PERIOD . . . . . . . . $ 76,086    $201,385       $ 76,086    $201,385
                                         ========    ========       ========    ========

The common stock of the Company is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                         September 30,    December 31,
                                                              2000            1999
                                                         -------------    ------------
                                                                 (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                        <C>             <C>
  Production . . . . . . . . . . . . . . . . . . . . .     $2,594,609      $2,587,288
  Transmission . . . . . . . . . . . . . . . . . . . .        942,564         928,758
  Distribution . . . . . . . . . . . . . . . . . . . .        852,300         818,697
  General (including nuclear fuel) . . . . . . . . . .        260,682         244,981
  Construction Work in Progress. . . . . . . . . . . .        243,805         190,303
                                                           ----------      ----------
          Total Electric Utility Plant . . . . . . . .      4,893,960       4,770,027
  Accumulated Depreciation and Amortization. . . . . .      2,290,841       2,194,397
                                                           ----------      ----------

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      2,603,119       2,575,630
                                                           ----------      ----------


NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
  FUEL DISPOSAL TRUST FUNDS. . . . . . . . . . . . . .        767,121         707,967
                                                           ----------      ----------


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .        259,074         213,658
                                                           ----------      ----------


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .         13,302           3,863
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .         84,691          91,268
    Affiliated Companies . . . . . . . . . . . . . . .         29,550          48,901
    Miscellaneous. . . . . . . . . . . . . . . . . . .         20,156          18,644
    Allowance for Uncollectible Accounts . . . . . . .           (735)         (1,848)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .         28,666          27,597
  Materials and Supplies . . . . . . . . . . . . . . .         89,384          84,149
  Accrued Utility Revenues . . . . . . . . . . . . . .           -             44,428
  Energy Trading Contracts . . . . . . . . . . . . . .        253,975          97,946
  Prepayments. . . . . . . . . . . . . . . . . . . . .          4,487           7,631
                                                           ----------      ----------

          TOTAL CURRENT ASSETS . . . . . . . . . . . .        523,476         422,579
                                                           ----------      ----------


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .        553,466         624,810
                                                           ----------      ----------


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .         22,500          32,052
                                                           ----------      ----------


            TOTAL. . . . . . . . . . . . . . . . . . .     $4,728,756      $4,576,696
                                                           ==========      ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)
                                                        September 30,     December 31,
                                                             2000             1999
                                                        -------------     ------------
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                       <C>              <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  2,500,000 Shares
    Outstanding - 1,400,000 Shares . . . . . . . . . .    $   56,584       $   56,584
  Paid-in Capital. . . . . . . . . . . . . . . . . . .       733,039          732,739
  Retained Earnings. . . . . . . . . . . . . . . . . .        76,086          166,389
                                                          ----------       ----------
          Total Common Shareholder's Equity. . . . . .       865,709          955,712
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . .         8,736            9,248
    Subject to Mandatory Redemption. . . . . . . . . .        64,945           64,945
  Long-term Debt . . . . . . . . . . . . . . . . . . .     1,295,388        1,126,326
                                                          ----------       ----------

          TOTAL CAPITALIZATION . . . . . . . . . . . .     2,234,778        2,156,231
                                                          ----------       ----------

OTHER NONCURRENT LIABILITIES:
  Nuclear Decommissioning. . . . . . . . . . . . . . .       552,081          501,185
  Other. . . . . . . . . . . . . . . . . . . . . . . .       186,420          242,522
                                                          ----------       ----------

          TOTAL OTHER NONCURRENT LIABILITIES . . . . .       738,501          743,707
                                                          ----------       ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .       190,000          198,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .          -             224,262
  Advances from Affiliates . . . . . . . . . . . . . .       113,423             -
  Accounts Payable - General . . . . . . . . . . . . .        91,170           78,784
  Accounts Payable - Affiliated Companies. . . . . . .        65,968           31,118
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .          -              48,970
  Interest Accrued . . . . . . . . . . . . . . . . . .        21,503           13,955
  Rent Accrued - Rockport Plant Unit 2 . . . . . . . .        23,427            4,963
  Obligations Under Capital Leases . . . . . . . . . .        44,219           11,072
  Energy Trading Contracts . . . . . . . . . . . . . .       249,418           95,564
  Other. . . . . . . . . . . . . . . . . . . . . . . .        77,708           86,721
                                                          ----------       ----------

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       876,836          793,409
                                                          ----------       ----------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       582,145          622,157
                                                          ----------       ----------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .       115,967          121,627
                                                          ----------       ----------

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . .        82,225           85,005
                                                          ----------       ----------

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .        98,304           54,560
                                                          ----------       ----------

CONTINGENCIES (Note 12)

            TOTAL. . . . . . . . . . . . . . . . . . .    $4,728,756       $4,576,696
                                                          ==========       ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>

<PAGE>
<TABLE>
<CAPTION>



                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                 Nine Months Ended
                                                                    September 30,
                                                                 2000           1999
                                                                 ----           ----
                                                                   (in thousands)

OPERATING ACTIVITIES:
<S>                                                           <C>            <C>
  Net Income (Loss). . . . . . . . . . . . . . . . . . . . .  $ (60,544)     $  37,899
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    122,345        115,014
    Amortization of Incremental Nuclear Refueling
      Outage Expenses (net). . . . . . . . . . . . . . . . .      4,830          6,413
    Unrecovered Fuel and Purchased Power Costs . . . . . . .     28,126        (82,213)
    Amortization (Deferral) of Nuclear Outage Costs (net). .     30,000        (90,000)
    Deferred Federal Income Taxes. . . . . . . . . . . . . .    (25,619)        57,254
    Deferred Investment Tax Credits. . . . . . . . . . . . .     (5,660)        (5,694)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .     23,303         (1,132)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     (6,304)       (10,200)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     44,428         (5,768)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .     47,236        (30,007)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (48,970)        (4,651)
    Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . .     18,464         18,464
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .    (43,393)        31,631
                                                              ---------      ---------
        Net Cash Flows From Operating Activities . . . . . .    128,242         37,010
                                                              ---------      ---------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (129,799)       (97,044)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .        587          1,904
                                                              ---------      ---------
        Net Cash Flows Used For Investing Activities . . . .   (129,212)       (95,140)
                                                              ---------      ---------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .    199,220        148,379
  Change in Advances from Affiliates (net) . . . . . . . . .    113,423           -
  Retirement of Cumulative Preferred Stock . . . . . . . . .       (314)        (1,042)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (48,000)       (74,500)
  Change in Short-term Debt (net). . . . . . . . . . . . . .   (224,262)        82,150
  Dividends Paid on Common Stock . . . . . . . . . . . . . .    (26,290)       (85,992)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .     (3,368)        (3,546)
                                                              ---------      ---------
        Net Cash Flows From Financing Activities . . . . . .     10,409         65,449
                                                              ---------      ---------

Net Increase in Cash and Cash Equivalents. . . . . . . . . .      9,439          7,319
Cash and Cash Equivalents at Beginning of Period . . . . . .      3,863         12,465
                                                              ---------      ---------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  13,302      $  19,784
                                                              =========      =========

Supplemental Disclosure:
  Cash paid  (received) for interest net of capitalized  amounts was $57,466,000
  and $54,928,000 and for income taxes was $43,675,000 and $(29,106,000) in 2000
  and  1999,  respectively.  Noncash  acquisitions  under  capital  leases  were
  $19,134,000 and $9,005,000 in 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>



                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                    THIRD QUARTER 2000 vs. THIRD QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

               Net income  increased $7 million for the third quarter  primarily
        due to the return to service of one of the Company's two nuclear  units.
        The Company  reported a $61  million  loss for the  year-to-date  period
        compared to net income of $38 million in 1999.  Increased  operating and
        maintenance  expenses  to prepare the  Company's  Cook Plant for restart
        following an extended outage is the primary reason for the  year-to-date
        earnings  decline.  An  extended  outage  of the  Cook  Plant  began  in
        September 1997 when both nuclear generating units were shut down because
        of questions regarding the operability of certain safety systems. Unit 2
        returned to service in June 2000 and  achieved  full power  operation on
        July 5, 2000. In accordance  with  settlement  agreements in Indiana and
        Michigan,   which  resolved  all  jurisdictional   rate-related   issues
        applicable to the Cook Plant's extended outage, certain restart expenses
        were  deferred in 1999.  The  settlements  in the  Indiana and  Michigan
        jurisdictions   were   approved  in  March  1999  and   December   1999,
        respectively,  retroactive to January 1, 1999. These deferrals are being
        amortized on a straight-line basis through December 31, 2003.
           Income statement line items which changed significantly were:
                                             Increase (Decrease)
                                Third Quarter         Year-to-Date
                                (in millions)     %   (in millions)    %
                                --------------    -   -------------    -

         Operating Revenues . . . . .   $ 12          3       $ 48         4
         Fuel Expense . . . . . . . .      4          9         12         9
         Purchased Power Expense. . .    (21)       (22)        31        14
         Other Operation Expense. . .     (1)       N.M.        77        22
         Maintenance Expense. . . . .     10    23         65        66
         Taxes Other Than Federal
           Income Taxes . . . . . . .      5         39          3         5
         Federal Income Taxes . . . .      3         41        (55)      N.M.
         Interest Charges . . . . . .      2          9          8        13

         N.M. = Not Meaningful



                  The increase in operating  revenues  resulted  from  increased
         wholesale  sales to the AEP Power Pool and sales to and forward  trades
         with other utility  systems and power  marketers by the AEP Power Pool.
         As a member of the AEP Power Pool,  the Company  shares in the revenues
         and costs of the AEP Power Pool's  wholesale  sales and forward trades.
         Forward  trading  sales and  purchases by the AEP Power Pool within the
         AEP System traditional  marketing area (within two transmission systems
         of the AEP System) are recorded on a net basis in  operating  revenues.
         AEP Power Pool members are 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.  As a result of the  Company's  obligation  to
         purchase power from an affiliated company,  the Company was required to
         purchase  additional  energy and capacity in 2000 due to the expiration
         of that  affiliate's  agreement  to  supply  power  to an  unaffiliated
         utility.  Since this capacity was no longer committed under a long-term
         contract  I&M was able to use it to supply  the AEP Power Pool and thus
         received  additional  wholesale  revenues from the AEP Power Pool. Also
         with the return to  service  of Cook  Plant  Unit 2 in June  2000,  the
         Company's available generation increased. Consequently, the Company was
         able to deliver additional power to the AEP Power Pool, contributing to
         the AEP Power Pool's and the  Company's  share of increase in wholesale
         sales and operating revenues.  A decline in retail sales and the effect
         of the settlement  agreements in Indiana and Michigan led to a decrease
         in operating  revenues from retail customers  partially  offsetting the
         wholesale increases.
                 Fuel expense  increased  primarily due to increased  generation
        reflecting  the  return to service  of the  Company's  Cook Plant Unit 2
        following an extended outage.
                 The decrease in purchased  power  expense for the third quarter
        resulted  mainly  from  reduced  purchases  of power  from  unaffiliated
        entities and the AEP Power Pool  reflecting a decreased need to purchase
        energy  with the  return  to  service  of one  unit at the  Cook  Plant.
        Purchased power expense  increased in the year-to-date  period primarily
        due to the Company's  obligation to purchase an  affiliate's  power when
        its agreement to supply power to an unaffiliated  utility expired at the
        end of 1999.
                 Other operation  expense  increased in the year-to-date  period
        and maintenance  expense  increased in both periods primarily due to the
        expenses  related to work to restart the Cook Plant units and the effect
        of  deferring  restart  expenditures  in 1999  under  the  terms  of the
        approved settlement agreement in Indiana.
                 Increased  accruals  for  Indiana  supplemental  net income tax
        expense  reflecting an increase in taxable  income is the primary reason
        for higher taxes other than federal income taxes.
                 The  increase  in federal  income tax expense  attributable  to
        operations  for the third  quarter was  primarily  due to an increase in
        pre-tax  operating  income offset in part by changes in certain book/tax
        timing differences accounted for on a flow-through basis for rate-making
        and financial reporting purposes.  The year-to-date  decrease in federal
        income tax expense  attributable  to  operations  was primarily due to a
        decrease in pre-tax operating income.
                 Interest charges increased as a result of additional  long-term
        and short-term borrowings mainly to fund the restart expenditures.


<PAGE>
<TABLE>
<CAPTION>



                                    KENTUCKY POWER COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)


                                          Three Months Ended         Nine Months Ended
                                             September 30,              September 30,
                                             2000       1999         2000         1999
                                             ----       ----         ----         ----
                                                          (in thousands)

<S>                                        <C>        <C>          <C>          <C>
OPERATING REVENUES . . . . . . . . . . . . $106,698   $94,939      $301,661     $271,911
                                           --------   -------      --------     --------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . . .   23,366    18,258        58,039       60,233
  Purchased Power. . . . . . . . . . . . .   35,881    32,177       108,115       82,524
  Other Operation. . . . . . . . . . . . .   14,117    10,607        36,604       34,726
  Maintenance. . . . . . . . . . . . . . .    6,098     5,522        20,903       15,360
  Depreciation and Amortization. . . . . .    7,828     7,356        23,107       21,833
  Taxes Other Than Federal Income Taxes. .    2,387     2,967         7,880        8,183
  Federal Income Taxes . . . . . . . . . .    3,231     3,808         8,210        9,215
                                           --------  --------      --------     --------

         TOTAL OPERATING EXPENSES. . . . .   92,908    80,695       262,858      232,074
                                           --------  --------      --------     --------

OPERATING INCOME . . . . . . . . . . . . .   13,790    14,244        38,803       39,837

NONOPERATING INCOME (LOSS) . . . . . . . .      243       111           868          (44)
                                           --------  --------      --------     --------

INCOME BEFORE INTEREST CHARGES . . . . . .   14,033    14,355        39,671       39,793

INTEREST CHARGES . . . . . . . . . . . . .    7,272     7,158        22,409       21,392
                                           --------  --------      --------     --------

NET INCOME . . . . . . . . . . . . . . . . $  6,761  $  7,197      $ 17,262     $ 18,401
                                           ========  ========      ========     ========


                         STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                            Three Months Ended       Nine Months Ended
                                               September 30,           September 30,
                                             2000        1999        2000         1999
                                             ----        ----        ----         ----
                                                          (in thousands)

BALANCE AT BEGINNING OF PERIOD . . . . . . $62,431     $67,770      $67,110      $71,452

NET INCOME . . . . . . . . . . . . . . . .   6,761       7,197       17,262       18,401

CASH DIVIDENDS DECLARED. . . . . . . . . .   7,590       7,443       22,770       22,329
                                           -------     -------      -------      -------

BALANCE AT END OF PERIOD . . . . . . . . . $61,602     $67,524      $61,602      $67,524
                                           =======     =======      =======      =======

The common stock of the Company is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                             KENTUCKY POWER COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)

                                                       September 30,      December 31,
                                                            2000              1999
                                                       -------------      -----------
                                                                (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                      <C>               <C>
  Production . . . . . . . . . . . . . . . . . . . . .   $  270,725        $  268,618
  Transmission . . . . . . . . . . . . . . . . . . . .      358,312           355,442
  Distribution . . . . . . . . . . . . . . . . . . . .      383,388           372,752
  General. . . . . . . . . . . . . . . . . . . . . . .       66,591            67,608
  Construction Work in Progress. . . . . . . . . . . .       14,540            14,628
                                                         ----------        ----------
          Total Electric Utility Plant . . . . . . . .    1,093,556         1,079,048
  Accumulated Depreciation and Amortization. . . . . .      353,406           340,008
                                                         ----------        ----------

          NET ELECTRIC UTILITY PLANT . . . . . . . . .      740,150           739,040
                                                         ----------        ----------


OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . .       41,305            20,416
                                                         ----------        ----------


CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . .        1,012               674
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . .       26,186            18,952
    Affiliated Companies . . . . . . . . . . . . . . .       18,488            15,223
    Miscellaneous. . . . . . . . . . . . . . . . . . .        5,613             8,343
    Allowance for Uncollectible Accounts . . . . . . .         (278)             (637)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . .        5,426            10,441
  Materials and Supplies . . . . . . . . . . . . . . .       17,410            18,113
  Accrued Utility Revenues . . . . . . . . . . . . . .         -               13,737
  Energy Trading Contracts . . . . . . . . . . . . . .       99,865            33,919
  Prepayments. . . . . . . . . . . . . . . . . . . . .          765             1,450
                                                         ----------        ----------

          TOTAL CURRENT ASSETS . . . . . . . . . . . .      174,487           120,215
                                                         ----------        ----------


REGULATORY ASSETS. . . . . . . . . . . . . . . . . . .      100,204            96,296
                                                         ----------        ----------


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . .        7,419            10,671
                                                         ----------        ----------


            TOTAL. . . . . . . . . . . . . . . . . . .   $1,063,565        $  986,638
                                                         ==========        ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                             KENTUCKY POWER COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)

                                                        September 30,     December 31,
                                                             2000             1999
                                                        -------------     ------------
                                                                 (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                       <C>               <C>
CAPITALIZATION:
  Common Stock - $50 Par Value:
    Authorized -  2,000,000 Shares
    Outstanding - 1,009,000 Shares . . . . . . . . . .    $   50,450        $ 50,450
  Paid-in Capital. . . . . . . . . . . . . . . . . . .       158,750         158,750
  Retained Earnings. . . . . . . . . . . . . . . . . .        61,602          67,110
                                                          ----------        --------
          Total Common Shareholder's Equity. . . . . .       270,802         276,310
  Long-term Debt . . . . . . . . . . . . . . . . . . .       200,991         260,782
                                                          ----------        --------

          TOTAL CAPITALIZATION . . . . . . . . . . . .       471,793         537,092
                                                          ----------        --------

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . .        21,553          23,797
                                                          ----------        --------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . .       140,000         105,000
  Short-term Debt. . . . . . . . . . . . . . . . . . .          -             39,665
  Advances from Affiliates . . . . . . . . . . . . . .        23,863            -
  Accounts Payable - General . . . . . . . . . . . . .        24,391           9,923
  Accounts Payable - Affiliated Companies. . . . . . .        38,038          19,743
  Customer Deposits. . . . . . . . . . . . . . . . . .         4,186           4,143
  Taxes Accrued. . . . . . . . . . . . . . . . . . . .         8,537           9,860
  Interest Accrued . . . . . . . . . . . . . . . . . .         7,335           4,843
  Energy Trading Contracts . . . . . . . . . . . . . .        97,847          33,094
  Other. . . . . . . . . . . . . . . . . . . . . . . .        10,910          12,020
                                                          ----------        --------

          TOTAL CURRENT LIABILITIES. . . . . . . . . .       355,107         238,291
                                                          ----------        --------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . .       168,972         165,007
                                                          ----------        --------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . .        12,014          12,908
                                                          ----------        --------

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . .        34,126           9,543
                                                          ----------        --------

CONTINGENCIES (Note 12)

            TOTAL. . . . . . . . . . . . . . . . . . .    $1,063,565        $986,638
                                                          ==========        ========

See Notes to Financial Statements beginning on page L-1.

</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                             KENTUCKY POWER COMPANY
                            STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                Nine Months Ended
                                                                  September 30,
                                                                2000          1999
                                                                ----          ----
                                                                  (in thousands)

OPERATING ACTIVITIES:
<S>                                                           <C>           <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 17,262      $ 18,401
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    23,112        21,838
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     4,081         2,361
    Deferred Investment Tax Credits. . . . . . . . . . . . .      (894)         (902)
    Amortization of Deferred Property Taxes. . . . . . . . .     4,157         4,035
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .    (8,128)        4,669
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     5,718        (7,762)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .    13,737         4,334
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    32,763        (2,612)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (1,323)         (362)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .    (2,810)       (1,705)
                                                              --------      --------
        Net Cash Flows From Operating Activities . . . . . .    87,675        42,295
                                                              --------      --------

INVESTING ACTIVITIES - Construction Expenditures . . . . . .   (23,765)      (28,144)
                                                              --------      --------

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company. . . . . . . . .      -           10,000
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (25,000)      (48,307)
  Change in Short-term Debt (net). . . . . . . . . . . . . .   (39,665)       45,615
  Change in Advances from Affiliates (net) . . . . . . . . .    23,863          -
  Dividends Paid . . . . . . . . . . . . . . . . . . . . . .   (22,770)      (22,329)
                                                              --------      --------
        Net Cash Flows Used For Financing Activities . . . .   (63,572)      (15,021)
                                                              --------      --------

Net Increase (Decrease) in Cash and Cash Equivalents . . . .       338          (870)
Cash and Cash Equivalents at Beginning of Period . . . . . .       674         1,935
                                                              --------      --------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  1,012      $  1,065
                                                              ========      ========

Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $19,776,000  and
  $19,420,000  and for income taxes was  $5,167,000  and  $7,271,000 in 2000 and
  1999, respectively.  Noncash acquisitions under capital leases were $2,440,000
  and $1,889,000 in 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>


<PAGE>



                             KENTUCKY POWER COMPANY
            MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS

                    THIRD QUARTER 2000 vs. THIRD QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

        Although  revenues rose 12% for the quarter and 11% for the year-to-date
period,  net  income  declined  by $0.4  million  or 6% and $1.1  million or 6%,
respectively,  as increases in operating  expense and interest expense more than
offset  the  revenue  increases.  Income  statement  line  items  which  changed
significantly were:
                                     Increase(Decrease)
                            Third Quarter      Year-to-Date
                            (in millions)   %  (in millions)  %

Operating Revenues . . . . .    $11.8      12     $29.8      11
Fuel Expense . . . . . . . .      5.1      28      (2.2)     (4)
Purchased Power Expense. . .      3.7      12      25.6      31
Other Operation Expense. . .      3.5      33       1.9       5
Maintenance Expense. . . . .      0.6      10       5.5      36
Depreciation Expense . . . .      0.5       6       1.3       6
Federal Income Tax . . . . .     (0.6)    (15)     (1.0)    (11)
Nonoperating Income. . . . .      0.1     119       0.9     N.M.
Interest Charges . . . . . .      0.1       2       1.0       5

N.M. = Not Meaningful
        The increases in operating  revenues and purchased power expense are due
to a significant  increase in AEP Power Pool  transactions and affili-ated power
purchases under a unit power agreement. The Company as a member of the AEP Power
Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to
and net forward  trades with other  utility  systems  and power  marketers.  The
Company's share of these AEP Power Pool sales are recorded as operating revenues
and  purchases  accounting  for the  increases in revenues and  purchased  power
expense.  Forward trading sales and purchases which are transactions  within the
AEP System  traditional  marketing area (within two transactions  systems of the
AEP System) are recorded on a net basis in operating revenues. As a result of an
affiliated  company's major industrial  customer's  decision not to continue its
purchased power agreement,  additional power was available to the AEP Power Pool
for wholesale sales also  contributing to the increase in the Company's  revenue
and  purchased  power  expense.  Purchased  power  also  increased  due  to  the
availability  of the Rockport  Plant from which the Company,  under a unit power
agreement,  purchases 15% of the available  power from Rockport.  Rockport Plant
generated 7% more KWH in the nine months ended  September  2000 than in the nine
months ended September 1999.
        Fuel expense  increased in the quarter due to  amortization  of deferred
fuel costs and decreased in the year-to-date period due to a decline in internal
generation.  The Big Sandy Plant Unit 2 began a planned outage on March 11, 2000
for boiler  inspections  and repairs and returned to service late in April.  Big
Sandy Unit 1 started a planned  outage on April 21, 2000 and returned to service
the second week in May after completion of boiler inspection and repairs.
        Other  operation  expense  increased due to emission  allowance  charges
under  Phase II of the 1990  Clean Air Act  Amendments.  Under  Phase II,  which
became  effective  January 1, 2000,  the  Company was  required to use  emission
allowances to comply with the new emissions standards. The average cost of those
allowances  are  charged  to  other  operation  expense  as  required.   In  the
year-to-date  period an increase in transmission  equalization  credits received
under the AEP East Region  Transmission  Agreement partially offset the emission
allowance  charges.  The  Company as a party to the AEP  Transmission  Agreement
shares  the  costs  associated  with the  ownership  of the  extra-high  voltage
transmission  system and certain  facilities at lower  voltages  based upon each
company's MLR and  investment.  An increase in MLR and  increased  investment in
transmission   plant  were  the  reasons  for  the   increase  in   transmission
equalization credits.
        The outages at Big Sandy Plant caused maintenance expense to increase in
the year-to-date period.  Comparing 1999 to 2000, unit 1 of the Big Sandy Plant,
experienced 3.6 weeks of various outages  compared to 1 week of outages in 1999.
Unit 2 experienced 6.8 weeks of outages in 2000 and 4.6 weeks in 1999.
        An  increase  in  transmission  plant  investment  and  improvements  to
distribution facilities accounted for the increase in depreciation expense.
        The decrease in operating  Federal  income tax expense was primarily due
        to a decrease in pre-tax  operating  book  income.  Nonoperating  income
        increased  due  to the  effect  of the  non-regulated  electric  trading
        outside the AEP Power Pool's
traditional  marketing area. 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 Company's share of these  non-regulated  trading  activities
are included in nonoperating income.
        Interest  charges  increased due to higher long-term debt interest rates
and an increase in average short-term debt interest rates.


