2000 Annual Reports


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


Audited Financial Statements and
Management's Discussion and Analysis





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                                    Contents
                                                                                               Page

<S>                                                                                             <C>
Glossary of Terms                                                                                 i

Forward Looking Information                                                                      iv

American Electric Power Company, Inc. and Subsidiary Companies
         Selected Consolidated Financial Data                                                    A-1
         Management's Discussion and Analysis of Results of Operations                           A-2
         Consolidated Statements of Income                                                       A-8
         Consolidated Balance Sheets                                                             A-9
         Consolidated Statements of Cash Flows                                                   A-11
         Consolidated Statements of Common Shareholders' Equity                                  A-12
         Schedule of Consolidated Cumulative Preferred
             Stocks of Subsidiaries                                                              A-13
         Schedule of Consolidated Long-term Debt of Subsidiaries                                 A-14
         Index to Notes to Consolidated Financial Statements                                     A-15
         Management's Responsibility                                                             A-16
         Independent Auditors' Report                                                            A-17

AEP Generating Company
         Selected Financial Data                                                                 B-1
         Management's Narrative Analysis of Results of Operations                                B-2
         Statements of Income and Statements of Retained Earnings                                B-3
         Balance Sheets                                                                          B-4
         Statements of Cash Flows                                                                B-6
         Statements of Capitalization                                                            B-7
         Index to Notes to Financial Statements                                                  B-8
         Independent Auditors' Report                                                            B-9

Appalachian Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                    C-1
         Management's Discussion and Analysis of Results of Operations                           C-2
         Consolidated Statements of Income                                                       C-5
         Consolidated Balance Sheets                                                             C-6
         Consolidated Statements of Cash Flows                                                   C-8
         Consolidated Statements of Retained Earnings                                            C-9
         Consolidated Statements of Capitalization                                               C-10
         Schedule of Long-term Debt                                                              C-11
         Index to Notes to Consolidated Financial Statements                                     C-12
         Independent Auditors' Report                                                            C-13


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Central Power & Light Company and Subsidiaries
         Selected Consolidated Financial Data                                                    D-1
         Management's Discussion and Analysis of Results of Operations                           D-2
         Consolidated Statements of Income                                                       D-5
         Consolidated Balance Sheets                                                             D-6
         Consolidated Statements of Cash Flows                                                   D-8
         Consolidated Statements of Retained Earnings                                            D-9
         Consolidated Statements of Capitalization                                               D-10
         Schedule of Long-term Debt                                                              D-11
         Index to Notes to Consolidated Financial Statements                                     D-12
         Independent Auditors' Report                                                            D-13

Columbus Southern Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                    E-1
         Management's Narrative Analysis of Results of Operations                                E-2
         Consolidated Statements of Income and
             Consolidated Statements of Retained Earnings                                        E-5
         Consolidated Balance Sheets                                                             E-6
         Consolidated Statements of Cash Flows                                                   E-8
         Consolidated Statements of Capitalization                                               E-9
         Schedule of Long-term Debt                                                              E-10
         Index to Notes to Consolidated Financial Statements                                     E-11
         Independent Auditors' Report                                                            E-12

Indiana Michigan Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                    F-1
         Management's Discussion and Analysis of Results of Operations                           F-2
         Consolidated Statements of Income                                                       F-5
         Consolidated Balance Sheets                                                             F-6
         Consolidated Statements of Cash Flows                                                   F-8
         Consolidated Statements of Retained Earnings                                            F-9
         Consolidated Statements of Capitalization                                               F-10
         Schedule of Long-term Debt                                                              F-11
         Index to Notes to Consolidated Financial Statements                                     F-13
         Independent Auditors' Report                                                            F-14

Kentucky Power Company
         Selected Financial Data                                                                 G-1
         Management's Narrative Analysis of Results of Operations                                G-2
         Statements of Income and Statements of Retained Earnings                                G-4
         Balance Sheets                                                                          G-5
         Statements of Cash Flows                                                                G-7
         Statements of Capitalization                                                            G-8
         Schedule of Long-term Debt                                                              G-9
         Index to Notes to Financial Statements                                                  G-10
         Independent Auditors' Report                                                            G-11


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Ohio Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                    H-1
         Management's Discussion and Analysis of Results of Operations                           H-2
         Consolidated Statements of Income                                                       H-5
         Consolidated Balance Sheets                                                             H-6
         Consolidated Statements of Cash Flows                                                   H-8
         Consolidated Statements of Retained Earnings                                            H-9
         Consolidated Statements of Capitalization                                               H-10
         Schedule of Long-term Debt                                                              H-11
         Index to Notes to Consolidated Financial Statements                                     H-13
         Independent Auditors' Report                                                            H-14

Public Service Company of Oklahoma and Subsidiaries
         Selected Consolidated Financial Data                                                    I-1
         Management's Narrative Analysis of Results of Operations                                I-2
         Consolidated Statements of Income and
             Consolidated Statements of Retained Earnings                                        I-4
         Consolidated Balance Sheets                                                             I-5
         Consolidated Statements of Cash Flows                                                   I-7
         Consolidated Statements of Capitalization                                               I-8
         Schedule of Long-term Debt                                                              I-9
         Index to Notes to Consolidated Financial Statements                                     I-10
         Independent Auditors' Report                                                            I-11

Southwestern Electric Power Company and Subsidiaries
         Selected Consolidated Financial Data                                                    J-1
         Management's Discussion and Analysis of Results of Operations                           J-2
         Consolidated Statements of Income and
             Consolidated Statements of Retained Earnings                                        J-5
         Consolidated Balance Sheets                                                             J-6
         Consolidated Statements of Cash Flows                                                   J-8
         Consolidated Statements of Capitalization                                               J-9
         Schedule of Long-term Debt                                                              J-10
         Index to Notes to Consolidated Financial Statements                                     J-11
         Independent Auditors' Report                                                            J-12

West Texas Utilities Company
         Selected Financial Data                                                                 K-1
         Management's Narrative Analysis of Results of Operations                                K-2
         Statements of Income and Statements of Retained Earnings                                K-4
         Balance Sheets                                                                          K-5
         Statements of Cash Flows                                                                K-7
         Statements of Capitalization                                                            K-8
         Schedule of Long-term Debt                                                              K-9
         Index to Notes to Financial Statements                                                  K-10
         Independent Auditors' Report                                                            K-11

Combined Notes to Financial Statements                                                           L-1

Management's Discussion and Analysis of Financial Condition,
    Contingencies and Other Matters                                                              M-1
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                                       iv
                                GLOSSARY OF TERMS
         When the following terms and  abbreviations  appear in the text of this
report, they have the meanings indicated below.

               Term                                Meaning

<S>                                 <C>
2004 True-up Proceeding............ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the
                                            amount of stranded costs and the recovery of such costs.
AEGCo.............................. AEP Generating Company, an electric utility subsidiary of AEP.
AEP................................ American Electric Power Company, Inc.
AEP Consolidated................... AEP and its majority owned subsidiaries consolidated.
AEP Credit....................,Inc. AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
                                            revenues for affiliated and unaffiliated domestic electric utility companies.
AEP East electric operating
companies..........................APCo, CSPCo, I&M, KPCo and OPCo.
AEPR............................... AEP Resources, Inc.
AEP System or the System........... The American Electric Power System, an integrated electric utility system, owned and
                                            operated by AEP's electric utility subsidiaries.
AEPSC.............................. American Electric Power Service Corporation, a service subsidiary providing management and
                                            professional services to AEP and its subsidiaries.
AEP Power Pool..................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo.  The Pool shares the
                                            generation, cost of generation and resultant wholesale system sales of the member
                                            companies.
AEP West electric operating
companies.......................... CPL, PSO, SWEPCo and WTU.
AFUDC.............................. Allowance for funds used during construction, a noncash nonoperating income item that is
                                            capitalized and recovered through depreciation over the service life of domestic
                                            regulated electric utility plant.
Alliance RTO....................... Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated
                                            utilities.
Amos Plant......................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and
                                            OPCo.
APCo............................... Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission................ Arkansas Public Service Commission.
Buckeye............................ Buckeye Power, Inc., an unaffiliated corporation.
CLECO.............................. Central Louisiana Electric Company, Inc., an unaffiliated corporation.
COLI............................... Corporate owned life insurance program.
Cook Plant......................... The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CPL................................ Central Power and Light Company, an AEP electric utility subsidiary.
CSPCo.............................. Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW...............................  Central and South West Corporation, a subsidiary of AEP.
CSW Energy......................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
                                            outside the United States.
D.C. Circuit Court................. The United States Court of Appeals for the District of Columbia Circuit.
DHMV............................... Dolet Hills Mining Venture.
DOE................................ United States Department of Energy.
ECOM............................... Excess Cost Over Market.
ENEC............................... Expanded Net Energy Costs.
EITF............................... The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT.............................. The Electric Reliability Council of Texas.
EWGs............................... Exempt Wholesale Generators.
FASB............................... Financial Accounting Standards Board.
Federal EPA........................ United States Environmental Protection Agency.
FERC............................... Federal Energy Regulatory Commission.
FMB ............................... First Mortgage Bond.
FUCOs.............................. Foreign Utility Companies.
GAAP............................... Generally Accepted Accounting Principles.
I&M................................ Indiana Michigan Power Company, an AEP electric utility subsidiary.
IPC................................ Installment Purchase Contract.
IRS................................ Internal Revenue Service.
IURC............................... Indiana Utility Regulatory Commission.
ISO................................ Independent system operator.
Joint Stipulation.................. Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding.
KPCo............................... Kentucky Power Company, an AEP electric utility subsidiary.
KPSC............................... Kentucky Public Service Commission.
KWH................................ Kilowatthour.
LIG................................ Louisiana Intrastate Gas.
Michigan Legislation............... The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
                                            customer choice of electricity supplier.
Midwest ISO........................ An independent operator of transmission assets in the Midwest.
MLR................................ Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool......................... AEP System's Money Pool.
MPSC............................... Michigan Public Service Commission.
MTN................................ Medium Term Notes.
MW................................. Megawatt.
MWH................................ Megawatthour.
NEIL............................... Nuclear Electric Insurance Limited.
Nox................................ Nitrogen oxide.
Nox Rule........................... A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states
                                            including seven of the states in which AEP companies operates.
NP................................. Notes Payable.
NRC................................ Nuclear Regulatory Commission.
Ohio Act........................... The Ohio Electric Restructuring Act of 1999.
Ohio EPA........................... Ohio Environmental Protection Agency.
OPCo..............................  Ohio Power Company, an AEP electric utility subsidiary.
OVEC............................... Ohio Valley Electric Corporation, an electric utility company in which AEP and  CSPCo own a
                                            44.2% equity interest.
PCBs............................... Polychlorinated Biphenyls.
PJM................................ Pennsylvania - New Jersey - Maryland regional transmission organization.
PRP..............................   Potentially Responsible Party.
PSO................................ Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO............................... The Public Utilities Commission of Ohio.
PUCT............................... The Public Utility Commission of Texas.
PUHCA.............................. Public Utility Holding Company Act of 1935, as amended.
PURPA.............................. The Public Utility Regulatory Policies Act of 1978.
RCRA............................... Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............ AEP subsidiaries who are SEC registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
                                            SWEPCo and WTU.
Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
                                            Indiana owned by AEGCo and I&M.
RTO................................ Regional Transmission Organization.
SEC................................ Securities and Exchange Commission.
SFAS............................... Statement of Financial Accounting Standards issued by the Financial Accounting Standards
                                            Board.
SFAS 71............................ Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain
                                                                                        -------------------------------------
                                            Types of Regulation.
                                            -------------------
SFAS 101........................... Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of
                                                                                         ------------------------------------
                                            Application of Statement 71.
SFAS 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of
                                                                                         --------------------------------
                                            Long-Lived Assets and for Long-Lived Assets to be Disposed of.
                                            --------------------------------------------------------------
SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
                                                                                         -------------------------------------
                                            and Hedging Activities.
SNF................................ Spent Nuclear Fuel.
SPP................................ Southwest Power Pool.
STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light
                                            Company, an AEP electric utility subsidiary .
STPNOC............................. STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf
                                            of its joint owners including CPL.
Superfund.........................  The Comprehensive Environmental, Response, Compensation and Liability Act.
SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary.
Texas Appeals Court................ The Third District of Texas Court of Appeals.
Texas Legislation.................. Legislation enacted in 1999 to restructure the electric utility industry in Texas.
Travis District Court.............. State District Court of Travis County, Texas.
TVA ............................... Tennessee Valley Authority.
U.K................................ The United Kingdom.
UN................................. Unsecured Note.
VaR................................ Value at Risk, a method to quantify risk exposure.
Virginia SCC....................... Virginia State Corporation Commission.
WV................................. West Virginia.
WVPSC.............................. Public Service Commission of West Virginia.
WPCo............................... Wheeling Power Company, an AEP electric distribution subsidiary.
WTU................................ West Texas Utilities Company, an AEP electric utility subsidiary.
Yorkshire.......................... Yorkshire Electricity Group plc, a U.K. regional electricity company owned jointly by AEP
                                            and New Century Energies.
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>

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FORWARD LOOKING INFORMATION

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



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This  discussion  includes  forward-looking  statements  within  the  meaning of
Section  21E of the  Securities  Exchange  Act of  1934.  These  forward-looking
statements reflect assumptions, and involve a number of risks and uncertainties.
Among the factors both foreign and domestic  that could cause actual  results to
differ  materially  from  forward  looking  statements  are:  electric  load and
customer growth;  abnormal weather  conditions;  available sources of and prices
for coal and gas; availability of generating capacity;  the impact of the merger
with CSW  including  actual  merger  savings  being less than the  related  rate
reductions; risks related to energy trading and construction under contract; the
speed and degree to which  competition  is  introduced  to our power  generation
business;  the structure and timing of a competitive  market for electricity and
its impact


on prices;  the ability to recover net regulatory  assets,  other stranded costs
and  implementation  costs in  connection  with  deregulation  of  generation in
certain  states;  new  legislation  and government  regulations;  the ability to
successfully control costs; the success of new business ventures;  international
developments affecting our foreign investments;  the economic climate and growth
in our service and trading territories both domestic and foreign; the ability of
the Company to  successfully  challenge  new  environmental  regulations  and to
successfully  litigate  claims  that the  Company  violated  the  Clean Air Act;
successful resolution of litigation regarding municipal franchise fees in Texas;
inflationary  trends;  changes in electricity  and gas market  prices;  interest
rates; foreign exchange rates, and other risks and unforeseen events.





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                      AMERICAN ELECTRIC POWER COMPANY, INC.
                            AND SUBSIDIARY COMPANIES



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                                      A-17
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Selected Consolidated Financial Data

Year Ended December 31,                2000       1999       1998       1997       1996
-----------------------------------------------------------------------------------------

INCOME STATEMENTS DATA (in millions):
<S>                                  <C>        <C>        <C>        <C>        <C>
Total Revenues                       $13,694    $12,407    $11,840    $11,163    $11,017
Operating Income                       2,026      2,325      2,280      2,198      2,368
Income From Continuing Operations        302        986        975        949        871
Discontinued Operations                 -          -          -          -           132
Extraordinary Loss                       (35)       (14)      -          (285)      -
Net Income                               267        972        975        664      1,003

December 31,                           2000       1999       1998       1997       1996
-----------------------------------------------------------------------------------------

BALANCE SHEETS DATA (in millions):
Property, Plant and Equipment        $38,088    $36,938    $35,655    $33,496    $32,443
Accumulated Depreciation
  and Amortization                    15,695     15,073     14,136     13,229     12,494
                                     -------    -------    -------    -------    -------
       Net Property,
         Plant and Equipment         $22,393    $21,865    $21,519    $20,267    $19,949
                                     =======    =======    =======    =======    =======

Total Assets                         $54,548    $35,719    $33,418    $30,092    $29,228

Common Shareholders' Equity            8,054      8,673      8,452      8,220      8,334

Cumulative Preferred Stocks
  of Subsidiaries:
  Not Subject to Mandatory Redemption     61         63        222        223        382

  Subject to Mandatory Redemption*       100        119        128        154        543

Trust Preferred Securities               334        335        335        335       -

Long-term Debt*                       10,754     11,524     11,113      9,354      9,112

Obligations Under Capital Leases*        614        610        539        549        422

*Including portion due within one year

Year Ended December 31,                2000       1999       1998       1997       1996
-----------------------------------------------------------------------------------------

COMMON STOCK DATA:
Earnings per Common Share:
  Continuing Operations                $0.94      $3.07      $3.06      $2.99      $2.79
  Discontinued Operations                -          -          -          -         0.42
  Extraordinary Loss                    (.11)      (.04)       -        (0.90)       -
                                       -----      -----      -----      -----      ------
  Net Income                           $0.83      $3.03      $3.06      $2.09      $3.21
                                       =====      =====      =====      =====      =====

Average Number of Shares
  Outstanding (in millions)              322        321        318        316        312

Market Price Range: High           $48-15/16   $48-3/16   $53-5/16    $    52    $44-3/4

                    Low             25-15/16    30-9/16    42-1/16     39-1/8     38-5/8

Year-end Market Price                 46-1/2     32-1/8    47-1/16     51-5/8     41-1/8

Cash Dividends on Common*              $2.40      $2.40      $2.40      $2.40      $2.40
Dividend Payout Ratio*                 289.2%      79.2%      78.4%     114.8%      74.5%
Book Value per Share                  $25.01     $26.96     $26.46     $25.91     $26.45

The consolidated  financial  statements give retroactive  effect to AEP's merger
with CSW,  which was accounted for as a pooling of interests,  as if AEP and CSW
had always been combined. *Based on AEP historical dividend rate.
</TABLE>

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AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Management's Discussion and Analysis of Results of Operations




<PAGE>



        American  Electric  Power  Company,  Inc.  (AEP)  is one of the  largest
investor owned electric  public utility  holding  companies in the U.S.  serving
over 4.8 million retail customers in eleven states (Arkansas, Indiana, Kentucky,
Louisiana,  Michigan,  Ohio,  Oklahoma,  Tennessee,  Texas,  Virginia  and  West
Virginia)  and  selling  bulk  power at  wholesale  both  within  and beyond its
domestic  retail service area.  AEP has 38,000  megawatts of generation and over
38,000 miles of transmission  lines and 186,000 miles of  distribution  lines in
the U.S.  Subsidiaries  own 1,250  megawatts as independent  power  producers in
Colorado,  Florida and Texas.  In recent  years AEP has  expanded  its  domestic
operations  to include gas  marketing,  processing,  storage and  transportation
operations,  electric,  gas and coal trading  operations  and  telecommunication
services and invested in and acquired  foreign  distribution  operations  in the
U.K.,  Australia and Brazil and electricity  generating  facilities in China and
Mexico. Subsidiaries also provide power engineering, generation and transmission
plant maintenance and construction,  and energy management  services  worldwide.
AEP is one of the largest  traders of electricity and gas in the U.S. In 2000 we
established an energy trading operation in Europe.

        Presently  AEP  is in  the  process  of  restructuring  its  assets  and
operations  to  separate  the  regulated   operations  from  the   non-regulated
operations  and to  functionally  and,  where  permitted  by  law,  structurally
unbundle its domestic  vertically  integrated  electric  utility  business  into
separate generation,  transmission and distribution  businesses.  The purpose of
this  restructuring  is to focus  our  management  and  technical  expertise  to
maximize  the  potential  for  growth  of  both   non-regulated   and  regulated
operations,  to  evaluate  the  performance  of  these  separate  and  different
businesses and


to  meet  the  separation   requirements  of  federal  and  state  restructuring
legislation  and  codes of  conduct.  Five of AEP's 11 states  (Arkansas,  Ohio,
Texas,  Virginia,  and West Virginia) are in various stages of  transitioning to
deregulation of generation and to customer choice and market-based  pricing from
monopoly and  regulator set rates for the retail sale of  electricity.  When the
transition is implemented in those states, transmission will be regulated by the
Federal Energy Regulatory  Commission and distribution services will continue to
be cost-based rate regulated by the states.  Although we are actively supporting
the  transition to  competition,  there is little  progress in the remaining six
states.  Therefore,  in the near term, our retail electric  business in Indiana,
Kentucky,  Louisiana,  Michigan,  Oklahoma  and  Tennessee  will  continue to be
operated  as an  integrated  public  utility  subject to state  regulation.  The
foreign energy  delivery  investments  and  operations  are not cost-based  rate
regulated but they are generally  subject to different  forms of price controls,
such as capped prices. As such these foreign  investments and operations will be
included in our unbundled regulated business.