<PAGE>
<TABLE>
<CAPTION>



                                OHIO POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                          Three Months Ended          Nine Months Ended
                                           September 30,                September 30,
                                           2000        1999          2000         1999
                                           ----        ----          ----         ----
                                                         (in thousands)

<S>                                      <C>         <C>          <C>          <C>
OPERATING REVENUES . . . . . . . . . . . $582,702    $544,451     $1,668,434   $1,561,259
                                         --------    --------     ----------   ----------
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .  188,727     173,857        581,289      532,075
  Purchased Power. . . . . . . . . . . .   46,772      68,836        129,125      125,808
  Other Operation. . . . . . . . . . . .   99,930      81,113        270,626      249,003
  Maintenance. . . . . . . . . . . . . .   28,128      27,434         89,753       81,425
  Depreciation and Amortization. . . . .   39,121      37,509        116,453      111,691
  Taxes Other Than Federal Income Taxes.   40,579      42,941        125,366      128,746
  Federal Income Taxes . . . . . . . . .   42,793      39,903        114,089      107,369
                                         --------    --------     ----------   ----------

          TOTAL OPERATING EXPENSES . . .  486,050     471,593      1,426,701    1,336,117
                                         --------    --------     ----------   ----------
OPERATING INCOME . . . . . . . . . . . .   96,652      72,858        241,733      225,142
NONOPERATING INCOME. . . . . . . . . . .    2,564       4,856          6,714        6,364
                                         --------    --------     ----------   ----------
INCOME BEFORE INTEREST CHARGES . . . . .   99,216      77,714        248,447      231,506
INTEREST CHARGES . . . . . . . . . . . .   22,155      21,481         66,937       62,587
                                         --------    --------     ----------   ----------
INCOME BEFORE EXTRAORDINARY ITEM . . . .   77,061      56,233        181,510      168,919

EXTRAORDINARY LOSS - DISCONTINUANCE OF
 REGULATORY ACCOUNTING FOR GENERATION
 (INCLUSIVE OF TAX BENEFIT
 OF $21,281,000) . . . . . . . . . . . .  (18,876)       -           (18,876)        -
                                         --------    --------     ----------   ----------
NET INCOME . . . . . . . . . . . . . . .   58,185      56,233        162,634      168,919
PREFERRED STOCK DIVIDEND REQUIREMENTS. .      315         364            951        1,098
                                         --------    --------     ----------   ----------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 57,870    $ 55,869     $  161,683   $  167,821
                                         ========    ========     ==========   ==========


                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                          Three Months Ended          Nine Months Ended
                                             September 30,             September 30,
                                           2000        1999          2000         1999
                                           ----        ----          ----         ----
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $615,834    $584,045     $587,424       $587,500
NET INCOME . . . . . . . . . . . . . . .   58,185      56,233      162,634        168,919
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .  158,704      57,704      234,110        173,110
    Cumulative Preferred Stock . . . . .      314         366          947          1,101
                                         --------    --------     --------       --------

BALANCE AT END OF PERIOD . . . . . . . . $515,001    $582,208     $515,001       $582,208
                                         ========    ========     ========       ========

The common stock of the Company is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                       OHIO POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                            September 30,    December 31,
                                                                 2000            1999
                                                            -------------    ------------
                                                                    (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                           <C>             <C>
  Production . . . . . . . . . . . . . . . . . . . . . . . .  $2,750,822      $2,713,421
  Transmission . . . . . . . . . . . . . . . . . . . . . . .     868,878         857,420
  Distribution . . . . . . . . . . . . . . . . . . . . . . .   1,029,512         999,679
  General (including mining assets). . . . . . . . . . . . .     703,964         713,882
  Construction Work in Progress. . . . . . . . . . . . . . .     127,739         116,515
                                                              ----------      ----------
          Total Electric Utility Plant . . . . . . . . . . .   5,480,915       5,400,917
  Accumulated Depreciation and Amortization. . . . . . . . .   2,716,760       2,621,711
                                                              ----------      ----------

          NET ELECTRIC UTILITY PLANT . . . . . . . . . . . .   2,764,155       2,779,206
                                                              ----------      ----------



OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . .     322,979         253,668
                                                              ----------      ----------



CURRENT ASSETS:
  Cash and Cash Equivalents. . . . . . . . . . . . . . . . .      34,980         157,138
  Advances to Affiliates . . . . . . . . . . . . . . . . . .     149,616            -
  Accounts Receivable:
    Customers. . . . . . . . . . . . . . . . . . . . . . . .     118,026         246,310
    Affiliated Companies . . . . . . . . . . . . . . . . . .     147,109          89,215
    Miscellaneous. . . . . . . . . . . . . . . . . . . . . .      30,865          22,055
    Allowance for Uncollectible Accounts . . . . . . . . . .      (1,026)         (2,223)
  Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . .      66,357         129,022
  Materials and Supplies . . . . . . . . . . . . . . . . . .      97,946          95,967
  Accrued Utility Revenues . . . . . . . . . . . . . . . . .        -             45,575
  Energy Trading Contracts . . . . . . . . . . . . . . . . .     353,205         134,567
  Prepayments and Other. . . . . . . . . . . . . . . . . . .      34,848          38,472
                                                              ----------      ----------

          TOTAL CURRENT ASSETS . . . . . . . . . . . . . . .   1,031,926         956,098
                                                              ----------      ----------



REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . .     655,575         594,385
                                                              ----------      ----------


DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . . .      36,760          93,852
                                                              ----------      ----------


            TOTAL. . . . . . . . . . . . . . . . . . . . . .  $4,811,395      $4,677,209
                                                              ==========      ==========

See Notes to Financial Statements beginning on page L-1.



</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                       OHIO POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                            September 30,    December 31,
                                                                 2000            1999
                                                            -------------    ------------
                                                                     (in thousands)
CAPITALIZATION AND LIABILITIES
<S>                                                           <C>             <C>
CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized -  40,000,000 Shares
    Outstanding - 27,952,473 Shares. . . . . . . . . . . .    $  321,201      $  321,201
  Paid-in Capital. . . . . . . . . . . . . . . . . . . . .       462,483         462,376
  Retained Earnings. . . . . . . . . . . . . . . . . . . .       515,001         587,424
                                                              ----------      ----------
          Total Common Shareholder's Equity. . . . . . . .     1,298,685       1,371,001
  Cumulative Preferred Stock:
    Not Subject to Mandatory Redemption. . . . . . . . . .        16,648          16,937
    Subject to Mandatory Redemption. . . . . . . . . . . .         8,850           8,850
  Long-term Debt . . . . . . . . . . . . . . . . . . . . .     1,078,952       1,139,834
                                                              ----------      ----------

          TOTAL CAPITALIZATION . . . . . . . . . . . . . .     2,403,135       2,536,622
                                                              ----------      ----------

OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . .       406,616         414,837
                                                              ----------      ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year . . . . . . . . . . .       120,476          11,677
  Short-term Debt. . . . . . . . . . . . . . . . . . . . .          -            194,918
  Accounts Payable - General . . . . . . . . . . . . . . .       147,134         180,383
  Accounts Payable - Affiliated Companies. . . . . . . . .       105,502          64,599
  Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .       157,757         179,112
  Interest Accrued . . . . . . . . . . . . . . . . . . . .        22,923          16,863
  Obligations Under Capital Leases . . . . . . . . . . . .        34,433          34,284
  Energy Trading Contracts . . . . . . . . . . . . . . . .       346,065         131,844
  Other. . . . . . . . . . . . . . . . . . . . . . . . . .       138,325          96,445
                                                              ----------      ----------

          TOTAL CURRENT LIABILITIES. . . . . . . . . . . .     1,072,615         910,125
                                                              ----------      ----------

DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . .       683,556         676,460
                                                              ----------      ----------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . .        26,160          35,838
                                                              ----------      ----------

DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . . .       219,313         103,327
                                                              ----------      ----------

CONTINGENCIES (Note 12)

            TOTAL. . . . . . . . . . . . . . . . . . . . .    $4,811,395      $4,677,209
                                                              ==========      ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                       OHIO POWER COMPANY AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                  Nine Months Ended
                                                                    September 30,
                                                                 2000           1999
                                                                 ----           ----
                                                                    (in thousands)
OPERATING ACTIVITIES:
<S>                                                           <C>            <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 162,634      $ 168,919
  Adjustments for Noncash Items:
    Depreciation, Depletion and Amortization . . . . . . . .    145,125        146,388
    Deferred Federal Income Taxes. . . . . . . . . . . . . .     (2,058)         7,529
    Deferred Fuel Costs (net). . . . . . . . . . . . . . . .    (33,259)       (14,632)
    Amortization of Deferred Property Taxes. . . . . . . . .     60,297         59,567
    Extraordinary Loss - Discontinuance of SFAS 71 . . . . .     18,876           -
  Changes in Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .     60,383       (109,658)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .     60,686        (51,186)
    Accrued Utility Revenues . . . . . . . . . . . . . . . .     45,575          5,355
    Accounts Payable . . . . . . . . . . . . . . . . . . . .      7,654        114,563
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    (21,355)       (73,130)
  Other (net). . . . . . . . . . . . . . . . . . . . . . . .     44,160         54,355
                                                              ---------      ---------
        Net Cash Flows From Operating Activities . . . . . .    548,718        308,070
                                                              ---------      ---------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (143,717)      (126,524)
  Proceeds from Sale of Property and Other . . . . . . . . .      4,404          2,003
                                                              ---------      ---------
        Net Cash Flows Used For Investing Activities . . . .   (139,313)      (124,521)
                                                              ---------      ---------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .     74,748        222,308
  Change in Short-term Debt (net). . . . . . . . . . . . . .   (194,918)       (25,400)
  Change in Advances to Affiliates (net) . . . . . . . . . .   (149,616)          -
  Retirement of Cumulative Preferred Stock . . . . . . . . .       (182)        (3,267)
  Retirement of Long-term Debt . . . . . . . . . . . . . . .    (26,538)      (155,866)
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (234,110)      (173,110)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .       (947)        (1,101)
                                                              ---------      ---------
        Net Cash Flows Used For Financing Activities . . . .   (531,563)      (136,436)
                                                              ---------      ---------

Net Increase (Decrease) in Cash and Cash Equivalents . . . .   (122,158)        47,113
Cash and Cash Equivalents at Beginning of Period . . . . . .    157,138         89,652
                                                              ---------      ---------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  34,980      $ 136,765
                                                              =========      =========

Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $59,963,000  and
  $52,526,000  and for income taxes was  $56,813,000 and $48,052,000 in 2000 and
  1999, respectively. Noncash acquisitions under capital leases were $12,734,000
  and $23,955,000 in 2000 and 1999, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>



                       OHIO POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                    THIRD QUARTER 2000 vs. THIRD QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

         Income before  extraordinary items increased $21 million or 37% for the
quarter and $13 million or 7% for the year-to-date  period due  predominantly to
an  increase  in  wholesale  sales  and  net  revenues  from  electric   trading
transactions and, in the third quarter, a reduction in purchased power costs. An
extraordinary   loss  related  to  the  discontinuance  of  SFAS  71  regulatory
accounting,  of  approximately  $19 million after tax, was recorded in September
2000 in  connection  with the  approval of a plan to  transition  the  company's
generation  business from cost based rate  regulation to customer  choice market
pricing (See Note 9 - Industry Restructuring).
         Income statement line items which changed significantly were:
                                     Increase (Decrease)
                            Third Quarter      Year-to-Date
                            (in millions)  %   (in millions)   %

Operating Revenues . . . . .     $38       7        $107       7
Fuel Expense . . . . . . . .      15       9          49       9
Purchased Power Expense. . .     (22)    (32)          3       3
Other Operation Expense. . .      19      23          22       9
Maintenance Expense. . . . .       1       3           8      10
Federal Income Taxes . . . .       3       7           7       6
Extraordinary Loss . . . . .     (19)    N.M.        (19)    N.M.

N.M. = Not Meaningful

         The increase in operating  revenues  resulted from increased  wholesale
sales to the AEP  Power  Pool,  the  Company's  share of  increased  Power  Pool
wholesale  sales to and net  revenues  from  trading of  electricity  with other
utility  systems and power  marketers.  The Company as a member of the AEP Power
Pool shares in the revenues and cost of the AEP Power Pool's whole-sale sales to
and forward trades with utility systems and power marketers. The Company's share
of Power Pool forward trades,  both purchases and sales, within the AEP System's
traditional  marketing area (within two transmission  systems of the AEP System)
are  recorded on a net basis in operating  revenues.  AEP Power Pool members are
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. As a result of one
of the Company's major industrial  customer's deciding not to continue its power
purchase agreement,  the Company was able to deliver additional power to the AEP
Power Pool accounting for part of the increase in wholesale revenues.  Wholesale
revenues  also  benefited  from  the  growth  in  AEP's  marketing  and  trading
operation,  favorable wholesale market conditions and increased  availability of
AEP Power Pool  generation for wholesale  sales.  The increase in AEP Power Pool
generation  availability  was due to the return to service of one an  affiliates
nuclear units in June 2000 and improved generating unit outage management.
         Fuel expense  increased 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.
         The decline in purchased power expense in the third quarter  reflects a
decrease in high cost  purchases by the Power Pool from  unaffiliated  entities.
With the  return to service in June 2000 of one of an  affiliate's  two  nuclear
units the affiliate was able to supply more power to the AEP Power Pool at lower
cost reducing the need to acquire power on the open market.
         Other  operation  expense  increased  primarily 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  incentive  compensation,  accounted  for the  increase in  generation
costs.
         Additional  generating plant boiler repairs  accounted for the increase
in maintenance  expense for the  year-to-date  period.  The increase in federal
income  taxes was  primarily  due to an  increase  in  pre-tax operating income
offset in part in the quarter by  changes in certain book/tax differences
accounted for on a flow-thru basis.
         An  extraordinary  loss was recorded in the third  quarter of 2000 when
the Company  discontinued  the application of SFAS 71 regulatory  accounting for
the generation  portion of its business due to the approval in September 2000 of
a stipulation  agreement by the PUCO providing for a transition  from cost based
rate regulation for the Company's  generation business to customer choice market
pricing.


<PAGE>
<TABLE>
<CAPTION>



                   PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                             Three Months Ended    Nine Months Ended
                                              September 30,            September 30,
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)

<S>                                        <C>        <C>          <C>        <C>
OPERATING REVENUES . . . . . . . . . . .   $358,710   $258,656     $729,211   $588,385
                                           --------   --------     --------   --------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    155,103     82,076      302,497    208,873
  Purchased Power. . . . . . . . . . . .     46,325     20,278       98,532     50,450
  Other Operation. . . . . . . . . . . .     32,236     35,751       84,468     89,407
  Maintenance. . . . . . . . . . . . . .      8,032      8,768       30,027     30,695
  Depreciation and Amortization. . . . .     19,632     18,558       57,470     55,557
  Taxes Other Than Federal Income Taxes.     12,660      9,439       28,718     28,676
  Federal Income Taxes . . . . . . . . .     28,285     26,066       35,700     31,802
                                           --------   --------    ---------   --------

          TOTAL OPERATING EXPENSES . . .    302,273    200,936      637,412    495,460
                                           --------   --------    ---------   --------

OPERATING INCOME . . . . . . . . . . . .     56,437     57,720       91,799     92,925

NONOPERATING INCOME. . . . . . . . . . .      7,211      1,430        7,927        920
                                           --------   --------    ---------   --------

INCOME BEFORE INTEREST CHARGES . . . . .     63,648     59,150       99,726     93,845

INTEREST CHARGES . . . . . . . . . . . .      9,319      8,893       29,532     27,208
                                           --------   --------     --------   --------

NET INCOME . . . . . . . . . . . . . . .     54,329     50,257       70,194     66,637

PREFERRED STOCK DIVIDEND REQUIREMENTS. .         52         54          158        160
                                           --------   --------     --------   ---------

EARNINGS APPLICABLE TO COMMON STOCK. . .   $ 54,277   $ 50,203     $ 70,036   $ 66,477
                                           ========   ========     ========   ========

                  CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                          Three Months Ended       Nine Months Ended
                                             September 30,            September 30,
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD
  AS PREVIOUSLY REPORTED . . . . . . . .   $120,995  $131,583     $142,018    $144,626
CONFORMING CHANGE IN ACCOUNTING POLICY .       -       (2,369)      (2,782)     (1,686)
                                           --------  --------     --------    --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD.    120,995   129,214      139,236     142,940
NET INCOME . . . . . . . . . . . . . . .     54,329    50,257       70,194      66,637
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .     17,000    15,000       51,000      45,000
    Preferred Stock. . . . . . . . . . .         52        53          158         159
                                           --------  --------     --------    ---------

BALANCE AT END OF PERIOD . . . . . . . .   $158,272  $164,418     $158,272    $164,418
                                           ========  ========     ========    ========

The common stock of the Company is wholly owned by AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)
                                                           September 30,   December 31,
                                                                2000           1999
                                                           -------------   ------------
                                                                   (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                          <C>            <C>
  Production. . . . . . . . . . . . . . . . . . . . . . . .  $  915,216     $  916,889
  Transmission. . . . . . . . . . . . . . . . . . . . . . .     395,594        392,029
  Distribution. . . . . . . . . . . . . . . . . . . . . . .     926,195        897,516
  General . . . . . . . . . . . . . . . . . . . . . . . . .     205,654        217,368
  Construction Work in Progress . . . . . . . . . . . . . .     105,976         35,903
                                                             ----------     ----------
          Total Electric Utility Plant. . . . . . . . . . .   2,548,635      2,459,705
  Accumulated Depreciation and Amortization . . . . . . . .   1,135,265      1,114,255
                                                             ----------     ----------

          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .   1,413,370      1,345,450
                                                             ----------     -----------

OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . .      78,190         46,205
                                                             ----------     ----------

CURRENT ASSETS:
  Cash and Cash Equivalents . . . . . . . . . . . . . . . .       5,644          3,173
  Accounts Receivable:
    Customers . . . . . . . . . . . . . . . . . . . . . . .      63,387         32,301
    Affiliated Companies. . . . . . . . . . . . . . . . . .       6,130          2,283
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . .      24,815         24,143
  Materials and Supplies. . . . . . . . . . . . . . . . . .      33,459         34,289
  Under-recovered Fuel Costs. . . . . . . . . . . . . . . .      41,809          6,469
  Energy Trading Contracts. . . . . . . . . . . . . . . . .     103,594           -
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .       1,161          1,572
                                                             ----------     ----------

          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     279,999        104,230
                                                             ----------     ----------

REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .      27,786         16,717
                                                             ----------     ----------

DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .      11,777         12,124
                                                             ----------     ----------

TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . .  $1,811,122     $1,524,726
                                                             ==========     ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                           September 30,   December 31,
                                                                2000           1999
                                                           -------------   ------------
                                                                   (in thousands)

CAPITALIZATION AND LIABILITIES
<S>                                                          <C>            <C>
CAPITALIZATION:
  Common Stock - $15 Par Value:
    Authorized Shares: 11,000,000
    Issued 10,482,000 shares and
    Outstanding Shares: 9,013,000 . . . . . . . . . . . . .  $  157,230     $  157,230
  Paid-in Capital . . . . . . . . . . . . . . . . . . . . .     180,000        180,000
  Retained Earnings . . . . . . . . . . . . . . . . . . . .     158,272        139,236
                                                             ----------     ----------
          Total Common Shareholder's Equity . . . . . . . .     495,502        476,466
                                                             ----------     ----------

  Cumulative Preferred Stock Not Subject
    To Mandatory Redemption . . . . . . . . . . . . . . . .       5,283          5,286
  PSO-Obligated, Mandatorily Redeemable Preferred
    Securities of Subsidiary Trust Holding Solely Junior
    Subordinated Debentures of PSO. . . . . . . . . . . . .      75,000         75,000
  Long-term Debt. . . . . . . . . . . . . . . . . . . . . .     344,745        364,516
                                                             ----------     ----------

          TOTAL CAPITALIZATION. . . . . . . . . . . . . . .     920,530        921,268
                                                             ----------     ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year. . . . . . . . . . . .      30,000         20,000
  Advances from Affiliates. . . . . . . . . . . . . . . . .     119,689         79,169
  Accounts Payable - General. . . . . . . . . . . . . . . .      93,268         44,088
  Accounts Payable - Affiliated Companies . . . . . . . . .      36,417         35,518
  Customer Deposits . . . . . . . . . . . . . . . . . . . .      18,524         17,752
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      31,165         18,480
  Interest Accrued. . . . . . . . . . . . . . . . . . . . .      10,730          5,420
  Energy Trading Contracts. . . . . . . . . . . . . . . . .     108,434           -
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      12,758          8,058
                                                             ----------     ----------

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .     460,985        228,485
                                                             ----------     ----------

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     306,260        281,916
                                                             ----------     ----------

DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . .       36,231         37,574
                                                             ----------     ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS . . . . . . . .      87,116         55,483
                                                             ----------     ----------

CONTINGENCIES (Note 12)

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $1,811,122     $1,524,726
                                                             ==========     ==========

See Notes to Financial Statements beginning on page L-1.

</TABLE>
<PAGE>
<TABLE>
<CAPTION>



               PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)

                                                                 Nine Months Ended
                                                                   September 30,
                                                                2000           1999
                                                                ----           ----
                                                                   (in thousands)
OPERATING ACTIVITIES:
<S>                                                           <C>            <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 70,194       $ 66,637
  Adjustments for Noncash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    57,470         56,290
    Deferred Income Taxes. . . . . . . . . . . . . . . . . .    19,798         11,993
    Deferred Investment Tax Credits. . . . . . . . . . . . .    (1,343)        (1,343)
  Changes in Certain Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .   (34,933)        (1,479)
    Fuel, Materials and Supplies . . . . . . . . . . . . . .       158         (1,610)
    Equity and Other Investments . . . . . . . . . . . . . .   (30,331)        (5,802)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    50,079        (31,971)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    12,685         15,763
    Other Deferred Credits . . . . . . . . . . . . . . . . .    22,627         10,761
    Fuel Recovery. . . . . . . . . . . . . . . . . . . . . .   (35,340)       (24,795)
    Other. . . . . . . . . . . . . . . . . . . . . . . . . .    12,150         22,695
                                                              --------       ---------
        Net Cash Flows From Operating Activities . . . . . .   143,214        117,139
                                                              --------       --------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .  (120,105)       (73,204)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .      -            (3,711)
                                                              --------       --------
        Net Cash Flows Used For Investing Activities . . . .  (120,105)       (76,915)
                                                              --------       --------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt . . . . . . . . . . . . . . . .      -            33,257
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (10,000)       (33,700)
  Change in Advances from Affiliates (net) . . . . . . . . .    40,520          4,500
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (51,000)       (45,000)
  Dividends Paid on Cumulative Preferred Stock . . . . . . .      (158)          (159)
                                                              --------       --------
        Net Cash Flows From Financing Activities . . . . . .   (20,638)       (41,102)
                                                              --------       --------

Net Increase (Decrease) in Cash and Cash Equivalents . . . .     2,471           (878)
Cash and Cash Equivalents at Beginning of Period . . . . . .     3,173          4,670
                                                              --------       --------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  5,644       $  3,792
                                                              ========       ========

Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $24,222,000  and
  $23,454,000  and for income taxes was  $13,925,395 and $16,614,000 in 2000 and
  1999, respectively.

See Notes to Consolidated Financial Statements beginning on page L-1.
</TABLE>
<PAGE>



                       PUBLIC SERVICE COMPANY OF OKLAHOMA
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                    THIRD QUARTER 2000 vs. THIRD QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999

         Net income  increased $4.1 million or 8% for the third quarter and $3.6
million  or 5% for the  year-to-date  due  mainly  to a gain  from the sale of a
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.
        Income statement line items which changed significantly were:
                                         Increase (Decrease)
                                Third Quarter      Year-to-Date
                                (in millions)   %  (in millions)   %

Operating Revenues . . . . . .       $100      39       $141      24
Fuel Expense . . . . . . . . .         73      89         94      45
Purchased Power Expense. . . .         26     128         48      95
Other Operation Expense. . . .         (4)    (10)        (5)     (6)
Taxes Other Than Federal
  Income Taxes . . . . . . . .          3      34        N.M.    N.M.
Federal Income Taxes . . . . .          2       9          4      12
Nonoperating Income. . . . . .          6     404          7     N.M.
Interest Charges . . . . . . .        N.M.      5          2       9

N.M. = Not Meaningful

         The  increase  in  operating   revenues  was  due  to  an  increase  in
fuel-related  revenues,  reflecting  increased fuel and purchased power expenses
and increased  wholesale  sales to  neighboring  utilities and  marketers.  Fuel
revenue  changes are generally  offset by increases in fuel and purchased  power
expenses due to the operation of a fuel clause mechanism in Oklahoma.
         The increases in fuel and purchased  power  expenses were due primarily
to a rise in the average  unit fuel cost and higher  prices for  economy  energy
purchases reflecting an increase in natural gas prices.
         Other  operation  expenses  decreased due primarily to the effect of an
unfavorable  reallocation  adjustment  recorded  in  1999  as a  result  of FERC
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 four separate  transmission systems as a single
unit.  The  agreement  also  established  the  method by which  these  companies
allocate revenues and costs received under open access transmission  tariffs. In
1999 the AEP West  electric  operating  companies  filed a revised  transmission
coordination  agreement  which  includes  changes that ensure a revenue and cost
allocation in proportion to each company's  respective  revenue  requirement for
service it provides  under a revised  open access  transmission  tariff.  In the
third quarter of 1999, PSO recorded the estimated  impact of the reallocation of
open access  transmission  tariff  revenues and costs  retroactive to 1997 which
caused PSO to record additional other operation expense.
        Taxes other than federal income taxes increased for the quarter due
primarily to an increase in state taxable income. Income tax expense
associated with utility operations increased as a result of an increase
in pre-tax book income. The increase in nonoperating income primarily
resulted from the gain on the sale of the Company's minority interest
in Scientech, Inc in 2000.
         Interest charges increased reflecting additional short-term borrowings.