        On November 1, 2000, AEP filed a restructuring plan under PUHCA with the
SEC seeking  approval to form two wholly owned holding  company  subsidiaries of
AEP to separately  own AEP's  regulated and  non-regulated  subsidiaries  and to
structurally  separate into separate legal entities along functional lines (i.e.
generation, transmission and distribution) six of the electric utility operating
companies  (APCo,  CPL,  CSPCo,  OPCo,  SWEPCo  and WTU).  These  six  operating
companies  do  business  in  the  states  that  are  implementing  restructuring
(Arkansas,  Ohio,  Texas,  Virginia and West Virginia).  The remaining  domestic
electric  operating  companies  will  be  functionally  unbundled  for  internal
management and internal  reporting  purposes and for financial segment reporting
but will not be structurally  unbundled into separate  companies since state law
and/or  regulation  prohibits  such  action.  One holding  company will hold the
unbundled  non-regulated electric generation  subsidiaries and the non-regulated
domestic and foreign subsidiaries including the European trading company and the
foreign  generating  companies,  while the other  holding  company will hold the
bundled  domestic   regulated   electric  utility   companies  and  the  foreign
distribution companies.  The restructuring will facilitate management's strategy
to grow the  deregulated  wholesale  electricity  supply  and  electric  and gas
trading  business and to evaluate the other business  operations to explore ways
to improve their results of operations  and to  continuously  evaluate and where
necessary reshape our business to grow earnings and improve  shareholder  value.
The legal transfer of assets and structural  separation  plans will also require
FERC, certain state and other regulatory approvals.

        2000  was a year of  accomplishment  that  positions  AEP  for  earnings
growth.  In 2000 we completed the merger of AEP and CSW, greatly  increasing the
scope and size of AEP;  achieved the targeted merger  savings;  returned the two
unit  2,110 MW Cook  Plant  to  service  after an  extended  outage;  reached  a
settlement  on a  restructuring  plan in  Ohio  that  will  allow  our  electric
generating and supply  business in Ohio to transition  over five years to market
pricing and recover its stranded cost, including  generation-related  regulatory
assets; continued to grow our domestic electricity and gas trading businesses to
become one of the largest  electricity and gas traders;  established and grew an
energy trading operation in Europe;  added to our gas assets and operations with
the  announcement  in the first  quarter of 2001 of the planned  acquisition  of
Houston Pipe Line Company; restructured our incentive compensation plans to more
closely  align them with the creation of  shareholder  value;  reduced our power
plant  operation and  maintenance  costs while  increasing  plant  availability;
established AEP Pro Serv,  Inc. to market AEP's expertise in power  engineering,
environmental  engineering and generating plant maintenance  services worldwide;
closed  contracts to design,  build,  operate and market the output of new power
plants for Dow  Chemical,  Buckeye  Power and Columbia  Energy;  and initiated a
re-design  of  our  existing  PeopleSoft   financial  software  as  part  of  an
enterprise-wide  application to fully  integrate our financial,  work management
and  supply  chain  software  and to  provide  data  on a  business  unit  basis
consistent with our corporate separation initiative.

        Although  2000 was a year  marked by  significant  accomplishments  that
position AEP for future earnings growth,  it resulted in a reduction in earnings
and  earnings  per share  due  mainly to  non-recurring  items,  such as: a loss
incurred from a court decision  disallowing tax deductions for interest  related
to AEP's COLI  program;  the  write-off of  non-recoverable  merger  costs;  the
expensing of Cook nuclear  restart  costs in contrast to 1999 when a significant
portion of the  restart  costs  were  deferred  with  regulatory  approval;  the
write-off of certain  extraordinary  costs that were  stranded  and  liabilities
incurred in connection with the  restructuring of the regulation of the electric
utility business in Ohio, Virginia, and West Virginia to transition that portion
of AEP's domestic electricity supply business from cost-based rate regulation to
customer choice and market pricing;  the recognition of losses associated with a
CSW  investment  in Chile which was sold in the fourth  quarter;  an  impairment
writedown  of AEP's  investment  in  Yorkshire  to reflect a pending sale of the
investment in 2001; and write-offs of unrecoverable  contract costs and goodwill
on certain of CSW's non-regulated businesses acquired in the merger.

        Earnings in 2001 are expected to improve  significantly  with the return
of Cook Plant's 2,110 MW of generating capacity due to the completion of restart
efforts and the cessation of significant restart costs at Cook and the growth of
our wholesale marketing and trading business.

        Our focus for 2001 will be on completing our corporate  separation  plan
to separate  our  regulated  and  non-regulated  businesses.  We believe  that a
successful  implementation  of this plan will support our business  objective of
unlocking  shareholder  value by  providing  managers  with a simpler  structure
through  which  business unit  performance  can be more easily  anticipated  and
monitored  thereby  focusing  management  attention;  permitting  more efficient
financing;  and  meeting  the  regulatory  codes of conduct  required as part of
industry restructuring.

      Although  management  expects  that the  future  outlook  for  results  of
operations is excellent  there are  contingencies,  challenges  and obstacles to
overcome  and  manage,  such as new more  stringent  Federal  EPA  environmental
requirements  and recent  complaints and related  litigation,  further delays in
transition to competition supported in part by concerns that California's energy
crisis could happen in our service territory, the recovery of generation-related
regulatory  assets and other stranded  costs in Texas and any  additional  state
jurisdictions  that we can successfully  promote the adoption of customer choice
and a transition to market pricing from  regulated  rate setting,  franchise fee
litigation in Texas, litigation concerning AEP's financial disclosures regarding
the extended Cook Plant safety outage and timing of the successful completion of
restart  efforts,  the  amortization  of transition  regulatory  assets from the
introduction  of  competition to our previously  regulated  domestic  generation
business and the  amortization  of deferred costs from the successful  effort to
restart  Cook Plant and to merge AEP and CSW and the  outcome of  litigation  to
recover  $90  million  of  duplicate  tax  expense  from May 2001 to April  2002
resulting  from  restructuring  in Ohio.  These  challenges,  contingencies  and
obstacles,  which are discussed in detail in the Notes to Consolidated Financial
Statements and in Management's  Discussion and Analysis of Financial  Condition,
Contingencies and Other Matters,  are receiving  management's full attention and
we intend to work  diligently  to resolve  these  matters  by  finding  workable
solutions  that balance the  interests of our  customers,  our employees and our
shareholders.

Results of Operations
Net Income

        Although revenues  increased by $1.3 billion net income declined to $267
million or $0.83 per share in 2000 from $972 million or $3.03 per share in 1999.
The  decrease  was  primarily  due  to  Cook  Nuclear  Plant  restart  costs,  a
disallowance  of tax  deductions  for  corporate  owned life  insurance  (COLI),
expensing of costs related to AEP's  recently  completed  merger with CSW, write
offs related to non-regulated  subsidiaries  and an extraordinary  loss from the
discontinuance  of regulatory  accounting for generation in certain  states.  In
1999 net income was virtually  un-changed  as increased  expenses to prepare the
Cook Nuclear Plant for restart, net of related deferrals,  were offset by a gain
from a sale of a 50% interest in a cogeneration project.

Revenues Increase

        AEP's revenues  include a significant  number of  transactions  from the
trading  of  electricity  and gas.  Revenues  from  trading of  electricity  are
recorded net of  purchases  as domestic  electric  utility  wholesale  sales for
transactions in AEP's traditional marketing area (up to two transmission systems
from the AEP service  territory) and as revenues from worldwide electric and gas
operations for transactions  beyond two transmission  systems from AEP. Revenues
from gas trading are  recorded net of  purchases  and reported in revenues  from
worldwide electric and gas operations. Trading transactions involve the purchase
and sale of substantial amounts of electricity and gas.

        The level of electricity trading trans-actions tends to fluctuate due to
the highly  competitive  nature of the short-term (spot) energy market and other
factors,  such as af-filiated and unaffiliated  generating plant  avail-ability,
weather  conditions and the economy.  The FERC rules, which introduced a greater
degree of competition into the wholesale energy market,  have had a major effect
on the  volume  of  electricity  trading  as most  electricity  is traded in the
short-term market.
        AEP's total  revenues  increased  10% in 2000 and 5% in 1999.  The table
below shows the changes in the  components of revenues  from  domestic  electric
utility  operations and worldwide  electric and gas operations.  While worldwide
electric and gas operations revenues increased 12% in 2000, most of the increase
in total  revenues was caused by the increased  revenues from domestic  electric
utility operations.

                      Increase (Decrease)
                      From Previous Year
(Dollars in Millions)  2000         1999
                    Amount   %   Amount   %
Domestic Electric
 Utility Operations:
  Retail:
   Residential      $  230       $  18
   Commercial          163          56
   Industrial          (71)         11
   Other                25           7
                    ------       -----
                       347  4.2     92   1.1

  Wholesale            672 59.9   (145)(11.5)
  Other                (30)(6.8)    57  15.3
                    ------       -----

    Total Domestic
     Electric Utility
     Operations        989 10.1      4    -

Worldwide Electric
 and Gas Operations    298 11.6    563  28.1
                    ------       -----

     Total          $1,287 10.4  $ 567   4.8
                    ======       =====

        The increase in total revenues from domestic electric utility operations
in 2000 was  primarily  due to a 38%  increase  in  wholesale  sales  volume and
increased retail fuel revenues as a result of higher gas prices used to generate
electricity. The reduction in industrial revenues in 2000 is attributable to the
expiration  of a long-term  contract  on  December  31,  1999.  The  significant
increase in  wholesale  sales  volume,  which  accounted  for a 60%  increase in
wholesale  revenues,  resulted  from efforts to grow AEP's energy  marketing and
trading  operations,  favorable  market  conditions,  and  the  availability  of
additional  generation  due to the  return to  service  of one of the Cook Plant
nuclear units in June 2000 and improved  generating unit availability due mainly
to improved  outage  management.  The second  Cook Plant unit which  returned to
service in December 2000 did not have a significant impact on revenues.





        In  1999  revenues  from  domestic  electric  utility   operations  were
unchanged. A 1% gain in retail revenues was more than offset by a 12% decline in
wholesale  revenues.   The  12%  decline  in  wholesale  revenues  in  1999  was
predominantly due to a decrease in wholesale energy sales and a reduction in net
revenues  from  power  trading  due to a decline in  margins.  The  decrease  in
wholesale  sales  reflects the expiration in July 1998 of a power contract which
supplied  power to  several  municipal  customers  and the  decision  by another
wholesale  customer  who buys energy  under a unit power  agreement  not to take
energy from AEP during an outage of that unit. The decline in wholesale  margins
in 1999 reflects the moderation of weather and the effected  capacity  shortages
experienced in the summer of 1998.

        Revenues from  worldwide  electric and gas  operations  increased 12% in
2000 due to  increased  natural gas and gas liquid  product  prices.  Volumes of
natural gas remained consistent with the prior year,  however,  prices increased
significantly.

        In 1999  revenues  derived from  worldwide  electric and gas  operations
increased  28%. This increase is primarily due to the  acquisitions  in December
1998,  of CitiPower in Australia and of LIG, and the  commercial  operation of a
two-unit 250 MW coal-fired generating plant in China.


Operating Expenses Increase

        Changes in the components of operating expenses were as follows:

                      Increase (Decrease)
                      From Previous Year
(Dollars in Millions)   2000        1999
                  Amount    %   Amount   %

Fuel and
 Purchased Power  $  679  19.7   $ (6) (0.2)
Maintenance and
 Other Operation     342  12.8     79   3.0
Merger Costs         203    -      -     -
Depreciation and
  Amortization        51   5.0     22   2.2
Taxes Other Than
  Income Taxes         7   1.1      5   0.8
Worldwide Electric
  and Gas
  Operations         304  13.3    422  22.7
                  ------         ----
      Total       $1,586  15.7   $522   5.5
                  ======         ====

        Fuel  and  purchased  power  expense  increased  20%  in  2000  due to a
significant increase in the cost of natural gas used for generation. Natural gas
usage for  generation  declined 5% while the cost of natural gas  consumed  rose
60%. Net income was not impacted by this  significant  cost  increase due to the
operation of fuel recovery mechanisms.  These fuel recovery mechanisms generally
provide for the  deferral  of fuel costs above the amounts  included in rates or
the  accrual of  revenues  for fuel  costs not yet  recovered.  Upon  regulatory
commission  review and approval of the  unrecovered  fuel costs,  the accrued or
deferred amounts are billed to customers.

        The  increase in  maintenance  and other  operation  expense in 2000 was
mainly due to increased expenditures to prepare the Cook Plant nuclear units for
restart  following an extended NRC monitored  outage and increased  usage of and
prices for  emissions  allowances.  The  increase  in Cook Plant  restart  costs
resulted  from the effect of deferring  restart costs in 1999 and an increase in
the  restart  expenditure  level.  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 and Unit 1 returned to service
in December and achieved full power  operation on January 3, 2001.  The increase
in emission  allowance  usage and prices  resulted from the stricter air quality
standards  of  Phase II of the  1990  Clean  Air Act  Amendments,  which  became
effective on January 1, 2000.  The increase in maintenance  and other  operation
expense in 1999 was  primarily due to a NRC required  10-year  inspection of STP
Units 1 and 2 and increased expenditures to prepare the Cook Plant nuclear units
for restart.  Although a portion of Cook Plant  restart  costs were  deferred in
1999  pursuant  to  regulatory  orders,  net  expenditures  charged  to  expense
increased over 1998.

        With the  consummation of the merger with CSW,  certain  deferred merger
costs were expensed.  The merger costs charged to expense  included  transaction
and transition  costs not allocable to and  recoverable  from  ratepayers  under
regulatory  commission  approved  settlement  agreements  to  share  net  merger
savings.

        Worldwide  electric and gas operations  expense in 2000 increased 13% to
$2.6 billion from $2.3 billion.  The increase was due to the increase in natural
gas  prices,  the  write  down  to  market  value  of a  CSW  available-for-sale
investment  in a  Chilean-based  electric  company sold in December 2000 and the
effect of a gain in 1999 on the planned sale of a 50% interest in a cogeneration
project.  Federal law limits ownership in qualifying  cogeneration facilities to
50%. CSW Energy constructed the project and completed the sale of a 50% interest
in the project to an  unaffiliated  entity in 1999.  Expenses  of the  worldwide
electric and gas operations increased in 1999 due to the addition of expenses of
businesses  acquired in December 1998 and the start of  commercial  operation of
the two-unit 250 MW coal-fired generating plant in China.




Interest and Preferred Dividends

        In 2000  interest  and  preferred  stock  dividends  increased by 16% to
$1,160 million from $996 million in 1999 due to additional interest expense from
the ruling on the litigation with the government disallowing COLI tax deductions
and AEP's intention to maintain  flexibility for corporate separation by issuing
short-term debt at flexible rates. The use of fixed interest rate swaps has been
employed to mitigate the risk from floating interest rates.

        The 11% increase in interest and preferred  stock  dividends in 1999 was
due primarily to increased  interest  expense on long-term debt.  Long-term debt
outstanding increased $564 million in 1999.

Other Income

        Other income  decreased from $139 million in 1999 to $33 million in 2000
primarily  due to a  write-down  of AEP's  Yorkshire  investment  to  reflect  a
proposed sale in 2001, losses of non-regulated  subsidiaries accounted for on an
equity basis, and a charge for the  discontinuance  of an electric storage water
heater demand side management program.

        Other income  increased 46% in 1999 primarily due to gains from the sale
of  investments  at SEEBOARD and from interest  income related to a cogeneration
power plant.

Income Taxes

        Income taxes increased in 2000 primarily due to an unfavorable ruling in
AEP's suit against the government over interest  deductions  claimed relating to
AEP's COLI program and nondeductible merger related costs.



<PAGE>
<TABLE>
<CAPTION>


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Income
------------------------------------------------------------------------------
(in millions - except per share amounts)

                                                           Year Ended December 31,
                                                    -------------------------------------
                                                     2000           1999           1998
                                                     ----           ----           ----

REVENUES:
<S>                                                 <C>            <C>            <C>
  Domestic Electric Utility Operations              $10,827        $ 9,838        $ 9,834
  Worldwide Electric and Gas Operations               2,867          2,569          2,006
                                                    -------        -------        -------

          TOTAL REVENUES                             13,694         12,407         11,840
                                                    -------        -------        -------

EXPENSES:
  Fuel and Purchased Power                            4,128          3,449          3,455
  Maintenance and Other Operation                     3,017          2,675          2,596
  Non-recoverable Merger Costs                          203           -              -
  Depreciation and Amortization                       1,062          1,011            989
  Taxes Other Than Income Taxes                         671            664            659
  Worldwide Electric and Gas Operations               2,587          2,283          1,861
                                                    -------        -------        -------

          TOTAL EXPENSES                             11,668         10,082          9,560
                                                    -------        -------        -------

OPERATING INCOME                                      2,026          2,325          2,280

OTHER INCOME (net)                                       33            139             95
                                                    -------        -------        --------

INCOME BEFORE INTEREST, PREFERRED
  DIVIDENDS AND INCOME TAXES                          2,059          2,464          2,375

INTEREST AND PREFERRED DIVIDENDS                      1,160            996            898
                                                    -------        -------        -------

INCOME BEFORE INCOME TAXES                              899          1,468          1,477

INCOME TAXES                                            597            482            502
                                                    -------        -------        -------

INCOME BEFORE EXTRAORDINARY ITEM                        302            986            975

EXTRAORDINARY LOSSES:
 DISCONTINUANCE OF REGULATORY ACCOUNTING
  FOR GENERATION                                        (35)            (8)          -
 LOSS ON REACQUIRED DEBT                               -                (6)          -
                                                    -------        -------        --------
NET INCOME                                          $   267        $   972        $   975
                                                    =======        =======        =======

AVERAGE NUMBER OF SHARES OUTSTANDING                    322            321            318
                                                        ===            ===            ===

EARNINGS PER SHARE:
  Income Before Extraordinary Item                   $ 0.94          $3.07          $3.06
  Extraordinary Losses                                (0.11)          (.04)           -
                                                     ------          -----          ------
  Net Income                                         $ 0.83          $3.03          $3.06
                                                     ======          =====          =====

CASH DIVIDENDS PAID PER SHARE                        $ 2.40          $2.40          $2.40
                                                     ======          =====          =====

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


</TABLE>


<PAGE>
<TABLE>
<CAPTION>

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
----------------------------------------------------------------------------------------------------------------------------
(in millions - except share data)

                                  December 31,
                                                         2000             1999
                                                         ----             ----
ASSETS

CURRENT ASSETS:
<S>                                                     <C>              <C>
  Cash and Cash Equivalents                             $   437          $   609
  Special Deposits                                         -                  50
  Accounts Receivable:
    Customers                                               827              553
    Miscellaneous                                         2,883            1,486
    Allowance for Uncollectible Accounts                    (11)             (12)
  Energy Trading Contracts                               16,627            1,001
  Other                                                   1,268            1,311
                                                        -------          -------

          TOTAL CURRENT ASSETS                           22,031            4,998
                                                        -------          -------

PROPERTY PLANT AND EQUIPMENT:
  Electric:
    Production                                           16,328           15,869
    Transmission                                          5,609            5,495
    Distribution                                         10,843           10,432
  Other (including gas and coal mining assets
    and nuclear fuel)                                     4,077            4,081
  Construction Work in Progress                           1,231            1,061
                                                        -------          -------
           Total Property, Plant and Equipment           38,088           36,938
  Accumulated Depreciation and Amortization              15,695           15,073
                                                        -------          -------

          NET PROPERTY, PLANT AND EQUIPMENT              22,393           21,865
                                                        -------          -------

REGULATORY ASSETS                                         3,698            3,464
                                                        -------          -------

INVESTMENTS IN POWER AND COMMUNICATIONS PROJECTS            782              862
                                                        -------          -------

GOODWILL (NET OF AMORTIZATION)                            1,382            1,531
                                                        -------          -------

LONG-TERM ENERGY TRADING CONTRACTS                        1,620              136
                                                        -------          -------

OTHER ASSETS                                              2,642            2,863
                                                        -------          -------

            TOTAL                                       $54,548          $35,719
                                                        =======          =======

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

</TABLE>

<PAGE>
<TABLE>
<CAPTION>


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
------------------------------------------------------------------------------------

                                                                   December 31,
                                                                2000          1999
                                                                ----          ----
LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
<S>                                                           <C>           <C>
  Accounts Payable                                            $ 2,627       $ 1,280
  Short-term Debt                                               4,333         3,012
  Long-term Debt Due Within One Year*                           1,152         1,367
  Energy Trading Contracts                                     16,801           964
  Other                                                         2,154         1,443
                                                              -------       -------

          TOTAL CURRENT LIABILITIES                            27,067         8,066
                                                              -------       -------


LONG-TERM DEBT*                                                 9,602        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                                           4,875         5,150
                                                              -------       -------

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2       203           213
                                                              -------       -------

DEFERRED INVESTMENT TAX CREDITS                                   528           580
                                                              -------       -------

LONG-TERM ENERGY TRADING CONTRACTS                              1,381           108
                                                              -------       -------

DEFERRED CREDITS AND REGULATORY LIABILITIES                       637           607
                                                              -------       -------

OTHER NONCURRENT LIABILITIES                                    1,706         1,648
                                                              -------       -------

CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES*                       161           182
                                                              -------       -------

COMMITMENTS AND CONTINGENCIES (Note 8)

COMMON SHAREHOLDERS' EQUITY:
  Common Stock-Par Value $6.50:
                            2000          1999
                            ----          ----
    Shares Authorized. .600,000,000   600,000,000
    Shares Issued. . . .331,019,146   330,692,317
    (8,999,992 shares were held in treasury
     at December 31, 2000 and 1999)                             2,152         2,149
  Paid-in Capital                                               2,915         2,898
  Accumulated Other Comprehensive Income (Loss)                  (103)           (4)
  Retained Earnings                                             3,090         3,630
                                                              -------       -------

          TOTAL COMMON SHAREHOLDERS' EQUITY                     8,054         8,673
                                                              -------       -------

            TOTAL                                             $54,548       $35,719
                                                              =======       =======

*See Accompanying Schedules.