<PAGE>
<TABLE>
<CAPTION>




              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                        CONSOLIDATED STATEMENTS OF INCOME
                                   (UNAUDITED)

                                           Three Months Ended       Nine Months Ended
                                               September 30,           September 30,
                                             2000      1999         2000        1999
                                             ----      ----         ----        ----
                                                         (in thousands)
<S>                                        <C>        <C>          <C>        <C>
OPERATING REVENUES . . . . . . . . . . .   $377,442   $312,035     $857,607   $751,987
                                           --------   --------     --------   --------

OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .    172,763    124,737      375,888    292,698
  Purchased Power. . . . . . . . . . . .     23,665     10,130       54,615     26,895
  Other Operation. . . . . . . . . . . .     39,417     42,003      111,477    106,267
  Maintenance. . . . . . . . . . . . . .     12,644     15,598       47,856     49,860
  Depreciation and Amortization. . . . .     27,978     25,464       78,460     76,988
  Taxes Other Than Federal Income Taxes.     17,518     10,859       41,634     44,195
  Federal Income Taxes . . . . . . . . .     22,145     21,703       30,338     32,464
                                           --------   --------     --------   --------
          TOTAL OPERATING EXPENSES . . .    316,130    250,494      740,268    629,367
                                           --------   --------     --------   --------

OPERATING INCOME . . . . . . . . . . . .     61,312     61,541      117,339    122,620
NONOPERATING INCOME (LOSS) . . . . . . .      1,008     (3,062)       1,453     (2,277)
                                           --------   --------     --------   --------
INCOME BEFORE INTEREST CHARGES . . . . .     62,320     58,479      118,792    120,343
INTEREST CHARGES . . . . . . . . . . . .     14,783     13,571       44,806     41,929
                                           --------   --------     --------   --------
INCOME BEFORE EXTRAORDINARY ITEM . . . .     47,537     44,908       73,986     78,414
EXTRAORDINARY LOSS - DISCONTINUANCE OF
  REGULATORY ACCOUNTING FOR GENERATION
  (NET OF TAXES OF $1,621,000) . . . . .       -        (3,011)        -        (3,011)
                                           --------   --------     --------   --------
NET INCOME . . . . . . . . . . . . . . .     47,537     41,897       73,986     75,403
PREFERRED STOCK DIVIDEND REQUIREMENTS. .         58         57          172        172
                                           --------   --------     --------   --------

EARNINGS APPLICABLE TO COMMON STOCK  . .   $ 47,479   $ 41,840     $ 73,814   $ 75,231
                                           ========   ========     ========   ========

                         STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                           Three Months Ended        Nine Months Ended
                                            September 30,              September 30,
                                             2000      1999          2000        1999
                                             ----      ----          ----        ----
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD AS
  PREVIOUSLY REPORTED. . . . . . . . . .   $278,881   $280,760     $288,018    $300,592
   Conforming Change in Accounting . . .
     Policy. . . . . . . . . . . . . . .       -        (4,787)      (4,472)     (4,010)
                                           --------   --------     --------    --------

ADJUSTED BALANCE AT BEGINNING OF PERIOD.    278,881    275,973      283,546     296,582
 NET INCOME . . . . . . . . . . . . . . .    47,537     41,897       73,986      75,403
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock. . . . . . . . . . . . .    15,500     27,000       46,500      81,000
    Preferred Stock . . . . . . . . . . .        58         57          172         172
                                           --------   --------     --------    ---------

BALANCE AT END OF PERIOD . . . . . . . .   $310,860   $290,813     $310,860    $290,813
                                           ========   ========     ========    ========

The Company is a wholly owned subsidiary of AEP.

See Notes to Financial Statements beginning on page L-1.
</TABLE>

<PAGE>
<TABLE>
<CAPTION>



              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)
                                                           September 30,   December 31,
                                                                2000           1999
                                                           -------------   ------------
                                                                   (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                          <C>            <C>
  Production. . . . . . . . . . . . . . . . . . . . . . . .  $1,406,245     $1,402,062
  Transmission. . . . . . . . . . . . . . . . . . . . . . .     517,133        484,327
  Distribution. . . . . . . . . . . . . . . . . . . . . . .     989,224        958,318
  General . . . . . . . . . . . . . . . . . . . . . . . . .     323,110        333,949
  Construction Work in Progress . . . . . . . . . . . . . .      58,829         52,775
                                                             ----------     ----------

          Total Electric Utility Plant. . . . . . . . . . .   3,294,541      3,231,431

  Accumulated Depreciation. . . . . . . . . . . . . . . . .   1,434,124      1,384,242
                                                             ----------     ----------

          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .   1,860,417      1,847,189
                                                             ----------     -----------

OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . .      73,708         37,080
                                                             ----------     ----------

CURRENT ASSETS:
  Cash and Cash Equivalents . . . . . . . . . . . . . . . .       3,512          3,043
  Accounts Receivable . . . . . . . . . . . . . . . . . . .      62,804         45,511
  Accounts Receivable - Affiliated Companies. . . . . . . .       6,275          6,053
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . .      59,812         60,844
  Underrecovered Fuel . . . . . . . . . . . . . . . . . . .      34,089           -
  Materials and Supplies. . . . . . . . . . . . . . . . . .      26,085         26,420
  Energy Trading Contracts. . . . . . . . . . . . . . . . .      88,550           -
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .      17,574         15,953
                                                             ----------     ----------

          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     298,701        157,824
                                                             ----------     ----------

REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .      54,081         47,180
                                                             ----------     ----------

DEFERRED CHARGES  . . . . . . . . . . . . . . . . . . . . .      20,333         16,942
                                                             ----------     ----------

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $2,307,240     $2,106,215
                                                             ==========     ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
                           CONSOLIDATED BALANCE SHEETS
                                   (UNAUDITED)

                                                           September 30,   December 31,
                                                                2000           1999
                                                           -------------   -----------
                                                                   (in thousands)

CAPITALIZATION AND LIABILITIES
<S>                                                          <C>            <C>
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 . . . . . . . . . . . . . . . . . . . .     310,860        283,546
                                                             ----------     ----------
          TOTAL COMMON SHAREHOLDER'S EQUITY . . . . . . . .     691,520        664,206

Preferred Stock . . . . . . . . . . . . . . . . . . . . . .       4,704          4,706
SWEPCO-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED
 SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR
 SUBORDINATED DEBENTURES OF SWEPCO. . . . . . . . . . . . .     110,000        110,000
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . .     645,527        495,973
                                                             ----------     ----------

TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . .   1,451,751      1,274,885
                                                             ----------     ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year. . . . . . . . . . . .         595         45,595
  Advances from Affiliates. . . . . . . . . . . . . . . . .      26,947        140,897
  Accounts Payable - General. . . . . . . . . . . . . . . .      96,030         60,689
  Accounts Payable - Affiliated Companies . . . . . . . . .      35,043         39,117
  Customer Deposits . . . . . . . . . . . . . . . . . . . .      15,857         14,236
  Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      47,457         24,374
  Interest Accrued. . . . . . . . . . . . . . . . . . . . .      11,971          9,792
  Energy Trading Contracts. . . . . . . . . . . . . . . . .      92,688           -
  Other . . . . . . . . . . . . . . . . . . . . . . . . . .      23,934         21,878
                                                             ----------     ----------

          TOTAL CURRENT LIABILITIES . . . . . . . . . . . .     350,522        356,578
                                                             ----------     ----------

DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     392,803        376,504
                                                             ----------     ----------

DEFERRED INVESTMENT TAX CREDITS . . . . . . . . . . . . . .      54,288         57,649
                                                             ----------     ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS . . . . . . . .      57,876         40,599
                                                             ----------     ----------

CONTINGENCIES (Note 12)

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $2,307,240     $2,106,215
                                                             ==========     ==========

See Notes to Financial Statements beginning on page L-1.
</TABLE>

<PAGE>
<TABLE>
<CAPTION>



              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIAREIS
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                 Nine Months Ended
                                                                   September 30,
                                                                2000           1999
                                                                ----           ----
                                                                   (in thousands)

OPERATING ACTIVITIES:
<S>                                                           <C>            <C>
  Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 73,986       $ 75,403
  Adjustments for NonCash Items:
    Depreciation and Amortization. . . . . . . . . . . . . .    83,060         81,122
    Deferred Income Taxes. . . . . . . . . . . . . . . . . .    10,901        (16,204)
    Deferred Investment Tax Credits  . . . . . . . . . . . .    (3,361)        (3,423)
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net). . . . . . . . . . . . . . . .   (17,515)       (34,306)
    Fuel, Material and Supplies. . . . . . . . . . . . . . .     1,367        (16,404)
    Accounts Payable . . . . . . . . . . . . . . . . . . . .    31,267         (5,546)
    Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .    23,083         35,411
    Fuel Recovery. . . . . . . . . . . . . . . . . . . . . .   (36,977)          (223)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .   (16,756)        37,020
                                                              --------       ---------
        Net Cash Flows From Operating Activities . . . . . .   149,055        152,850
                                                              --------       --------

INVESTING ACTIVITIES:
  Construction Expenditures. . . . . . . . . . . . . . . . .   (92,379)       (73,127)
  Other. . . . . . . . . . . . . . . . . . . . . . . . . . .       232         (3,545)
                                                              --------       --------
        Net Cash Flows Used For Investing Activities . . . .   (92,147)       (76,672)
                                                              --------       --------

FINANCING ACTIVITIES:
  Redemption of Preferred Stock. . . . . . . . . . . . . . .        (1)            (1)
  Proceeds from Issuance of Long-term Debt . . . . . . . . .   149,634           -
  Retirement of Long-term Debt . . . . . . . . . . . . . . .   (45,450)       (43,787)
  Change in Advances from Affiliates (net) . . . . . . . . .  (113,950)        47,370
  Dividends Paid on Common Stock . . . . . . . . . . . . . .   (46,500)       (81,000)
  Dividends Paid on Preferred Stock. . . . . . . . . . . . .      (172)          (172)
                                                              --------       --------
        Net Cash Flows Used For Financing Activities . . . .   (56,439)       (77,590)
                                                              --------       --------

Net Increase (Decrease) in Cash and Cash Equivalents . . . .       469         (1,412)
Cash and Cash Equivalents at Beginning of Period . . . . . .     3,043          4,444
                                                              --------       --------
Cash and Cash Equivalents at End of Period . . . . . . . . .  $  3,512       $  3,032
                                                              ========       ========


Supplemental Disclosure:
  Cash  paid  for  interest  net of  capitalized  amounts  was  $42,627,000  and
  $40,056,000  and for income taxes was  $16,040,000 and $32,812,000 in 2000 and
  1999, respectively.

See Notes to Financial Statements beginning on page L-1.
</TABLE>

<PAGE>



              SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

                    THIRD QUARTER 2000 vs. THIRD QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999


         Net income increased $5.6 million, or 13%, for the quarter and was $1.4
million, or 2%, lower for the nine months ended September 30, 2000. The increase
for the quarter  resulted  primarily from increased  nonoperating  income and an
extraordinary  loss  due to the  discontinuance  of  regulatory  accounting  for
generation in 1999. The decrease for the year-to-date  period resulted primarily
from  increased  operating  expenses and interest  charges offset in part by the
effect of the extraordinary loss in 1999.
        Income statement line items which changed significantly were:
                                         Increase (Decrease)
                                Third Quarter      Year-to-Date
                                (in millions)   %  (in millions)   %

Operating Revenues . . . . . .       $65       21      $106       14
Fuel Expense . . . . . . . . .        48       39        83       28
Purchased Power Expense. . . .        14      134        28      103
Other Operation Expense. . . .        (3)      (6)        5        5
Maintenance Expense. . . . . .        (3)     (19)       (2)      (4)
Depreciation and Amortization.         3       10         1        2
Taxes Other Than Federal
  Income Taxes . . . . . . . .         7       61        (3)      (6)
Nonoperating Income. . . . . .         4      133         4      164
Interest Charges . . . . . . .         1        9         3        7

         The increase in operating  revenues  resulted  from higher fuel related
revenues due to increased  fuel and  purchased  power  expense,  the post merger
implementation  of AEP's power marketing and trading  operations which increased
wholesale sales to neighboring utilities and power marketers, and an unfavorable
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 four
separate  transmission  systems as a single unit. The agreement also establishes
the method by which these  companies  allocate  transmission  revenues  received
under open access transmission  tariffs. In 1999 the AEP West electric operating
companies  filed a revised  transmission  coordination  agreement which includes
changes  that  ensure a  revenue  allocation  in  proportion  to each  company's
respective  revenue  requirement  for service it provides  under a revised  open
access  transmission  tariff. In the third quarter of 1999, SWEPCo and the other
AEP West  electric  operating  companies  recorded the  estimated  impact of the
reallocation of open access  transmission  tariff  revenues  retroactive to 1997
which caused  SWEPCo to record a reduction  to revenues in the third  quarter of
1999 thereby increasing comparative revenues.
         Fuel expense increased due primarily to an increase in the average unit
cost of fuel as a result of higher spot market natural gas prices.
         The increase in purchased  power  expenses was  primarily  caused by an
increase in the cost of economy  energy  purchases due to increased  spot market
gas prices.
         Other  operation  expense  decreased for the quarter as a result of the
effect of an unfavorable  adjustment recorded in 1999 for allocated transmission
services.  Other  operation  expenses  were up in the  year-to-date  period  due
primarily to increased customer accounts expenses, increased insurance expenses,
and increased  regulatory  and  consulting  expenses for a sales tax audit which
more than offset the effect of the unfavorable  transmission services adjustment
recorded in 1999.
         A reduction in overhead  line tree trimming work caused the decrease in
maintenance  expense for the quarter.  In the year-to-date period the decline in
maintenance  expense  reflects  a decrease  in  generating  station  maintenance
activity.
         Depreciation  and  amortization  expense  increased  due to  changes in
depreciation  rates  associated  with  rate-related  settlements in Arkansas and
Louisiana in 1999.
         The  increase in taxes other than  federal  income  taxes for the third
quarter was due to an increase in ad valorem taxes in 2000.  The decrease in the
year-to-date  taxes other than  federal  income  taxes was a result of decreased
state taxable income.


<PAGE>



         Nonoperating income increased due to a 1999 write off of Cajun Electric
Power Cooperative  acquisition expenses.  SWEPCo had deferred  approximately $13
million in costs related to its attempt to acquire Cajun's  non-nuclear  assets.
Under a settlement  agreement,  SWEPCo received a $7.5 million reimbursement and
reflected an after tax loss in the third quarter of 1999 of $3.7 million.
         The increase in interest  charges can be  attributed to the issuance of
additional long-term debt in 2000.





<PAGE>
<TABLE>
<CAPTION>



                         WEST TEXAS UTILITIES COMPANY
                              STATEMENTS OF INCOME
                                   (UNAUDITED)

                                           Three Months Ended     Nine Months Ended
                                               September 30,          September 30,
                                             2000       1999        2000      1999
                                             ----       ----        ----      ----
                                                         (in thousands)

<S>                                        <C>        <C>         <C>       <C>
OPERATING REVENUES . . . . . . . . . . .   $201,191   $164,104    $425,268  $352,938
                                           --------   --------    --------  --------
OPERATING EXPENSES:
  Fuel . . . . . . . . . . . . . . . . .     57,728     41,478     133,515    93,821
  Purchased Power. . . . . . . . . . . .     54,686     28,328      92,034    49,096
  Other Operation. . . . . . . . . . . .     32,046     24,761      68,101    65,835
  Maintenance. . . . . . . . . . . . . .      4,959      4,283      14,866    14,744
  Depreciation and Amortization. . . . .     22,717     20,734      42,050    42,358
  Taxes Other Than Federal Income Taxes.      7,096      6,464      18,712    21,049
  Federal Income Taxes . . . . . . . . .      5,394     11,026      12,706    15,722
                                           --------   --------   ---------  --------

          TOTAL OPERATING EXPENSES . . .    184,626    137,074     381,984   302,625
                                           --------   --------   ---------  --------

OPERATING INCOME . . . . . . . . . . . .     16,565     27,030      43,284    50,313
NONOPERATING INCOME (LOSS) . . . . . . .       (202)       332      (3,441)      504
                                           --------   --------   ---------  --------
INCOME BEFORE INTEREST CHARGES . . . . .     16,363     27,362      39,843    50,817
INTEREST CHARGES . . . . . . . . . . . .      5,693      5,949      17,270    18,356
                                           --------   --------    --------  --------
INCOME BEFORE EXTRAORDINARY ITEM . . . .     10,670     21,413      22,573    32,461
EXTRAORDINARY LOSS - DISCONTINANCE OF
  REGULATORY ACCOUNTING FOR GENERATION
  (NET OF TAXES OF $2,941,000) . . . . .       -        (5,461)       -       (5,461)
                                           --------   --------    --------  --------
NET INCOME . . . . . . . . . . . . . . .     10,670     15,952      22,573    27,000
PREFERRED STOCK DIVIDENDS REQUIREMENTS .         26         26          78        78
                                           --------   --------    --------  ---------

EARNINGS APPLICABLE TO COMMON STOCK. . .   $ 10,644   $ 15,926    $ 22,495  $ 26,922
                                           ========   ========    ========  ========

                         STATEMENTS OF RETAINED EARNINGS
                                   (UNAUDITED)

                                           Three Months Ended     Nine Months Ended
                                               September 30,         September 30,
                                             2000      1999        2000        1999
                                             ----      ----        ----        ----
                                                         (in thousands)
BALANCE AT BEGINNING OF PERIOD
  AS PREVIOUSLY REPORTED. . . .. . . . .   $116,093  $114,772    $115,856    $117,189
CONFORMING CHANGE IN ACCOUNTING POLICY .       -       (2,836)     (2,614)     (2,249)
                                           --------  --------    --------    --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD.    116,093   111,936     113,242     114,940

NET INCOME . . . . . . . . . . . . . . .     10,670    15,952      22,573      27,000

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock . . . . . . . . . . . .      4,500     7,000      13,500      21,000
    Preferred Stock. . . . . . . . . . .         26        26          78          78
                                           --------  --------    --------    ---------

BALANCE AT END OF PERIOD . . . . . . . .   $122,237  $120,862    $122,237    $120,862
                                           ========  ========    ========    =========

The common stock of the Company is wholly owned by AEP.

       See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>




                          WEST TEXAS UTILITIES COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)

                                                             September 30,  December 31,
                                                                 2000           1999
                                                             -------------  ------------
                                                                   (in thousands)

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                          <C>            <C>
  Production. . . . . . . . . . . . . . . . . . . . . . . .  $  422,972     $  429,783
  Transmission. . . . . . . . . . . . . . . . . . . . . . .     234,824        220,479
  Distribution. . . . . . . . . . . . . . . . . . . . . . .     412,670        403,206
  General . . . . . . . . . . . . . . . . . . . . . . . . .     110,543        113,945
  Construction Work in Progress . . . . . . . . . . . . . .      28,242         15,131
                                                             ----------     ----------
          Total Electric Utility Plant. . . . . . . . . . .   1,209,251      1,182,544
  Accumulated Depreciation and Amortization . . . . . . . .     506,207        495,847
                                                             ----------     ----------
          NET ELECTRIC UTILITY PLANT. . . . . . . . . . . .     703,044        686,697
                                                             ----------     ----------

OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . .      33,505         21,570
                                                             ----------     ----------

CURRENT ASSETS:
  Cash and Cash Equivalents . . . . . . . . . . . . . . . .       8,660          6,074
  Accounts Receivable:
    Customers . . . . . . . . . . . . . . . . . . . . . . .      40,833         45,742
    Affiliated Companies. . . . . . . . . . . . . . . . . .       9,835          4,837
  Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . .      13,548         17,133
  Materials and Supplies. . . . . . . . . . . . . . . . . .      11,145         14,029
  Under-recovered Fuel Costs. . . . . . . . . . . . . . . .      48,303         14,652
  Energy Trading Contracts. . . . . . . . . . . . . . . . .      27,456           -
  Prepayments . . . . . . . . . . . . . . . . . . . . . . .       1,075            619
                                                             ----------     ----------

          TOTAL CURRENT ASSETS. . . . . . . . . . . . . . .     160,855        103,086
                                                             ----------     ----------

REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . .      14,071         16,687
                                                             ----------     ----------

DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . .       5,146         20,108
                                                             ----------     ----------

            TOTAL . . . . . . . . . . . . . . . . . . . . .  $  916,621     $  848,148
                                                             ==========     ==========


See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                          WEST TEXAS UTILITIES COMPANY
                                 BALANCE SHEETS
                                   (UNAUDITED)

                                                              September 30,  December 31,
                                                                   2000          1999
                                                              -------------  ------------
                                                                     (in thousands)

  CAPITALIZATION AND LIABILITIES
<S>                                                            <C>            <C>
  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 . . . . . . . . . . . . . . . . . . . .     122,237        113,242
                                                               ----------     ----------
            Total Common Shareholder's Equity . . . . . . . .     261,687        252,692
    Preferred Stock . . . . . . . . . . . . . . . . . . . . .       2,482          2,482
    Long-term Debt. . . . . . . . . . . . . . . . . . . . . .     263,792        263,686
                                                               ----------     ----------

            TOTAL CAPITALIZATION. . . . . . . . . . . . . . .     527,961        518,860
                                                               ----------     ----------

  CURRENT LIABILITIES:
    Long-term Debt Due Within One Year. . . . . . . . . . . .        -            40,000
    Advances from Affiliates. . . . . . . . . . . . . . . . .      47,646         21,408
    Accounts Payable - General. . . . . . . . . . . . . . . .      60,034         39,611
    Accounts Payable - Affiliated Companies . . . . . . . . .      15,716         19,770
    Taxes Accrued . . . . . . . . . . . . . . . . . . . . . .      13,750         12,458
    Interest Accrued. . . . . . . . . . . . . . . . . . . . .       7,441          4,165
    Energy Trading Contracts. . . . . . . . . . . . . . . . .      28,739           -
    Other . . . . . . . . . . . . . . . . . . . . . . . . . .      13,339         13,906
                                                               ----------     ----------

            TOTAL CURRENT LIABILITIES . . . . . . . . . . . .     186,665        151,318
                                                               ----------     ----------

  DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . .     152,951        148,992
                                                               ----------     ----------

  DEFERRED INVESTMENT TAX CREDITS . . . . . . . . . . . . . .      24,369         25,323
                                                               ----------     ----------

  DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . .      24,675          3,655
                                                               ----------     ----------

  CONTINGENCIES (Note 12)

              TOTAL . . . . . . . . . . . . . . . . . . . . .  $  916,621     $  848,148
                                                               ==========     ==========

  See Notes to Financial Statements beginning on page L-1.

</TABLE>
<PAGE>
<TABLE>
<CAPTION>



                          WEST TEXAS UTILITIES COMPANY
                            STATEMENTS OF CASH FLOWS
                                   (UNAUDITED)
                                                                   Nine Months Ended
                                                                      September 30,
                                                                  2000           1999
                                                                  ----           ----
                                                                     (in thousands)

  OPERATING ACTIVITIES:
<S>                                                             <C>            <C>
    Net Income . . . . . . . . . . . . . . . . . . . . . . . .  $ 22,573       $ 27,000
    Adjustments for Noncash Items:
      Depreciation and Amortization. . . . . . . . . . . . . .    43,750         32,558
      Deferred Income Taxes. . . . . . . . . . . . . . . . . .     5,586          7,911
      Deferred Investment Tax Credits. . . . . . . . . . . . .      (953)          (956)
      Extraordinary Loss - Discontinuance of SFAS 71 . . . . .      -             5,461
    Changes in Assets and Liabilities:
      Accounts Receivable. . . . . . . . . . . . . . . . . . .       (89)           759
      Fuel, Materials and Supplies . . . . . . . . . . . . . .     6,469         (1,378)
      Accounts Payable . . . . . . . . . . . . . . . . . . . .    16,369          9,730
      Taxes Accrued. . . . . . . . . . . . . . . . . . . . . .     1,292          7,415
      Fuel Recovery. . . . . . . . . . . . . . . . . . . . . .   (33,651)        (9,052)
    Other. . . . . . . . . . . . . . . . . . . . . . . . . . .    12,518            350
                                                                --------       ---------
          Net Cash Flows From Operating Activities . . . . . .    73,864         79,798
                                                                --------       --------

  INVESTING ACTIVITIES:
    Construction Expenditures. . . . . . . . . . . . . . . . .   (44,050)       (35,444)
    Other. . . . . . . . . . . . . . . . . . . . . . . . . . .       112         (2,828)
                                                                --------       --------
          Net Cash Flows Used For Investing Activities . . . .   (43,938)       (38,272)
                                                                --------       --------

  FINANCING ACTIVITIES:
    Retirement of Long-term Debt . . . . . . . . . . . . . . .   (40,000)          -
    Change in Advances from Affiliates (net) . . . . . . . . .    26,238         (4,573)
    Dividends Paid on Common Stock . . . . . . . . . . . . . .   (13,500)       (21,000)
    Dividends Paid on Preferred Stock. . . . . . . . . . . . .       (78)           (78)
                                                                --------       --------
          Net Cash Flows Used For Financing Activities . . . .   (27,340)       (25,651)
                                                                --------       --------

  Net Increase in Cash and Cash Equivalents. . . . . . . . . .     2,586         15,875
  Cash and Cash Equivalents at Beginning of Period . . . . . .     6,074          2,093
                                                                --------       --------
  Cash and Cash Equivalents at End of Period . . . . . . . . .  $  8,660       $ 17,968
                                                                ========       ========

  Supplemental Disclosure:
    Cash paid for  interest  net of  capitalized  amounts  was  $13,994,000  and
    $10,067,000  and for income taxes was  $5,442,000 and $1,749,000 in 2000 and
    1999, respectively.