</TABLE>

<PAGE>
<TABLE>
<CAPTION>


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
--------------------------------------------------------------------------------------------------------------------------------
(in millions)

                            Year Ended December 31,
                                                   2000            1999            1998
                                                   ----            ----            ----

OPERATING ACTIVITIES:
<S>                                              <C>             <C>              <C>
  Net Income                                     $   267         $   972          $   975
  Adjustments for Noncash Items:
    Depreciation and Amortization                  1,299           1,294            1,171
    Deferred Federal Income Taxes                   (170)            180               (2)
    Deferred Investment Tax Credits                  (36)            (38)             (37)
    Amortization (Deferral) of Operating
      Expenses and Carrying Charges (net)             48            (151)              15
    Equity in Earnings of Yorkshire
      Electricity Group plc                          (44)            (45)             (38)
    Extraordinary Item                                35              14             -
    Deferred Costs Under Fuel Clause Mechanisms     (449)           (191)              36
  Changes in Certain Current Assets
    and Liabilities:
      Accounts Receivable (net)                   (1,632)            (80)            (329)
      Fuel, Materials and Supplies                   147            (162)             (23)
      Accrued Utility Revenues                       (79)            (35)               5
      Accounts Payable                             1,322              74              270
      Taxes Accrued                                  172              29               20
  Payment of Disputed Tax and Interest
    Related to COLI                                  319             (16)            (303)
  Other (net)                                        304            (231)             195
                                                 -------         -------          -------
        Net Cash Flows From Operating Activities   1,503           1,614            1,955
                                                 -------         -------          -------

INVESTING ACTIVITIES:
  Construction Expenditures                       (1,773)         (1,680)          (1,396)
  Investment in CitiPower                           -               -              (1,054)
  Investment in Gas Assets                          -               -                (340)
  Other                                               19               7              (54)
                                                 -------         -------          -------
        Net Cash Flows Used For
          Investing Activities                    (1,754)         (1,673)          (2,844)
                                                 -------         -------          -------

FINANCING ACTIVITIES:
  Issuance of Common Stock                            14              93               96
  Issuance of Long-term Debt                       1,124           1,391            2,645
  Retirement of Cumulative Preferred Stock           (20)           (170)             (28)
  Retirement of Long-term Debt                    (1,565)           (915)          (1,101)
  Change in Short-term Debt (net)                  1,308             812              264
  Dividends Paid on Common Stock                    (805)           (833)            (827)
  Other Financing Activities                        -                (43)            -
                                                 -------         -------          -------
        Net Cash Flows From Financing Activities      56             335            1,049
                                                 -------         -------          -------

Effect of Exchange Rate Change on Cash                23              (2)            -
                                                 -------         -------          -------

Net Increase (Decrease) in Cash and
 Cash Equivalents                                   (172)            274              160
Cash and Cash Equivalents January 1                  609             335              175
                                                 -------         -------          -------
Cash and Cash Equivalents December 31            $   437         $   609          $   335
                                                 =======         =======          =======

See Notes to Consolidated 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
------------------------------------------------------------------------------------------------------------
(in millions)
                                                                                  Accumulated
                                                                                  Other
                   Common Stock Paid-In Retained Comprehensive
                                            Shares  Amount   Capital   Earnings   Income (Loss)   Total

<S>                                          <C>    <C>      <C>       <C>        <C>            <C>
JANUARY 1, 1998                              326    $2,036   $2,818    $3,356     $  23          $8,233
Conforming Change in Accounting Policy        -       -        -          (13)       -              (13)
Reclassification Adjustment                   -         85      (85)     -           -             -
                                             ---    ------   ------    ------     -----          ------
Adjusted Balance at Beginning of Period      326     2,121    2,733     3,343        23           8,220
Issuances                                      2        13       83      -           -               96
Retirements and Other                         -       -           2         3        -                5
Cash Dividends Declared                       -       -        -         (827)       -             (827)
                                                                                                 ------
                                                                                                  7,494
Comprehensive Income:
 Other Comprehensive Income, Net of Taxes
  Foreign Currency Translation Adjustment     -       -        -         -            6               6
  Unrealized Loss on Securities               -       -        -         -          (14)            (14)
  Adjustments for Gain
   Included in Net Income                     -       -        -         -           (7)             (7)
  Minimum Pension Liability                   -       -        -         -           (1)             (1)
  Net Income                                  -       -        -          975        -              975
                                                                                                 ------
   Total Comprehensive Income                                                                       959
                                             ---    ------   ------   -------     -----          ------

DECEMBER 31, 1998                            328     2,134    2,818     3,494         7           8,453
Conforming Change in Accounting Policy        -       -        -           (1)      -                (1)
                                             ---    ------   ------   -------     -----          ------
Adjusted Balance at Beginning of Period      328     2,134    2,818     3,493         7           8,452
Issuances                                      3        15       77      -          -                92
Retirements and Other                         -       -           3      -          -                 3
Cash Dividends Declared                       -       -        -         (833)      -              (833)
                                                                                                 ------
                                                                                                  7,714
Comprehensive Income:
 Other Comprehensive Income, Net of Taxes
  Foreign Currency Translation Adjustment     -       -        -         -          (13)            (13)
  Minimum Pension Liability                   -       -        -         -            2               2
  Net Income                                  -       -        -          972       -               972
                                                                                                 ------
   Total Comprehensive Income                                                                       961
                                             ---    ------   ------   -------     -----          -------

DECEMBER 31, 1999                            331     2,149    2,898     3,632        (4)          8,675
Conforming Change in Accounting Policy        -       -        -           (2)      -                (2)
                                             ---     -----    -----     -----     -----          ------
Adjusted Balance at Beginning of Period      331     2,149    2,898     3,630        (4)          8,673
Issuances                                     -          3       11      -          -                14
Cash Dividends Declared                       -       -        -         (805)      -              (805)
Other                                         -       -           6        (2)      -                 4
                                                                                                 ------
                                                                                                  7,886
Comprehensive Income:
 Other Comprehensive Income, Net of Taxes
  Foreign Currency Translation Adjustment     -       -        -         -         (119)           (119)
  Reclassification Adjustment
   For Loss Included in Net Income            -       -        -         -           20              20
  Net Income                                  -       -        -          267       -               267
                                                                                                 ------
   Total Comprehensive Income                                                                       168
                                             ---    ------   ------     ------    -----          -------

DECEMBER 31, 2000                            331    $2,152   $2,915     $3,090    $(103)         $8,054
                                             ===    ======   ======     ======    =====          ======


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


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


AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
--------------------------------------------------------------------------------------------------------

                                                             December 31, 2000
                                       -----------------------------------------------------------------
                                         Call
                                       Price per             Shares              Shares       Amount (In
                                       Share (a)           Authorized(b)      Outstanding(g)  Millions)
--------------------------------------------------------------------------------------------------------

Not Subject to Mandatory Redemption:
<S>                                    <C>                    <C>                  <C>         <C>
  4.00% - 5.00%                        $102-$110              1,525,903            614,608     $ 61
                                                                                               ====

Subject to Mandatory Redemption:
  5.90% - 5.92% (c)                       (d)                 1,950,000            333,100     $ 33
  6.02% - 6-7/8% (c)                      (e)                 1,650,000            513,450       52
  7% (f)                                  (f)                   250,000            150,000       15
                                                                                               ----
    Total Subject to Mandatory
      Redemption (c)                                                                           $100
                                                                                               ====



                                                             December 31, 1999
                                       -----------------------------------------------------------------
                                         Call
                                       Price per             Shares              Shares       Amount (In
                                       Share (a)           Authorized(b)      Outstanding(g)  Millions)
--------------------------------------------------------------------------------------------------------

Not Subject to Mandatory Redemption:
  4.00% - 5.00%                        $102-$110            1,525,903            629,671       $ 63
                                                                                               ====

Subject to Mandatory Redemption:
  5.90% - 5.92% (c)                       (d)               1,950,000            343,100       $ 34
  6.02% - 6-7/8% (c)                      (e)               1,950,000            597,950         60
  7% (f)                                  (f)                 250,000            250,000         25
                                                                                               ----
    Total Subject to Mandatory
      Redemption (c)                                                                           $119
                                                                                               ====
NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES

(a)    At the option of the  subsidiary  the shares may be  redeemed at the call
       price plus accrued dividends.  The involuntary  liquidation preference is
       $100 per share for all outstanding shares.
(b)    As of December 31, 2000 the subsidiaries  had 13,592,750,  22,200,000 and
       7,713,495  shares  of  $100,  $25  and  no  par  value  preferred  stock,
       respectively, that were authorized but unissued.
(c)    Shares  outstanding  and  related  amounts  are stated net of  applicable
       retirements through sinking funds(generally at par) and reacquisitions of
       shares  in  anticipation  of  future   requirements.   The   subsidiaries
       reacquired enough shares in 1997 to meet all sinking fund requirements on
       certain  series  until  2008 and on  certain  series  until 2009 when all
       remaining
       outstanding  shares must be redeemed.  The sinking fund provisions of the
       series subject to mandatory redemption aggregate (after deducting sinking
       fund  requirements)  of $5 million  in 2002,  $12  million  in 2003,  $12
       million in 2004 and $2 million in 2005.
(d)    Not callable prior to 2003; after that the call price is $100 per share.
(e)    Not callable prior to 2000; after that the call price is $100 per share.
(f)    With sinking fund.
(g)      The number of shares of preferred stock redeemed is 209,563 shares in 2000, 1,698,276 shares in
      1999 and 281,250 shares in 1998.


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



AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Long-term Debt of Subsidiaries
----------------------------------------------------------------------------------------------------------------

                              Weighted Average
Maturity                        Interest Rate    Interest Rates at December 31,        December 31,
--------                      -----------------  ------------------------------   ----------------------
                              December 31, 2000       2000            1999         2000          1999
                              -----------------       ----            ----         ----          ----
                                                                                       (in millions)
                                                                                       -------------

FIRST MORTGAGE BONDS
<S>                                  <C>           <C>             <C>            <C>           <C>
  2000-2003                          6.96%         5.91%-8.95%     5.25%-8.95%    $ 1,247       $ 1,621
  2004-2008                          6.97%         6-1/8%-8%       6-1/8%-8%        1,140         1,148
  2020-2025                          7.74%         6-7/8%-8.80%    6-7/8%-8.80%     1,104         1,172

INSTALLMENT PURCHASE CONTRACTS (a)
  2000-2009                          5.53%         4.90%-7.70%     4.80%-7.70%        234           235
  2011-2030                          6.02%         4.875%-8.20%    3.332%-8.20%     1,447         1,477

NOTES PAYABLE (b)
  2000-2021                          7.14%         6.20%-9.60%     5.8675%-9.60%    1,181         2,030

SENIOR UNSECURED NOTES
  2000-2004                          6.99%         6.50%-7.45%     6.07%-7.45%      2,049         1,403
  2005-2009                          6.59%         6.24%-6.91%     6.24%-6.91%        475           488
  2038                               7.30%         7.20%-7-3/8%    7.20%-7-3/8%       340           340

JUNIOR DEBENTURES
  2025-2038                          8.05%         7.60%-8.72%     7.60%-8.72%        620           620

YANKEE BONDS AND EURO BONDS
  2001-2006                          8.51%         7.98%-8.875%    7.98%-8.875%       684           742

OTHER LONG-TERM DEBT (c)                                                              280           300

Unamortized Discount (net)                                                            (47)          (52)
                                                                                  -------       -------
Total Long-term Debt
  Outstanding (d)                                                                  10,754        11,524
Less Portion Due Within One Year                                                    1,152         1,367
                                                                                  -------       -------
Long-term Portion                                                                 $ 9,602       $10,157
                                                                                  =======       =======

NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES

(a) For certain  series of  installment  purchase  contracts  interest rates are
subject to periodic  adjustment.  Certain  series will be purchased on demand at
periodic  interest-adjustment  dates.  Letters of credit  from banks and standby
bond purchase agreements support certain series.
(b) Notes payable represent outstanding  promissory notes issued under term loan
agreements  and  revolving  credit  agreements  with a number of banks and other
financial institutions.  At expiration all notes then issued and outstanding are
due and payable.  Interest  rates are both fixed and  variable.  Variable  rates
generally  relate to specified  short-term  interest rates.  (c) Other long-term
debt consists of a liability  along with accrued  interest for disposal of spent
nuclear fuel (see Note 8 of the Notes to Consolidated  Financial Statements) and
financing  obligation  under sale  lease back  agreements.  (d)  Long-term  debt
outstanding at December 31, 2000 is payable as follows:

     Principal Amount (in millions)

     2001                $ 1,152
     2002                  1,167
     2003                  1,628
     2004                    884
     2005                    616
     Later Years           5,354
                         -------
       Total Principal
            Amount        10,801
        Unamortized
          Discount           (47)
                         -------
            Total        $10,754
                         =======


</TABLE>
<PAGE>


AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES
Index to Notes  to Consolidated Financial Statements
-----------------------------------------------------------------------------

The notes listed below are combined with the notes to financial  statements  for
AEP and its other subsidiary  registrants.  The combined footnotes begin on page
L-1.

                                                     Combined
                                                     Footnote
                                                     Reference

Significant Accounting Policies                      Note 1

Extraordinary Items                                  Note 2

Merger                                               Note 3

Nuclear Plant Restart                                Note 4

Rate Matters                                         Note 5

Effects of Regulation                                Note 6

Industry Restructuring                               Note 7

Commitments and Contingencies                        Note 8

Acquisitions                                         Note 9

International Investments                            Note 10

Staff Reductions                                     Note 11

Benefit Plans                                        Note 12

Stock-Based Compensation                             Note 13

Business Segments                                    Note 14

Financial Instruments, Credit and Risk Management    Note 15

Income Taxes                                         Note 16

Supplementary Information                            Note 17

Leases                                               Note 18

Lines of Credit and Factoring of Receivables         Note 19

Unaudited Quarterly Financial Information            Note 20

Trust Preferred Securities                           Note 21





<PAGE>


MANAGEMENT'S RESPONSIBILITY
------------------------------------------------------------------

         The management of American Electric Power Company,  Inc. is responsible
for the integrity and objectivity of the information and representations in this
annual report, including the consolidated financial statements. These statements
have been prepared in conformity with generally accepted accounting  principles,
using informed estimates where appropriate,  to reflect the Company's  financial
condition and results of  operations.  The  information in other sections of the
annual report is consistent with these statements.

         The Company's  Board of Directors has  oversight  responsibilities  for
determining  that  management has fulfilled its obligation in the preparation of
the  financial  statements  and  in the  ongoing  examination  of the  Company's
established  internal  control  structure  over financial  reporting.  The Audit
Committee, which consists solely of outside directors and which reports directly
to the Board of Directors,  meets regularly with  management,  Deloitte & Touche
LLP -  independent  auditors and the Company's  internal  audit staff to discuss
accounting, auditing and reporting matters. To ensure auditor independence, both
Deloitte & Touche LLP and the internal audit staff have  unrestricted  access to
the Audit Committee.

         The  financial  statements  have been audited by Deloitte & Touche LLP,
whose  report  appears  on the next page.  The  auditors  provide an  objective,
independent review as to management's discharge of its responsibilities  insofar
as they relate to the fairness of the Company's reported financial condition and
results of  operations.  Their  audit  includes  procedures  believed by them to
provide reasonable  assurance that the financial statements are free of material
misstatement  and  includes an  evaluation  of the  Company's  internal  control
structure over financial reporting.





<PAGE>


INDEPENDENT AUDITORS' REPORT
------------------------------------------------------------------------------


To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:

         We have audited the  consolidated  balance sheets of American  Electric
Power Company,  Inc. and its  subsidiaries as of December 31, 2000 and 1999, and
the related  consolidated  statements of income,  comprehensive  income,  common
shareholders'  equity,  and cash flows for each of the three years in the period
ended December 31, 2000. These financial  statements are the  responsibility  of
the Company's  management.  Our  responsibility  is to express an opinion on the
financial statements based on our audits. The consolidated  financial statements
give retroactive  effect to the merger of American Electric Power Company,  Inc.
and  its   subsidiaries   and  Central  and  South  West   Corporation  and  its
subsidiaries,  which  has  been  accounted  for as a  pooling  of  interests  as
described in Note 3 to the consolidated  financial statements.  We did not audit
the  consolidated  balance sheet of Central and South West  Corporation  and its
subsidiaries as of December 31, 1999, or the related consolidated  statements of
income,  comprehensive  income,  common shareholders' equity, and cash flows for
the years ended  December  31, 1999 and 1998,  which  statements  reflect  total
assets of  $14,162,000,000  as of  December  31,  1999,  and total  revenues  of
$5,537,000,000  and  $5,482,000,000  for the years ended  December  31, 1999 and
1998,  respectively.  Those  consolidated  statements,  before  the  restatement
described in Note 3, were audited by other auditors whose report, dated February
25, 2000,  has been  furnished to us, and our opinion,  insofar as it relates to
those  amounts   included  for  Central  and  South  West  Corporation  and  its
subsidiaries  for 1999 and 1998,  is based  solely on the  report of such  other
auditors.

         We conducted our audits in accordance with auditing standards generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial statement  presentation.  We believe that our audits and the report of
the other auditors provide a reasonable basis for our opinion.

         In our  opinion,  based  on our  audits  and the  report  of the  other
auditors,  the  consolidated  financial  statements  referred  to above  present
fairly, in all material  respects,  the financial  position of American Electric
Power Company,  Inc. and its  subsidiaries as of December 31, 2000 and 1999, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2000 in conformity with  accounting  principles
generally accepted in the United States of America.

         We also audited the  adjustments  described in Note 3 that were applied
to restate the 1999 and 1998 financial  statements to give retroactive effect to
the  change in the  method of  accounting  for  vacation  pay  accruals.  In our
opinion, such adjustments are appropriate and have been properly applied.



Deloitte & Touche LLP
Columbus, Ohio
February 26, 2001

<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors of
Central and South West Corporation:

We have  audited  the  consolidated  balance  sheets of  Central  and South West
Corporation (a Delaware corporation) and subsidiary companies as of December 31,
1999, and the related  consolidated  statements of income,  stockholders' equity
and cash flows,  for each of the two years in the period ended December 31, 1999
prior to the  restatement  (and,  therefore,  are not presented  herein) for the
retroactive  effect of the  conforming  change in the method of  accounting  for
vacation pay accruals and certain conforming reclassifications to the historical
financial  statements  as  described  in  Note  3 to the  restated  consolidated
financial  statements.  These financial statements are the responsibility of the
Corporation's  management.  Our responsibility is to express an opinion on these
financial  statements  based  on our  audits.  We did not  audit  the  financial
statements  of CSW UK Holdings  (1999) and CSW UK Finance  Company  (1998) which
statements  reflect total assets and total revenues of 20 percent and 31 percent
in 1999, and total revenues of 32 percent in 1998, respectively,  of the related
consolidated  totals.  Those  statements  were audited by other  auditors  whose
reports have been furnished to us, and our opinion, insofar as it relates to the
amounts included for those entities, is based solely on the reports of the other
auditors.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable  assurance about whether the financial  statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting  the amounts and  disclosures in the financial  statements.  An audit
also includes assessing the accounting principles used and significant estimates
made by  management,  as well as  evaluating  the  overall  financial  statement
presentation.  We  believe  that our audits  and the  reports of other  auditors
provide a reasonable basis for our opinion.