  See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>



                          WEST TEXAS UTILITIES COMPANY
          MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
          -------------------------------------------------------------
                    THIRD QUARTER 2000 vs. THIRD QUARTER 1999
                                       AND
                     YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
                     ---------------------------------------

                  Income before extraordinary items decreased $11 million or 50%
       for the  quarter  and $10  million  or 30%  for the  year-to-date  period
       largely due to the effects of a 1999 FERC order related to a transmission
       coordination agreement. The transmission  coordination agreement provides
       the  means  by which  the AEP West  electric  operating  companies  plan,
       operate and maintain their four separate transmission systems as a single
       unit. The agreement also  establishes the method by which these companies
       allocate revenues  received under open access  transmission  tariffs.  In
       1999  the  AEP  West  electric   operating   companies  filed  a  revised
       transmission  coordination agreement which includes changes that ensure a
       revenue  allocation in proportion to each  company's  respective  revenue
       requirement   for  service  it  provides  under  a  revised  open  access
       transmission  tariff. In the third quarter of 1999, WTU and the other AEP
       West electric  operating  companies  recorded the estimated impact of the
       reallocation of open access transmission  tariff revenues  retroactive to
       1997  which  caused  WTU  to  record  additional   revenues  and  thereby
       increasing net income in 1999.
                  An extraordinary loss related to the discontinuance of SFAS 71
       regulatory accounting of $5.5 million after tax was recorded in September
       1999.


<PAGE>



                  Income statement line items which changed significantly were:
                                                 Increase (Decrease)
                                        Third Quarter      Year-to-Date
                                        (in millions)   %  (in millions)   %

       Operating Revenues, . . . . . . .    $ 37       23      $72        20
       Fuel Expense. . . . . . . . . . .      16       39       40        42
       Purchased Power Expense . . . . .      26       93       43        87
       Other Operation Expense . . . . .       7       29        2         3
       Depreciation and Amortization . .       2       10       -        N.M.
       Taxes Other Than Federal
         Income Taxes. . . . . . . . . .       1       10       (2)      (11)
       Federal Income Taxes. . . . . . .      (6)     (51)      (3)      (19)
       Nonoperating Income . . . . . . .      (1)     N.M.      (4)      N.M.
       Interest Charges. . . . . . . . .      -       N.M.      (1)       (6)
       Extraordinary Loss. . . . . . . .       5      N.M.       5       N.M.

       N.M. = Not Meaningful

                  The  increase  in  operating  revenues  was  due to  increased
       fuel-related  revenues,   reflecting  higher  fuel  and  purchased  power
       expenses,  and an increase  in  weather-related  demand for  electricity.
       Under the  operation of a fuel clause  mechanism  in Texas,  revenues are
       accrued  to  reflect  fuel and  purchased  power  cost  increases.  These
       increases were partially  offset by a reduction in non-MWH  revenue.  The
       decline in non-MWH  revenue was  primarily  due to the effect of the 1999
       FERC transmission coordination agreement order.
                  The  increase in fuel expense was due to a rise in the average
       unit fuel cost  resulting  from an increase  in the spot market  price of
       natural gas.
                  Purchased  power  expense  increased  due  primarily  to a 40%
       increase in the cost per MWH  purchased to replace  generation at a power
       plant which was out of service for more than half of the current  quarter
       as a result of a control room fire.
                  The increase in other  operation  expense was due primarily to
       an increase in transmission expenses that resulted from new higher 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.
                  Depreciation and amortization  expense increased for the third
       quarter due to the recordation of increased accruals for estimated excess
       earnings under the Texas Legislation.
                  The decrease in taxes other than federal  income taxes for the
       year-to-date  period  was  primarily  due to lower ad  valorem  and state
       franchise taxes.
                  Federal income taxes attributable to operations  decreased due
       primarily to a decrease in pre-tax net income. The decrease in
       nonoperating income was due primarily to the termination of
       merchandise sales and the cost of phasing out these sales.
                  Interest  charges  decreased  as a result  of a  reduction  in
       long-term borrowings.
                  An  extraordinary  loss was  recorded in the third  quarter of
       1999  when  WTU  discontinued  the  application  of  SFAS  71  regulatory
       accounting for the generation  portion of its business as a result of the
       Texas  Legislation  providing  for a  transition  from  cost  based  rate
       regulation  for the  Company's  generation  business to  customer  choice
       market pricing.



<PAGE>



       NOTES TO FINANCIAL STATEMENTS AND THE REGISTRANT TO WHICH THEY APPLY


       Note  1. General          AEP, AEGCo, APCo, CPL, CSPCo, I&M,
                                 KPCo, OPCo, PSO, SWEPCo, WTU

       Note  2. Extraordinary
                 Item            AEP, APCo, CSP, OPCo, SWEPCo, WTU

       Note  3. Merger           AEP, CPL, I&M, KPCo, PSO, SWEPCo, WTU

       Note  4. Cook
                 Plant Shutdown  AEP, I&M

       Note  5. Financing
                 Activities      AEP, APCo, CPL, CSPCo, I&M, KPCo,
                                 OPCo, PSO, SWEPCo, WTU

       Note  6. Money Pool       AEP, AEGCo, CPL, CSPCo, I&M, KPCo,
                                 OPCo, PSO, SWEPCo, WTU

       Note  7. Factoring of
                 Receivables     AEP, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
                                 SWEPCo, WTU

       Note  8. Rate Matters     AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo,
                                 SWEPCo, WTU

       Note  9. Industry
                 Restructuring   AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO,
                                 SWEPCo, WTU

       Note 10. Business
                 Segments        AEP

       Note 11. South American
                 Investments     AEP

       Note 12. Contingencies    AEP, AEGCo, APCo, CPL, CSPCo, I&M,
                                 KPCo, OPCo, PSO, SWEPCo, WTU


<PAGE>




                          NOTES TO FINANCIAL STATEMENTS
                               SEPTEMBER 30, 2000
                                   (UNAUDITED)

1.      GENERAL

               The accompanying unaudited financial statements should be read in
        conjunction with the 1999 audited financial statements.  For AEP, AEGCo,
        APCo, CSPCo,  I&M, KPCo and OPCo the 1999 audited  financial  statements
        are included in their 1999 Annual Reports, which are incorporated in and
        filed with their Form 10-K.  The 1999 audited  financial  statements for
        CPL,  PSO,  SWEPCo and WTU are  included  in their  Form  10-K.  Certain
        prior-period amounts have been reclassified to conform to current-period
        presentation.  In the opinion of management,  these unaudited  financial
        statements reflect all adjustments  (consisting of only normal recurring
        accruals) which are necessary for a fair  presentation of the results of
        operations for interim periods.

2.      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
         jurisdictions.  See Note 9 "Industry Restructuring" for descriptions of
         the restructuring plans and related accounting  effects.  The following
         table shows the components of the  extraordinary  items reported on the
         consolidated statement of income:

                                     Three Months Ended  Nine Months Ended
                                        September 30,      September 30,
                                     ------------------  -----------------
                                        2000      1999     2000     1999
                                        ----      ----     ----     ----
                                                  (in millions)
         Extraordinary Items -
           Discontinuance of
           Regulatory Accounting
           for Generation:
           Ohio Jurisdiction (Net of
           Tax of $35 Million). . . .   $(44)     $ -     $(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)     -        (8)
                                         ----      ---    ----      ---

            Extraordinary Items . . .    $(44)     $(8)   $(35)     $(8)
                                         =====     ===    ====      ===

3.      MERGER OF AEP AND CSW

               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.

        CSW's four wholly-owned domestic electric utility subsidiaries are: CPL,
        PSO, SWEPCo and WTU. CSW also has the following principal subsidiaries:
        CSW International, CSW Energy, Seeboard, CSW Credit, C3 Communications,
        Inc. and CSW Energy Services, Inc.

               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:

                                Three Months Ended     Nine Months Ended
                                September 30, 1999     September 30, 1999
                                ------------------     ------------------
                                              (in millions)
        Revenues:
          AEP                         $1,914                 $5,251
          CSW                          1,618                  4,162
                                      ------                 ------
          AEP After Pooling           $3,532                 $9,413
                                      ======                 ======

        Extraordinary Items:
          AEP                           $ -                    $ -
          CSW                            (8)                    (8)
                                        ---                    ---
          AEP After Pooling             $(8)                   $(8)
                                        ===                    ===

        Net Income:
          AEP                           $174                   $413
          CSW                            222                    370
          Conforming Adjustment           (1)                    (4)
                                        ----                   ----
          AEP After Pooling             $395                   $779
                                        ====                   ====

               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 $16.4  million at  December  31, 1999 and reduce net income by
        $0.8 million and $3.8 million for the three months and nine months ended
        September 1999, respectively.


<PAGE>



               The  following  table  shows  the  vacation  accrual   conforming
adjustment for CSW's registrant utility subsidiaries:

                                              Net Income Reductions
                                          Three Months   Nine Months
                       Net Asset             Ended          Ended
                      Reduction At        September 30,  September 30,
                   December 31, 1999           1999           1999
                   -----------------      -------------  -------------
                     (in millions)                (in millions)
             CPL           $5.3                $0.2           $1.1
             PSO            2.8                 0.1            0.8
             SWEPCo         4.5                 0.2            1.0
             WTU            2.6                 0.1            0.7

               In  connection  with  the  merger,  $181  million  ($169  million
        after-tax)  of  non-recoverable   merger  costs  were  expensed  through
        September 30, 2000. Such costs 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  $38  million  recoverable  from  ratepayers  were
        deferred  pursuant to settlement  agreements.  Deferred merger costs are
        being  amortized over five to eight year recovery  periods  depending on
        the specific terms of the settlement agreements. 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.
        The  settlement  agreements  provide for a sharing of net merger savings
        with  certain  regulated  customers  over  periods of up to eight  years
        through rate reductions beginning in the third quarter of 2000.

               In  connection  with the merger,  the PUCT  approved a settlement
        agreement  that  provides for,  among other  things,  sharing net merger
        savings with Texas customers of CPL, SWEPCo and WTU over six years after
        consummation of the merger through rate reduction riders.

               The IURC and MPSC approved  merger  settlement  agreements  that,
        among other  things,  provide for sharing net merger  savings with I&M's
        retail  customers  over eight years  through  reductions  to  customers'
        bills.  The  terms  of the  Indiana  settlement  require  reductions  in
        customers'  bills of approximately  $67 million over eight years.  Under
        the  Michigan  settlement,  billing  credits  will  be  used  to  reduce
        customers' bills by  approximately  $14 million over eight years for net
        guaranteed merger savings.

               The KPSC  approved  a  settlement  agreement  that,  among  other
        things,  provides for sharing net merger  savings with KPCo's  customers
        over eight years through  reductions to customers'  bills.  The Kentucky
        customers'   share  of  the  net  merger   savings  is  expected  to  be
        approximately $28 million.

               A  merger  settlement  agreement  for  PSO  was  approved  by the
        Oklahoma Corporation  Commission that, among other things,  provides for
        sharing  approximately $28 million in guaranteed net merger savings over
        five years with Oklahoma customers.

               The  Arkansas  Public  Service  Commission  approved an agreement
        related to the merger which, among other things, provides for $6 million
        of net merger savings to reduce SWEPCo  customers  rates over five years
        in Arkansas.

               SWEPCo's  Louisiana  customers  will  receive  approximately  $18
        million  of  merger  savings  over  eight  years  according  to a merger
        approval order issued by the Louisiana Public Service Commission.

               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  divestiture of 1,904 MW of generating  capacity was required
        as a  condition  of  regulatory  approval  of the merger by the FERC and
        PUCT.  Under  the   FERC-approved   merger   settlement   agreement  the
        divestiture  of 550 MW of  generating  capacity  comprised  of 300 MW of
        capacity in SPP and 250 MW of capacity in ERCOT is required. The FERC is
        requiring AEP and CSW to divest their entire  ownership  interest in and
        operational control of the entire generating facilities that produce the
        capacity to be divested. The FERC required divestiture of the identified
        ERCOT  capacity  must be  completed  by March  15,  2001 and for the SPP
        capacity by July 1, 2002.  The FERC found that  certain  energy sales in
        SPP and ERCOT would be a reasonable  and  effective  interim  mitigation
        measure  until  the  required  SPP  and  ERCOT   divestitures  could  be
        completed.  The Texas settlement calls for the divestiture of a total of
        1,604 MW of generating capacity within Texas inclusive of 250 MW ordered
        to be divested by FERC. The divestiture  under the Texas  settlement can
        not  proceed  until two years  after the merger  closes to  satisfy  the
        requirements to use pooling-of-interests  accounting treatment. The FERC
        divestiture is not limited by the pooling rules because it is regulatory
        ordered.

               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
        prior  periods  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.

4.      COOK PLANT SHUTDOWN

               As discussed in the 1999 Annual  Report,  the Cook Plant was shut
        down in September  1997 due to questions  regarding the  operability  of
        certain safety systems that arose during a NRC architect engineer design
        inspection.

               On July 5, 2000,  Cook Plant Unit 2, the first unit  scheduled to
        restart, reached 100% power completing its restart process.

               On July 26, 2000,  I&M  announced  that the restart of Cook Plant
        Unit 1 would cost an additional  $145 million and was scheduled to occur
        in the first quarter of 2001. However, unforeseen issues or difficulties
        encountered in preparing Unit 1 for restart could  potentially delay its
        return to service.

               Expenditures  to restart the Cook Plant units had been  estimated
        to total  approximately  $574 million.  The  additional  $145 million to
        restart  Unit 1 raises  the  total  estimate  to $719  million.  Through
        September  30,  2000,  $592 million has been spent to restart the units.
        For the nine months  ended  September  30, 2000,  restart  costs of $249
        million  were  recorded  in other  operation  and  maintenance  expense,
        including  amortization  of $30  million  of  restart  costs  previously
        deferred in  accordance  with  settlement  agreements in the Indiana and
        Michigan  retail   regulatory   jurisdictions.   Also  pursuant  to  the
        settlement agreements, accrued fuel-related revenues of $28 million were
        amortized in 2000. At September 30, 2000, deferred restart costs of $130
        million remained in regulatory assets to be amortized through 2003. Also
        deferred as a regulatory asset at September 30, 2000 are $122 million of
        fuel-related revenues to be amortized through December 31, 2003 for both
        jurisdictions.

               The  costs  of the  extended  outage  and  restart  efforts  will
        continue  to  have a  material  adverse  effect  on  future  results  of
        operations  and on cash flows  until the second unit is  restarted.  The
        amortization of restart costs 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  deferrals  is $40  million.
        Management  believes that the second Cook Plant unit,  Unit 1, will also
        be successfully returned to service. However, if for some unknown reason
        it is not returned to service or its return is delayed  significantly it
        would have an even greater  material adverse effect on future results of
        operations, cash flows and financial condition.

5.      FINANCING ACTIVITIES

               During the first nine  months of 2000,  AEP  subsidiaries  issued
        $951  million of  long-term  notes at variable  interest  rates with due
        dates  ranging  from  2001 to  2007.  Also  short-term  debt  borrowings
        increased by $1.4 billion.  The AEP System  companies  have in the past,
        and may in the future,  acquire  outstanding  debt and  preferred  stock
        securities in open market transactions.

               The following table lists long-term notes issued during the first
        nine months of 2000 by the subsidiaries that are registrants:

                   Issuance    Interest    Due
        Company    Amount        Rate      Date
        -------    --------    --------    ----
              (in millions)

    APCo         $ 75      Floating    June 27, 2001
    CPL           150      Floating    February 22, 2002
    I&M           200      Floating    September 3, 2002
    OPCo           75      Floating    May 16, 2001
    SWEPCo        150      Floating    March 1, 2002

               Retirements  of debt  during  2000  were:  first  mortgage  bonds
        totaling  $416  million and due dates  ranging  from 2000 to 2024,  $268
        million of long-term notes with variable interest rates as well as fixed
        rates  ranging  from 6.43% to 6.57%,  a $625  million  revolving  credit
        agreement that matured and was refinanced with short-term debt and a $45
        million revolving credit agreement that was redeemed early.


<PAGE>



               The following  table lists specific  long-term  debt  retirements
        during  the  first  nine  months  of  2000  by  subsidiaries   that  are
        registrants:

                               Principal
                   Type         Amount    Interest  Due
        Company    of Debt      Retired     Rate    Date
        -------    -------    ----------- --------  ----
                         (in millions)   (%)

        APCo       IPC           $ 30       7.40    January 1, 2014
        APCo       FMB             48       6.35    March 1, 2000
        APCo       FMB             48       6.71    June 1, 2000
        CPL        FMB            100       6       April 1, 2000
        CPL        FMB             50       7.5     March 1, 2020
        CSPCo      FMB             19       7.25    October 1, 2002
        I&M        FMB             48       6.40    March 1, 2000
        KPCo       NP              25       6.57    April 1, 2000
        OPCo       MTN             13       6.24    December 4, 2008
        PSO        MTN             10       6.43    March 30, 2000
        SWEPCo     FMB             45       5.25    April 1, 2000
        WTU        FMB             40       7.5     April 1, 2000

               CSPCo redeemed 100,000 shares of its 7% series of preferred stock
on August 1, 2000.

6.      MONEY POOL

               In  June  2000  the  AEP  System  established  a  Money  Pool  to
        coordinate short-term borrowings for certain subsidiaries, primarily the
        domestic  electric  utility  operating  companies.  The operation of the
        Money Pool is designed to match on a daily basis the available  cash and
        borrowing requirements of the participants,  thereby minimizing the need
        for  short-term  borrowings  from external  sources and  increasing  the
        interest income for participants with available cash.  Participants with
        excess cash loan funds to the Money Pool reducing the amount of external
        funds AEP needs to borrow to meet the short-term  cash  requirements  of
        other  participants  whose short-term cash  requirements are met through
        advances  from the Money Pool.  AEP borrows the funds on a daily  basis,
        when  necessary,  to meet the net cash  requirements  of the Money  Pool
        participants. A weighted average daily interest rate which is calculated
        based  on the  outstanding  short-term  debt  borrowings  made by AEP is
        applied to each Money Pool participant's daily outstanding investment or
        debt  position to determine  interest  income or interest  expense.  The
        Money Pool participants  include interest income in nonoperating  income
        and interest expense in interest charges.  As a result of becoming Money
        Pool  participants,  AEGCo,  CSPCo,  I&M,  KPCo and OPCo  retired  their
        short-term  debt. CPL, PSO,  SWEPCo and WTU  participated in a CSW money
        pool prior to the merger and subsequent to the merger participate in the
        AEP Money Pool. At September 30, 2000,  participating  subsidiaries  who
        are net  investors  from the Money Pool report their  investment  in the
        Money Pool as Advances to Affiliates and companies who are net borrowers
        from the  Money  Pool  report  their  debt  position  as  Advances  from
        Affiliates on their balance sheets.


<PAGE>




7.      FACTORING OF RECEIVABLES

               AEP Credit,  Inc. factors electric customer accounts  receivable
        for affiliated  operating companies and unaffiliated companies.  Prior
        to September 1, 2000, AEP Credit,  Inc. was known as CSW Credit. AEP
        Credit,  Inc. issues commercial paper on a stand  alone  basis and does
        not  participate  in the Money  Pool.  In June 2000 the  factoring  of
        customer  accounts receivable for affiliated  companies was expanded as
        a result of the merger.  At September 30, 2000, AEP Credit,  Inc. had a
        $2 billion revolving credit agreement which had $1.5 billion of
        commercial paper outstanding.

               Under the  factoring  arrangement  most of the domestic  electric
        subsidiary  companies  sell without  recourse  certain of their customer
        accounts  receivable and accrued utility revenue balances to AEP Credit,
        Inc. and are charged a fee based on AEP Credit,  Inc.'s 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 September 30, 2000,
        the amount of factored accounts  receivable and accrued utility revenues
        for each registrant subsidiary was as follows:

               Company       (in millions)
               -------

               CPL               $200
               CSPCo              111
               I&M                101
               KPCo                24
               OPCo                96
               PSO                135
               SWEPCo             111
               WTU                 60

8.      RATE MATTERS

        FERC Jurisdiction - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

            As discussed in the 1999 Annual Report,  APCo, CSPCo, I&M, KPCo, and
      OPCo filed a settlement  agreement  for FERC  approval  related to an open
      access transmission tariff. A provision was recorded in 1999 for an agreed
      to refund including interest which was part of the settlement agreement.

            On March 16, 2000, the FERC approved the settlement  agreement filed
      in December  1999  resolving  the issues on  rehearing  of a July 30, 1999
      order. Under terms of the settlement, APCo, CSPCo, I&M, KPCo, and OPCo are
      required  to make  refunds  retroactive  to  September  7, 1993 to certain
      customers  affected by the July 30, 1999 FERC order. The refunds were made
      in two  payments.  Pursuant to FERC  orders the first  payment was made in
      February  2000 and the  second  payment  was made on  August 1,  2000.  In
      addition, a new lower rate of $1.55 kw/month was made effective January 1,
      2000, for all transmission  service customers.  Also as agreed, a new rate
      of $1.42  kw/month took effect on June 16, 2000 upon  consummation  of the
      AEP/CSW  merger.  Prior to January 1, 2000,  the rate was $2.04  kw/month.
      Unless the market volume of physical power  transactions grows to increase
      the  utilization  of the AEP  System's  transmission  lines,  the new open
      access   transmission   rate  will  adversely  impact  future  results  of
      operations and cash flows.

      West Virginia Jurisdiction - Affecting AEP and APCo

            As discussed in the 1999 Annual Report,  APCo has been involved in a
      WV rate  proceeding  regarding  base and ENEC rates.  On February 7, 2000,
      APCo and other parties to the proceeding  filed a Joint  Stipulation  with
      the WVPSC for approval.

            The Joint  Stipulation's main provisions include no change in either
      base or ENEC  rates  effective  January  1, 2000 from  those base and ENEC
      rates in effect from November 1, 1996 until December 31, 1999 (these rates
      provide for recovery of regulatory assets including any generation-related
      regulatory  assets through frozen  transition  rates and a wires charge of
      0.5 mills per kwh); the suspension of annual ENEC recovery proceedings and
      deferral  accounting for any over or under recovery  effective  January 1,
      2000; and the retention,  as a regulatory liability, on the books of a net
      cumulative deferred ENEC recovery balance of $66 million as established by
      a WVPSC order on December 27, 1996.  The Joint  Stipulation  provides that
      when  deregulation of generation occurs in WV, APCo will use this retained
      regulatory liability to reduce  generation-related  regulatory assets and,
      to  the  extent  possible,   any  additional  costs  or  obligations  that
      deregulation may impose.  The elimination of ENEC recovery  proceedings in
      WV will  subject AEP and APCo to the risk of fuel market  price  increases
      and  reductions  in wholesale  sales levels which could  adversely  affect
      results of operations and cash flows.

               Also under the Joint Stipulation  APCo's share of any net savings
        from the merger  between AEP and CSW prior to December 31, 2004 shall be
        retained  by APCo.  As a result,  all costs  incurred in the merger that
        were  allocated  to APCo shall be fully  charged to expense to partially
        offset merger  savings as of December 31, 2004 and shall not be included
        in any WV rate  proceeding  after that date.  After  December  31, 2004,
        current  distribution savings related to the merger will be reflected in
        rates in any  future  rate  proceeding  before  the  WVPSC to  establish
        distribution  rates or to adjust  rate caps  during  the  transition  to
        market based rates.  When  deregulation of generation  occurs in WV, the
        net retained  generation-related merger savings shall be used to recover
        any  generation-related  regulatory  assets that are not recovered under
        the  other  provisions  of the  Joint  Stipulation  and  the  mechanisms
        provided  for  in  the  deregulation  legislation  and,  to  the  extent
        possible,   to  recover  any  additional   costs  or  obligations   that
        deregulation  may  impose  on  APCo.   Regardless  of  whether  the  net
        cumulative deferred ENEC recovery balance and the net merger savings are
        sufficient to offset all of APCo's generation-related regulatory assets,
        under  the  terms of the  Joint  Stipulation  there  will be no  further
        explicit   adjustment  to  APCo's  rates  to  provide  for  recovery  of
        generation-related regulatory assets beyond the above discussed specific
        adjustments  provided in the Joint Stipulation and the 0.5 mills per KWH
        wires charge in the WV Restructuring  Plan (see Note 9 for discussion of
        WV  Restructuring  Plan).  On June 2,  2000,  the WVPSC  issued an order
        approving the Joint Stipulation.


<PAGE>




        Texas Jurisdictional Fuel Factor Filings - Affecting AEP, CPL, SWEPCo
        and WTU

               AEP's Texas electric  operating  companies have been experiencing
        natural gas fuel price increases which have resulted in under-recoveries
        of  fuel  costs  and  the  need to seek  increases  in  fuel  rates  and
        surcharges to recover past under-recoveries.

               In March  2000 the PUCT  approved a  settlement  related to CPL's
        January 2000 fuel factor filing. The settlement provided for an increase
        in fuel factor  revenues of $43.3  million  annually  beginning in March
        2000 and a prospective surcharge to provide $24.7 million for previously
        under-recovered fuel cost beginning in April 2000.

               In July  2000  CPL  filed,  with the  PUCT,  an  application  for
        authority to implement  an increase in fuel factors  effective  with the
        September 2000 billing month.  CPL also proposed to implement an interim
        fuel  surcharge  to collect its  under-recovered  fuel costs,  including
        accumulated interest,  over a 12-month period beginning in October 2000.
        In August 2000, a settlement  was reached  between the various  parties.
        The settlement  allows CPL to increase its fuel factor by $173.5 million
        and  provides  for  a  surcharge   of  $21.3   million  for   previously
        under-recovered  fuel costs for the period from December 1, 1999 through
        May 31, 2000 and a surcharge  not to exceed $65.1  million for projected
        under-recoveries  for the period from June 2000  through  August 2000. A
        compliance  filing detailing the actual  under-recoveries  for June 2000
        through  August 2000 was made in September  2000 and was approved by the
        PUCT in November 2000. The actual under-recovery for the months of June,
        July  and  August  2000  was  $93.7  million.  As a  consequence  of the
        limitations in the Order, the remaining  under-recovery  amount of $28.6
        million is being carried forward into  subsequent fuel  surcharge/refund
        calculations.