In our  opinion,  based on our audits and the  reports  of other  auditors,  the
financial  statements prior to the restatement referred to above present fairly,
in all  material  respects,  the  financial  position  of Central and South West
Corporation and subsidiary companies as of December 31, 1999, and the results of
their  operations  and their  cash flows for each of the two years in the period
ended  December 31, 1999, in conformity  with  accounting  principles  generally
accepted in the United States.






Arthur Andersen LLP

Dallas, Texas
February 25, 2000

<PAGE>

AUDITOR's REPORT TO THE MEMBERS OF CSW UK HOLDINGS

We  have  audited  the  consolidated  balance  sheets  of  CSW UK  Holdings  and
subsidiaries  as of 31 December 1999 and the related  consolidated  statement of
earnings  and  statement  of  cash  flows  for  the  years  then  ended.   These
consolidated  financial  statements  are  the  responsibility  of the  Company's
management.  Our  responsibility is to express an opinion on these  consolidated
financial statements based on our audit.

We conducted our audit in accordance with generally  accepted auditing standards
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable  assurance about whether the financial  statements are free
of material misstatement. An audit includes examining, or a test basis, evidence
supporting  the amounts and  disclosures in the financial  statements.  An audit
also includes assessing the accounting principles used and significant estimates
made by  management  as well  as  evaluating  the  overall  financial  statement
presentation.  We believe  that our audit  provides a  reasonable  basis for our
opinion.

In our opinion, the consolidated  financial statements referred to above and not
included herein present fairly, in all material respects, the financial position
of CSW UK Holdings and  subsidiaries at 31 December 1999 and the result of their
operations  and cash flows for the year then ended in conformity  with generally
accepted accounting principles in the United Kingdom.

Generally accepted  accounting  principles in the United Kingdom vary in certain
significant respects from generally accepted accounting principles in the United
States.  Application of generally accepted  accounting  principles in the United
States would have affected results of operations and shareholders'  equity as of
and for the year ended 31 December 1999 to the extent summarized in the notes to
the consolidated financial statements.





KPMG Audit Plc
Chartered Accountants
London, England

17 January 2000

<PAGE>

AUDITOR'S REPORT TO THE MEMBERS OF CSW UK FINANCE COMPANY

We have audited the  consolidated  balance  sheet of CSW UK Finance  Company and
subsidiaries  as of 31 December 1998 and the related  consolidated  statement of
earnings  and  statements  of  cash  flows  for  the  year  then  ended.   These
consolidated  financial  statements  are  the  responsibility  of the  Company's
management.  Our  responsibility is to express an opinion on these  consolidated
financial statements based on our audit.

We conducted our audit in accordance with generally  accepted auditing standards
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable  assurance about whether the financial  statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting  the amounts and  disclosures in the financial  statements.  An audit
also includes assessing the accounting principles used and significant estimates
made by  management  as well  as  evaluating  the  overall  financial  statement
presentation.  We believe  that our audit  provides a  reasonable  basis for our
opinion.

In our opinion, the consolidated  financial statements referred to above and not
included herein present fairly, in all material respects, the financial position
of CSW UK Finance  Company and  subsidiaries at 31 December 1998 and the results
of their  operations  and cash flows for the year then ended in conformity  with
generally accepted accounting principles in the United Kingdom.

Generally accepted  accounting  principles in the United Kingdom vary in certain
significant respects from generally accepted accounting principles in the United
States.  Application of generally accepted  accounting  principles in the United
States would have affected results of operations and shareholders'  equity as of
and for the year ended 31 December 1998 to the extent summarized in the notes to
the consolidated financial statements.





KPMG Audit Plc
Chartered Accountants
London, England
18 January 1999


<PAGE>















                             AEP GENERATING COMPANY


<PAGE>
<TABLE>
<CAPTION>


                                       B-9
AEP GENERATING COMPANY
Selected Financial
Data
---------------------------------------------------------------------------------------------------------------

                                                   Year Ended December 31,
                                    -----------------------------------------------------
                                      2000       1999       1998       1997       1996
                                      ----       ----       ----       ----       ----
                                                       (in thousands)
INCOME STATEMENTS DATA:

<S>                                 <C>        <C>        <C>        <C>        <C>
  Operating Revenues                $228,516   $217,189   $224,146   $227,868   $225,892
  Operating Expenses                 220,092    211,849    215,415    218,828    215,997
                                    --------   --------   --------   --------   --------
  Operating Income                     8,424      5,340      8,731      9,040      9,895
  Nonoperating Income                  3,429      3,659      3,364      3,603      3,695
                                    --------   --------   --------   --------   --------
  Income Before Interest Charges      11,853      8,999     12,095     12,643     13,590
  Interest Charges                     3,869      2,804      3,149      3,857      4,159
                                    --------   --------   --------   --------   --------
  Net Income                        $  7,984   $  6,195   $  8,946   $  8,786   $  9,431
                                    ========   ========   ========   ========   ========


                                                          December 31,
                                    ------------------------------------------------------
                                      2000       1999       1998       1997       1996
                                      ----       ----       ----       ----       ----
                                                       (in thousands)

BALANCE SHEETS DATA:

  Electric Utility Plant            $642,302   $640,093   $636,460   $633,450   $632,257
  Accumulated Depreciation           315,566    295,065    277,855    257,191    238,532
                                    --------   --------   --------   --------   --------
  Net Electric Utility Plant        $326,736   $345,028   $358,605   $376,259   $393,725
                                    ========   ========   ========   ========   ========

  Total Assets                      $374,602   $398,640   $403,892   $419,058   $442,911
                                    ========   ========   ========   ========   ========


  Common Stock and Paid-in Capital  $ 24,434   $ 30,235   $ 36,235   $ 40,235   $ 45,235
  Retained Earnings                    9,722      3,673      2,770      2,528      1,886
                                    --------   --------   --------   --------   --------
  Total Common Shareholder's Equity $ 34,156   $ 33,908   $ 39,005   $ 42,763   $ 47,121
                                    ========   ========   ========   ========   ========

  Long-term Debt (a)                $ 44,808   $ 44,800   $ 44,792   $ 69,570   $ 89,554
                                    ========   ========   ========   ========   ========

  Total Capitalization
    and Liabilities                 $374,602   $398,640   $403,892   $419,058   $442,911
                                    ========   ========   ========   ========   ========


 (a) Including portion due within one year.
</TABLE>
<PAGE>


AEP GENERATING COMPANY
Management's Narrative Analysis of Results of Operations



<PAGE>



        AEP  Generating  Company is engaged in the generation and wholesale sale
of electric power to two affiliates under long-term agreements.

        Operating  revenues are derived  from the sale of Rockport  Plant energy
and capacity to two affiliated companies, I&M and KPCo pursuant to FERC approved
long-term unit power  agreements.  Under the terms of its unit power  agreement,
I&M is  required  to buy all of AEGCo's  Rockport  capacity  when the unit power
agreement  with KPCo  expires in 2004.  The unit power  agreements  provide  for
recovery of costs  including a FERC approved rate of return on common equity and
a return on other capital net of temporary cash investments.

        Net income  increased $1.8 million or 29% as a result of the recordation
of income tax accrual  adjustments  and an increase in return on other  capital.
Comparative net income was increased by the income tax accrual adjustments since
an unfavorable income tax accrual adjustment was recorded in 1999 and income tax
accrual  adjustments  are not  included in billings  under the terms of the unit
power  agreements.  Return  on other  capital  increased  as a result  of higher
interest charges without an offset for earnings on temporary cash investments in
2000.

        Income statement items which changed significantly were:

                                Increase
                               (Decrease)
(dollars in millions)      From Previous Year
                            Amount        %

Operating Revenues. . . . . $11.3         5
Fuel Expense. . . . . . . .   8.5         9
Maintenance Expense . . . .  (0.9)       (8)
Taxes Other Than Federal
 Income Taxes . . . . . . .   0.5        10
Interest Charges. . . . . .   1.1        38


        The  increase in operating  revenues  reflects  recovery  under the unit
power  agreements  of higher fuel expense and an increase in the return on other
capital.

        Fuel  expense  increased  due to an  increase in  generation  reflecting
greater  availability  of the  Rockport  Plant  generating  units in 2000 and an
increase in the cost of fuel.

        The  decrease  in   maintenance   expense  can  be  attributed  to  cost
containment  efforts and the shorter duration in 2000 of maintenance outages for
boiler inspection and repair than in 1999.

        Taxes other than federal  income taxes  increased  due to an increase in
state income taxes which resulted from an increase in taxable income in 2000 and
adjustments to estimated  prior year taxes  following the filing of the 1999 and
1998 returns.

        The  increase in interest  charges was  primarily  due to an increase in
interest rates in 2000.  AEGCo's long-term debt interest rates are variable on a
daily basis which results in interest charges  adjusting  quickly to market rate
changes.



<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
Statements of Income
------------------------------------------------------------------------------------------


                                                             Year Ended December 31,
                                                       -----------------------------------
                                                         2000         1999         1998
                                                         ----         ----         ----
                                                                 (in thousands)

<S>                                                    <C>          <C>          <C>
OPERATING REVENUES                                     $228,516     $217,189     $224,146
                                                       --------     --------     --------

OPERATING EXPENSES:
  Fuel                                                  102,978       94,481       96,791
  Rent - Rockport Plant Unit 2                           68,283       68,283       68,283
  Other Operation                                        10,295       10,451       10,001
  Maintenance                                             9,616       10,492       11,894
  Depreciation                                           22,162       21,845       21,652
  Taxes Other Than Federal Income Taxes                   5,060        4,585        3,495
  Federal Income Taxes                                    1,698        1,712        3,299
                                                       --------     --------     --------

            TOTAL OPERATING EXPENSES                    220,092      211,849      215,415
                                                       --------     --------     --------

OPERATING INCOME                                          8,424        5,340        8,731

NONOPERATING INCOME                                       3,429        3,659        3,364
                                                       --------     --------     --------

INCOME BEFORE INTEREST CHARGES                           11,853        8,999       12,095

INTEREST CHARGES                                          3,869        2,804        3,149
                                                       --------     --------     --------

NET INCOME                                             $  7,984     $  6,195     $  8,946
                                                       ========     ========     ========


Statements of Retained
Earnings
--------------------------------------------------------------------------------------------------------------------

                                                              Year Ended December 31,
                                                       -----------------------------------
                                                          2000         1999         1998
                                                          ----         ----         ----
                                                                  (in thousands)

RETAINED EARNINGS JANUARY 1                              $3,673       $2,770       $2,528

NET INCOME                                                7,984        6,195        8,946

CASH DIVIDENDS DECLARED                                   1,935        5,292        8,704
                                                         ------       ------       ------

RETAINED EARNINGS DECEMBER 31                            $9,722       $3,673       $2,770
                                                         ======       ======       ======

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

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


AEP GENERATING COMPANY
Balance Sheets
-----------------------------------------------------------------------------------------


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

ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                               <C>           <C>
  Production                                                      $635,215      $629,286
  General                                                            2,795         2,400
  Construction Work in Progress                                      4,292         8,407
                                                                  --------      --------
          Total Electric Utility Plant                             642,302       640,093

  Accumulated Depreciation                                         315,566       295,065
                                                                  --------      --------


          NET ELECTRIC UTILITY PLANT                               326,736       345,028
                                                                  --------      --------





CURRENT ASSETS:
  Cash and Cash Equivalents                                          2,757           317
  Accounts Receivable:
   Affiliated Companies                                             21,374        22,464
   Miscellaneous                                                     2,341         2,643
  Fuel - at average cost                                            11,006        17,505
  Materials and Supplies - at average cost                           3,979         3,966
  Prepayments                                                          145           150
                                                                  --------      --------

          TOTAL CURRENT ASSETS                                      41,602        47,045
                                                                  --------      --------



REGULATORY ASSETS                                                    5,504         5,744
                                                                  --------      --------


DEFERRED CHARGES                                                       760           823
                                                                  --------      --------



                    TOTAL                                         $374,602      $398,640
                                                                  ========      ========

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

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


AEP GENERATING COMPANY
----------------------------------------------------------------------------------------------------------------------------------

                                                                       December 31,
                                                                    2000          1999
                                                                    ----          ----
                                                                      (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - Par Value $1,000:
<S>                                                               <C>           <C>
    Authorized and Outstanding - 1,000 Shares                     $  1,000      $  1,000
  Paid-in Capital                                                   23,434        29,235
  Retained Earnings                                                  9,722         3,673
                                                                  --------      --------
          TOTAL CAPITALIZATION AND COMMON SHAREHOLDER'S EQUITY      34,156        33,908
                                                                  --------      --------


OTHER NONCURRENT LIABILITIES                                           358           592
                                                                  --------      --------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                                44,808        44,800
  Short-term Debt - Notes Payable                                     -           24,700
  Advances from Affiliates                                          28,068          -
  Accounts Payable:
    General                                                          6,109         7,539
    Affiliated Companies                                             7,724        19,451
  Taxes Accrued                                                      4,993         4,285
  Rent Accrued - Rockport Plant Unit 2                               4,963         4,963
  Other                                                              4,443         4,763
                                                                  --------      --------
          TOTAL CURRENT LIABILITIES                                101,108       110,501
                                                                  --------      --------

DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2        122,188       127,759
                                                                  --------      --------

REGULATORY LIABILITIES:
  Deferred Investment Tax Credits                                   59,718        63,114
  Amounts Due to Customers for Income Taxes                         23,996        26,266
                                                                  --------      --------

          TOTAL REGULATORY LIABILITIES                              83,714        89,380
                                                                  --------      --------

DEFERRED INCOME TAXES                                               32,928        36,500
                                                                  --------      --------

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

CONTINGENCIES (Note 8)

                    TOTAL                                         $374,602      $398,640
                                                                  ========      ========

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


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


AEP GENERATING COMPANY
Statements of Cash Flows
------------------------------------------------------------------------------------------

                                                             Year Ended December 31,
                                                       -----------------------------------
                                                         2000         1999         1998
                                                         ----         ----         ----
                                                                 (in thousands)
OPERATING ACTIVITIES:
<S>                                                    <C>          <C>          <C>
  Net Income                                           $  7,984     $  6,195     $  8,946
  Adjustments for Noncash Items:
     Depreciation                                        22,162       21,845       21,652
     Deferred Federal Income Taxes                       (5,842)      (5,282)       5,544
     Deferred Investment Tax Credits                     (3,396)      (3,448)      (3,454)
     Amortization of Deferred Gain on Sale and
       Leaseback - Rockport Plant Unit 2                 (5,571)      (5,571)      (5,571)
  Changes in Certain Current Assets and Liabilities:
     Accounts Receivable                                  1,392       (2,213)      (2,184)
     Fuel, Materials and Supplies                         6,486       (6,263)        (855)
     Accounts Payable                                   (13,157)      14,394        2,892
     Taxes Accrued                                          708        1,058         (193)
  Other (net)                                             1,232       (1,570)       2,542
                                                       --------     --------     --------
         Net Cash Flows From Operating Activities        11,998       19,145       29,319
                                                       --------     --------     --------

INVESTING ACTIVITIES:
  Construction Expenditures                              (5,190)      (8,349)      (6,574)
  Proceeds From Sales of Property                          -             331        2,254
                                                       --------     --------     ---------
         Net Cash Flows Used For Investing Activities    (5,190)      (8,018)      (4,320)
                                                       --------     --------     --------

FINANCING ACTIVITIES:
  Return of Capital to Parent Company                    (5,801)      (6,000)      (4,000)
  Retirement of Long-term Debt                             -            -         (25,000)
  Change in Short-term Debt (net)                       (24,700)         250       12,700
  Change in Advances From Affiliates (net)               28,068         -            -
  Dividends Paid                                         (1,935)      (5,292)      (8,704)
                                                       --------     --------     --------
         Net Cash Flows Used For Financing Activities    (4,368)     (11,042)     (25,004)
                                                       --------     --------     --------

Net Increase (Decrease) in Cash and Cash Equivalents      2,440           85           (5)
Cash and Cash Equivalents January 1                         317          232          237
                                                       --------     --------     --------
Cash and Cash Equivalents December 31                  $  2,757     $    317    $     232
                                                       ========     ========    =========

Supplemental Disclosure:
  Cash paid  (received) for interest net of capitalized  amounts was $3,531,000,
  $2,468,000 and $3,060,000 and for income taxes was $6,820,000,  $6,565,000 and
  $(2,131,000) in 2000, 1999 and 1998, respectively.

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


AEP GENERATING COMPANY
Statements of Capitalization
---------------------------------------------------------------------------------------------

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

<S>                                                            <C>              <C>
COMMON STOCK EQUITY (a)                                        $ 34,156         $ 33,908
                                                               --------         --------

LONG-TERM DEBT
Installment Purchase Contracts - City of Rockport (b)
 Series   Due Date
  1995 A, 2025 (c)                                               22,500           22,500
  1995 B, 2025 (c)                                               22,500           22,500
Unamortized Discount                                               (192)            (200)
Amount Due Within One Year                                      (44,808)         (44,800)
                                                               --------         --------
                                                                   -                -
                                                               --------         --------
TOTAL CAPITALIZATION                                           $ 34,156         $ 33,908
                                                               ========         ========



(a)   In 2000,  1999 and 1998,  AEGCo returned  capital to AEP in the amounts of
      $5.8 million, $6 million and $4 million, respectively. There were no other
      material transactions  affecting common stock and paid-in capital in 2000,
      1999 and 1998.
(b)      Installment  purchase  contracts were entered into in connection  with
      the issuance of pollution  control revenue bonds by the
      City of Rockport,  Indiana.  Under the terms of the installment  purchase
      contracts,  AEGCo is required to pay amounts sufficient
      to enable the  payment of interest  and  principal  on the related
      pollution  control  revenue  bonds  issued to  refinance  the
      construction  costs of pollution  control  facilities  at the Rockport
      Plant.  On the Series 1995 A and B bonds the principal is
      payable at  maturity  or on the  demand of  bondholders.  AEGCo has
      agreements  that  provide  for  brokers  to  remarket  bonds
      tendered.  In the event the bonds cannot be  remarketed,  AEGCo has a
      standby bond purchase  agreement  with a bank that provides
      for the bank to purchase any bonds not remarketed.  The purchase
      agreement expires in 2001.  Therefore,  the installment purchase
      contracts have been reclassified as due within one year.
(c)   These series have an adjustable interest rate that can be a daily, weekly,
      commercial  paper or term rate as  designated by AEGCo.  AEGCo  selected a
      daily rate which  ranged  from 1.65% to 6.1%  during 2000 and 1.4% to 5.2%
      during 1999 and averaged 4.1% in 2000 and 3.2% in 1999. The interest rates
      were 5% and 4.9% at December  31, 2000 and 4.95% and 4.8% at December  31,
      1999 for Series A and Series B, respectively.


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

</TABLE>
<PAGE>



AEP GENERATING COMPANY
Index to Notes to Financial Statements

The notes listed below are combined with the notes to financial  statements  for
AEP and its other subsidiary  registrants.  The combined footnotes begin on page
L-1.

                                                           Combined
                                                           Footnote
                                                           Reference

Significant Accounting Policies                            Note 1

Effects of Regulation                                      Note 6

Commitments and Contingencies                              Note 8

Business Segments                                          Note 14

Financial Instruments, Credit and Risk Management          Note 15

Income Taxes                                               Note 16

Leases                                                     Note 18

Lines of Credit and Factoring of Receivables               Note 19

Unaudited Quarterly Financial Information                  Note 20

Related Party Transactions                                 Note 23





<PAGE>


INDEPENDENT AUDITORS' REPORT
-----------------------------------


To the Shareholder and Board of Directors
of AEP Generating Company:

         We have  audited the  accompanying  balance  sheets and  statements  of
capitalization  of AEP Generating  Company as of December 31, 2000 and 1999, and
the related statements of income,  retained earnings, and cash flows for each of
the  three  years  in the  period  ended  December  31,  2000.  These  financial
statements   are  the   responsibility   of  the   Company's   management.   Our
responsibility  is to express an opinion on these financial  statements based on
our audits.