               In August  2000 WTU  filed,  with the PUCT,  an  application  for
        authority to implement  an increase in fuel factors  effective  with the
        October 2000 billing  month.  WTU also  proposed to implement an interim
        fuel  surcharge  to collect its  under-recovered  fuel costs,  including
        accumulated interest,  over a 6-month period beginning in November 2000.
        In October 2000, a settlement was reached  between the various  parties.
        The settlement  allows WTU to increase its fuel factors by $42.6 million
        and  provides  for  a  surcharge   of  $19.6   million  for   previously
        under-recovered  fuel costs for the period from  August 1, 1999  through
        June 30,  2000. A final order from the Texas  Commission  to approve the
        settlement is pending.

               In November 2000 SWEPCo filed,  with the PUCT, an application for
        authority  to  implement  an increase  in fuel factor  revenues of $11.9
        million  effective  with the January  2001  billing  month.  SWEPCo also
        proposed to  implement  a  six-month  interim  fuel  surcharge  of $13.0
        million  for  under-recoveries  for the  period  from July 1999  through
        September 2000 beginning with the January 2001 billing month.

        Fuel Reconciliation Filing - SWEPCo

               On June 30, 2000,  SWEPCo filed with the PUCT an  application  to
        reconcile  fuel  costs  and  to  request   authorization  to  carry  the
        unrecovered balance forward into the next reconciliation  period. During
        the reconciliation  period of January 1, 1997 through December 31, 1999,
        SWEPCo  incurred  $347 million of Texas  jurisdiction  eligible fuel and
        fuel-related  expenses,  including  $4 million of carrying  costs on the
        unamortized  balance of a coal dispute settlement  payment.  Upon review
        should  the  PUCT   disallow   fuel  cost   recoveries   for  the  Texas
        jurisdiction,  it would  result in a refund or  credit  surcharge  which
        would have an adverse  effect on future  results of operations  and cash
        flows. A final order is expected in the second quarter of 2001.

9.      INDUSTRY RESTRUCTURING

            Restructuring  legislation  has been  enacted in seven of the eleven
        state retail  jurisdictions  in which the AEP domestic  electric utility
        companies  operate.  The  legislation  provides  for a  transition  from
        cost-based  regulation of bundled  electric  service to customer  choice
        market  pricing  for  the  supply  of  electricity.   The  enactment  of
        restructuring legislation and the ability to determine transition rates,
        wires  charges  and any  resultant  extraordinary  gain  or  loss  under
        restructuring  legislation  enabled  AEP  and  certain  subsidiaries  to
        discontinue  regulatory  accounting  under the  application  of SFAS 71.
        Prior to  restructuring,  the electric utility  companies  accounted for
        their  operations  according  to the  cost-based  regulatory  accounting
        principles  of SFAS 71.  Under  the  provisions  of SFAS 71,  regulatory
        assets and regulatory  liabilities  are recorded to reflect the economic
        effects of regulation and to match expenses with regulated revenues. The
        discontinuance  of the  application of SFAS 71 is in accordance with the
        provisions  of SFAS  101.  Pursuant  to  those  provisions  and  further
        guidance provided in EITF Issue 97-4, a company is required to write-off
        regulatory  assets and  liabilities  related to deregulated  operations,
        unless  recovery  of  such  amounts  is  provided  through  rates  to be
        collected  in a  portion  of  operations  which  continues  to  be  rate
        regulated.  Additionally,  a company  experiencing a  discontinuance  of
        cost-based  rate regulation is required to determine if any plant assets
        are impaired under SFAS 121. A SFAS 121 accounting  impairment  analysis
        involves  estimating  cumulative  future  non-discounted  net cash flows
        arising from the use of assets. If the cumulative  undiscounted net cash
        flows  exceed  the net  book  value  of the  assets,  then  there  is no
        impairment of the assets for accounting purposes.

            As legislative and regulatory  proceedings  evolve, the AEP electric
        operating  companies doing business in the seven states that have passed
        restructuring  legislation are applying the standards discussed above to
        discontinue SFAS 71 regulatory accounting. The following is a summary of
        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 the AEP System's seven state regulatory jurisdictions
        affected by restructuring legislation.


<PAGE>



        Virginia Restructuring - Affecting AEP and APCo

               Under 1999  Virginia  restructuring  legislation  a transition to
        choice of supplier for retail customers will commence on January 1, 2002
        and be  completed,  subject  to a finding  by the  Virginia  SCC that an
        effective  competitive  market  exists by  January 1, 2004 but not later
        than January 1, 2005. The Virginia restructuring legislation provides an
        opportunity for recovery of just and reasonable net stranded  generation
        costs.  The  mechanisms  in the Virginia law for stranded  cost recovery
        are: a capping of incumbent  utility  transition  rates until as late as
        July 1, 2007,  and the  application of a wires charge upon customers who
        may depart the  incumbent  utility in favor of an  alternative  supplier
        prior to the termination of the rate cap. The  legislation  provides for
        the  establishment  of  capped  rates  prior  to  January  1,  2001  and
        establishment  of a wires  charge by the fourth  quarter of 2001.  Since
        APCo does not intend to request new rates, its current rates will become
        the  capped  rates.  In the third  quarter  of 2000,  the  Virginia  SCC
        directed APCo to file a cost of service study using 1999 as a test year.
        In the opinion of counsel,  Virginia's restructuring law does not permit
        the Virginia SCC to change rates for the transition period.

        WV Restructuring Plan - Affecting AEP and APCo

               As discussed in the 1999 Annual Report, the WVPSC issued an order
        on January 28, 2000  approving an  electricity  restructuring  plan.  On
        March 11, 2000, the WV legislature  approved the  restructuring  plan by
        joint  resolution.  The joint resolution  provides that the WVPSC cannot
        implement the plan until the legislature makes necessary tax law changes
        to preserve  the revenues of the state and local  governments.  Electric
        service in West Virginia is provided by APCo and WPCo.

               The  provisions  of the  restructuring  plan provide for customer
        choice to begin after all  necessary  rules are in place (the  "starting
        date");  deregulation  of  generation  assets  occurring on the starting
        date;  functional   separation  of  the  generation,   transmission  and
        distribution  businesses on the starting date and their legal  corporate
        or  structural  separation  no later than  January 1, 2005; a transition
        period  of up to 13  years,  during  which the  incumbent  utility  must
        provide default service for customers who do not change suppliers unless
        an alternative  default supplier is selected  through a  WVPSC-sponsored
        bidding  process;  capped  and fixed  rates for the  13-year  transition
        period as discussed below;  deregulation of metering and billing;  a 0.5
        mills per KWH wires charge  applicable  to all retail  customers for the
        period January 1, 2001 through December 31, 2010 intended to provide for
        recovery  of  any  stranded  cost  including  net   regulatory   assets;
        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 to be used as  determined by the WVPSC to
        offset market prices paid for electricity in the eleventh,  twelfth, and
        thirteenth  year of the  transition  period  by  residential  and  small
        commercial customers that do not choose an alternative supplier.

               Default rates for residential and small commercial  customers are
        capped for four  years  after the  starting  date and then  increase  as
        specified in the plan for the next six years.  In years  eleven,  twelve
        and thirteen of the transition period, the power supply rate shall equal
        the market price of comparable  power.  Default rates for industrial and
        large commercial  customers will be discounted by 1% for four and a half
        years,  beginning July 1, 2000, and then increased at pre-defined levels
        for the next three  years.  After seven years the power  supply rate for
        industrial and large commercial  customers will be market based.  APCo's
        Joint  Stipulation  agreement,  discussed  in Note 8  above,  which  was
        approved  by the  WVPSC on June 2, 2000 in  connection  with a base rate
        filing,  also  provides  additional  mechanisms  to  recover  regulatory
        assets.

        APCo Discontinues Application of SFAS 71

               In June 2000 APCo discontinued the application of SFAS 71 for its
        Virginia  and  WV  retail  jurisdictional  portions  of  its  generation
        business  since  generation  is no longer  considered  to be  cost-based
        regulated in those  jurisdictions  and  management was able to determine
        APCo's transition rates and wires charges.  The discontinuance in the WV
        jurisdiction  was possible as a result of a June 2, 2000 approval of the
        Joint Stipulation which established  rates, wires charges and regulatory
        asset recovery  procedures during the transition period to market rates.
        APCo  was  also  able  to  discontinue  application  of  SFAS 71 for the
        generation portion of its Virginia retail  jurisdiction after management
        decided  that APCo would not request  capped  rates  different  from its
        current rates. The existence of effective  restructuring  legislation in
        Virginia  and the  probability  that  the WV  legislation  would  become
        effective with the passage of required tax legislation in 2001 supported
        management's  decision to discontinue SFAS 71 regulatory  accounting for
        APCo's electricity generation and supply business.

               APCo's  discontinuance  of SFAS 71 for generation  resulted in an
        extraordinary  gain,  in the  second  quarter  of 2000,  of $9  million.
        Management  believes that it is probable that all net regulatory  assets
        related to the Virginia and WV  generation  business  will be recovered.
        Therefore,  under the provisions of EITF 97-4, APCo's generation-related
        net regulatory  assets were transferred to the  distribution  portion of
        the  business  and are being  amortized  as they are  recovered  through
        charges  to  regulated   distribution   customers.   APCo  performed  an
        accounting  impairment  analysis on its generating assets under SFAS 121
        and concluded that there was no impairment of generation assets.

        Ohio Restructuring Law - Affecting AEP, CSPCo and OPCo

               As  discussed  in the 1999 Annual  Report,  the Ohio Act provides
        for,  among other things,  customer  choice of electricity  supplier,  a
        residential rate reduction of 5% for the generation portion of rates and
        a freezing of generation rates including fuel rates beginning on January
        1, 2001. The Ohio Act also provides for a five-year transition period to
        move from cost-based rates to market pricing for generation services. It
        authorizes the PUCO to address certain major transition issues including
        unbundling of rates and the recovery of  transition  costs which include
        regulatory  assets,  generating  asset  impairments  and other  stranded
        costs, employee severance and retraining costs, consumer education costs
        and  other  restructuring  and  transition  costs.  Stranded  costs  are
        generation  costs that are not deemed to be recoverable in a competitive
        market.




               On  September   28,   2000,   the  PUCO   approved,   with  minor
        modifications,  a stipulation  agreement  between CSPCo,  OPCo, the PUCO
        staff, the Ohio Consumers' Counsel and other concerned parties.  The key
        provisions of the stipulation agreement are:

o           Recovery of  generation-related  regulatory  assets over seven years
            for OPCo and eight years for CSPCo through frozen  transition  rates
            for the first five years of the  recovery  period and a wires charge
            for the remaining years.
o           A shopping  incentive (a price  credit) of 2.5 mills per KWH for the
            first 25% of CSPCo  residential  customers  that  switch  suppliers.
            There is no shopping incentive for OPCo customers.
o           The  absorption  of $40  million by CSPCo and OPCo ($20  million per
            company) of consumer  education,  implementation and transition plan
            filing costs with deferral of the remaining  costs,  plus a carrying
            charge,  as a regulatory  asset for recovery in future  distribution
            rates.
o           CSPCo and OPCo will make  available  a fund of up to $10  million to
            reimburse  customers who choose to purchase their power from another
            company for  certain  transmission  charges  imposed by PJM and/or a
            Midwest  ISO on  generation  originating  in the  Midwest ISO or PJM
            areas.
o           The statutory 5% reduction in the generation  component of
            residential  tariffs will remain in effect for the entire 5 year
            transition period.
o           The companies' request for a $90 million gross receipts tax rider to
            recover duplicate gross receipts tax would be considered  separately
            by the PUCO.

               The  gross  receipts  tax  issue  was  considered  by the PUCO in
        hearings held in June 2000.  In the  September 28, 2000 order  approving
        the  stipulation  agreement,  the  PUCO  determined  that  there  was no
        duplicate tax overlap period and denied the request for a gross receipts
        tax rider.  Under the Ohio Act the gross  receipts  tax will be replaced
        with a KWH based excise tax. The last year for which electric  utilities
        will pay the excise tax based on gross  receipts  is the tax year ending
        April 30, 2002. As of May 1, 2001 electric  distribution  companies will
        be  subject to an excise  tax based on KWH sold to Ohio  customers.  The
        gross receipts tax is paid at the beginning of the tax year, deferred by
        CSPCo and OPCo as a prepaid  expense and amortized to expense during the
        tax year  pursuant to the tax law whereby the payment of the tax results
        in the privilege to conduct  business in the year  following the payment
        of the tax.  The  change in the tax law to impose an excise tax based on
        KWH sold to Ohio customers commencing before the expiration of the gross
        receipts  tax  privilege  period will  result in a 12 month  period when
        CSPCo and OPCo are  recording as an expense both the gross  receipts tax
        and the  excise  tax.  CSPCo and OPCo filed for  rehearing  of the gross
        receipts  tax issue.  Unless this issue is  resolved  in the  companies'
        favor,  it will have an  adverse  effect on results  of  operations  and
        financial position from May 1, 2001 to April 30, 2002.

               Beginning January 1, 2001, fuel costs will not be subject to PUCO
        fuel  recovery  proceedings.  Deferred  fuel costs at December  31, 2000
        which  represent  under  or over  recoveries  will  be one of the  items
        included in the PUCO's final  determination of net regulatory  assets to
        be collected  during the  transition  period.  The  elimination  of fuel
        clause  recoveries  in 2001 in Ohio will subject AEP,  CSPCo and OPCo to
        the risk of fuel  market  price  increases  and could  adversely  affect
        future results of operations and cash flows beginning in 2001.

        CSPCo and OPCo Discontinue the Application of SFAS 71
        for the Ohio Jurisdiction

               In September 2000 CSPCo and OPCo  discontinued the application of
        SFAS 71 for their Ohio retail  jurisdictional  generation business since
        generation is no longer  cost-based  regulated in that  jurisdiction and
        management  was able to  determine  their  transition  rates  and  wires
        charges.  The  discontinuance in the Ohio jurisdiction was possible as a
        result of the PUCO's  September  28, 2000  approval  of the  stipulation
        agreement  which  established  rates,  wires charges and net  regulatory
        asset recovery procedures during the transition to market rates.

               CSPCo's  and  OPCo's  discontinuance  of SFAS  71 for  generation
        resulted in after tax extraordinary  losses in the third quarter of 2000
        of  $25  million  and  $19   million,   respectively,   due  to  certain
        unrecoverable   generation-related   regulatory  assets  and  transition
        expenses.  Management  believes that  substantially  all net  regulatory
        assets related to the Ohio generation business will be recovered.  Under
        the  provisions  of EITF 97-4,  CSPCo's  and  OPCo's  generation-related
        recoverable net regulatory  assets were  transferred to the transmission
        and  distribution  portion of the business and will be amortized as they
        are recovered through charges to customers.  CSPCo and OPCo performed an
        accounting impairment analysis on their generating assets under SFAS 121
        and concluded there was no impairment of generation assets.

        Arkansas Restructuring - Affecting AEP and SWEPCo

             In 1999  legislation  was enacted in Arkansas that will  ultimately
        restructure the electric utility industry. Its major provisions are:

o retail  competition begins January 1, 2002 but can be delayed until as late as
June 30, 2003 by the Arkansas  Commission;  o  transmission  facilities  must be
operated by an ISO if owned by a company which also owns  generation  assets;  o
rates will be frozen  for one to three  years;  o market  power  issues  will be
addressed by the Arkansas  Commission;  and o a progress  report to the Arkansas
General  Assembly on the development of competition in electric  markets and its
impact
             on retail customers is required by January 2001.

                  In  an  Arkansas  Commission  proceeding  to  investigate  the
        progress toward competition and what  recommendations  should be made to
        the General  Assembly,  a delay of the start date for  competition  from
        January  1, 2002 to  October  1, 2003 or as late as  October 1, 2005 was
        discussed.   Such  delay  would  require   amendments  to  the  existing
        legislation,  which  could be  requested  in the  Arkansas  Commission's
        progress  report to the  General  Assembly.  The timing of the  ultimate
        deregulation  of  SWEPCo's  generation  business  in Arkansas is unclear
        pending the  findings of the  Arkansas  Commission  and the  response to
        those findings by the Arkansas General Assembly.

        Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU

            In June 1999 the Texas Legislation was signed into law which,  among
other things:

o        gives Texas customers of investor-owned  utilities the opportunity to
         choose their electric  provider  beginning January 1,2002;
o        provides for the recovery of regulatory  assets and of other  stranded
         costs  through  securitization  and  non-bypassable wires charges;
o        requires reductions in NOx and sulfur dioxide emissions;
o        provides for a rate freeze until  January 1, 2002  followed by a 6%
         rate reduction for residential and small commercial  customers,  an
         additional rate reduction for low-income  customers and a number of
         customer protections;
o        provides  for an earnings  test for each of the three years of the rate
         freeze period (1999  through  2001);
o        provides for certain  limits for  ownership and control of generation
         capacity by companies;
o        provides for elimination of the fuel clause reconciliation process;and
o        provides for a 2004 true-up proceeding for stranded  costs  including
         final fuel  recovery  balances,  net  regulatory assets,certain
         environmental costs, accumulated excess earnings and other issues.

                  Delivery of electricity will continue 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,  a  transmission  utility and a
        distribution  utility.  In May 2000 CPL,  SWEPCo  and WTU filed  revised
        structural  separation  plans which the PUCT approved on July 7, 2000 in
        an interim order.

                  Under the Texas  Legislation,  electric utilities are allowed,
        with the  approval  of the PUCT,  to recover  stranded  costs  including
        generation-related  regulatory  assets that may not be  recoverable in a
        future competitive  market. The approved costs can be refinanced through
        securitization, which is a financing structure designed to provide state
        sponsored lower financing costs than are available through  conventional
        public utility  financings.  The  securitized  amounts plus interest are
        then recovered through a non-bypassable wires charge.

                  In 1999 CPL filed an  application  with the PUCT to securitize
        approximately $1.27 billion of its retail generation-related  regulatory
        assets and  approximately  $47 million in other qualified  restructuring
        costs. On February 10, 2000, the PUCT tentatively approved a settlement,
        which will permit CPL to  securitize  approximately  $764 million of net
        regulatory  assets.  The PUCT's order authorized  issuance of up to $797
        million of securitization  bonds including the $764 million for recovery
        of net regulatory assets and $33 million for other qualified refinancing
        costs.  The $764 million for recovery of net regulatory  assets reflects
        the recovery of $949 million of regulatory assets offset by $185 million
        of customer benefits associated with accumulated  deferred income taxes.
        CPL had previously proposed in its filing to flow these benefits back to
        customers  over  the  14-year  term  of the  securitization  bonds.  The
        remaining  regulatory  assets  originally  included  by CPL in its  1999
        securitization  request  were  included  in a March 2000 filing with the
        PUCT,  requesting  recovery of an  additional  $1.1  billion of stranded
        costs.  The March  2000  filing of $1.1  billion  included  recovery  of
        approximately $800 million of STP costs included in utility plant on the
        balance sheet of CPL and in property,  plant and  equipment-electric  on
        the balance sheet of AEP Consolidated. The STP costs had previously been
        identified as ECOM by the PUCT for regulatory  purposes.  The March 2000
        filing  will  determine  the  initial  amount  of  stranded  costs to be
        recovered  beginning  January 1, 2002. The PUCT required CPL to submit a
        revised filing using an administrative model developed by the PUCT Staff
        which reduced the amount of the initial stranded costs estimates to $361
        million.  Management  does not agree  with the  critical  inputs to this
        model. A final  determination  of stranded costs and their recovery will
        occur  as  part  of  the  2004  true-up  proceeding.  The  total  amount
        recoverable can be securitized.

                  On  April  11,  2000,   four   parties   appealed  the  PUCT's
        securitization  order to the Travis County District Court.  One of these
        appeals challenges CPL's ability to recover securitization charges under
        the Texas Constitution. CPL will not be able to issue the securitization
        bonds until these appeals are resolved.

                  The Texas Legislation  provides that each year during the 1999
        through 2001 rate freeze  period,  electric  utilities are subject to an
        earnings test. For electric  utilities with stranded costs, such as 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.  Utilities
        without  stranded  costs,  such as SWEPCo and WTU, must either flow such
        excess earnings  amounts back to customers or make capital  expenditures
        to improve  transmission  or  distribution  facilities or to improve air
        quality.  The Texas  Legislation  requires PUCT approval of the earnings
        test calculation.

                  Regarding the 1999 earnings  test,  CPL,  SWEPCo and WTU filed
        reports  showing  excess  earnings of $21 million,  $1 million and zero,
        respectively.  The PUCT Staff  issued its report on the excess  earnings
        calculations  filed by CPL,  SWEPCo  and WTU and  calculated  the excess
        earnings amounts to be $41 million,  $3 million and $11 million for CPL,
        SWEPCo and WTU,  respectively.  Management  has  recorded  an  estimated
        provision  for 1999 excess  earnings  and does not expect that the final
        resolution of 1999 excess earnings will have a material effect on future
        results of operations.  CPL and WTU also recorded an estimated provision
        for excess 2000  earnings of $9 million per company in the third quarter
        of 2000.
                  A Texas  settlement  agreement in connection  with the AEP and
        CSW  merger  permits  CPL to apply  for  regulatory  purposes  up to $20
        million  of STP ECOM  plant  assets  a year in 2000  and 2001 to  reduce
        excess earnings,  if any. For book purposes,  STP ECOM plant assets will
        be  depreciated  in accordance  with GAAP, on a systematic  and rational
        basis unless impaired.  To the extent excess earnings exceed $20 million
        in 2000 or 2001 CPL will  establish  a  regulatory  liability  or reduce
        regulatory assets by a charge to earnings.

                 Beginning  January 1,  2002,  fuel costs will not be subject to
        PUCT fuel reconciliation proceedings.  Consequently, CPL, SWEPCo and WTU
        will file a final fuel  reconciliation  with the PUCT  which  reconciles
        their fuel costs  through the period  ending  December 31,  2001.  These
        final fuel  balances  will be included in each  company's  2004  true-up
        proceeding.  The  elimination  of the fuel clause  recoveries in 2002 in
        Texas will subject AEP,  CPL,  SWEPCo and WTU to the risk of fuel market
        price increases and could adversely  affect future results of operations
        beginning in 2002.

        Discontinuance of the Application of SFAS 71 for Arkansas and Texas

                  The  financial   statements  of  CPL,   SWEPCo  and  WTU  have
        historically  reflected  the economic  effects of regulation by applying
        the  requirements of SFAS 71. As a result of the scheduled  deregulation
        of generation in Arkansas and Texas,  the application of SFAS 71 for the
        generation  portion of the business in those states was  discontinued in
        the third  quarter of 1999.  Under the  provisions  of EITF 97-4,  CPL's
        generation-related   net  regulatory  assets  were  transferred  to  the
        distribution  portion of the  business and will be amortized as they are
        recovered  through  charges  to  customers.   Management  believes  that
        substantially all of CPL's  generation-related  regulatory assets should
        be   recovered   under  the  Texas   Legislation.   CPL's   recovery  of
        generation-related regulatory assets and stranded costs are subject to a
        final  determination  by the PUCT in 2004. If future events were to make
        the recovery of generation-related regulatory assets no longer probable,
        CPL  would  write-off  the  portion  of such  regulatory  assets  deemed
        unrecoverable as a non-cash extraordinary charge to earnings.

                  The Texas  Legislation  provides  that all finally  determined
        stranded costs will be recovered.  Since SWEPCo and WTU are not expected
        to have net stranded costs, all generation-related net regulatory assets
        were written off as  non-recoverable  in the third  quarter of 1999 when
        they  discontinued  application  of SFAS 71  regulatory  accounting.  An
        impairment  analysis for generation  assets under SFAS 121 was completed
        for  CPL,  SWEPCo  and  WTU  which  concluded  there  was no  accounting
        impairment  of  generation  assets when the  application  of SFAS 71 was
        discontinued.  CPL, SWEPCo and WTU will test their generation assets for
        impairment under SFAS 121 when circumstances change. Management believes
        that on a discounted  basis CPL's cash flows will  probably be less than
        its   generating   assets'  net  book  value  and   together   with  its
        generation-related   regulatory   assets  should  create  a  recoverable
        stranded  cost for  regulatory  purposes  under the  Texas  Legislation.
        Therefore,  management  continues  to carry on  CPL's  balance  sheet at
        September 30, 2000, $953 million of regulatory  assets already  approved
        for  securitization  and $194 million of net  regulatory  assets pending
        approval for securitization.  A final determination of whether they will
        be securitized will be made as part of the 2004 true-up proceeding.

             CPL, SWEPCo, and WTU continue to analyze the impact of the electric
        utility  industry  restructuring  legislation  on their  Texas  electric
        operations.  Although  management  believes  that the Texas  Legislation
        provides for full  recovery of stranded  costs and that the companies do
        not have a recordable  accounting  impairment,  a final determination of
        whether CPL will experience an accounting loss or whether SWEPCo and WTU
        will  experience  any  additional  accounting  loss from an inability to
        recover  generation-related  regulatory  assets and other  restructuring
        related  costs in Texas and  Arkansas  cannot be made until such time as
        the  litigation and the  regulatory  process are complete  following the
        2004 true-up  proceeding.  In the event CPL, SWEPCo,  and WTU are unable
        after the 2004 true-up  proceeding  to recover all or a portion of their
        generation-related   regulatory   assets,   stranded   costs  and  other
        restructuring  related costs, it could have a material adverse effect on
        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 has less than
        one million customers in Michigan. Consequently, I&M was not immediately
        required to comply with the Michigan Legislation.

               The following is the stated purpose of the Michigan Legislation:

o        Allow all retail customers a choice of electric suppliers;
o        Encourage MPSC to foster competition;
o        Provide protection to customers who remain with their incumbent
             supplier;
o        Diversify ownership of electric generation;
o        Ensure the availability of safe, reliable electric power at
             reasonable rates; and
o        Improve economic development opportunities.

                  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.   On  October  2,  2000,  I&M  filed  a  restructuring
        implementation  plan as required by a MPSC  order.  The plan  identifies
        I&M's  proposal  to file  with  the MPSC on June 5,  2001 its  unbundled
        rates, open access tariffs,  terms of service and supporting  schedules.
        Described  in  the  plan  are  I&M's   intentions  and  preparation  for
        competition  related to supplier  transactions,  customer  transactions,
        rate  unbundling,   education   programs,   and  regional   transmission
        organization.  I&M  proposes a  methodology  to  determine  stranded and
        implementation costs and requests the continuation of a wires charge for
        nuclear   decommissioning   costs.   Approval   of   the   restructuring
        implementation plan is pending before the MPSC.

                  Management  has  concluded  that as of September  30, 2000 the
        requirements  to apply SFAS 71  continue to be met since I&M's rates for
        generation in Michigan will  continue to be cost-based  regulated  until
        the MPSC approves rates and wires charges in 2001. The  establishment of
        rates and  wires  charges  under a MPSC  approved  transition  plan will
        enable  management  to determine the ability to recover  stranded  costs
        including   regulatory   assets  and  other   implementation   costs,  a
        requirement to discontinue the application of SFAS 71.

                  Upon the  discontinuance  of SFAS 71, I&M will,  if necessary,
        have  to  write  off  its  Michigan  jurisdictional   generation-related
        regulatory  assets to the extent that they cannot be recovered under the
        transition  rates and wires  charges  and  record  any asset  accounting
        impairments in accordance with SFAS 121.

                  The  amount  of  regulatory  assets  recorded  on the books at
        September 30, 2000  applicable to I&M's Michigan  retail  jurisdictional
        generation  business is  approximately  $45 million  before  related tax
        effects.  Based on  management's  current  projections  of rates,  wires
        charges and future market prices,  management  does not anticipate  that
        I&M will experience any material tangible asset accounting impairment or
        regulatory  asset  write-offs.  Ultimately,  however,  whether  I&M will
        experience  material  regulatory asset write-offs will depend on whether
        the MPSC approves their recovery in future orders.

                  A  determination  of  whether  I&M will  experience  any asset
        impair-ment loss regarding its Michigan retail jurisdictional generating
        assets  and any loss  from a  possible  inability  to  recover  Michigan
        generation-related  regulatory  assets and other transition costs cannot
        be  made  until  such  time  as the  rates  and the  wires  charges  are
        determined through the regulatory process. In the event I&M is unable to
        recover all or a portion of its  generation-related  regulatory  assets,
        stranded costs and other implementation  costs, it could have a material
        adverse  effect on  results  of  operations,  cash  flows  and  possibly
        financial condition.

         Oklahoma Restructuring - Affecting AEP and PSO

                  In  1997,  the  Oklahoma   Legislature  passed   restructuring
         legislation   providing  for  retail  access  by  July  1,  2002.  That
         legislation called for a number of studies to be completed on a variety
         of  restructuring   issues,   including  independent  system  operator,
         technical,  financial,  transition and consumer issues. During 1998 and
         1999 several of the studies were completed.
                  The  information  from the studies was  expected to be used in
         the development of additional industry restructuring legislation during
         the 2000 legislative session.

                  Several additional electric industry  restructuring bills were
         filed in the 2000  Oklahoma  Legislative  session.  The proposed  bills
         generally   supplemented   the   industry   restructuring   legislation
         previously  enacted in Oklahoma which lacked specific  procedures for a
         transition   to  market   based   competitive   prices.   The  industry
         restructuring  legislation  previously  passed  did  not  delegate  the
         establishment  of  transition  procedures  to the Oklahoma  Corporation
         Commission.  The 2000  Oklahoma  legislative  session  adjourned in May
         without  passing  further   restructuring   legislation  and  will  not
         reconvene until 2001.

                  Management  has  concluded  that as of September  30, 2000 the
        requirements  to apply SFAS 71  continue to be met since PSO's rates for
        generation in Oklahoma will  continue to be cost-based  regulated  until
        the Oklahoma Legislature approves further restructuring  legislation and
        transition  rates and wires  charges are  established  under an approved
        transition  plan.  Until  management is able to determine the ability to
        recover  stranded  costs  which  includes  regulatory  assets  and other
        implementation  costs,  PSO cannot  discontinue  application  of SFAS 71
        accounting under GAAP.

                  Upon the  discontinuance  of SFAS 71, PSO will,  if necessary,
        have  to  write  off  its  Oklahoma  jurisdictional   generation-related
        regulatory  assets to the extent that they cannot be recovered under the
        transition  rates and wires  charges,  when  determined,  and record any
        asset accounting impairments in accordance with SFAS 121.

                  A  determination  of  whether  PSO will  experience  any asset
        impairment loss regarding its Oklahoma retail jurisdictional  generating
        assets  and any loss  from a  possible  inability  to  recover  Oklahoma
        generation-related  regulatory  assets and other transition costs cannot
        be  made  until  such  time  as the  rates  and the  wires  charges  are
        determined through the legislative or regulatory  process.  In the event
        PSO is unable to  recover  all or a  portion  of its  generation-related
        regulatory assets and implementation costs, Oklahoma restructuring could
        have a material adverse effect on results of operations and cash flows.

10.     BUSINESS SEGMENTS
        -----------------

               AEP's principal business segment is its cost-based rate regulated
        Domestic  Electric  Utility  business  consisting  of  eleven  regulated
        utility operating companies providing bundled, generation,  distribution
        and transmission  electric  services in eleven states.  Also included in
        this segment are AEP's  electric power  wholesale  marketing and trading
        activities  conducted within two transmission  systems of the AEP System
        that are conducted as part of regulated  operations  and subject to cost
        of service rate regulation.



               The AEP consolidated income statement caption  "Revenues-Domestic
        Electric  Utilities"  includes  both the retail and  wholesale  domestic
        electricity  supply  businesses  which are cost-based  rate regulated in
        Kentucky, Indiana, Michigan,  Louisiana,  Oklahoma and Tennessee and are
        in the process of  transitioning  to market  based  pricing in Arkansas,
        Ohio,  Texas,  WV and  Virginia.  Since the  domestic  electric  utility
        companies have not yet structurally separated their retail and wholesale
        electricity  supply business from their regulated  distribution  service
        business,  separate  financial  data is not  available  and the Domestic
        Electric Utilities business will continue to be reported as one business
        segment which is the only reportable  segment for the domestic  electric
        operating subsidiaries.

               The AEP consolidated income statement caption "Revenues-Worldwide
        Electric and Gas  Operations"  includes three  segments:  Foreign Energy
        Delivery,  Worldwide  Energy  investments and other.  The Foreign Energy
        Delivery segment includes investments in overseas electric  distribution
        and supply  companies  (Seeboard and Yorkshire in the U.K. and CitiPower
        in  Australia).  The Worldwide  Energy  Investments  segment  represents
        domestic  and  international   investments  in  energy-related  gas  and
        electric  projects  including the  development  and  management of those
        projects.  Such investment  activities include electric generation,  and
        natural gas pipeline, storage and other natural gas services.

               The other  segment which is included in AEP  consolidated  income
        statement as part of  Worldwide  Electric  and Gas  Operations  includes
        non-regulated  electric trading activities outside of AEP marketing area
        (beyond  two  transmission  systems  from the AEP  System)  gas  trading
        activities,  telecommunication  services,  and the  marketing of various
        energy related products and services.
<TABLE>
<CAPTION>

               Financial data for what has been AEP's four business segments for
        the  nine  months  ending  September  30,  2000 and 1999 is shown in the
        following table:
    <S>                           <C>          <C>        <C>          <C>            <C>         <C>
                                  Domestic     Foreign    Worldwide
                                  Electric     Energy     Energy                   Reconciling    AEP
                                  Utilities*   Delivery   Investments    Other     Adjustments    Consolidated
      September 30, 2000                                           (in millions)
         Revenues from

          external customers      $ 8,124      $1,429     $  620       $  (39)        $  -        $10,134
          transactions with other
          operating segments         -                        80          269          (349)         -
         Segment net income (loss)    430         114        (18)         (37)           -            489
         Total assets              28,182       4,288      2,739        5,309            -         40,518
      September 30, 1999
         Revenues from
          external customers        7,567       1,447        407           (8)           -          9,413
          transactions with other
          operating segments         -                        45          146          (191)         -
         Segment net income (loss)    713          88         10          (32)           -            779
         Total assets              25,754       4,716      2,532        1,914            -         34,916

        *  Includes  the  domestic   generation   retail  and  wholesale  supply
        businesses  a  significant  portion of which is  undergoing a transition
        from  regulated  cost based bundled rates to open access market  pricing
        but which have not yet been unbundled i.e.,  structurally separated from
        the distribution and transmission  portions of the vertically integrated
        electric utility business.
</TABLE>


               In October 2000,  management announced its intent to structurally
        separate its  operations  into two business  segments,  a  non-regulated
        business  and a  regulated  business.  Separation  of its  non-regulated
        generation  business from its regulated bundled generation  distribution
        and  transmission  businesses  will not be complete  until the  electric
        operating  subsidiaries  have completed their structural  separation and
        made the  necessary  changes  to their  accounting  software,  books and
        records.

11.     SOUTH AMERICAN INVESTMENTS
        --------------------------

                CSW  International  owns  a  44%  equity  interest  in  Vale,  a
        Brazilian  electric operating company which it had purchased for a total
        of $149 million.  The investment is covered by a put option,  which,  if
        exercised, requires CSW International's partners in Vale to purchase CSW
        International's  Vale shares at a minimum price equal to the U.S. dollar
        equivalent  of  CSW   International's   purchase  price.  As  a  result,
        management has concluded that CSW  International's  investment  carrying
        amount  will not be  reduced  below the put  option  value  unless it is
        deemed to be a permanent impairment and CSW International's  partners in
        Vale are deemed unable to fulfill their  responsibilities  under the put
        option.   Vale  has   experienced   losses  from   operations   and  CSW
        International's  investment has been affected by the  devaluation of the
        Brazilian  Real. CSW  International's  cumulative  equity share of these
        operating and foreign currency  translation losses through September 30,
        2000 are approximately $28 million,  net of tax, and $32 million, net of
        tax, respectively.  Pursuant to the put option arrangement, these losses
        are  not  reflected  in  the  carrying  value  of the  Vale  investment.
        Conversely,  CSW  International  will not recognize any future  earnings
        from Vale until the operating losses are recovered.

                As of September 30, 2000,  CSW  International  had invested $110
        million in the stock of a Chilean  electric  company.  The investment is
        classified  as  securities  available  for sale and as such  changes  in
        market value that are deemed to be temporary  and foreign  exchange rate
        changes  are  reflected  in other  comprehensive  income.  In the second
        quarter of 2000  management  determined that the decline in market value
        of the shares was other than temporary.  As a result a write down of $33
        million ($21 million  after tax) to market was recorded in June 2000 and
        is included in worldwide electric and gas expenses. Based on the quarter
        end foreign  exchange rate, the value of the investment at September 30,
        2000 was $53 million. The decline in foreign exchange rates has resulted
        in a  cumulative  loss of $19  million  ($12  million  after  tax) as of
        September 30, 2000 which is included in other comprehensive income.

12.     CONTINGENCIES

        COLI Litigation - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo

               As  discussed in the 1999 Annual  Report,  the  deductibility  of
        certain  interest  deductions  related  to COLI for  taxable  years 1991
        through 1996 is under review by the IRS.  Adjustments  have been or will
        be  proposed  by  the  IRS  disallowing  COLI  interest  deductions.   A
        disallowance of the COLI interest  deductions through September 30, 2000
        would reduce AEP  Consolidated  earnings by  approximately  $319 million
        (including   interest).   Potential  earnings  reductions  for  affected
        registrant subsidiaries are as follows:

                                     (in millions)
               APCo                      $ 79
               CSPCo                       43
               I&M                         66
               KPCo                         8
               OPCo                       118

               AEP and its  subsidiaries  made  payments  of taxes and  interest
        attributable to COLI interest  deductions for taxable years 1991 through
        1998 to avoid the  potential  assessment by the IRS of above market rate
        interest on the contested  amount.  The payments to the IRS are included
        on the  AEP  Consolidated  balance  sheet  in  other  assets  and on the
        subsidiaries'  balance sheets in other property and investments  pending
        the resolution of this matter.  The companies are seeking refunds of all
        amounts paid plus interest through litigation.

               In order to resolve this issue,  AEP and its  subsidiaries  filed
        suit in 1998 against the United  States in the U.S.  District  Court for
        the Southern  District of Ohio.  The trial began on October 30, 2000. In
        1999 a  U.S.  Tax  Court  judge  decided  in the  Winn-Dixie  Stores  v.
        Commissioner  case that a corporate  taxpayer's COLI interest  deduction
        should be  disallowed.  In October  2000, a judge for the U.S.  District
        Court for  Delaware  reached  a similar  decision  in  Internal  Revenue
        Service vs. C.M. Holdings, Inc. Notwithstanding the Tax Court's and U.S.
        District  Court's  decisions,  management  has made no provision for any
        possible  adverse  earnings impact from this matter because it believes,
        and has been  advised  by  outside  counsel,  that it has a  meritorious
        position  and is  vigorously  pursuing  its  lawsuit.  In the  event the
        resolution  of this  matter  is  unfavorable,  it will  have a  material
        adverse  impact on  results  of  operations,  cash  flows  and  possibly
        financial condition.

        Shareholders' Litigation - Affecting AEP

               On June 23,  2000,  a  complaint  was filed in the U.S.  District
        Court  for  the  Eastern  District  of  New  York  seeking   unspecified
        compensatory  damages  against AEP and four former or present  officers.
        The individual  plaintiff also seeks certification as the representative
        of a class  consisting  of all persons and  entities  who  purchased  or
        otherwise  acquired AEP common stock between July 25, 1997, and June 25,
        1999.  The  complaint  alleges that the  defendants  knowingly  violated
        federal securities laws by disseminating materially false and misleading
        statements  concerning,  among other things, the undisclosed  materially
        impaired  condition  of the Cook  Plant,  AEP's  inability  to  properly
        monitor,  manage, repair, supervise and report on operations at the Cook
        Plant and the materially  adverse conditions these problems were having,
        and would continue to have, on AEP's deteriorating  financial condition,
        and  ultimately on AEP's  operations,  liquidity  and stock price.  Four
        other similar class action  complaints have been filed and the court has
        consolidated  the five  cases.  The  plaintiffs  are  required to file a
        consolidated  complaint  pursuant to this court order.  The  defendants'
        motion to transfer this case to the U.S. District Court for the Southern
        District of Ohio was granted on  November 3, 2000.  Management  believes
        these  shareholder  actions are without merit and intends to oppose them
        vigorously.




        Municipal Franchise Fee Litigation - Affecting AEP and CPL

               CPL has been involved in litigation regarding municipal franchise
        fees in Texas as a result of a class  action  suit  filed by the City of
        San  Juan,  Texas in 1996.  The City of San Juan  claims  CPL  underpaid
        municipal  franchise  fees and seeks  damage of up to $300  million plus
        attorney's  fees. CPL filed a counterclaim  for overpayment of franchise
        fees.

               During  1997,  1998 and 1999 the  litigation  moved  procedurally
        through  the  Texas  Court  System  and was  sent to  mediation  without
        resolution.

               In 1999 a class notice was mailed to each of the cities served by
        CPL. Over 90 of the 128 cities  declined to  participate in the lawsuit.
        However,  CPL  has  pledged  that  if any  final,  non-appealable  court
        decision  in  the  litigation  awards  a  judgement  against  CPL  for a
        franchise underpayment, CPL will extend the principles of that decision,
        with regard to the franchise  underpayment,  to the cities that declined
        to participate in the litigation. In December 1999, the court ruled that
        the class of plaintiffs  would  consist of  approximately  30 cities.  A
        trial date for June 2001 has been set.

               Although management believes that it has substantial  defenses to
        the  cities'  claims and  intends to defend  itself  against the cities'
        claims  and  pursue  its  counterclaims  vigorously,  management  cannot
        predict  the  outcome  of this  litigation  or its  impact on results of
        operations, cash flows or financial condition.

        Texas Base Rate Litigation - Affecting AEP and CPL

               In  November  1995 CPL filed with the PUCT a request to  increase
        its retail base rates by $71 million.  In October 1997 the PUCT issued a
        final order which  lowered CPL's annual retail base rates by $19 million
        from the rate  level  which  existed  prior to May  1996.  The PUCT also
        included a "glide path" rate  methodology in the final order pursuant to
        which annual rates were reduced by $13 million beginning May 1, 1998 and
        an additional reduction of $13 million on May 1, 1999.

               CPL appealed the final order to the Travis  District  Court.  The
        primary  issues  being  appealed  include:  the  classification  of $800
        million  of  invested  capital in STP as ECOM and  assigning  it a lower
        return on equity than other generation  property;  the use of the "glide
        path" rate reduction  methodology;  and an $18 million  disallowance  of
        billings from an  affiliate,  CSW  Services.  CPL has a 25.2%  ownership
        interest  in  STP.  As  part  of the  appeal,  CPL  sought  a  temporary
        injunction to prohibit the PUCT from  implementing the "glide path" rate
        reduction  methodology.  The  temporary  injunction  was  denied and the
        "glide path" rate reduction was implemented. In February 1999 the Travis
        District  Court  affirmed  the PUCT  order in regard to the three  major
        items discussed above.

                  CPL appealed the Travis District Court's findings to the Texas
         Appeals  Court  which in July 2000,  issued its opinion  upholding  the
         Travis District Court except for the disallowance of affiliated service
         company  billings.   Under  Texas  law,  specific  findings   regarding
         affiliate  transactions  must  be  made  by  PUCT.  In  regards  to the
         affiliate  expense issue, the findings were not complete in the opinion
         of the Texas Appeals Court who remanded the issue back to PUCT.

                  CPL has  sought  a  rehearing  of the  Texas  Appeals  Court's
         opinion.  The Texas Appeals Court has requested briefs related to CPL's
         rehearing  request from  interested  parties.  Management  is unable to
         predict  the  final  resolution  of  its  appeal.   If  the  appeal  is
         unsuccessful it will continue to adversely affect results of operations
         and cash flows.

                  As part of the AEP/CSW  merger  approval  process in Texas,  a
         stipulation  agreement was approved which resulted in the withdrawal of
         the  appeal  related to the "glide  path"  rate  methodology.  CPL will
         continue its appeal of the ECOM classification for STP property and the
         disallowed affiliated billings.

         Lignite Mining Agreement Litigation - Affecting SWEPCo

               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.  In 1982,  SWEPCo and CLECO entered into a
         lignite mining  agreement  with DHMV, a partnership  for the mining and
         delivery of lignite from a portion of these reserves.

               In April  1997,  SWEPCo and CLECO sued DHMV and its  partners  in
         U.S.  District Court for the Western  District of Louisiana  seeking to
         enforce various obligations of DHMV under the lignite mining agreement,
         including  provisions  relating  to the quality of  delivered  lignite,
         pricing,  and mine reclamation  practices.  In June 1997, DHMV filed an
         answer  denying the  allegations  in the suit and filed a  counterclaim
         asserting  various  contract-related  claims  against SWEPCo and CLECO.
         SWEPCo  and  CLECO  have  denied  the  allegations   contained  in  the
         counterclaims.  In January  1999,  SWEPCo and CLECO  amended the claims
         against DHMV to include a request that the lignite mining  agreement be
         terminated.

               In April 2000,  the parties agreed to settle the  litigation.  As
         part of the settlement,  DHMV's  interest in the mining  operations and
         related  debt and other  obligations  will be  purchased  by SWEPCo and
         CLECO.  The closing date for the  settlement is December 31, 2000.  The
         litigation  has been stayed until January 2001 to give the parties time
         to consummate the settlement agreement.

               Management  believes that the  resolution of this matter will not
         have a  material  effect  on  results  of  operations,  cash  flows  or
         financial condition.

         Federal EPA  Complaint and Notice of Violation - Affecting  AEP,  APCo,
CSPCo, I&M, KPCo and OPCo

               As discussed in the 1999 Annual  Report,  the AEP System has been
        involved in litigation regarding generating plant emissions.  Notices of
        Violation  were issued and a  complaint  was filed by Federal EPA in the
        U.S. District Court that alleges the AEP System and eleven  unaffiliated
        utilities  made  modifications  to generating  units at certain of their
        coal-fired  generating  plants over the course of the past 25 years that
        extended unit  operating  lives or increased  unit  generating  capacity
        without a preconstruction  permit in violation of the Clean Air Act. The
        complaint  was  amended in March  2000 to add  allegations  for  certain
        generating  units  previously  named  in the  complaint  and to  include
        additional  AEP System  generating  units  previously  named only in the
        Notices of  Violation  in the  complaint.  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.

               A number of northeastern and eastern states were granted leave to
        intervene in the Federal  EPA's action  against the AEP System under the
        Clean Air Act. A lawsuit  against  power  plants owned by the AEP System
        alleging  similar  violations  to those in the Federal EPA complaint and
        Notices of Violation  was filed by a number of special  interest  groups
        and has been consolidated with the Federal EPA action.

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

               On May 10, 2000,  the AEP System filed  motions to dismiss all or
        portions of the  complaints.  Briefing on these motions was completed on
        August  2,  2000.  Management  believes  its  maintenance,   repair  and
        replacement  activities  were in  conformity  with the Clean Air Act and
        intends to vigorously pursue its defense of this matter.

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

        NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo
and SWEPCo

               As discussed in the 1999 Annual Report,  Federal EPA issued a NOx
        rule that requires substantial reductions in NOx emissions in 22 eastern
        states,  including  certain states in which the AEP System's  generating
        plants are located. A number of utilities,  including certain AEP System
        companies,  filed  petitions  seeking a review of the final  rule in the
        D.C.  Circuit  Court.  In March 2000,  the D.C.  Circuit  Court issued a
        decision generally upholding the NOx rule. The D.C. Circuit Court issued
        an order in August 2000 which extends the final  compliance  date to May
        31, 2004. In September 2000 following  denial by the D.C.  Circuit Court
        of a request for rehearing, the industry petitioners,  including the AEP
        System companies, petitioned the U.S. Supreme Court for review.

               In a related  matter,  on April 19,  2000,  TNRCC  adopted  rules
        requiring significant  reductions in NOx emissions from utility sources,
        including CPL and SWEPCo. The rule's compliance date is May 2003 for CPL
        and 2005 for SWEPCo.  The rule is being  challenged in state court by an
        unaffiliated utility.

               In June 2000 OPCo  announced that it was beginning a $175 million
        installation of selective catalytic reduction technology (expected to be
        operational  in 2001) to reduce NOx  emissions on its two-unit  2,600 MW
        Gavin Plant.

               Preliminary  estimates indicate that compliance with the NOx rule
        upheld by the D.C.  Circuit Court as well as  compliance  with the TNRCC
        rule could result in required capital expenditures of approximately $1.6
        billion for AEP Consolidated.  Estimated  compliance costs by registrant
        subsidiary company are as follows:

                                       (in millions)
               AEGCo                      $125
               APCo                           365
               CPL                          57
               CSPCo                       136
               I&M                         202
               KPCo                        106
               OPCo                        624
               SWEPCo                       28

               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  through  regulated rates and/or future market prices for
        electricity  where generation is deregulated,  they will have an adverse
        effect  on  future  results  of  operations,  cash  flows  and  possibly
        financial condition.

        Other

               AEP,  AEGCo,  APCo,  CSPCo,  I&M,  KPCo and OPCo  continue  to be
        involved in certain other matters discussed in their 1999 Annual Report.

               CPL, PSO, SWEPCo and WTU continue to be involved in certain other
matters discussed in their 1999 Form 10-K.


<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 subsidiary  registrants.  Management's discussion and analysis of
results of operations  for AEP and each of its  subsidiary  registrants  for the
third  quarter  and nine  months  ended  September  30 is  presented  with their
financial statements earlier in this document.
FINANCIAL CONDITION
        Total plant and  property  additions  including  capital  leases for the
year-to-date period were $1.3 billion for AEP Consolidated.  The following table
shows the additions by certain AEP subsidiary registrants.
        Company                     Amount
        -------                     ------
                                (in millions)
        APCo                        $144
        CPL                          137
        I&M                          149
        OPCo                         155
        PSO                          120
        SWEPCo                        92
        WTU                           44
        During  the first  nine  months  of 2000 AEP  Consolidated  issued  $951
million of  long-term  obligations  at variable  interest  rates,  retired  $1.4
billion of long-term  debt with  interest  rates  ranging from 5.25% to 8.4% and
increased  short-term  debt by $1.4 billion  from 1999  year-end  balances.  The
following  table  shows  the debt  issuances  and  retirements  by  certain  AEP
subsidiary registrants:
                Security     Interest         Due
Company       Type         Rate           Date      Amount
-------     --------     --------         ----      ------
                            (%)                 (in millions)
Issuances:
        APCo      UN         Variable          2001      $ 75
        CPL       UN         Variable          2002       150
        I&M       UN         Variable          2002       200
        OPCo      UN         Variable          2001        75
        SWEPCo    UN         Variable          2002       150
Retirements:
        APCo      IPC        7.40              2014        30
        APCo      FMB        6.35              2000        48
        APCo      FMB        6.71              2000        48
        CPL       FMB        7-1/2             2020        50
        CPL       FMB        6                 2000       100
        I&M       FMB        6.40              2000        48
        OPCo      MTN        6.24              2008        13
        PSO       MTN        6.43              2000        10
        SWEPCo    FMB        5.25              2000        45
        WTU       FMB        7-1/2             2000        40
        The AEP  System  companies  have  in the  past,  and may in the  future,
acquire   outstanding  debt  and  preferred  stock  securities  in  open  market
transactions.
        During the second  quarter  the AEP System  established  a Money Pool to
coordinate short-term borrowings for certain of its subsidiaries,  primarily the
U.S. domestic electric utility operating  companies.  The operation of the Money
Pool is  designed  to match on a daily basis the  available  cash and  borrowing
requirements  of the  participants,  thereby  minimizing the need for borrowings
from external  sources.  The daily cash positions of the participants are netted
and if  there is a  deficiency  in  cash,  AEP  raises  funds  through  external
borrowing  to meet the Money  Pool's  needs.  If there is a net  excess in cash,
external  borrowings  are paid  down,  or, if there are no  external  borrowings
maturing, the excess funds are invested.
        AEP Credit,  Inc.  factors  electric  customer  accounts  receivable for
affiliated  operating  companies and  unaffiliated companies.  AEP Credit,  Inc.
issues  commercial  paper on a stand alone basis and does not  participate in
the Money Pool. In June 2000 the  factoring of customer  accounts  receivable
for  affiliated  companies was expanded as a result of the merger with CSW to
include I&M and OPCo.  AEP Credit, Inc. was formerly known as CSW Credit.
        The  shutdown  of the Cook Plant and the  related  costs to restart  its
units  contributed to the reduction in I&M's retained earnings to $76 million at
September 30, 2000. Unless approval is received from the SEC under the PUHCA and
the FERC under the Federal Power Act, I&M can only pay dividends out of retained
earnings on its  outstanding  common  stock held by its parent,  AEP, and on its
publicly held  outstanding  preferred  stock. In the event I&M has  insufficient
retained earnings to make preferred  dividend  payments,  management  intends to
seek SEC and FERC approval to make preferred  dividend  payments out of its $733
million of capital surplus.  Failure to obtain such approvals would restrict for
some period of time the  ability of I&M to make  preferred  and common  dividend
payments.  Mortgage  indentures,  charter  provisions  and orders of  regulatory
authorities  place various  restrictions on the use of retained earnings for the
payment of cash dividends on I&M's common stock.  As of September 30, 2000, $5.9
million of I&M's retained earnings were so restricted.