         We conducted our audits in accordance with auditing standards generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

         In our  opinion,  such  financial  statements  present  fairly,  in all
material  respects,  the  financial  position  of AEP  Generating  Company as of
December 31, 2000 and 1999, and the results of its operations and its cash flows
for each of the three years in the period ended  December 31, 2000 in conformity
with accounting principles generally accepted in the United States of America.



Deloitte & Touche LLP
Columbus, Ohio
February 26, 2001


<PAGE>












                   APPALACHIAN POWER COMPANY AND SUBSIDIARIES



<PAGE>
<TABLE>
<CAPTION>


                                      C-13
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data

                                                  Year Ended December 31,
                               -----------------------------------------------------------
                                   2000        1999        1998        1997        1996
                                   ----        ----        ----        ----        ----
                                                      (in thousands)

INCOME STATEMENTS DATA:

<S>                             <C>         <C>         <C>         <C>         <C>
  Operating Revenues            $1,860,165  $1,650,937  $1,672,244  $1,628,515  $1,624,869
  Operating Expenses             1,659,011   1,409,701   1,443,701   1,388,521   1,381,993
                                ----------  ----------  ----------  ----------  ----------
  Operating Income                 201,154     241,236     228,543     239,994     242,876
  Nonoperating Income (Loss)        11,752       8,096      (8,301)       (222)        128
                                ----------  ----------  ----------  ----------  ----------
  Income Before Interest Charges   212,906     249,332     220,242     239,772     243,004
  Interest Charges                 148,000     128,840     126,912     119,258     109,315
                                ----------  ----------  ----------  ----------  ----------
  Income Before
    Extraordinary Item              64,906     120,492      93,330     120,514     133,689
  Extraordinary Gain                 8,938        -           -           -           -
                                ----------  ----------  ----------  ----------  ----------
  Net Income                        73,844     120,492      93,330     120,514     133,689
  Preferred Stock Dividend
    Requirements                     2,504       2,706       2,497       7,006      15,938
                                ----------  ----------  ----------  ----------  ----------
  Earnings Applicable to
    Common Stock                $   71,340  $  117,786  $   90,833  $  113,508  $  117,751
                                ==========  ==========  ==========  ==========  ==========



                                                  Year Ended December 31,
                                ----------------------------------------------------------
                                   2000        1999        1998        1997        1996
                                   ----        ----        ----        ----        ----
                                                      (in thousands)

BALANCE SHEETS DATA:

  Electric Utility Plant        $5,418,278  $5,262,951  $5,087,359  $4,901,046  $4,717,132
  Accumulated Depreciation and
     Amortization                2,188,796   2,079,490   1,984,856   1,869,057   1,782,017
                                ----------  ----------  ----------  ----------  ----------
  Net Electric Utility Plant    $3,229,482  $3,183,461  $3,102,503  $3,031,989  $2,935,115
                                ==========  ==========  ==========  ==========  ==========
  Total Assets                  $6,646,153  $4,354,400  $4,047,038  $3,883,430  $3,800,737
                                ==========  ==========  ==========  ==========  ==========

  Common Stock and
    Paid-in Capital             $  975,676  $  974,717  $  924,091  $  873,506  $  835,838
  Retained Earnings                120,584     175,854     179,461     207,544     208,472
                                ----------  ----------  ----------  ----------  ----------
  Total Common Shareholder's
    Equity                      $1,096,260  $1,150,571  $1,103,552  $1,081,050  $1,044,310
                                ==========  ==========  ==========  ==========  ==========

  Cumulative Preferred Stock:
    Not Subject to Mandatory
      Redemption                $   17,790  $   18,491  $   19,359  $   19,747  $   29,815
    Subject to Mandatory
      Redemption                    10,860      20,310      22,310      22,310     190,000
                                ----------  ----------  ----------  ----------  ----------
        Total Cumulative
          Preferred Stock       $   28,650  $   38,801  $   41,669  $   42,057  $  219,815
                                ==========  ==========  ==========  ==========  ==========

  Long-term Debt (a)            $1,605,818  $1,665,307  $1,552,455  $1,494,535  $1,365,842
                                ==========  ==========  ==========  ==========  ==========

  Obligations Under Capital
    Leases (a)                  $   63,160  $   64,645  $   65,175  $   60,110  $   51,969
                                ==========  ==========  ==========  ==========  ==========

  Total Capitalization and
    Liabilities                 $6,646,153  $4,354,400  $4,047,038  $3,883,430  $3,800,737
                                ==========  ==========  ==========  ==========  ==========



(a) Including portion due within one year

</TABLE>


<PAGE>





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis
of Results of Operations
------------------------------------------------------------------------------



<PAGE>


         APCo is a public utility  engaged in the  generation,  purchase,  sale,
transmission  and  distribution of electric power to 909,000 retail customers in
southwestern  Virginia and southern West  Virginia.  APCo as a member of the AEP
Power Pool shares in the revenues  and costs of the AEP Power  Pool's  wholesale
sales to  neighboring  utility  systems  and power  marketers.  APCo also  sells
wholesale power to municipalities.

         The cost of the AEP System's generating capacity is allocated among the
AEP Power Pool  members  based on their  relative  peak  demands and  generating
reserves  through the  payment of  capacity  charges and the receipt of capacity
credits.  AEP Power Pool members are also  compensated  for their  out-of-pocket
costs of energy  delivered to the AEP Power Pool and charged for energy received
or purchased from the AEP Power Pool.

         The AEP Power Pool  calculates  each company's  prior twelve month peak
demand relative to the total peak demand of all member  companies as a basis for
sharing  revenues and costs.  The result of this  calculation is the member load
ratio (MLR) which  determines  each company's  per-centage  share of revenues or
costs.  APCo 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.  Revenues from forward  electricity  trades
are recorded net of purchases as operating  revenues for  transactions  in AEP's
traditional marketing area (up to two trans-mission systems from the AEP service
territory) and as nonoperating  income for transactions  beyond two transmission
systems from AEP. The AEP Power Pool also enters into power trading transactions
for options,  futures and swaps.  APCo's share of these transactions is recorded
in nonoperating income.

         In February 2001 the U.S.  District Court for the Southern  District of
Ohio ruled  against AEP and certain of its  subsidiaries,  including  APCo, in a
suit over  deductibility  of interest  claimed in AEP's  consolidated tax return
related to a corporate  owned life insurance  (COLI)  program.  In 1998 and 1999
APCo paid the disputed  taxes and  interest  attributable  to the COLI  interest
deductions  for taxable  years  1991-98.  The  payments  were  included in Other
Property and Investments  pending the resolution of this matter.  As a result of
the Court's decision, net income was reduced by $82 million in 2000.

Results of Operations

Net Income

         Income before  extraordinary  items  decreased  $55.6 million or 46% in
2000  primarily  due to the  COLI  decision.  An  extraordinary  gain  from  the
discontinuance  of SFAS 71  regulatory  accounting  of $9 million  after tax was
recorded  in June  2000.  (See  Note 7 of the  Notes to  Consolidated  Financial
Statements).

         Net income  increased  $27.2 million or 29% in 1999  primarily due to a
nonoperating gain in 1999 on the sale of real estate and mining assets by APCo's
inactive mining subsidiaries and a decline in operating expenses.

Operating Revenues

         The 13% increase in  operating  revenues in 2000  resulted  from APCo's
share of increased  wholesale  electricity  transactions  by the AEP Power Pool.
Operating  revenues  decreased  1% in  1999  primarily  due  to a  de-crease  in
wholesale  sales and a decline  in net  revenues  reflecting  lower  margins  on
whole-sale trading transactions.  The changes in the components of revenues were
as follows:

                    Increase (Decrease)
                    From Previous Year
(dollars in millions)
---------------------
                     2000           1999
                  ---------------------------
                  Amount   %    Amount     %
Retail:
   Residential    $ 15.5        $ 19.4
   Commercial        9.2          17.1
   Industrial      (15.1)         (4.4)
   Other             1.7           0.9
                  ------        ------
                    11.3   1      33.0     3

Wholesale          237.0  88     (80.6)  (23)
Transmission and
  Other            (39.1)(44)     26.3    42
                  ------        ------

     Total        $209.2  13    $(21.3)   (1)
                  ======        ======

         Retail  revenues  increased in 1999  primarily  due to a 2% increase in
retail sales reflecting higher residential and commercial sales. The increase in
retail sales was primarily due to colder winter weather and customer growth.

         The  increase in  wholesale  revenues  in 2000 is due to a  significant
increase in AEP Power Pool transactions.  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 contributing to the increase in APCo's wholesale revenues.  The decline in
wholesale  revenues in 1999 reflects the  termination of a contract with several
municipal  customers  in July 1998 and a decline in margins on  regulated  power
trading transactions.  The decline in margins reflects the moderation in 1999 of
extreme  weather in 1998 and  capacity  shortages  experienced  in the summer of
1998.

         In 2000 transmission and other revenues decreased  substantially due to
the  combined  effect of an  unfavorable  mark-to-market  adjustment  in 2000 on
outstanding forward trading contracts, a favorable adjustment to a provision for
revenue  refunds  recorded in 1999 in  connection  with the execution of a final
rate refund and a favorable  adjustment  to rental  income in 1999 for agreed to
retroactive billings to telecommunications companies for pole attachments.


Operating Expenses

         Operating  expenses  increased 18% in 2000 primarily due to an increase
in purchased  power expense,  other  operation  expense and federal income taxes
offset in part by a decrease in fuel expense. The decrease in operating expenses
in 1999 was mainly due to a decline in purchased  power expense.  Changes in the
components of operating expenses are as follows:

                     Increase (Decrease)
                     From Previous Year
(dollars in millions)
---------------------
                   2000             1999
               -----------------------------
                Amount    %    Amount    %

Fuel            $(75.6) (17)   $  7.2    2
Purchased Power  223.8   88     (49.0) (16)
Other Operation   33.0   13      (5.1)  (2)
Maintenance        0.7    1     (11.0)  (8)
Depreciation and
  Amortization    14.2   10       5.1    4
Taxes Other Than
  Federal Income
  Taxes            8.8    8       1.5    1
Federal Income
 Taxes            44.4   63      17.3   32
                ------         ------
  Total         $249.3   18    $(34.0)  (2)
                ======         ======

         Fuel  expense  decreased  in 2000  due to the  combined  effect  of the
discontinuance  of deferral  accounting for over or under recovery of fuel costs
in the West Virginia jurisdiction effective January 1, 2000 under the terms of a
rate  settlement  agreement and a decline in generation  due to scheduled  plant
maintenance. The increase in fuel expense in 1999 was primarily due to increases
in generation reflecting greater utilization of internally generated power.

         The  significant  increase in purchased  power expense in 2000 reflects
additional  purchases  of power from the AEP Power Pool as a result of increased
availability of generation. The AEP Power Pool was able to supply more energy to
APCo since an affiliate's out of service nuclear unit went on line in June 2000,
a major industrial customer  discontinued  purchasing power from an affiliate in
January 2000, and generating unit outage management improved.

         The  reduction in purchased  power expense in 1999 was primarily due to
reduced  capacity  charges  from the AEP Power Pool as a result of  declines  in
APCo's MLR and  decreased  purchases  from the AEP Power  Pool.  The  decline in
purchases  from the AEP  Power  Pool can be  attributed  to  increased  internal
generation and the termination of a contract with several municipal customers.

         The  increase in other  operation  expense in 2000 was due to increased
marketing  and  trading  costs  including   increased   accruals  for  incentive
compensation  and  increased  use of emission  allowances  due to  stricter  air
quality  standards of Phase II of the 1990 Clean Air Act Amendments which became
effective January 1, 2000.

         Maintenance  expense  decreased  in  1999  primarily  as  a  result  of
expenditures  during 1998 to restore  service  and make  repairs  following  two
severe snowstorms.

         Depreciation  and  amortization  expense  increased  in 2000 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 being recovered
through  regulated  rates (see Note 7 for further  discussion  of the effects of
restructuring). Additional investments in distribution plant also contributed to
the increase in depreciation and amortization expense.

         The  increase  in taxes  other  than  federal  income  taxes in 2000 is
primarily due to an increase in the WV state income taxes due to disallowance of
the COLI program interest deductions.

         Federal income taxes  attributable to operations  increased in 2000 due
to the  disallowance  of  COLI  interest  deductions.  The  increase  in 1999 is
primarily due to an increase in pre-tax  operating income and changes in certain
book/tax  differences  accounted  for on a  flow-through  basis for  rate-making
purposes.

Nonoperating Income

         The increase in  nonoperating  income in 1999 is  primarily  due to the
effect of non-regulated electricity trading and a gain on the sale of coal lands
and  mining  assets  by  APCo's  inactive  coal  mining  subsidiaries.  In  1999
nonoperating  income  included a gain from APCo's  share of the AEP Power Pool's
trading transactions outside of the AEP System's traditional  marketing area. In
November  1999  the  subsidiaries  sold  coal  lands  and  mining  assets  to an
unaffiliated company that had been leasing the assets.

Interest Charges

         Interest  charges  increased  in  2000  due to  recognizing  previously
deferred  interest  payments  to the IRS related to the COLI  disallowances  and
interest on resultant state income tax deficiencies.

Extraordinary Gain

         The  extraordinary  gain  recorded  in June 2000 was the  result of the
discontinuance of SFAS 71 for the generation portion of APCo's business.




<PAGE>
<TABLE>
<CAPTION>


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income

                            Year Ended December 31,
                                                    2000           1999           1998
                                                    ----           ----           ----
                                                              (in thousands)

<S>                                              <C>            <C>            <C>
OPERATING REVENUES                               $1,860,165     $1,650,937     $1,672,244
                                                 ----------     ----------     ----------

OPERATING EXPENSES:
 Fuel                                               369,161        444,711        437,500
 Purchased Power                                    477,910        254,100        303,116
 Other Operation                                    282,610        249,616        254,718
 Maintenance                                        124,493        123,834        134,856
 Depreciation and Amortization                      163,089        148,874        143,809
 Taxes Other Than Federal Income Taxes              126,447        117,641        116,070
 Federal Income Taxes                               115,301         70,925         53,632
                                                 ----------     ----------     ----------
          Total Operating Expenses                1,659,011      1,409,701      1,443,701
                                                 ----------     ----------     ----------

OPERATING INCOME                                    201,154        241,236        228,543

NONOPERATING INCOME (LOSS)                           11,752          8,096         (8,301)
                                                 ----------     ----------     ----------

INCOME BEFORE INTEREST CHARGES                      212,906        249,332        220,242

INTEREST CHARGES                                    148,000        128,840        126,912
                                                 ----------     ----------     ----------

INCOME BEFORE EXTRAORDINARY ITEM                     64,906        120,492         93,330

EXTRAORDINARY GAIN - DISCONTINUANCE OF
 REGULATORY ACCOUNTING FOR GENERATION
 (Inclusive of Tax Benefit of $7,872,000)             8,938           -              -
                                                 ----------     ----------     -----------

NET INCOME                                           73,844        120,492         93,330

PREFERRED STOCK DIVIDEND REQUIREMENTS                 2,504          2,706          2,497
                                                 ----------     ----------     ----------

EARNINGS APPLICABLE TO COMMON STOCK              $   71,340     $  117,786     $   90,833
                                                 ==========     ==========     ==========

See Notes to Consolidated Financial Statements Beginning on Page L-1.
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
------------------------------------------------------------------------------------------

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

ELECTRIC UTILITY PLANT:
<S>                                                           <C>              <C>
   Production                                                 $2,058,952       $2,014,968
   Transmission                                                1,177,079        1,151,377
   Distribution                                                1,816,925        1,741,685
   General                                                       254,371          247,798
   Construction Work in Progress                                 110,951          107,123
                                                              ----------       ----------
                 Total Electric Utility Plant                  5,418,278        5,262,951
   Accumulated Depreciation and Amortization                   2,188,796        2,079,490
                                                              ----------       ----------
                 NET ELECTRIC UTILITY PLANT                    3,229,482        3,183,461
                                                              ----------       ----------


OTHER PROPERTY AND INVESTMENTS                                    56,967          126,592
                                                              ----------       ----------

LONG-TERM ENERGY TRADING CONTRACTS                               322,688           33,954
                                                              ----------       ----------


CURRENT ASSETS:
   Cash and Cash Equivalents                                       5,847           64,828
   Advances to Affiliates                                          8,387             -
   Accounts Receivable:
      Customers                                                  243,298          109,525
      Affiliated Companies                                        63,919           37,827
      Miscellaneous                                               16,179            9,154
      Allowance for Uncollectible Accounts                        (2,588)          (2,609)
   Fuel - at average cost                                         39,076           58,161
   Materials and Supplies - at average cost                       57,515           56,917
   Accrued Utility Revenues                                       66,499           53,418
   Energy Trading Contracts                                    2,036,001          143,777
   Prepayments                                                     6,307            7,713
                                                              ----------       ----------
                 TOTAL CURRENT ASSETS                          2,540,440          538,711
                                                              ----------       ----------


REGULATORY ASSETS                                                447,750          436,894
                                                              ----------       ----------

DEFERRED CHARGES                                                  48,826           34,788
                                                              ----------       ----------
                     TOTAL                                    $6,646,153       $4,354,400
                                                              ==========       ==========

See Notes to Consolidated Financial Statements Beginning on Page L-1.


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


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
-------------------------------------------------------------------------------------------------------------

                                                                      December 31,
                                                             -----------------------------
                                                                 2000             1999
                                                                 ----             ----
                                                                     (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
   Common Stock - No Par Value:
      Authorized - 30,000,000 Shares
<S>                                                           <C>             <C>
      Outstanding - 13,499,500 Shares                         $  260,458      $   260,458
   Paid-in Capital                                               715,218          714,259
   Retained Earnings                                             120,584          175,854
                                                              ----------      -----------
                Total Common Shareholder's Equity              1,096,260        1,150,571
   Cumulative Preferred Stock:
       Not Subject to Mandatory Redemption                        17,790           18,491
       Subject to Mandatory Redemption                            10,860           20,310
   Long-term Debt                                              1,430,812        1,539,302
                                                              ----------       ----------
                TOTAL CAPITALIZATION                           2,555,722        2,728,674
                                                              ----------       ----------

OTHER NONCURRENT LIABILITIES                                     105,883          132,130
                                                              ----------       ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                            175,006          126,005
   Short-term Debt                                               191,495          123,480
   Accounts Payable - General                                    153,422           59,150
   Accounts Payable - Affiliated Companies                       107,556           42,459
   Taxes Accrued                                                  63,258           49,038
   Customer Deposits                                              12,612           12,898
   Interest Accrued                                               21,555           19,079
   Energy Trading Contracts                                    2,091,804          140,279
   Other                                                          85,378           71,044
                                                              ----------       ----------
                TOTAL CURRENT LIABILITIES                      2,902,086          643,432
                                                              ----------       ----------

DEFERRED INCOME TAXES                                            682,474          671,917
                                                              ----------       ----------

DEFERRED INVESTMENT TAX CREDITS                                   43,093           57,259
                                                              ----------       ----------

LONG-TERM ENERGY TRADING CONTRACTS                               259,438           26,256
                                                              ----------       ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                       97,457           94,732
                                                              ----------       ----------

COMMITMENTS AND CONTINGENCIES (Note 8)

                    TOTAL                                     $6,646,153       $4,354,400
                                                              ==========       ==========

See Notes to Consolidated Financial Statements Beginning on Page L-1.