OTHER MATTERS
Cook Plant Shutdown - AEP, I&M

        As discussed in the 1999 Annual Report,  the Cook Plant was shut down in
September  1997 due to questions  regarding the  operability  of certain  safety
systems that arose during a NRC architect engineer design inspection.
        On July 5, 2000, Cook Plant Unit 2, the first unit scheduled to restart,
        reached 100% power completing its restart process. On July 26, 2000, I&M
        announced that the restart of Cook Plant Unit 1 would cost an additional
        $145 million and is
scheduled to occur in the first quarter of 2001.  However,  unforeseen issues or
difficulties encountered in preparing Unit 1 for restart could potentially delay
its return to service.
        Expenditures to restart the Cook Plant units had been estimated to total
approximately $574 million. The additional $145 million to restart Unit 1 raises
the total estimate to $719 million. Through September 30, 2000, $592 million has
been spent to restart the units.  For the nine months ended  September 30, 2000,
restart costs of $249 million were recorded in other  operation and  maintenance
expense,  including  amortization  of $30  million of restart  costs  previously
deferred in accordance  with  settlement  agreements in the Indiana and Michigan
retail  regulatory  jurisdictions.  Also pursuant to the settlement  agreements,
accrued  fuel-related  revenues  of $28  million  were  amortized  in  2000.  At
September  30,  2000,  deferred  restart  costs  of  $130  million  remained  in
regulatory  assets to be amortized  through 2003.  Also deferred as a regulatory
asset at  September  30, 2000 are $122  million of  fuel-related  revenues to be
amortized through December 31, 2003 for both jurisdictions.
        The cost of the extended  outage and restart  efforts  will  continue to
have a material adverse effect on future results of operations and on cash flows
until the second unit is restarted.  The  amortization of restart costs 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 deferrals is
$40 million.  Management  believes that the second Cook Plant unit, Unit 1, will
also be successfully returned to service. However, if for some unknown reason it
is not returned to service or its return is delayed  significantly it would have
an even greater  material  adverse effect on future results of operations,  cash
flows and financial condition.
Restructuring Legislation
         Restructuring legislation has been enacted in seven of the eleven state
retail  jurisdictions  in which  the AEP  domestic  electric  utility  companies
operate. The legislation provided for a transition from cost-based regulation of
bundled  electric  service to customer  choice market  pricing for the supply of
electricity.  The  enactment  of  restructuring  legislation  and the ability to
determine  transition rates, wires charges and any resultant  extraordinary gain
or loss under restructuring  legislation enabled AEP and certain subsidiaries to
discontinue  regulatory  accounting  under the  application of SFAS 71. Prior to
restructuring,  the electric  utility  companies  accounted for their operations
according to the cost-based  regulatory  accounting principles of SFAS 71. Under
the  provisions of SFAS 71,  regulatory  assets and regulatory  liabilities  are
recorded to reflect the economic  effects of  regulation  and to match  expenses
with regulated revenues.  The discontinuance of the application of SFAS 71 is in
accordance  with the  provisions of SFAS 101.  Pursuant to those  provisions and
further guidance provided in EITF Issue 97-4, a company is required to write-off
regulatory  assets and  liabilities  related to deregulated  operations,  unless
recovery of such amounts is provided  through rates to be collected in a portion
of operations  which  continues to be rate  regulated.  Additionally,  a company
experiencing  a  dis-continuance  of cost-based  rate  regulation is required to
determine if any plant assets are impaired under SFAS 121. A SFAS 121 accounting
impairment  analysis involves  estimating  cumulative future  non-discounted net
cash flows arising from the use of assets.  If the cumulative  undiscounted  net
cash flows exceed the net book value of the assets,  then there is no impairment
of the assets for accounting purposes.
         As legislative  and  regulatory  proceedings  evolve,  the AEP electric
operating  companies  doing  business  in the  seven  states  that  have  passed
restructuring   legislation  are  applying  the  standards  discussed  above  to
discontinue  SFAS 71  regulatory  accounting.  The  following  is a  summary  of
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
the AEP System's seven state regulatory  jurisdictions affected by restructuring
legislation.

Virginia Restructuring - Affecting AEP and APCo
        Under 1999 Virginia restructuring  legislation a transition to choice of
supplier for retail customers will commence on January 1, 2002 and be completed,
subject to a finding by the Virginia SCC that an  effective  competitive  market
exists by  January 1, 2004 but not later than  January  1,  2005.  The  Virginia
restructuring  legislation  provides  an  opportunity  for  recovery of just and
reasonable net stranded generation costs. The mechanisms in the Virginia law for
stranded  cost  recovery are: a capping of incumbent  utility  transition  rates
until  as late as July 1,  2007,  and the  application  of a wires  charge  upon
customers  who may  depart  the  incumbent  utility  in favor of an  alternative
supplier prior to the termination of the rate cap. The legislation  provides for
the establish-ment of capped rates prior to January 1, 2001 and establishment of
a wires  charge by the  fourth  quarter  of 2001.  Since APCo does not intend to
request new rates,  its current rates will become the capped rates. In the third
quarter of 2000,  the Virginia SCC directed APCo to file a cost of service study
using 1999 as a test year. In the opinion of counsel,  Virginia's  restructuring
law does not permit the Virginia SCC to change rates for the transition period.

WV Restructuring Plan - Affecting AEP and APCo
        As  discussed  in the 1999 Annual  Report,  the WVPSC issued an order on
January 28, 2000 approving an electricity restructuring plan. On March 11, 2000,
the WV legislature  approved the  restructuring  plan by joint  resolution.  The
joint  resolution  provides  that the WVPSC cannot  implement the plan until the
legislature  makes  necessary  tax law changes to preserve  the  revenues of the
state and local  governments.  Electric  service in West Virginia is provided by
APCo and WPCo.


        The provisions of the restructuring  plan provide for customer choice to
begin after all necessary rules are in place (the "starting date"); deregulation
of generation  assets occurring on the starting date;  functional  separation of
the generation,  transmission and  distribution  businesses on the starting date
and their legal  corporate  or  structural  separation  no later than January 1,
2005; a transition period of up to 13 years,  during which the incumbent utility
must provide default service for customers who do not change suppliers unless an
alternative  default  supplier is  selected  through a  WVPSC-sponsored  bidding
process;  capped and fixed rates for the 13-year  transition period as discussed
below;  deregulation  of metering and billing;  a 0.5 mills per KWH wires charge
applicable  to all  retail  customers  for the period  January  1, 2001  through
December  31,  2010  intended  to provide  for  recovery  of any  stranded  cost
including net regulatory assets;  establishment of a rate stabilization deferral
balance of $81 million  ($76  million by APCo and $5 million by WPCo) by the end
of year ten of the  transition  period to be used as  determined by the WVPSC to
offset  market  prices  paid  for  electricity  in the  eleventh,  twelfth,  and
thirteenth  year of the transition  period by residential  and small  commercial
customers that do not choose an alternative supplier.
        Default rates for residential and small commercial  customers are capped
for four years after the  starting  date and then  increase as  specified in the
plan  for the next six  years.  In years  eleven,  twelve  and  thirteen  of the
transition  period,  the power  supply  rate  shall  equal the  market  price of
comparable  power.  Default rates for industrial and large commercial  customers
will be discounted by 1% for four and a half years,  beginning July 1, 2000, and
then increased at pre-defined levels for the next three years. After seven years
the power supply rate for  industrial  and large  commercial  customers  will be
market based. APCo's Joint Stipulation agreement, discussed in Note 8, which was
approved  by the WVPSC on June 2, 2000 in  connection  with a base rate  filing,
also provides additional mechanisms to recover regulatory assets.


<PAGE>



        The elimination of ENEC recovery  proceedings in WV will subject AEP and
APCo to the risk of fuel market  price  increases  and  reductions  in wholesale
sales levels which could adversely  affect results of operations and cash flows.
Management will work aggressively to mitigate this risk by seeking to hedge such
risk where appropriate and possible.

APCo Discontinues Application of SFAS 71
        In  June  2000  APCo  discontinued  the  application  of SFAS 71 for its
Virginia and WV retail jurisdictional  portions of its generation business since
generation  is  no  longer  considered  to  be  cost-based  regulated  in  those
jurisdictions  and management was able to determine APCo's  transition rates and
wires  charges.  The  discontinuance  in the WV  jurisdiction  was possible as a
result of a June 2, 2000  approval of the Joint  Stipulation  which  established
rates,  wires  charges  and  regulatory  asset  recovery  procedures  during the
transition period to market rates. APCo was also able to discontinue application
of SFAS 71 for the generation portion of its Virginia retail  jurisdiction after
management  decided that APCo would not request capped rates  different from its
current rates. The existence of effective restructuring  legislation in Virginia
and the  probability  that the WV  legislation  would become  effective with the
passage of required tax legislation in 2001 supported  management's  decision to
discontinue SFAS 71 regulatory accounting for APCo's electricity  generation and
supply business.
        APCo's   discontinuance  of  SFAS  71  for  generation  resulted  in  an
extraordinary  gain, in the second  quarter of 2000,  of $9 million.  Management
believes  that it is  probable  that all net  regulatory  assets  related to the
Virginia and WV  generation  business will be  recovered.  Therefore,  under the
provisions of EITF 97-4,  APCo's  generation-related  net regulatory assets were
transferred to the distribution  portion of the business and are being amortized
as they are recovered through charges to regulated distribution customers.  APCo
performed an accounting  impairment analysis on its generating assets under SFAS
121 and concluded that there was no impairment of generation assets.



<PAGE>



Ohio Restructuring Law - Affecting AEP, CSPCo and OPCo
        As discussed in the 1999 Annual Report, the Ohio Act provides for, among
other things,  customer  choice of  electricity  supplier,  a  residential  rate
reduction of 5% for the generation portion of rates and a freezing of generation
rates  including  fuel rates  beginning  on  January 1, 2001.  The Ohio Act also
provides  for a five-year  transition  period to move from  cost-based  rates to
market  pricing  for  generation  services.  It  authorizes  the PUCO to address
certain major transition  issues including  unbundling of rates and the recovery
of  transition  costs  which  include   regulatory   assets,   generating  asset
impairments and other stranded costs,  employee  severance and retraining costs,
consumer education costs and other restructuring and transition costs.  Stranded
costs  are  generation  costs  that  are  not  deemed  to  be  recoverable  in a
competitive market.
        On September 28, 2000, the PUCO approved,  with minor  modifications,  a
stipulation  agreement between CSPCo,  OPCo, the PUCO staff, the Ohio Consumers'
Counsel and other  concerned  parties.  The key  provisions  of the  stipulation
agreement are:

o           Recovery of  generation-related  regulatory  assets over seven years
            for OPCo and eight years for CSPCo through frozen  transition  rates
            for the first five years of the  recovery  period and a wires charge
            for the remaining years.
o           A shopping  incentive (a price  credit) of 2.5 mills per KWH for the
            first 25% of CSPCo  residential  customers  that  switch  suppliers.
            There is no shopping incentive for OPCo customers.
o           The  absorption  of $40  million by CSPCo and OPCo ($20  million per
            company) of consumer  education,  implementation and transition plan
            filing costs with deferral of the remaining  costs,  plus a carrying
            charge,  as a regulatory  asset for recovery in future  distribution
            rates.
o           CSPCo and OPCo will make  available  a fund of up to $10  million to
            reimburse  customers who choose to purchase their power from another
            company for  certain  transmission  charges  imposed by PJM and/or a
            Midwest  ISO on  generation  originating  in the  Midwest ISO or PJM
            areas.
o           The statutory 5% reduction in the generation  component of
            residential tariffs will remain in effect for the entire 5 year
            transition period.
o           The companies' request for a $90 million gross receipts tax rider to
            recover duplicate gross receipts tax would be considered  separately
            by the PUCO.

        The gross receipts tax issue was considered by the PUCO in hearings held
in June  2000.  In the  September  28,  2000  order  approving  the  stipulation
agreement,  the PUCO  determined  that there was no duplicate tax overlap period
and denied the request for a gross  receipts  tax rider.  Under the Ohio Act the
gross  receipts tax will be replaced  with a KWH based excise tax. The last year
for which electric  utilities will pay the excise tax based on gross receipts is
the tax year ending  April 30,  2002.  As of May 1, 2001  electric  distribution
companies will be subject to an excise tax based on KWH sold to Ohio  customers.
The gross  receipts tax is paid at the  beginning  of the tax year,  deferred by
CSPCo and OPCo as a prepaid expense and amortized to expense during the tax year
pursuant to the tax law whereby the payment of the tax results in the  privilege
to conduct  business in the year following the payment of the tax. The change in
the  tax law to  impose  an  excise  tax  based  on KWH  sold to Ohio  customers
commencing before the expiration of the gross receipts tax privilege period will
result in a 12 month period when CSPCo and OPCo are recording as an expense both
the gross receipts tax and the excise tax. CSPCo and OPCo filed for rehearing of
the gross  receipts tax issue.  Unless this issue is resolved in the  companies'
favor,  it will have an adverse  effect on results of  operations  and financial
position from May 1, 2001 to April 30, 2002.
        Beginning  January 1, 2001,  fuel costs will not be subject to PUCO fuel
recovery  proceedings.  Deferred fuel costs at December 31, 2000 which represent
under or over  recoveries  will be one of the items included in the PUCO's final
determination  of net  regulatory  assets to be collected  during the transition
period.  The elimination of fuel clause  recoveries in 2001 in Ohio will subject
AEP,  CSPCo  and OPCo to the  risk of fuel  market  price  increases  and  could
adversely  affect future results of operations and cash flows beginning in 2001.
Management will work aggressively to mitigate this risk by seeking to hedge such
risk where appropriate and possible.

CSPCo and OPCo Discontinue the Application of SFAS 71 for the Ohio Jurisdiction
        In September 2000 CSPCo and OPCo discontinued the application of SFAS 71
for their Ohio retail jurisdictional  generation business since generation is no
longer  cost-based  regulated in that  jurisdiction  and  management was able to
determine their transition rates and wires charges.  The  discontinuance  in the
Ohio  jurisdiction  was  possible as a result of the PUCO's  September  28, 2000
approval of the stipulation agreement which established rates, wires charges and
net regulatory asset recovery procedures during the transition to market rates.
        CSPCo's and OPCo's  discontinuance of SFAS 71 for generation resulted in
after tax  extraordinary  losses in the third quarter of 2000 of $25 million and
$19  million,  respectively,  due to certain  unrecoverable  generation  related
regulatory   assets  and   transition   expenses.   Management   believes   that
substantially all net regulatory assets related to the Ohio generation  business
will be  recovered.  Under the  provisions  of EITF  97-4,  CSPCo's  and  OPCo's
generation-related  recoverable  net regulatory  assets were  transferred to the
transmission and  distribution  portion of the business and will be amortized as
they are recovered  through  charges to customers.  CSPCo and OPCo  performed an
accounting  impairment  analysis on their  generating  assets under SFAS 121 and
concluded there was no impairment of generation assets.

Arkansas Restructuring - Affecting AEP and SWEPCo
         In 1999  legislation  was  enacted  in  Arkansas  that will  ultimately
restructure the electric utility industry. Its major provisions are:

o retail  competition begins January 1, 2002 but can be delayed until as late as
June 30, 2003 by the Arkansas  Commission;  o  transmission  facilities  must be
operated by an ISO if owned by a company which also owns  generation  assets;  o
rates will be frozen  for one to three  years;  o market  power  issues  will be
addressed by the Arkansas  Commission;  and o a progress  report to the Arkansas
General  Assembly on the development of competition in electric  markets and its
impact
             on retail customers is required by January 2001.

         In an Arkansas Commission proceeding to investigate the progress toward
competition and what  recommendations  should be made to the General Assembly, a
delay of the start date for competition  from January 1, 2002 to October 1, 2003
or as late as October 1, 2005 was discussed. Such delay would require amendments
to  the  existing  legislation,   which  could  be  requested  in  the  Arkansas
Commission's progress report to the General Assembly. The timing of the ultimate
deregulation of SWEPCo's  generation business in Arkansas is unclear pending the
findings of the Arkansas  Commission  and the response to those  findings by the
Arkansas General Assembly.

Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
        In June 1999 the Texas  Legislation  was signed  into law  which,  among
other things:

o        gives Texas customers of investor-owned  utilities the opportunity to
         choose their electric  provider  beginning January 1, 2002;
o        provides for the recovery of regulatory  assets and of other  stranded
         costs  through  securitization  and  non-bypassable wires charges;
o        requires reductions in NOx and sulfur dioxide emissions;
o        provides for a rate freeze until  January 1, 2002  followed by a 6%
         rate reduction for residential and small commercial  customers,  an
         additional rate reduction for low-income  customers and a number of
         customer protections;
o        provides  for an earnings  test for each of the three years of the rate
         freeze period (1999  through  2001);
o        provides for certain  limits for  ownership and control of generation
         capacity by companies;
o       provides for elimination of the fuel clause reconciliation process; and
o        provides for a 2004 true-up proceeding for stranded  costs  including
         final fuel  recovery  balances,  net  regulatory assets, certain
         environmental costs, accumulated excess earnings and other issues.

         Delivery of electricity will continue 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, a transmission  utility and a distribution  utility. In May
2000 CPL,  SWEPCo and WTU filed revised  structural  separation  plans which the
PUCT approved on July 7, 2000 in an interim order.
         Under the Texas Legislation,  electric utilities are allowed,  with the
approval of the PUCT, to recover  stranded  costs  including  generation-related
regulatory  assets that may not be recoverable in a future  competitive  market.
The  approved  costs  can  be  refinanced  through  securitization,  which  is a
financing  structure  designed to provide state  sponsored lower financing costs
than  are  available  through   conventional  public  utility  financings.   The
securitized  amounts plus interest are then recovered  through a  non-bypassable
wires charge.
         In  1999  CPL  filed  an  application   with  the  PUCT  to  securitize
approximately $1.27 billion of its retail  generation-related  regulatory assets
and  approximately  $47  million  in other  qualified  restructuring  costs.  On
February 10, 2000, the PUCT tentatively approved a settlement, which will permit
CPL to  securitize  approximately  $764 million of net  regulatory  assets.  The
PUCT's order authorized  issuance of up to $797 million of securitization  bonds
including the $764 million for recovery of net regulatory assets and $33 million
for other  qualified  refinancing  costs.  The $764  million for recovery of net
regulatory  assets  reflects the recovery of $949 million of  regulatory  assets
offset by $185 million of customer benefits associated with accumulated deferred
income taxes.  CPL had previously  proposed in its filing to flow these benefits
back to  customers  over  the  14-year  term of the  securitization  bonds.  The
remaining   regulatory   assets   originally   included   by  CPL  in  its  1999
securitization  request  were  included  in a March 2000  filing  with the PUCT,
requesting  recovery of an additional $1.1 billion of stranded costs.  The March
2000 filing of $1.1 billion included  recovery of approximately  $800 million of
STP costs included in utility plant on the balance sheet of CPL and in property,
plant and  equipment-electric on the balance sheet of AEP Consolidated.  The STP
costs  had  previously  been  identified  as ECOM  by the  PUCT  for  regulatory
purposes.  The March 2000 filing will  determine the initial  amount of stranded
costs to be recovered beginning January 1, 2002. The PUCT required CPL to submit
a revised filing using an administrative model developed by the PUCT Staff which
reduced the amount of the initial  stranded  costs  estimates  to $361  million.
Management  does not  agree  with the  critical  inputs to this  model.  A final
determination  of stranded  costs and their  recovery  will occur as part of the
2004 true-up proceeding. The total amount recoverable can be securitized.
         On April 11,  2000,  four parties  appealed  the PUCT's  securitization
order to the Travis County District Court. One of these appeals challenges CPL's
ability to recover securitization charges under the Texas Constitution. CPL will
not be able to issue the securitization bonds until these appeals are resolved.
         The Texas  Legislation  provides that each year during the 1999 through
2001 rate freeze period, electric utilities are subject to an earnings test. For
electric  utilities with stranded costs,  such as 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.  Utilities  without stranded costs, such as SWEPCo and
WTU,  must either flow such excess  earnings  amounts  back to customers or make
capital  expenditures to improve  transmission or distribution  facilities or to
improve  air  quality.  The Texas  Legislation  requires  PUCT  approval  of the
earnings test calculation.
         Regarding the 1999  earnings  test,  CPL,  SWEPCo and WTU filed reports
showing excess earnings of $21 million, $1 million and zero,  respectively.  The
PUCT Staff issued its report on the excess earnings  calculations  filed by CPL,
SWEPCo and WTU and calculated the excess earnings amounts to be $41 million,  $3
million and $11 million for CPL,  SWEPCo and WTU,  respectively.  Management has
recorded an estimated provision for the 1999 excess earnings and does not expect
that the final resolution of 1999 excess earnings will have a material effect on
future results of operations.  CPL and WTU also recorded an estimated  provision
for excess 2000 earnings of $9 million per company in the third quarter of 2000.
         A Texas settlement  agreement in connection with the AEP and CSW merger
permits CPL to apply for regulatory purposes up to $20 million of STP ECOM plant
assets a year in 2000 and  2001 to  reduce  excess  earnings,  if any.  For book
purposes,  STP ECOM plant assets will be depreciated in accordance with GAAP, on
a systematic and rational basis unless  impaired.  To the extent excess earnings
exceed $20 million in 2000 or 2001 CPL will establish a regulatory  liability or
reduce regulatory assets by a charge to earnings.
        Beginning  January 1, 2002,  fuel costs will not be subject to PUCT fuel
reconciliation proceedings.  Consequently, CPL, SWEPCo and WTU will file a final
fuel  reconciliation with the PUCT which reconciles their fuel costs through the
period ending  December 31, 2001.  These final fuel balances will be included in
each  company's  2004 true-up  proceeding.  The  elimination  of the fuel clause
recoveries in 2002 in Texas will subject AEP, CPL, SWEPCo and WTU to the risk of
fuel  market  price  increases  and could  adversely  affect  future  results of
operations  beginning in 2002.  Management will work to aggressively manage this
risk by seeking to hedge such risk where appropriate and possible.

Discontinuance of the Application of SFAS 71 for Arkansas and Texas
         The  financial  statements  of CPL,  SWEPCo  and WTU have  historically
reflected the economic  effects of regulation  by applying the  requirements  of
SFAS 71. As a result of the scheduled deregulation of generation in Arkansas and
Texas, the application of SFAS 71 for the generation  portion of the business in
those states was discontinued in the third quarter of 1999. Under the provisions
of EITF 97-4, CPL's generation-related net regulatory assets were transferred to
the  distribution  portion of the  business  and will be  amortized  as they are
recovered through charges to customers.  Management  believes that substantially
all of CPL's generation-related  regulatory assets should be recovered under the
Texas Legislation.  CPL's recovery of  generation-related  regulatory assets and
stranded  costs are  subject to a final  determination  by the PUCT in 2004.  If
future events were to make the recovery of generation-related  regulatory assets
no longer  probable,  CPL would write-off the portion of such regulatory  assets
deemed unrecoverable as a non-cash extraordinary charge to earnings.
         The Texas  Legislation  provides that all finally  determined  stranded
costs  will be  recovered.  Since  SWEPCo and WTU are not  expected  to have net
stranded costs, all generation-related net regulatory assets were written off as
non-recoverable in the third quarter of 1999 when they discontinued  application
of SFAS 71 regulatory  accounting.  An impairment analysis for generation assets
under SFAS 121 was completed for CPL,  SWEPCo and WTU which  concluded there was
no accounting  impairment of generation  assets when the  application of SFAS 71
was  discontinued.  CPL,  SWEPCo and WTU will test their  generation  assets for
impairment under SFAS 121 when circumstances change. Management believes that on
a discounted  basis CPL's cash flows will  probably be less than its  generating
assets'  net book  value and  together  with its  generation-related  regulatory
assets should create a recoverable  stranded cost for regulatory  purposes under
the Texas Legislation. Therefore, management continues to carry on CPL's balance
sheet at September 30, 2000, $953 million of regulatory  assets already approved
for  securitization  and $194 million of net regulatory  assets pending approval
for  securitization.  A final  determination of whether they will be securitized
will be made as part of the 2004 true-up proceeding.
         CPL,  SWEPCo,  and WTU  continue to analyze the impact of the  electric
utility industry  restructuring  legislation on their Texas electric operations.
Although  management  believes  that the  Texas  Legislation  provides  for full
recovery  of  stranded  costs and that the  companies  do not have a  recordable
accounting  impairment,  a final  determination of whether CPL, SWEPCo,  and WTU
will   experience   any   accounting   loss  from  an   inability   to   recover
generation-related  regulatory assets and other  restructuring  related costs in
Texas and  Arkansas  cannot be made  until such time as the  litigation  and the
regulatory  process are complete following the 2004 true-up  proceeding.  In the
event CPL,  SWEPCo,  and WTU are unable  after the 2004  true-up  proceeding  to
recover all or a portion of their generation-related regulatory assets, stranded
costs and other  restructuring  related costs, it could have a material  adverse
effect on 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 has less  than one  million
customers in Michigan.  Consequently, I&M was not immediately required to comply
with the Michigan Legislation.
        The following is the stated purpose of the Michigan Legislation: o Allow
all retail customers a choice of electric suppliers;  o Encourage MPSC to foster
competition; o Provide protection to customers who remain with their incumbent
           supplier;
o        Diversify ownership of electric generation;
o        Ensure the availability of safe, reliable electric power at
           reasonable rates; and
o        Improve economic development opportunities.