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


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows

                                                           Year Ended December 31,
                                                    --------------------------------------
                                                       2000          1999          1998
                                                       ----          ----          ----
                                                                (in thousands)

OPERATING ACTIVITIES:
<S>                                                 <C>           <C>           <C>
   Net Income                                       $   73,844    $ 120,492     $  93,330
   Adjustments for Noncash Items:
      Depreciation and Amortization                    163,202      149,791       144,967
      Deferred Federal Income Taxes                      8,602       13,033        (2,338)
      Deferred Investment Tax Credits                   (4,915)      (4,972)       (5,265)
      Deferred Power Supply Costs (net)                (84,408)      35,955        30,081
      Provision for Rate Refunds                        (4,818)       4,818       (31,019)
      Extraordinary Gain - Discontinuance of SFAS 71    (8,938)        -             -
   Changes in Certain Current Assets and Liabilities:
      Accounts Receivable (net)                       (166,911)      10,989        (1,562)
      Fuel, Materials and Supplies                      18,487       (4,812)       (5,006)
      Accrued Utility Revenues                         (13,081)      (7,433)        5,223
      Accounts Payable                                 159,369       (9,273)       14,066
      Taxes Accrued                                     14,220       13,319        (5,830)
      Revenue Refunds Accrued                              181      (95,267)       91,956
      Incentive Plan Accrued                            10,662        1,507        (3,429)
   Disputed Tax and Interest Related to COLI            72,440       (4,124)      (68,316)
   Change in Operating Reserves                        (19,770)       7,451        10,052
   Net Change in Energy Trading Contracts                3,749      (14,531)        3,529
   Rate Stabilization Deferral                          75,601         -             -
   Other (net)                                          (9,647)     (24,681)       13,011
                                                    ----------    ---------     ---------
        Net Cash Flows From Operating Activities       287,869      192,262       283,450
                                                    ----------    ---------     ---------

INVESTING ACTIVITIES:
   Construction Expenditures                          (199,285)    (211,416)     (204,869)
   Proceeds from Sales of Property and Other               159       19,296         2,930
   Net Cost of Removal and Other                        (7,500)     (24,373)       (9,286)
                                                    ----------    ---------     ---------
        Net Cash Flows Used For
          Investing Activities                        (206,626)    (216,493)     (211,225)
                                                    ----------    ---------     ---------

FINANCING ACTIVITIES:
   Capital Contributions from Parent Company              -          50,000        50,000
   Issuance of Long-term Debt                           74,788      227,236       211,944
   Retirement of Cumulative Preferred Stock             (9,924)      (2,675)         (294)
   Retirement of Long-term Debt                       (136,166)    (116,688)     (157,973)
   Change in Short-term Debt (net)                      68,015       47,080       (53,900)
   Change in Advances to Affiliates                     (8,387)        -             -
   Dividends Paid on Common Stock                     (126,612)    (121,392)     (118,916)
   Dividends Paid on Cumulative Preferred Stock         (1,938)      (2,257)       (2,278)
                                                    ----------    ---------     ---------
        Net Cash Flows From (Used For)
          Financing Activities                        (140,224)      81,304       (71,417)
                                                    ----------    ---------     ---------

Net Increase (Decrease) in Cash and Cash Equivalents   (58,981)      57,073           808
Cash and Cash Equivalents January 1                     64,828        7,755         6,947
                                                    ----------    ---------     ---------
Cash and Cash Equivalents December 31               $    5,847    $  64,828     $   7,755
                                                    ==========    =========     =========

Supplemental Disclosure:
  Cash  paid  for  interest  net  of  capitalized   amounts  was   $124,579,000,
  $125,900,000   and   $124,027,000   and  for  income  taxes  was  $63,682,000,
  $55,157,000  and  $65,102,000 in 2000,  1999 and 1998,  respectively.  Noncash
  acquisitions   under  capital  leases  were   $14,116,000,   $13,868,000   and
  $21,146,000 in 2000, 1999 and 1998, respectively.

See Notes to Consolidated Financial Statements Beginning on Page L-1.
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings

                                                             Year Ended December 31,
                                                       -----------------------------------
                                                         2000         1999         1998
                                                         ----         ----         ----
                                                                 (in thousands)

<S>                                                    <C>          <C>          <C>
Retained Earnings January 1                            $175,854     $179,461     $207,544
Net Income                                               73,844      120,492       93,330
                                                       --------     --------     --------
                                                        249,698      299,953      300,874
                                                       --------     --------     --------
Deductions:
   Cash Dividends Declared:
     Common Stock                                       126,612      121,392      118,916
     Cumulative Preferred Stock:
        4-1/2% Series                                       811          850          875
        5.90%  Series                                       307          425          455
        5.92%  Series                                       364          364          364
        6.85%  Series                                       289          579          579
                                                       --------     --------     --------
                Total Cash Dividends Declared           128,383      123,610      121,189

   Capital Stock Expense                                    731          489          224
                                                       --------     --------     --------
                Total Deductions                        129,114      124,099      121,413
                                                       --------     --------     --------

Retained Earnings December 31                          $120,584     $175,854     $179,461
                                                       ========     ========     ========

See Notes to Consolidated Financial Statements Beginning on Page L-1.
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization

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

<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $1,096,260        $1,150,571
                                                                                 ----------        ----------

PREFERRED STOCK - authorized shares 8,000,000 no par value

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series(a)      2000 (b)        Year Ended December 31,       December 31, 2000
------     ------------     ----------------------------     -----------------
                              2000      1999      1998
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4-1/2%       $110.00          7,011     8,671     3,878            177,905           17,790            18,491
                                                                                     ------            ------

Subject to Mandatory Redemption:

5.90% (c)      (e)           10,000    20,000      -                47,100            4,710             5,710
5.92% (c)      (e)             -         -         -                61,500            6,150             6,150
6.85% (d)      (f)           84,500      -         -                  -                -                8,450
                                                                                     ------            ------

                                                                                     10,860            20,310
                                                                                     ------            ------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                739,015           844,472
Installment Purchase Contracts                                                      234,782           264,217
Senior Unsecured Notes                                                              468,113           392,844
Junior Debentures                                                                   161,367           161,228
Other Long-term Debt                                                                  2,541             2,546
Less Portion Due Within One Year                                                   (175,006)         (126,005)
                                                                                 ----------        ----------

  Long-term Debt Excluding Portion Due Within One Year                            1,430,812         1,539,302
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $2,555,722        $2,728,674
                                                                                 ==========        ==========


(a)  The sinking fund provisions of each series subject to mandatory  redemption
     have been met by purchase of shares in advance of the due date.
(b)  The  cumulative  preferred  stock is callable at the price  indicated  plus
     accrued  dividends.  The  involuntary  liquidation  preference  is $100 per
     share.  The  aggregate  involuntary  liquidation  price  for all  shares of
     cumulative preferred stock may not exceed $300 million. The unissued shares
     of  the  cumulative  preferred  stock  may  or may  not  possess  mandatory
     redemption characteristics upon issuance.
(c)  Commencing in 2003 and continuing  through 2007 APCo may redeem at $100 per
     share  25,000  shares of the 5.90%  series and  30,000  shares of the 5.92%
     series  outstanding  under  sinking fund  provisions  at its option and all
     outstanding  shares must be reacquired in 2008. Shares redeemed in 2000 and
     1999 may be applied to meet the sinking fund requirement.
(d)  Commencing in 2000 and  continuing  through date of  redemption,  a sinking
     fund for the 6.85%  cumulative  preferred stock will require the redemption
     of 60,000 shares each year, in each case at $100 per share. The Company has
     the  non-cumulative  option to redeem up to 60,000 additional shares on any
     sinking fund date at a redemption price of $100 per share.
(e)      Not callable until after 2002.
(f)      This series of preferred stock was redeemed in 2000.





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





APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
---------------------------------------------------

First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2000       1999
                           ----       ----
                          (in thousands)
% Rate Due

6.35   2000 - March 1    $   -      $ 48,000
6.71   2000 - June 1         -        48,000
6-3/8  2001 - March 1     100,000    100,000
7.38   2002 - August 15    50,000     50,000
7.40   2002 - December 1   30,000     30,000
6.65   2003 - May 1        40,000     40,000
6.85   2003 - June 1       30,000     30,000
6.00   2003 - November 1   30,000     30,000
7.70   2004 - September 1  21,000     21,000
7.85   2004 - November 1   50,000     50,000
8.00   2005 - May 1        50,000     50,000
6.89   2005 - June 22      30,000     30,000
6.80   2006 - March 1     100,000    100,000
8.50   2022 - December 1   70,000     70,000
7.80   2023 - May 1        30,237     30,237
7.15   2023 - November 1   20,000     20,000
7.125  2024 - May 1        45,000     50,000
8.00   2025 - June 1       45,000     50,000
Unamortized Discount       (2,222)    (2,765)
                         --------   --------
  Total                  $739,015   $844,472
                         ========   ========

         Certain  indentures  relating  to  the  first  mortgage  bonds  contain
improvement,  maintenance  and replacement  provisions  requiring the deposit of
cash or bonds with the trustee,  or in lieu thereof,  certification  of unfunded
property additions.

Installment  purchase  contracts have been entered into, in connection  with the
issuance of pollution  control  revenue  bonds by  governmental  authorities  as
follows:

                             December 31,
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due
Industrial Development
 Authority of
 Russell County, Virginia:

7.70   2007 - November 1 $ 17,500   $ 17,500
5.00   2021 - November 1   19,500     19,500

Putnam County, West Virginia:

5.45   2019 - June 1       40,000     40,000
6.60   2019 - July 1       30,000     30,000

Mason County, West Virginia:

7-7/8  2013 - November 1   10,000     10,000
7.40   2014 - January 1      -        30,000
6.85   2022 - June 1       40,000     40,000
6.60   2022 - October 1    50,000     50,000
6.05   2024 - December 1   30,000     30,000
Unamortized Discount       (2,218)    (2,783)
                         --------   --------
  Total                  $234,782   $264,217
                         ========   ========



         Under the terms of the installment purchase contracts, APCo is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated  maturities  and upon  mandatory  redemptions)  of related  pollution
control revenue bonds issued to finance the  construction  of pollution  control
facilities at certain plants.

Senior unsecured notes outstanding were as follows:

                            December 31,
                          2000       1999
                          ----       ----
                           (in thousands)
% Rate Due
------ ------------------
 (a)   2001 - June 27   $ 75,000   $   -
7.45   2004 - November 1  50,000     50,000
6.60   2009 - May 1      150,000    150,000
7.20   2038 - March 31   100,000    100,000
7.30   2038 - June 30    100,000    100,000
Unamortized Discount      (6,887)    (7,156)
                        --------   --------
  Total                 $468,113   $392,844
                        ========   ========

(a) A floating  interest rate is determined monthly.
    The rate on December 31, 2000 was 6.95%.

Junior debentures outstanding were as follows:

                            December 31,
                         2000         1999
                         ----         ----
                          (in thousands)
8-1/4% Series A due
  2026 - September 30  $ 75,000     $ 75,000
8% Series B due 2027
  - March 31             90,000       90,000
Unamortized Discount     (3,633)      (3,772)
                       --------     --------
  Total                $161,367     $161,228
                       ========     ========

         Interest may be deferred  and payment of principal  and interest on the
junior  debentures is subordinated  and subject in right to the prior payment in
full of all senior indebtedness of the Company.

         At December 31, 2000,  future  annual  long-term  debt  payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2001                       $  175,006
2002                           80,006
2003                          100,007
2004                          121,008
2005                           80,010
Later Years                 1,064,741
                           ----------
  Total Principal Amount    1,620,778
Unamortized Discount          (14,960)
                           ----------
    Total                  $1,605,818
                           ==========



<PAGE>


APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements


The notes listed below are combined with the notes to financial  statements  for
AEP and its other subsidiary  registrants.  The combined footnotes begin on page
L-1.

                                                     Combined
                                                     Footnote
                                                     Reference

Significant Accounting Policies                      Note 1

Extraordinary Items                                  Note 2

Rate Matters                                         Note 5

Effects of Regulation                                Note 6

Industry Restructuring                               Note 7

Commitments and Contingencies                        Note 8

Staff Reduction                                      Note 11

Benefit Plans                                        Note 12

Business Segments                                    Note 14

Financial Instruments, Credit and Risk Management    Note 15

Income Taxes                                         Note 16

Supplementary Information                            Note 17

Leases                                               Note 18

Lines of Credit and Factoring of Receivables         Note 19

Unaudited Quarterly Financial Information            Note 20

Related Party Transactions                           Note 23






<PAGE>




INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of Appalachian Power Company:

     We  have  audited  the   accompanying   consolidated   balance  sheets  and
consolidated  statements of  capitalization of Appalachian Power Company and its
subsidiaries  as of  December  31, 2000 and 1999,  and the related  consolidated
statements of income,  retained  earnings,  and cash flows for each of the three
years in the period ended December 31, 2000. These financial  statements are the
responsibility of the Company's management.  Our responsibility is to express an
opinion on these financial statements based on our audits.

     We conducted our audits in accordance  with  auditing  standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

    In our opinion,  such consolidated  financial  statements present fairly, in
all material  respects,  the financial position of Appalachian Power Company and
its  subsidiaries  as of December  31,  2000 and 1999,  and the results of their
operations  and their cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001



<PAGE>


                CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES


<PAGE>
<TABLE>
<CAPTION>


                                      D-13
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data

                                               Year Ended December 31,
                           ---------------------------------------------------------------
                              2000         1999         1998         1997         1996
                              ----         ----         ----         ----         ----
                                                      (in thousands)
INCOME STATEMENTS DATA:
<S>                        <C>          <C>          <C>          <C>          <C>
  Operating Revenues       $1,771,177   $1,482,475   $1,406,117   $1,376,282   $1,300,688
  Operating Expenses        1,464,079    1,188,490    1,123,330    1,124,963    1,019,498
                           ----------   ----------   ----------   ----------   ----------
  Operating Income            307,098      293,985      282,787      251,319      281,190
  Nonoperating Income
   (Loss)                       7,235        8,113          760        8,277      (11,145)
                           ----------   ----------   ----------   ----------   ----------
  Income Before Interest
    Charges                   314,333      302,098      283,547      259,596      270,045
  Interest Charges            124,766      114,380      122,036      131,173      127,451
                           ----------   ----------   ----------   ----------   ----------
  Income Before
    Extraordinary Item        189,567      187,718      161,511      128,423      142,594
  Extraordinary Loss             -          (5,517)        -            -            -
                           ----------   ----------   ----------   ----------   -----------
  Net Income                  189,567      182,201      161,511      128,423      142,594
  Preferred Stock Dividend
    Requirements                  241        6,931        6,901        9,523       13,563
  Gain (Loss) on Reacquired
    Preferred Stock              -          (2,763)        -           2,402         -
                           ----------   ----------   ----------   ----------   -----------
  Earnings Applicable to
    Common Stock           $  189,326   $  172,507   $  154,610   $  121,302   $  129,031
                           ==========   ==========   ==========   ==========   ==========

                                                      December 31,
                           ---------------------------------------------------------------
                              2000         1999          1998          1997          1996
                              ----         ----          ----          ----          ----
                                                    (in thousands)
BALANCE SHEETS DATA:
  Electric Utility Plant   $5,592,444   $5,511,894   $5,336,191   $5,215,749   $5,116,570
  Accumulated Depreciation
    and Amortization        2,297,189    2,247,225    2,072,686    1,891,406    1,732,252
                           ----------   ----------   ----------   ----------   ----------
  Net Electric Utility
   Plant                   $3,295,255   $3,264,669   $3,263,505   $3,324,343   $3,384,318
                           ==========   ==========   ==========   ==========   ==========

  Total Assets             $5,472,496   $4,847,850   $4,735,476   $4,897,380   $4,919,014
                           ==========   ==========   ==========   ==========   ==========

  Common Stock and Paid-in
    Capital                $  573,888   $  573,888   $  573,888   $  573,888   $  573,888
  Retained Earnings           792,219      758,894      734,387      828,777      864,475
                           ----------   ----------   ----------   ----------   ----------
  Total Common
   Shareholder's Equity    $1,366,107   $1,332,782   $1,308,275   $1,402,665   $1,438,363
                           ==========   ==========   ==========   ==========   ==========
  Preferred Stock          $    5,967   $    5,967   $  163,204   $  163,204   $  250,351
                           ==========   ==========   ==========   ==========   ==========

  CPL - Obligated,
   Mandatorily Redeemable
   Preferred Securities of
   Subsidiary Trust Holding
   Solely Junior
   Subordinated Dentures of
   CPL                        148,500      150,000      150,000      150,000         -
                           ----------   ----------   ----------   ----------   -----------

  Long-term Debt (a)       $1,454,559   $1,454,541   $1,350,706   $1,414,335   $1,613,805
                           ==========   ==========   ==========   ==========   ==========

  Total Capitalization
    and Liabilities        $5,472,496   $4,847,850   $4,735,476   $4,897,380   $4,919,014
                           ==========   ==========   ==========   ==========   ==========



(a) Including portion due within one year.

</TABLE>
<PAGE>





CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis
of Results of Operations
--------------------------------------------------



<PAGE>



       CPL is a  public  utility  engaged  in the  generation,  purchase,  sale,
transmission and  distribution of electric power and provides  electric power to
approximately  680,000  retail  customers  in  southern  Texas.  CPL also  sells
electric  power  at  wholesale  to other  utilities,  municipalities  and  rural
electric   cooperatives.   CPL  participates  in  power  marketing  and  trading
activities conducted on its behalf by the AEP System.

       CPL 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.
Revenues from trading of electricity  are recorded net of purchases as operating
revenues.

Results of Operations

         Income  before  extraordinary  item  increased $2 million or 1% in 2000
primarily  as a result  of  increased  retail  energy  sales,  the  post  merger
implementation  of AEP's power marketing and trading  operations which increased
wholesale  sales to neighboring  utilities and power marketers and the effect of
an  unfavorable  adjustment  in  1999  as  a  result  of  FERC's  approval  of a
transmission  coordination agreement.  These items were offset in part by a rise
in interest expense.  Income before  extraordinary item increased $26 million or
16% in 1999 as a result of lower interest charges and increased retail sales. In
1999  CPL  recorded  an  extraordinary  loss  as  a  result  of a  write-off  of
unamortized expenses associated with the reacquisition of long-term debt.


Operating Revenues

         Operating  revenues  increased 19% in 2000 and 5% in 1999. The increase
in 2000 was primarily due to an increase in fuel-related  revenues and a rise in
energy  sales.  Increases in retail and  transmission  revenues were the primary
reasons for the increase in 1999.

         The following analyzes the changes in operating revenues:

                    Increase (Decrease)
                    From Previous Year
(dollars in millions)
---------------------
                     2000           1999
               -----------------------------
               Amount    %    Amount     %
Retail:
   Residential $109.5         $13.4
   Commercial    66.9          16.1
   Industrial    39.5          21.1
   Other          6.9           3.7
               ------         -----
                222.8   17     54.3      4

Wholesale        64.8   85      9.2     14
Transmission
 and Other        1.1    1     12.9     15
               ------         -----
     Total     $288.7   19    $76.4      5
               ======         =====

        Retail  operating  revenues  increased 17% in 2000 due to an increase in
fuel and purchased power related revenues,  reflecting rising prices for natural
gas  and  purchased  power,  and  an  increase  in  weather-related  demand  for
electricity.  In 1999 an increase in fuel and purchased  power related  revenues
and a modest  increase in usage  accounted for the increase in retail  revenues.
The increase in 1999 revenues was partially  offset by a reduction in base rates
resulting  from a PUCT rate  order.  Since the Texas  fuel and  purchased  power
clause recovery  mechanism  provides for the accrual of revenues to recover fuel
and purchased  power cost  increases  until reviewed and approved for billing to
customers  by the PUCT,  increases  in fuel and  purchased  power  expenses  and
related accrued revenues do not adversely affect results of operations.





        The significant  increase in wholesale  revenues in 2000 is attributable
to increased sales to other utilities and CPL's initial  participation after the
merger in the AEP System's power marketing and trading operations. The volume of
electricity  sales  to  other  utilities,   both  affiliated  and  unaffiliated,
increased as demand for energy rose in response to warmer summer weather.  Since
CPL  became a  subsidiary  of AEP as a result of the  merger in June  2000,  CPL
shares in the AEP System's power marketing and trading  transactions  with other
non-affiliated  entities.  Trading involves the purchase and sale of substantial
amounts of electricity with  non-affiliated  parties.  Revenues from trading are
recorded net of purchases.

Operating Expenses Increase

         Total operating expenses increased 23% in 2000 and 6% in 1999 primarily
due to increased costs of fuel and purchased power and a rise in other operation
expense. The changes in the components of operating expenses were:

                       Increase (Decrease)
                       From Previous Year
(dollars in millions)
---------------------
                       2000           1999
                 ----------------------------
                 Amount    %    Amount    %

Fuel             $146.9    36  $ 18.0      5
Purchased Power   109.2   160    28.1     70
Other Operation    28.4    10    30.1     12
Maintenance        (9.6)  (14)    6.4     10
Depreciation and
 Amortization       1.1     1    (7.1)    (4)
Taxes Other Than
 Federal Income
 Taxes             (4.5)   (5)   13.6     19
Federal Income
 Taxes              4.1     4   (23.9)   (21)
                 ------        ------
    Total        $275.6    23  $ 65.2      6
                 ======        ======

         Fuel expense  increased in 2000 and 1999 primarily due to a rise in the
average cost of fuel primarily from a large increases in natural gas prices. CPL
uses natural gas as fuel for 71% of its generating  capacity.  The nature of the
natural gas market is such that both  long-term  and  short-term  contracts  are
generally based on the current spot market price.  Changes in natural gas prices
affect CPL's fuel expense,  however,  as explained above,  they generally do not
impact results of operations.