         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. On October 2,
2000, I&M filed a restructuring implementation plan as required by a MPSC order.
The plan  identifies  I&M's  proposal  to file with the MPSC on June 5, 2001 its
unbundled rates, open access tariffs, terms of service and supporting schedules.
Described  in the plan are I&M's  intentions  and  preparation  for  competition
related  to  supplier  transactions,  customer  transactions,  rate  unbundling,
education  programs,  and  regional  transmission  organization.  I&M proposes a
methodology  to  determine  stranded and  implementation  costs and requests the
continuation of a wires charge for nuclear  decommissioning  costs.  Approval of
the restructuring implementation plan is pending before the MPSC.
         Management has concluded that as of September 30, 2000 the requirements
to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan
will continue to be cost-based regulated until the MPSC approves rates and wires
charges  in 2001.  The  establishment  of rates and wires  charges  under a MPSC
approved  transition  plan will enable  management  to determine  the ability to
recover  stranded costs  including  regulatory  assets and other  implementation
costs, a requirement to discontinue the application of SFAS 71.
         Upon the  discontinuance  of SFAS 71, I&M will, if  necessary,  have to
write off its Michigan  jurisdictional  generation-related  regulatory assets to
the extent that they cannot be recovered  under the  transition  rates and wires
charges and record any asset accounting impairments in accordance with SFAS 121.
         The amount of regulatory  assets recorded on the books at September 30,
2000 applicable to the I&M's Michigan retail jurisdictional  generation business
is approximately  $45 million before related tax effects.  Based on management's
current projections of rates, wires charges and future market prices, management
does not  anticipate  that I&M  will  experience  any  material  tangible  asset
accounting  impairment  or regulatory  asset  write-offs.  Ultimately,  however,
whether I&M will experience  material regulatory asset write-offs will depend on
whether the MPSC approves their recovery in future orders.
         A  determination  of whether I&M will  experience any asset  impairment
loss regarding its Michigan retail jurisdictional generating assets and any loss
from a possible  inability  to recover  Michigan  generation-related  regulatory
assets and other  transition  costs  cannot be made until such time as the rates
and the wires charges are  determined  through the  regulatory  process.  In the
event I&M is  unable  to  recover  all or a  portion  of its  generation-related
regulatory assets,  stranded costs and other implementation costs, it could have
a material  adverse  effect on results of  operations,  cash flows and  possibly
financial condition.


<PAGE>




Oklahoma Restructuring - Affecting AEP and PSO

         In 1997,  the Oklahoma  Legislature  passed  restructuring  legislation
providing  for retail  access by July 1,  2002.  That  legislation  called for a
number  of  studies  to be  completed  on a  variety  of  restructuring  issues,
including  independent  system operator,  technical,  financial,  transition and
consumer issues. During 1998 and 1999 several of the studies were completed.
         The  information  from  the  studies  was  expected  to be  used in the
development of additional  industry  restructuring  legislation  during the 2000
legislative session.
        Several additional  electric industry  restructuring bills were filed in
the 2000 Oklahoma Legislative session. The proposed bills generally supplemented
the industry  restructuring  legislation  previously  enacted in Oklahoma  which
lacked specific  procedures for a transition to market based competitive prices.
The industry  restructuring  legislation  previously passed did not delegate the
establishment of transition  procedures to the Oklahoma Corporation  Commission.
The 2000 Oklahoma  legislative  session adjourned in May without passing further
restructuring legislation and will not reconvene until 2001.
         Management has concluded that as of September 30, 2000 the requirements
to apply SFAS 71 continue to be met since PSO's rates for generation in Oklahoma
will continue to be cost-based regulated until the Oklahoma Legislature approves
further  restructuring  legislation  and transition  rates and wires charges are
established  under an approved  transition  plan.  Until  management  is able to
determine the ability to recover stranded costs which includes regulatory assets
and other  implementation  costs, PSO cannot discontinue  application of SFAS 71
accounting under GAAP.
         Upon the  discontinuance  of SFAS 71, PSO will, if  necessary,  have to
write off its Oklahoma  jurisdictional  generation-related  regulatory assets to
the extent that they cannot be recovered  under the  transition  rates and wires
charges,  when  determined,  and  record  any asset  accounting  impairments  in
accordance with SFAS 121.
         A  determination  of whether PSO will  experience any asset  impairment
loss regarding its Oklahoma retail jurisdictional generating assets and any loss
from a possible  inability  to recover  Oklahoma  generation-related  regulatory
assets and other  transition  costs  cannot be made until such time as the rates
and the wires  charges are  determined  through the  legislative  or  regulatory
process.  In the  event  PSO is  unable  to  recover  all  or a  portion  of its
generation-related   regulatory  assets  and  implementation   costs,   Oklahoma
restructuring  could have a material adverse effect on results of operations and
cash flows.

COLI Litigation - Affecting AEP, APCo, I&M and OPCo
         As discussed in the 1999 Annual Report,  the  deductibility  of certain
interest deductions related to COLI for taxable years 1991 through 1996 is under
review  by the  IRS.  Adjustments  have  been  or will  be  proposed  by the IRS
disallowing  COLI  interest  deductions.  A  disallowance  of the COLI  interest
deductions through September 30, 2000 would reduce AEP Consolidated  earnings by
approximately $319 million (including  interest).  Potential earnings reductions
for certain affected registrant subsidiaries are as follows:

        Company                      Amount
        -------                      ------
                                      (in millions)
        APCo                                 $ 79
        I&M                                    66
        OPCo                                  118

        AEP  and  its   subsidiaries   made   payments  of  taxes  and  interest
attributable to COLI interest  deductions for taxable years 1991 through 1998 to
avoid the  potential  assessment by the IRS of above market rate interest on the
contested  amount.  The payments to the IRS are included on the AEP Consolidated
balance sheet in other assets and on the  subsidiaries'  balance sheets in other
property and  investments  pending the resolution of this matter.  The companies
are seeking refunds of all amounts paid plus interest through litigation.
        In order to resolve this issue, AEP and its  subsidiaries  filed suit in
1998  against  the United  States in the U.S.  District  Court for the  Southern
District of Ohio.  The trail began on October 30, 2000. In 1999 a U.S. Tax Court
judge decided in the  Winn-Dixie  Stores v.  Commissioner  case that a corporate
taxpayer's  COLI interest  deduction  should be  disallowed.  In October 2000, a
judge for the U.S.  District  Court for Delaware  reached a similar  decision in
Internal Revenue Service vs. C.M. Holdings, Inc. Notwithstanding the Tax Court's
and U.S.  District Court's  decisions,  management has made no provision for any
possible adverse  earnings impact from this matter because it believes,  and has
been  advised by outside  counsel,  that it has a  meritorious  position  and is
vigorously  pursuing its lawsuit.  In the event the resolution of this matter is
unfavorable,  it will have a material  adverse  impact on results of operations,
cash flows and possibly financial condition.

Shareholders' Litigation - Affecting AEP
        On June 23, 2000, a complaint was filed in the U.S.  District  Court for
the  Eastern  District  of New York  seeking  unspecified  compensatory  damages
against AEP and four former or present officers.  The individual  plaintiff also
seeks  certification as the  representative of a class consisting of all persons
and entities who  purchased or otherwise  acquired AEP common stock between July
25, 1997, and June 25, 1999. The complaint alleges that the defendants knowingly
violated  federal   securities  laws  by  disseminating   materially  false  and
misleading statements concerning, among other things, the undisclosed materially
impaired  condition  of the Cook Plant,  AEP's  inability  to properly  monitor,
manage,  repair,  supervise  and report on  operations at the Cook Plant and the
materially  adverse conditions these problems were having, and would continue to
have,  on AEP's  deteriorating  financial  condition,  and  ultimately  on AEP's
operations,   liquidity  and  stock  price.  Four  other  similar  class  action
complaints have been filed and the court has  consolidated  the five cases.  The
plaintiffs are required to file a consolidated  complaint pursuant to this court
order. The defendants'  motion to transfer this case to the U.S.  District Court
for the  Southern  District of Ohio was granted on November 3, 2000.  Management
believes these shareholder  actions are without merit and intends to oppose them
vigorously.


<PAGE>



Municipal Franchise Fee Litigation - Affecting AEP and CPL
        CPL has been involved in litigation  regarding  municipal franchise fees
in Texas as a result of a class action suit filed by the City of San Juan, Texas
in 1996. The City of San Juan claims CPL underpaid  municipal franchise fees and
seeks  damage  of  up  to  $300  million  plus  attorney's  fees.  CPL  filed  a
counterclaim for overpayment of franchise fees.
        During 1997, 1998 and 1999 the litigation moved procedurally through the
Texas Court System and was sent to mediation without resolution.
        In 1999 a class  notice was mailed to each of the cities  served by CPL.
Over 90 of the 128 cities declined to participate in the lawsuit.  However,  CPL
has pledged that if any final,  non-appealable  court decision in the litigation
awards a judgement against CPL for a franchise underpayment, CPL will extend the
principles of that decision, with regard to the franchise  underpayment,  to the
cities that declined to  participate  in the  litigation.  In December 1999, the
court  ruled that the class of  plaintiffs  would  consist of  approximately  30
cities. A trial date for June 2001 has been set.
        Although  management  believes that it has  substantial  defenses to the
cities'  claims and intends to defend  itself  against  the  cities'  claims and
pursue its  counterclaims  vigorously,  management cannot predict the outcome of
this litigation or its impact on results of operations,  cash flows or financial
condition.

Federal EPA Complaint and Notice of Violation -
Affecting AEP, APCo, I&M, and OPCo

        As discussed in the 1999 Annual Report, the AEP System has been involved
in litigation  regarding  generating plant emissions.  Notices of Violation were
issued and a complaint was filed by Federal EPA in the U.S.  District Court that
alleges the AEP System and eleven  unaffiliated  utilities made modifications to
generating  units at  certain of their  coal-fired  generating  plants  over the
course of the past 25 years that extended unit operating lives or increased unit
generating  capacity without a preconstruction  permit in violation of the Clean
Air Act. The complaint was amended in March 2000 to add  allegations for certain
generating units previously named in the complaint and to include additional AEP
System generating units previously named only in the Notices of Violation in the
complaint.  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.
        A number of  northeastern  and  eastern  states  were  granted  leave to
intervene in the Federal EPA's action against the AEP System under the Clean Air
Act. A lawsuit  against  power plants owned by the AEP System  alleging  similar
violations  to those in the Federal EPA  complaint  and Notices of Violation was
filed by a number of special interest groups and has been  consolidated with the
Federal EPA action.
        The Clean Air Act  authorizes  civil  penalties of up to $27,500 per day
per  violation  at each  generating  unit  ($25,000 per day prior to January 30,
1997). Civil penalties,  if ultimately imposed by the court, and the cost of any
required new pollution  control  equipment,  if the court accepts  Federal EPA's
contentions, could be substantial.
        On May 10, 2000, the AEP System filed motions to dismiss all or portions
of the  complaints.  Briefing on these  motions was completed on August 2, 2000.
Management believes its maintenance,  repair and replacement  activities were in
conformity  with the Clean Air Act and intends to vigorously  pursue its defense
of this matter.
        In the event the AEP System does not prevail,  any capital and operating
costs of additional  pollution control equipment that may be required as well as
any penalties imposed would adversely affect future results of operations,  cash
flows and  possibly  financial  condition  unless  such  costs can be  recovered
through regulated rates, and where states are deregulating generation, unbundled
transition  period  generation  rates,  stranded  cost wires  charges and future
market prices for electricity.

NOx Reductions - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo
        As  discussed in the 1999 Annual  Report,  Federal EPA issued a NOx rule
that requires  substantial  reductions  in NOx  emissions in 22 eastern  states,
including  certain  states  in which  the AEP  System's  generating  plants  are
located.  A number of utilities,  including certain AEP System companies,  filed
petitions seeking a review of the final rule in the D.C. Circuit Court. In March
2000, the D.C. Circuit Court issued a decision generally upholding the NOx rule.
The D.C.  Circuit  Court issued an order in August 2000 which  extends the final
compliance date to May 31, 2004. In September 2000 following  denial by the D.C.
Circuit Court of a request for rehearing,  the industry  petitioners,  including
the AEP System companies, petitioned the U.S. Supreme Court for review.
        In a related  matter,  on April 19, 2000,  TNRCC adopted rules requiring
significant reductions in NOx emissions from utility sources,  including CPL and
SWEPCo.  The rule's compliance date is May 2003 for CPL and 2005 for SWEPCo. The
rule is being challenged in state court by an unaffiliated utility.
        In June  2000  OPCo  announced  that  it was  beginning  a $175  million
installation  of  selective  catalytic  reduction  technology  (expected  to  be
operational  in 2001) to reduce NOx  emissions  on its  two-unit  2,600 MW Gavin
Plant.
        Preliminary  estimates indicate that compliance with the NOx rule upheld
by the D.C. Circuit Court as well as compliance with the TNRCC rule could result
in  required  capital   expenditures  of  approximately  $1.6  billion  for  AEP
Consolidated.
        The following  table shows the estimated  compliance cost for certain of
AEP's subsidiary registrants.

        Company               Amount
        -------               ------
                          (in millions)
        APCo                  $365
        CPL                     57
        I&M                    202
        OPCo                   624
        SWEPCo                  28

        Since  compliance  costs cannot be estimated with certainty,  the actual
cost to comply could be  significantly  different than the preliminary  estimate
depending upon the compliance alternatives selected to achieve reductions in NOx
emissions.  Unless the  depreciation  of such costs are recovered from customers
through  regulated  rates and/or  future  market  prices for  electricity  where
generation is deregulated, they will have an adverse effect on future results of
operations, cash flows and possibly financial condition.

New Accounting  Standards - Affecting AEP, AEGCo,  APCo, CPL, CSPCo,  I&M, KPCo,
OPCo, PSO, SWEPCo and WTU
        SFAS 133, Accounting for Derivative  Instruments and Hedging Activities,
as  amended  by SFAS 137 and SFAS  138,  will be  effective  for the AEP  System
beginning  January  1, 2001.  SFAS 133  requires  that  entities  recognize  all
derivatives  as either  assets or  liabilities  and measure  them at fair value.
Changes  in the  fair  value  of  derivative  assets  and  liabilities  must  be
recognized  currently  in net income or other  comprehensive  income  except for
certain  hedges  that are deemed to be  effective.  Derivatives  that are highly
effective  in  hedging  underlying  transactions  can  lessen  the impact on net
income.
        It appears at this time that the  adoption of SFAS 133, as amended,  for
AEP's non-commodity derivatives is expected to result in an immaterial effect on
net  income  and on other  comprehensive  income  based on the  fair  values  of
existing  non-commodity  derivatives at September 30, 2000. However,  the actual
effect on future  net  income  and other  comprehensive  income of SFAS 133 will
depend  upon the  number  and  amount of  derivatives  that will exist at future
balances sheet dates and the market values of those derivative at those dates.
        AEP's  energy  commodity  trading  contracts  are  generally   currently
marked-to-market  under the Financial  Accounting  Standards  Board's EITF 98-10
with  changes  reflected  in net income and on the  balance  sheet.  There-fore,
implementation  of  SFAS  133  is  not  expected  to  significantly  affect  the
accounting for energy commodity trading contracts. However, currently, there are
outstanding  issues under  consideration by the Financial  Accounting  Standards
Board's Derivative Implementation Group that may affect the accounting treatment
of certain  energy  contracts  which  could  result in certain  contracts  being
marked-to-market that are not presently being  marked-to-market.  As a result we
cannot determine the effect of implementation that SFAS 133 will have on the AEP
System's energy contracts.
        The SEC has issued Staff Accounting  Bulletin 101 "Revenue  Recognition"
which provided  guidance on the timing and methods of recognizing  revenues that
SEC  registrants  must adopt in the fourth quarter of 2000. The adoption of this
Staff  Accounting  Bulletin  is not  expected  to have a material  effect on the
financial  statements of the AEP System  companies  since the AEP System already
follows the principles outlined in this Staff Accounting Bulletin.




<PAGE>



        QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risks
        AEP and its  subsidiaries  have certain  market risks  inherent in their
business  activities from changes in fuel and energy commodity  prices,  foreign
currency  exchange rates and interest rates.  Market risk represents the risk of
loss that may impact  operations  due to adverse  changes  in  commodity  market
prices, foreign currency exchange rates and interest rates.

Commodity Price Risk - Affecting AEP, APCo, CPL,  CSPCo,  I&M, KPCo,  OPCo, PSO,
SWEPCo and WTU
        The  average  exposure  to  market  risk for AEP  consolidated  from the
trading  of  electricity  and  natural  gas  and  related  financial  derivative
instruments  was less than $20 million at September  30, 2000 and $14 million at
December 31, 1999 based on the use of a risk measurement  model which calculates
VaR. 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 three-day  holding period.  Based on the VaR model, the exposure to market
risk  from  the  trading  of  electricity  and  related   financial   derivative
instruments of the AEP subsidiary registrants was as follows:

                   September 30, December 31,
        Company       2000               1999
        -------   ------------       --------------
                         (in millions)

        APCo             $3            $4
        CPL               1             -
        CSPCo             2             3
        I&M               2             3
        KPCo              1             1
        OPCo              3             4
        PSO               3             -
        SWEPCo            2             -
        WTU               1             -

        CPL, PSO, SWEPCo and WTU did not engage in trading  activities  prior to
the merger.  Therefore,  the market  risk from  trading  activities  was zero at
December 31, 1999 for CPL, PSO, SWEPCo and WTU.


<PAGE>




Foreign Currency Exchange Rates - Affecting AEP
        AEP is exposed to foreign  currency  exchange rate risk from investments
in foreign  ventures.  Cross  currency  swaps are being  used to manage  adverse
changes in the floating exchange rate between the U.S. dollar and British pounds
for AEP's  subsidiary  Seeboard.  At September  30,  2000,  there were two cross
currency  swap  contracts.  The table  presented  below  represents  third party
valuations of their fair value:

Contract            Maturity Date     Maturity Value         Market Value
--------            -------------     --------------         ------------
                                                 (in millions)

Cross currency swaps   8/1/01             $200                  $ 7.0
Cross currency swaps   8/1/06              200                  $(7.5)

        Based on these valuations,  AEP's position in these swaps represented an
unrealized  loss of $1 million at September 30, 2000.  This  unrealized  loss is
offset by unrealized  gains related to the  underlying  liability  being hedged,
which are included in long-term  debt on AEP's  consolidated  balance sheet at a
carrying value of approximately  $400 million.  Management expects to hold these
contracts to maturity.
Interest Rates - Affecting AEP, APCo, CPL, CSPCo,  I&M, KPCo,  OPCo, PSO, SWEPCo
and WTU
        The exposure to changes in interest rates from  short-term and long-term
borrowings at September 30, 2000 is not  materially  different  than at December
31, 1999.


<PAGE>



                           PART II. OTHER INFORMATION

Item 1.  Legal Proceedings.

American Electric Power Company, Inc. ("AEP") and Ohio Power Company ("OPCo")

        On August 31, 2000, the U.S.  Environmental  Protection Agency ("Federal
EPA")  Region 5, issued a Notice of  Violation  ("NOV") to OPCo's Gavin Plant in
connection with stack limit emissions.  Among other alleged violations,  the NOV
alleges violation of the Federal  EPA-approved Ohio air pollution nuisance rule.
AEP has  submitted a request for a  conference  to discuss the NOV with Region 5
officials.

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

Central Power and Light Company ("CPL")

        The  annual  meeting  of  shareholders  was held on July  17,  2000 at 1
Riverside Plaza, Columbus,  Ohio. At the meeting,  6,755,535 votes were cast FOR
each of the following  seven persons for election as directors and there were no
votes  withheld and such  persons were elected  directors to hold office for one
year or until their successors are elected and qualify:

               E. Linn Draper, Jr.                       Thomas V. Shockley III
               Henry W. Fayne                            Susan Tomasky
               William J. Lhota                          Joseph H. Vipperman
               Armando A. Pena

        No other business was transacted at the meeting.

Public Service Company of Oklahoma ("PSO")

        The  annual  meeting  of  shareholders  was held on July  17,  2000 at 1
Riverside Plaza, Columbus,  Ohio. At the meeting,  9,013,000 votes were cast FOR
each of the following  seven persons for election as directors and there were no
votes  withheld and such  persons were elected  directors to hold office for one
year or until their successors are elected and qualify:

               E. Linn Draper, Jr.                       Thomas V. Shockley III
               Henry W. Fayne                            Susan Tomasky
               William J. Lhota                          Joseph H. Vipperman
               Armando A. Pena

        No other business was transacted at the meeting.

Southwestern Electric Power Company ("SWEPCo")

        The  annual  meeting  of  shareholders  was held on July  17,  2000 at 1
Riverside Plaza, Columbus,  Ohio. At the meeting,  7,536,640 votes were cast FOR
each of the following  seven persons for election as directors and there were no
votes  withheld and such  persons were elected  directors to hold office for one
year or until their successors are elected and qualify:

               E. Linn Draper, Jr.                       Thomas V. Shockley III
               Henry W. Fayne                            Susan Tomasky
               William J. Lhota                          Joseph H. Vipperman
               Armando A. Pena

        No other business was transacted at the meeting.

West Texas Utilities Company ("WTU")

        The  annual  meeting  of  shareholders  was held on July  17,  2000 at 1
Riverside Plaza, Columbus,  Ohio. At the meeting,  5,488,560 votes were cast FOR
each of the following  seven persons for election as directors and there were no
votes  withheld and such  persons were elected  directors to hold office for one
year or until their successors are elected and qualify:

               E. Linn Draper, Jr.                       Thomas V. Shockley III
               Henry W. Fayne                            Susan Tomasky
               William J. Lhota                          Joseph H. Vipperman
               Armando A. Pena

        No other business was transacted at the meeting.

Item 5.  Other Information.

AEP and Appalachian Power Company ("APCo")

        Reference  is made to pages 18 and 19 of the Annual  Report on Form 10-K
for the year ended  December 31, 1999 ("1999  10-K") for a discussion  of APCo's
proposed  transmission  facilities.  On October 2, 2000,  the  Hearing  Examiner
issued his report to the  Virginia  State  Corporation  Commission  recommending
approval of a 90-mile  765,000-volt  line to connect  the  Wyoming and  Jacksons
Ferry  substations.  On October  27,  2000,  APCo filed with the Public  Service
Commission of West Virginia a request to amend its May 1998 order to accommodate
this potential change in the Virginia portion of the project.

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

        (a)    Exhibits:

        APCo, CPL, Columbus Southern Power Company ("CSPCo"),
        Indiana Michigan Power Company ("I&M"), Kentucky Power Company
        ("KEPCo"), OPCo, PSO, SWEPCo and WTU

    Exhibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges.

        AEP, AEP Generating  Company,  APCo, CPL, CSPCo, I&M, KEPCo,  OPCo, PSO,
SWEPCo and WTU

               Exhibit 27 - Financial Data Schedule.

        (b)    Reports on Form 8-K or 8-K/A:

Companies Reporting       Date of Report      Items Reported

CPL, PSO, SWEPCo and WTU  July 5, 2000        Item 4. Changes in Registrant's
                                                      Certifying Accountant

                                              Item 7. Financial Statements and
                                                      Exhibits


AEP                       June 15, 2000       Item 7. Financial Statements and
                                                      Exhibits



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

        No reports on Form 8-K were filed during the quarter ended September 30,
2000.


<PAGE>
                                   Signature




        Pursuant to the  requirements  of the  Securities  Exchange Act of
1934,  each  registrant has duly caused this report to be signed on its behalf
by the undersigned  thereunto duly authorized.  The signatures for each
undersigned  company shall be deemed to relate only to matters having reference
to such company and any subsidiaries thereof.

                      AMERICAN ELECTRIC POWER COMPANY, INC.



        By: /s/:Armando A. Pena        By: /s/:Leonard V. Assante
                  Armando A. Pena              Leonard V. Assante
                  Treasurer                    Deputy Controller



                             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



        By: /s/:Armando A. Pena        By: /s/:Leonard V. Assante
                  Armando A. Pena              Leonard V. Assante
                  Vice President and           Deputy Controller
                  Treasurer



Date: November 10, 2000