         The rise in purchased  power  expense in 2000 was due to an increase in
the cost of purchased electricity as a result of 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.  Purchased power expense increased
70% in 1999 due primarily to higher economy energy purchases reflecting the rise
in natural gas prices.

       Other operation expense increased in 2000 due primarily to an increase in
transmission  expenses that resulted from new prices for the ERCOT  transmission
grid.  Each year ERCOT  establishes new rates to allocate the costs of the Texas
transmission  system  to  Texas  electric  utilities.   In  addition  to  higher
transmission   expenses,   other  operation  expense  increased  due  to  higher
administrative  expenses  resulting  from the  Company's  share of STP voluntary
severance expenses and Texas regulatory expenses.

       In 1999 the increase in other  operation  expense was caused  mainly by a
rise in outside  service  expenses  associated  with the Texas  Legislation  and
securitization  of  generation-related  regulatory  assets,  as well  as  higher
transmission expenses. The increase in transmission expense was due primarily to
the  settlement of a complaint  with Texas  Utilities  Electric  Company and the
absence in 1999 of a  transmission  service  agreement  adjustment  made in 1998
related to a final order by the PUCT on a joint  complaint  filed by CPL and WTU
asserting that Texas  Utilities  Electric  Company had been  effectively  double
charging for transmission service within ERCOT.

       Maintenance  expenses decreased in 2000 and increased in 1999 as a result
of a 10-year service  inspection and refueling of STP Units 1 and 2 performed in
1999.  Also  contributing  to the increase in  maintenance  expense in 1999 were
scheduled power plant repairs at some of CPL's other generating plants.

       Taxes other than income taxes  increased in 1999 due  primarily to higher
franchise tax expenses.

       Federal income tax expense associated with utility  operations  decreased
in 1999 as a result of reduced taxable income, the  reclassification  of certain
income tax related  regulatory assets designated for  securitization  consistent
with the Texas Legislation, and prior year income tax liability adjustments.

Interest Charges

       The  increase in  interest  charges in 2000 can be  attributed  to higher
average interest rates  associated with short term and long term debt.  Interest
charges  decreased in 1999 due  primarily to the maturity and  reacquisition  of
long-term debt during 1998 and 1999.

Preferred Stock Dividends

       Preferred stock dividends decreased in 2000 as a result of the redemption
of preferred  stock in the fourth  quarter of 1999,  which resulted in a loss on
reacquired preferred stock recorded in 1999.





<PAGE>
<TABLE>
<CAPTION>


CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Income

                                                           Year Ended December 31,
                                                   ---------------------------------------
                                                      2000           1999         1998
                                                      ----           ----         ----
                                                                (in thousands)

<S>                                                <C>            <C>          <C>
OPERATING REVENUES                                 $1,771,177     $1,482,475   $1,406,117
                                                   ----------     ----------   ----------

OPERATING EXPENSES:
  Fuel                                                550,903        403,989      385,944
  Purchased Power                                     177,387         68,155       40,062
  Other Operation                                     319,539        291,131      261,058
  Maintenance                                          60,528         70,165       63,779
  Depreciation and Amortization                       178,786        177,702      184,805
  Taxes Other Than Federal Income Taxes                80,009         84,538       70,927
  Federal Income Tax                                   96,927         92,810      116,755
                                                   ----------     ----------   ----------
           Total Operating Expenses                 1,464,079      1,188,490    1,123,330
                                                   ----------     ----------   ----------

OPERATING INCOME                                      307,098        293,985      282,787

NONOPERATING INCOME                                     7,235          8,113          760
                                                   ----------     ----------   ----------

INCOME BEFORE INTEREST CHARGES                        314,333        302,098      283,547

INTEREST CHARGES                                      124,766        114,380      122,036
                                                   ----------     ----------   ----------

INCOME BEFORE EXTRAORDINARY ITEM                      189,567        187,718      161,511

EXTRAORDINARY LOSS ON REACQUIRED DEBT
  (INCLUSIVE OF TAX $2,971,000)                          -            (5,517)        -
                                                   ----------     ----------   -----------

NET INCOME                                            189,567        182,201      161,511

PREFERRED STOCK DIVIDEND REQUIREMENTS                     241          6,931        6,901

LOSS ON REACQUIRED PREFERRED STOCK                        -           (2,763)        -
                                                   ----------     ----------   -----------

EARNINGS APPLICABLE TO COMMON STOCK                $  189,326     $  172,507   $  154,610
                                                   ==========     ==========   ==========

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

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


CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
------------------------------------------------------------------------------------------

                                                                     December 31,
                                                                 2000            1999
                                                                    (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                           <C>             <C>
 Production                                                   $3,175,867      $3,152,319
 Transmission                                                    581,931         566,629
 Distribution                                                  1,221,750       1,157,091
 General                                                         237,764         307,378
 Construction Work in Progress                                   138,273         101,550
 Nuclear Fuel                                                    236,859         226,927
                                                              ----------      ----------
         Total Electric Utility Plant                          5,592,444       5,511,894
 Accumulated Depreciation and Amortization                     2,297,189       2,247,225
                                                              ----------      ----------
         NET ELECTRIC UTILITY PLANT                            3,295,255       3,264,669
                                                              ----------      ----------

OTHER PROPERTY AND INVESTMENTS                                    44,225          41,433
                                                              ----------      ----------

LONG-TERM ENERGY TRADING CONTRACTS                                66,231            -
                                                              ----------      -----------

CURRENT ASSETS:
 Cash and Cash Equivalents                                        14,253           7,995
 Special Deposits for Reacquisition of Long-term Debt               -             50,000
 Accounts Receivable:
  General                                                         67,787          49,228
  Affiliated Companies                                            31,272          15,254
  Allowance for Uncollectible Accounts                            (1,675)           -
 Fuel Inventory - at LIFO cost                                    22,842          26,434
 Materials and Supplies - at average cost                         53,108          58,196
 Under-recovered Fuel Costs                                      127,295          30,423
 Energy Trading Contracts                                        481,206            -
 Prepayments                                                       3,014           3,188
                                                              ----------      ----------
         TOTAL CURRENT ASSETS                                    799,102         240,718
                                                              ----------      ----------


REGULATORY ASSETS                                                202,440         223,359
                                                              ----------      ----------

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

NUCLEAR DECOMMISSIONING TRUST FUND                                93,592          86,122
                                                              ----------      ----------

DEFERRED CHARGES                                                  18,402          38,300
                                                              ----------      ----------

           TOTAL                                              $5,472,496      $4,847,850
                                                              ==========      ==========

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


CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
-----------------------------------------------------------------------------------------------------

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

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
 Common Stock - $25 Par Value:
   Authorized - 12,000,000 Shares
<S>                                                           <C>             <C>
   Outstanding - 6,755,535 Shares                             $  168,888      $  168,888
 Paid-in Capital                                                 405,000         405,000
 Retained Earnings                                               792,219         758,894
                                                              ----------      ----------
           Total Common Shareholder's Equity                   1,366,107       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                                                 1,254,559       1,304,541
                                                              ----------      ----------
           TOTAL CAPITALIZATION                                2,775,133       2,793,290
                                                              ----------      ----------

CURRENT LIABILITIES:
 Long-term Debt Due Within One Year                              200,000         150,000
 Advances from Affiliates                                        269,712         322,158
 Accounts Payable - General                                      128,957          88,702
 Accounts Payable - Affiliated Companies                          40,962          35,344
 Taxes Accrued                                                    55,526          41,121
 Interest Accrued                                                 26,217          14,723
 Energy Trading Contracts                                        489,888            -
 Other                                                            40,630          25,349
                                                              ----------      ----------
           TOTAL CURRENT LIABILITIES                           1,251,892         677,397
                                                              ----------      ----------

DEFERRED INCOME TAXES                                          1,242,797       1,234,175
                                                              ----------      ----------

DEFERRED INVESTMENT TAX CREDITS                                  128,100         133,306
                                                              ----------      ----------

LONG-TERM ENERGY TRADING CONTRACTS                                65,740            -
                                                              ----------      -----------

DEFERRED CREDITS                                                   8,834           9,682
                                                              ----------      ----------

COMMITMENTS AND CONTINGENCIES (Note 8)

             TOTAL                                            $5,472,496      $4,847,850
                                                              ==========      ==========

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


CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows

                            Year Ended December 31,
                                                     2000          1999          1998
                                                     ----          ----          ----
                                                              (in thousands)

OPERATING ACTIVITIES:
<S>                                                <C>           <C>           <C>
  Net Income                                       $ 189,567     $ 182,201     $ 161,511
  Adjustments for Noncash Items:
   Depreciation and Amortization                     178,786       177,702       184,805
   Refunds Due Customers                                -             -          (63,713)
   Changes for Investments and Assets                   -             -           18,669
   Extraordinary Loss on Reacquired Debt                -            5,517          -
   Deferred Income Taxes                              16,263        19,938        (8,328)
   Deferred Investment Tax Credits                    (5,207)       (5,207)       (3,858)
  Changes in Certain Current Assets and Liabilities:
   Accounts Receivable (net)                         (32,902)      (13,426)       10,255
   Fuel, Materials and Supplies                        8,680        (4,476)          (48)
   Interest Accrued                                   11,494       (12,313)       (1,343)
   Fuel Recovery                                     (96,872)      (40,046)       52,364
   Accounts Payable                                   45,873        (3,061)       41,179
   Taxes Accrued                                      14,405        (5,734)       33,297
  Transmission Coordination Agreement Settlement      15,519       (15,519)         -
  Other (net)                                         21,023        19,420        12,839
                                                   ---------     ---------     ---------
   Net Cash Flows From Operating Activities          366,629       304,996       437,629
                                                   ---------     ---------     ---------

INVESTING ACTIVITIES:
  Construction Expenditures                         (199,484)     (210,823)     (123,803)
  Proceeds from Sales of Property and Other             -           15,063        (7,181)
                                                   ---------     ---------     ---------
    Net Cash Flows Used For Investing Activities    (199,484)     (195,760)     (130,984)
                                                   ---------     ---------     ---------

FINANCING ACTIVITIES:
 Issuance of Long-term Debt                          149,248       358,887          -
 Redemption of Preferred Stock                          -         (160,001)         -
 Retirement of Long-term Debt                       (151,440)     (261,700)      (64,000)
 Change in Advances from Affiliates (net)            (52,446)      161,860        17,517
 Special Deposit for Reacquisitions                   50,000       (50,000)         -
 Dividends Paid on Common Stock                     (156,000)     (148,000)     (249,000)
 Dividends Paid on Cumulative Preferred Stock           (249)       (7,835)       (7,219)
                                                   ---------     ---------     ---------
    Net Cash Flows Used For Financing Activities    (160,887)     (106,789)     (302,702)
                                                   ---------     ---------     ---------

Net Increase in Cash and Cash Equivalents              6,258         2,447         3,943
Cash and Cash Equivalents January 1                    7,995         5,548         1,605
                                                   ---------     ---------     ---------
Cash and Cash Equivalents December 31              $  14,253     $   7,995     $   5,548
                                                   =========     =========     =========


Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts (including  distributions on
  Trust Preferred Securities) was $110,010,000, $125,222,000 and $99,239,000 and
  for income taxes was  $48,141,000,  $78,393,000  and $94,245,000 in 2000, 1999
  and 1998, respectively.

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

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


CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings

                            Year Ended December 31,
                                                   2000            1999            1998
                                                   ----            ----            ----
                                                              (in thousands)

BALANCE AT BEGINNING OF PERIOD
<S>                                              <C>             <C>             <C>
  AS PREVIOUSLY REPORTED                         $764,225        $739,031        $833,282
CONFORMING CHANGE IN ACCOUNTING POLICY             (5,331)         (4,644)         (4,505)
                                                 --------        --------        --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD           758,894         734,387         828,777
NET INCOME                                        189,567         182,201         161,511

DEDUCTIONS:
 Cash Dividends Declared:
   Common Stock                                   156,000         148,000         249,000
   Preferred Stock                                    241           6,931           6,901
 Other                                                  1            -               -

LOSS ON REACQUIRED PREFERRED STOCK                   -             (2,763)           -
                                                 --------        --------        ---------

BALANCE AT END OF PERIOD                         $792,219        $758,894        $734,387
                                                 ========        ========        ========

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

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


CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization

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

<S>                                                                              <C>               <C>
COMMON SHAREHOLDERS' EQUITY                                                      $1,366,107        $1,332,782
                                                                                 ----------        ----------

PREFERRED STOCK - authorized shares 3,035,000 $100 par value

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2000            Year Ended December 31,       December 31, 2000
------     ------------     ----------------------------     -----------------
                              2000      1999      1998
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4.00%        $105.75           -         -         -                42,038            4,204             4,204
4.20%         103.75           -         -         -                17,476            1,748             1,748
Premium                                                                                  15                15
                                                                                 ----------        ----------
  Total Preferred Stock                                                               5,967             5,967
                                                                                 ----------        ----------

TRUST PREFERRED SECURITIES:

 CPL-obligated,  mandatorily redeemable preferred securities of subsidiary trust
 holding solely Junior Subordinated Debentures of CPL, 8.00%,
 due April 30, 2037                                                                 148,500           150,000
                                                                                 ----------        ----------

LONG-TERM (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                615,000           764,991
Installment Purchase Contracts                                                      489,559           489,550
Senior Unsecured Notes                                                              350,000           200,000
Less Portion Due Within One year                                                   (200,000)         (150,000)
                                                                                 ----------        ----------

Long-term Debt Excluding Portion Due Within One Year                              1,254,559         1,304,541
                                                                                 ----------        ----------

     TOTAL CAPITALIZATION                                                        $2,775,133        $2,793,290
                                                                                 ==========        ==========



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

</TABLE>
<PAGE>





CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt



<PAGE>



First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2000       1999
                           ----       ----
                          (in thousands)
% Rate Due
7.50   2020 - March 1    $   -      $ 50,000
7.25   2004 - October 1   100,000    100,000
7.50   2002 - December 1  115,000    115,000
6-7/8  2003 - February 1   50,000     50,000
7-1/8  2008 - February 1   75,000     75,000
6.00   2000 - April 1        -       100,000
7.50   2023 - April 1      75,000     75,000
6-5/8  2005 - July 1      200,000    200,000
Unamortized Discount         -            (9)
                         --------   --------
  Total                  $615,000   $764,991
                         ========   ========

         Certain  indentures  relating  to  the  first  mortgage  bonds  contain
improvement,  maintenance  and replacement  provisions  requiring the deposit of
cash or bonds with the trustee,  or in lieu thereof,  certification  of unfunded
property additions.

Installment  purchase  contracts  have been entered into in connection  with the
issuance of pollution  control  revenue  bonds by  governmental  authorities  as
follows:

                             December 31,
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due
Matagorda County
 Naviagation District,
 Texas:

6.00   2028 - July 1     $120,265   $120,265
6.10   2028 - July 1      100,635    100,635
6-1/8  2030 - May 1        60,000     60,000
4.90   2030 - May 1       111,700    111,700
4.95   2030 - May 1        50,000     50,000

Guadalupe-Blanco
 River Authority District,
 Texas:
(a)    2015 - November 1   40,890     40,890

Red River Authority
 District, Texas:
6.00   2020 - June 1        6,330      6,330
Unamortized Discount         (261)      (270)
                         --------   --------
  Total                  $489,559   $489,550
                         ========   ========

(a) A floating  interest rate is  determined monthly.
    The rate on December 31, 2000 was 4.90%.



         Under the terms of the installment purchase contracts,  CPL is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated  maturities  and upon  mandatory  redemptions)  of related  pollution
control revenue bonds issued to finance the  construction  of pollution  control
facilities at certain plants.

Senior unsecured notes outstanding were as follows:

                            December 31,
                          2000       1999
                          ----       ----
                           (in thousands)
% Rate Due
------ ------------------
 (b)   2001 - November 23 $200,000 $200,000
 (c)   2002 - February 22  150,000     -
                          -------- ---------
  Total                   $350,000 $200,000
                          ======== ========

(b)      A floating interest rate is determined
    monthly.  The rate on December 31, 2000
    was 7.35063%.
(c)      A floating interest rate is determined
    monthly.  The rate on December 31, 2000
    was 7.20313%.

         At December 31, 2000,  future  annual  long-term  debt  payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2001                       $  200,000
2002                          265,000
2003                           50,000
2004                          100,000
2005                          200,000
Later Years                   639,820
                           ----------
  Total Principal Amount    1,454,820
Unamortized Discount             (261)
                           ----------
    Total                  $1,454,559
                           ==========



<PAGE>


CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
------------------------------------------------------------

The notes listed below are combined with the notes to financial  statements  for
AEP and its other subsidiary  registrants.  The combined footnotes begin on page
L-1.

                                                          Combined
                                                          Footnote
                                                          Reference

Significant Accounting Policies                           Note 1

Extraordinary Items                                       Note 2

Merger                                                    Note 3

Rate Matters                                              Note 5

Effects of Regulation                                     Note 6

Industry Restructuring                                    Note 7

Commitments and Contingencies                             Note 8

Benefit Plans                                             Note 12

Business Segments                                         Note 14

Financial Instruments, Credit and Risk Management         Note 15

Income Taxes                                              Note 16

Lines of Credit and Factoring of Receivables              Note 19

Unaudited Quarterly Financial Information                 Note 20

Trust Preferred Securities                                Note 21

Jointly Owned Electric Utility Plant                      Note 22

Related Party Transactions                                Note 23




<PAGE>


INDEPENDENT AUDITORS' REPORT
--------------------------------------------


To the Shareholders and Board of Directors
of Central Power and Light Company:

         We  have  audited  the  accompanying  consolidated  balance  sheet  and
consolidated  statement of capitalization of Central Power and Light Company and
subsidiary as of December 31, 2000, and the related  consolidated  statements of
income,  retained  earnings,  and cash  flows  for the year  then  ended.  These
financial  statements are the  responsibility of the Company's  management.  Our
responsibility  is to express an opinion on these financial  statements based on
our audit.  The consolidated  financial  statements of the Company for the years
ended December 31, 1999 and 1998, before the restatement  described in Note 3 to
the  consolidated  financial  statements,  were audited by other  auditors whose
report,  dated  February 25, 2000,  expressed  an  unqualified  opinion on those
statements.

         We conducted our audit in accordance with auditing standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audit  provides  a
reasonable basis for our opinion.

         In our opinion,  the 2000  consolidated  financial  statements  present
fairly, in all material  respects,  the financial  position of Central Power and
Light Company and  subsidiary as of December 31, 2000,  and the results of their
operations  and their  cash  flows for the year then  ended in  conformity  with
accounting principles generally accepted in the United States of America.

         We also audited the  adjustments  described in Note 3 that were applied
to  restate  the  1999  and  1998  consolidated  financial  statements  to  give
retroactive  effect to the  conforming  change in the method of  accounting  for
vacation pay accruals. In our opinion, such adjustments are appropriate and have
been properly applied.



Deloitte & Touche LLP
Columbus, Ohio
February 26, 2001

<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors of
Central Power and Light Company:

We have audited the  accompanying  consolidated  balance sheets and consolidated
statements  of  capitalization  of  Central  Power  and Light  Company  (a Texas
corporation and a wholly owned subsidiary of Central and South West Corporation)
and  subsidiary  company as of December 31, 1999,  and the related  consolidated
statements  of income,  retained  earnings  and cash flows,  for each of the two
years in the period  ended  December  31,  1999 prior to the  restatement  (and,
therefore,  are  not  presented  herein)  for  the  retroactive  effect  of  the
conforming  change in the method of  accounting  for  vacation  pay accruals and
certain conforming  reclassifications  to the historical financial statements as
described in Note 3 to the restated  consolidated  financial  statements.  These
financial statements are the responsibility of Central Power and Light Company's
management.  Our  responsibility is to express an opinion on these  consolidated
financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable  assurance about whether the financial  statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting  the amounts and  disclosures in the financial  statements.  An audit
also includes assessing the accounting principles used and significant estimates
made by  management,  as well as  evaluating  the  overall  financial  statement
presentation.  We believe  that our audits  provide a  reasonable  basis for our
opinion.

In our opinion,  the consolidated  financial statements prior to the restatement
referred to above  present  fairly,  in all  material  respects,  the  financial
position  of  Central  Power and Light  Company  and  subsidiary  company  as of
December 31, 1999, and the results of their  operations and their cash flows for
each of the two years in the period ended December 31, 1999, in conformity  with
accounting principles generally accepted in the United States.






Arthur Anderson LLP

Dallas, Texas
February 25, 2000

<PAGE>












                         COLUMBUS SOUTHERN POWER COMPANY
                                AND SUBSIDIARIES


<PAGE>
<TABLE>
<CAPTION>


                                      E-12
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
----------------------------------------------------------------------------------------------

                                                Year Ended December 31,
                              ----------------------------------------------------------
                                 2000        1999        1998        1997        1996
                                 ----        ----        ----        ----        ----
                                                    (in thousands)
INCOME STATEMENTS DATA:

<S>                           <C>         <C>         <C>         <C>         <C>
  Operating Revenues          $1,356,408  $1,229,994  $1,187,745  $1,094,851  $1,105,683
  Operating Expenses           1,160,531   1,007,204     975,534     899,724     920,136
                              ----------  ----------  ----------  ----------  ----------
  Operating Income               195,877     222,790     212,211     195,127     185,547
  Nonoperating Income (Loss)       5,153       2,709      (1,343)      3,137        (970)
                              ----------  ----------  ----------  ----------  ----------
  Income Before Interest
    Charges                      201,030     225,499     210,868     198,264     184,577
  Interest Charges (net)          80,828      75,229      77,824      78,885      77,469
                              ----------  ----------  ----------  ----------  ----------
  Income Before Extraordinary
     Item                        120,202     150,270     133,044     119,379     107,108
  Extraordinary Item             (25,236)       -           -           -           -
                              ----------  ----------  ----------  ----------  -----------
  Net Income                      94,966     150,270     133,044     119,379     107,108
  Preferred Stock Dividend
    Requirements                   1,783       2,131       2,131       2,442       6,029
                              ----------  ----------  ----------  ----------  ----------
  Earnings Applicable
    to Common Stock           $   93,183  $  148,139  $  130,913  $  116,937  $  101,079
                              ==========  ==========  ==========  ==========  ==========

                                                      December 31,
                              ------------------------------------------------------------
                                 2000        1999        1998        1997        1996
                                 ----        ----        ----        ----        ----
BALANCE SHEETS DATA:                                (in thousands)

  Electric Utility Plant      $3,266,794  $3,151,619  $3,053,565  $2,976,110  $2,899,893
  Accumulated Depreciation     1,299,697   1,210,994   1,134,348   1,074,588   1,016,909
                              ----------  ----------  ----------  ----------  ----------
  Net Electric Utility Plant  $1,967,097  $1,940,625  $1,919,217  $1,901,522  $1,882,984
                              ==========  ==========  ==========  ==========  ==========

  Total Assets                $3,894,934  $2,809,990  $2,681,690  $2,613,860  $2,541,586
                              ==========  ==========  ==========  ==========  ==========

  Common Stock and Paid-in
    Capital                   $  614,380  $  613,899  $  613,518  $  613,138  $  615,735
  Retained Earnings               99,069     246,584     186,441     138,172      99,582
                              ----------  ----------  ----------  ----------  ----------
  Total Common Shareholder's
    Equity                    $  713,449  $  860,483  $  799,959  $  751,310  $  715,317
                              ==========  ==========  ==========  ==========  ==========

  Cumulative Preferred
    Stock - Subject to
    Mandatory Redemption (a)  $   15,000  $   25,000  $   25,000  $   25,000  $   75,000
                              ==========  ==========  ==========  ==========  ==========

  Long-term Debt (a)          $  899,615  $  924,545  $  959,786  $  969,600  $  897,281
                              ==========  ==========  ==========  ==========  ==========

  Obligations Under Capital
    Leases (a)                $   42,932  $   40,270  $   42,362  $   38,587  $   36,134
                              ==========  ==========  ==========  ==========  ==========

  Total Capitalization and
    Liabilities               $3,894,934  $2,809,990  $2,681,690  $2,613,860  $2,541,586
                              ==========  ==========  ==========  ==========  ==========

(a)      Including portion due within one year.
</TABLE>

<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Management's Narrative Analysis of
Results of
Operations
------------------------------------------------------------



<PAGE>


      Columbus  Southern  Power  Company  is a  public  utility  engaged  in the
generation,  purchase,  sale, transmission and distribution of electric power to
667,000 retail  customers in central and southern Ohio. CSPCo as a member of the
AEP  Power  Pool  shares  in the  revenues  and  costs of the AEP  Power  Pool's
wholesale sales to neighboring  utility systems and power marketers.  CSPCo also
sells wholesale power to municipalities.

      The cost of the AEP System's  generating  capacity is allocated  among the
AEP Power Pool  members  based on their  relative  peak  demands and  generating
reserves  through  the  payment of  capacity  charges  and  receipt of  capacity
credits.  AEP Power Pool members are also  compensated  for their  out-of-pocket
costs of energy  delivered to the AEP Power Pool and charged for energy received
from the AEP Power Pool.

      The AEP Power Pool  calculates  each  company's  prior  twelve  month peak
demand relative to the total peak demand of all member  companies as a basis for
sharing AEP Power Pool revenues and costs. The result of this calculation is the
member load ratio (MLR) which determines each company's  percentage share of AEP
Power Pool revenues and costs. CSPCo 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.  Revenues from
forward  electricity  trades are recorded net of purchases as operating revenues
for transactions in AEP's  traditional  marketing area (up to two  trans-mission
systems  from  the  AEP  service  territory)  and  as  nonoperating  income  for
transactions beyond two transmission systems from AEP. The AEP Power Pool also

enters into power trading  transactions for options,  futures and swaps. CSPCo's
share of these transactions is recorded in nonoperating income.

        In February 2001 the U.S.  District  Court for the Southern  District of
Ohio ruled against AEP and certain of its  subsidiaries,  including  CSPCo, in a
suit over  deductibility  of interest  claimed in AEP's  consolidated tax return
related to a corporate  owned life insurance  (COLI)  program.  In 1998 and 1999
CSPCo paid the disputed  taxes and interest  attributable  to the COLI  interest
deductions  for taxable  years  1991-98.  The  payments  were  included in Other
Property and Investments  pending the resolution of this matter.  As a result of
the Court's decision, net income was reduced by $41 million in 2000.

Results of Operations
Net Income Decreases

        Income  before  extraordinary  item  decreased  by  $30  million  or 20%
primarily  due to increases in federal  income tax expense and related  interest
charges  as a  result  of  the  U.S.  District  Court's  decision  denying  COLI
deductions.  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 PUCO  approval of a plan to transition  CSPCo's  generation
business from cost based rate regulation to customer choice and market pricing.


<PAGE>


Operating Revenues Increase

        Operating revenues increased $126.4 million in 2000 due to a significant
increase in AEP Power Pool wholesale marketing and trading transactions. Changes
in the components of operating revenues were as follows:

                          Increase (Decrease)
                          From Previous Year
(dollars in millions)    Amount       %
----------------------   ------       -

Retail:
  Residential            $  0.8
  Commercial               14.1
  Industrial               (6.0)
  Other                     0.9
                         ------

Wholesale                 123.5     102.6
Transmission               (0.1)     (0.2)
Other                      (6.8)    (32.1)
                         ------

     Total               $126.4      10.3
                         ======

        The increase in wholesale  revenues is due to a significant  increase in
AEP  Power  Pool  transactions.  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 CSPCo's  wholesale Power Pool
revenues.  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.  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.

Operating Expenses Rise

        Operating  expenses  increased by 15% in 2000 mostly due to increases in
purchased  power  expense,  other  operation  expense and federal  income taxes.
Changes in the components of operating expenses were:
                         Increase (Decrease)
                         From Previous Year
(dollars in millions)      Amount       %
----------------------     ------       -

Fuel                        $ 3.6      2.0
Purchased Power Expense      82.2     31.0
Other Operation Expense      31.2     16.3
Maintenance Expense           4.5      6.8
Depreciation                  5.1      5.4
Taxes Other Than Federal
 Income Taxes                 3.1      2.6
Federal Income Taxes         23.6     27.5
                           ------

     Total                 $153.3     15.2
                           ======

        The  increase  in other  operation  expense was due to  increased  power
generation  costs that  resulted  from higher  emission  allowance  consumption,
increased  emission  allowance  cost  and  increased  costs  for  power  trading
reflecting the growth of the power marketing and trading operation.

        The increase in purchased power expense reflects additional purchases of
power from the AEP Power Pool as a result of increased  availability of AEP Pool
generation.  The AEP Power Pool was able to supply more energy to CSPCo since an
affiliate's  out of  service  nuclear  unit went on line in June  2000,  a major
industrial customer  discontinued  purchasing power from an affiliate in January
2000, and generating unit outage managements improved.

        Additional  generating  unit boiler repairs and  maintenance of overhead
transmission  and  distribution  lines accounted for the increase in maintenance
expense.



<PAGE>


        Depreciation expenses increased due to additional plant investment.

        The  increase in federal  income tax expense  was  primarily  due to the
court ruling related to the AEP's COLI program.

Nonoperating Income

        The  increase in  nonoperating  income in 2000 was due to an increase in
net gains from non-regulated AEP Power Pool 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  after the state of Ohio  reviewed  the  matter and
determined that no further corrective action would be required.

Interest Charges Increase

        Interest  charges  increased as a result of the  recognition of deferred
interest payments to the IRS related to the COLI disallowances.

Extraordinary Loss

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



<PAGE>
<TABLE>
<CAPTION>




COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of
Income
-------------------------------------------------------------------------------------------------------------

                            Year Ended December 31,
                                                  2000            1999            1998
                                                  ----            ----            ----
                                                             (in thousands)

<S>                                            <C>             <C>             <C>
OPERATING REVENUES                             $1,356,408      $1,229,994      $1,187,745
                                               ----------      ----------      ----------

OPERATING EXPENSES:
  Fuel                                            189,155         185,511         189,031
  Purchased Power                                 347,693         265,457         237,688
  Other Operation                                 221,775         190,614         202,720
  Maintenance                                      69,676          65,229          62,095
  Depreciation                                     99,640          94,532          91,218
  Taxes Other Than Federal Income Taxes           123,291         120,147         116,548
  Federal Income Taxes                            109,301          85,714          76,234
                                               ----------      ----------      ----------
      TOTAL OPERATING EXPENSES                  1,160,531       1,007,204         975,534
                                               ----------      ----------      ----------

OPERATING INCOME                                  195,877         222,790         212,211

NONOPERATING INCOME (LOSS)                          5,153           2,709          (1,343)
                                               ----------      ----------      ----------

INCOME BEFORE INTEREST CHARGES                    201,030         225,499         210,868

INTEREST CHARGES                                   80,828          75,229          77,824
                                               ----------      ----------      ----------

INCOME BEFORE EXTRAORDINARY ITEM                  120,202         150,270         133,044

EXTRAORDINARY LOSS:
  Discontinuance of Regulatory
  Accounting for Generation
  (inclusive of tax benefit of $14,148,000)       (25,236)           -               -
                                               ----------      ----------      ----------

NET INCOME                                         94,966         150,270         133,044

PREFERRED STOCK DIVIDEND REQUIREMENTS               1,783           2,131           2,131
                                               ----------      ----------      ----------

EARNINGS APPLICABLE TO COMMON STOCK            $   93,183      $  148,139      $  130,913
                                               ==========      ==========      ==========

Consolidated Statements of Retained Earnings
----------------------------------------------------------------------------------------------------------------------------------

                                                             Year Ended December 31,
                                                     -------------------------------------
                                                       2000          1999          1998
                                                       ----          ----          ----
                                                                (in thousands)

Retained Earnings January 1                          $246,584      $186,441      $138,172
Net Income                                             94,966       150,270       133,044
                                                     --------      --------      --------
                                                      341,550       336,711       271,216
                                                     --------      --------      --------
Deductions:
Cash Dividends Declared:
  Common Stock                                        240,600        87,996        82,644
  Cumulative Preferred Stock - 7% Series                1,400         1,750         1,750
                                                     --------      --------      --------
          Total Cash Dividends Declared               242,000        89,746        84,394
Capital Stock Expense                                     481           381           381
                                                     --------      --------      --------
          Total Deductions                            242,481        90,127        84,775
                                                     --------      --------      --------
Retained Earnings December 31                        $ 99,069      $246,584      $186,441
                                                     ========      ========      ========

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


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance
Sheets
------------------------------------------------------------------------------------------

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

ELECTRIC UTILITY PLANT:
<S>                                                       <C>                  <C>
  Production                                              $1,564,254           $1,544,858
  Transmission                                               360,302              350,826
  Distribution                                             1,096,365            1,032,550
  General                                                    156,534              141,137
  Construction Work in Progress                               89,339               82,248
                                                          ----------           ----------
          Total Electric Utility Plant                     3,266,794            3,151,619
  Accumulated Depreciation                                 1,299,697            1,210,994
                                                          ----------           ----------

          NET ELECTRIC UTILITY PLANT                       1,967,097            1,940,625
                                                          ----------           ----------

OTHER PROPERTY AND INVESTMENTS                                39,848               80,008
                                                          ----------           ----------

LONG-TERM ENERGY TRADING CONTRACTS                           172,167               21,278
                                                          ----------           ----------

CURRENT ASSETS:
  Cash and Cash Equivalents                                   11,600                5,107
  Accounts Receivable:
   Customers                                                  73,711               77,418
   Affiliated Companies                                       49,591               28,453
   Miscellaneous                                              18,807                8,887
   Allowance for Uncollectible Accounts                         (659)              (3,045)
  Fuel - at average cost                                      13,126               21,484
  Materials and Supplies - at average cost                    38,097               41,696
  Accrued Utility Revenues                                     9,638               48,117
  Energy Trading Contracts                                 1,085,989               90,103
  Prepayments                                                 46,735               37,969
                                                          ----------           ----------
          TOTAL CURRENT ASSETS                             1,346,635              356,189
                                                          ----------           ----------


REGULATORY ASSETS                                            291,553              339,103
                                                          ----------           ----------

DEFERRED CHARGES                                              77,634               72,787
                                                          ----------           ----------

           TOTAL                                          $3,894,934           $2,809,990
                                                          ==========           ==========

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


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
-------------------------------------------------------------------------------------------------

                                                                   December 31,
                                                         -------------------------------
                                                             2000                1999
                                                             ----                ----
                                                                  (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - No Par Value:
    Authorized - 24,000,000 Shares
<S>                                                      <C>                 <C>
    Outstanding - 16,410,426 Shares                      $   41,026          $   41,026
  Paid-in Capital                                           573,354             572,873
  Retained Earnings                                          99,069             246,584
                                                         ----------          ----------
           Total Common Shareholder's Equity                713,449             860,483
  Cumulative Preferred Stock -
   Subject to Mandatory Redemption                           15,000              25,000
  Long-term Debt                                            899,615             924,545
                                                         ----------          ----------
           TOTAL CAPITALIZATION                           1,628,064           1,810,028
                                                         ----------          ----------

OTHER NONCURRENT LIABILITIES                                 47,584              43,056
                                                         ----------          ----------

CURRENT LIABILITIES:
  Short-term Debt                                              -                 45,500
  Advances from Affiliates                                   88,732                -
  Accounts Payable - General                                 89,846              28,279
  Accounts Payable - Affiliated Companies                    72,493              52,776
  Taxes Accrued                                             162,904             143,477
  Interest Accrued                                           13,369              13,936
  Energy Trading Contracts                                1,115,967              87,911
  Other                                                      60,701              34,375
                                                         ----------          ----------
           TOTAL CURRENT LIABILITIES                      1,604,012             406,254
                                                         ----------          ----------

DEFERRED INCOME TAXES                                       422,759             447,607
                                                         ----------          ----------

DEFERRED INVESTMENT TAX CREDITS                              41,234              44,716
                                                         ----------          ----------

DEFERRED CREDITS                                             12,861              41,875
                                                         ----------          ----------

LONG-TERM ENERGY TRADING CONTRACTS                          138,420              16,454
                                                         ----------          ----------

COMMITMENTS AND CONTINGENCIES (Note 8)

           TOTAL                                         $3,894,934          $2,809,990
                                                         ==========          ==========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
--------------------------------------------------------

                            Year Ended December 31,
                                                      2000        1999           1998
                                                      ----        ----           ----
                                                             (in thousands)

OPERATING ACTIVITIES:
<S>                                                <C>          <C>            <C>
  Net Income                                       $   94,966   $ 150,270      $133,044
  Adjustments for Noncash Items:
    Depreciation                                      100,182      94,962        91,426
    Deferred Federal Income Taxes                      (4,063)     10,481        17,101
    Deferred Investment Tax Credits                    (3,482)     (3,994)       (4,224)
    Deferred Fuel Costs (net)                           5,352       8,889       (11,311)
    Extraordinary Loss - Discontinuance of SFAS 71     25,236        -             -
  Changes in Certain Current Assets and Liabilities:
    Accounts Receivable (net)                         (29,737)      5,166        (5,910)
    Fuel, Materials and Supplies                       11,957      (7,777)       (8,226)
    Accrued Utility Revenues                           38,479      (7,990)       11,638
    Accounts Payable                                   81,284       9,292           476
  Disputed Tax and Interest Related to COLI            39,483      (2,240)      (37,243)
  Other (net)                                           7,480     (13,426)       29,776
                                                   ----------   ---------     ---------
          Net Cash Flows From Operating Activities    367,137     243,633       216,547
                                                   ----------   ---------     ---------

INVESTING ACTIVITIES:
  Construction Expenditures                          (127,987)   (115,321)     (114,979)
  Proceeds from Sale and Leaseback
    Transactions and Other                              1,560       1,858         2,637
                                                   ----------   ---------     ---------
          Net Cash Flows Used For
           Investing Activities                      (126,427)   (113,463)     (112,342)
                                                   ----------   ---------     ---------

FINANCING ACTIVITIES:
  Change in Advances from Affiliates (net)             88,732        -             -
  Issuance of Long-term Debt                             -           -          111,075
  Retirement of Preferred Stock                       (10,000)       -             -
  Retirement of Long-term Debt                        (25,274)    (35,523)     (122,206)
  Change in Short-term Debt (net)                     (45,500)     (7,000)      (14,100)
  Dividends Paid on Common Stock                     (240,600)    (87,996)      (82,644)
  Dividends Paid on Cumulative Preferred Stock         (1,575)     (1,750)       (1,750)
                                                   ----------   ---------     ---------
          Net Cash Flows Used For
            Financing Activities                     (234,217)   (132,269)     (109,625)
                                                   ----------   ---------     ---------

Net Increase (Decrease) in Cash and
 Cash Equivalents                                       6,493      (2,099)       (5,420)
Cash and Cash Equivalents January 1                     5,107       7,206        12,626
                                                   ----------   ---------     ---------
Cash and Cash Equivalents December 31              $   11,600   $   5,107     $   7,206
                                                   ==========   =========     =========

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was $68,506,000, $72,007,000
  and  $73,917,000  and  for  income  taxes  was  $81,109,000,  $71,809,000  and
  $53,410,000 in 2000, 1999 and 1998,  respectively.  Noncash acquisitions under
  capital leases were $10,777,000,  $6,855,000 and $11,107,000 in 2000, 1999 and
  1998, respectively.

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


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization


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

<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $  713,449        $  860,483
                                                                                 ----------        ----------

PREFERRED STOCK - authorized shares 2,500,000 $100 par value
                  authorized shares 7,000,000 $25 par value

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2000            Year Ended December 31,       December 31, 2000
------     ------------     ----------------------------     -----------------
                              2000      1999      1998
                              ----      ----      ----

Subject to Mandatory Redemption:

7.00%          (a)          100,000      -         -               150,000           15,000            25,000
                                                                                 ----------        ----------


LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                537,119           562,327
Installment Purchase Contracts                                                       91,166            91,112
Senior Unsecured Notes                                                              159,318           159,212
Junior Debentures                                                                   112,012           111,894
                                                                                 ----------        ----------

  Total Long-term Debt                                                              899,615           924,545
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $1,628,064        $1,810,028
                                                                                 ==========        ==========


(a)  Commencing  in 2000, a sinking fund will require the  redemption  of 50,000
     shares at $100 a share on or before August 1 of each year.  The Company has
     the right, on each sinking fund date, to redeem an additional 50,000 shares
     which  the  company  did in  August  2000.  Redemption  of this  series  is
     prohibited  prior to August 1, 2000. The sinking fund  provisions of the 7%
     series aggregate $5,000,000 in 2002, 2003 and 2004.



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

</TABLE>

<PAGE>





COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
-------------------------------------------------



<PAGE>



First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2000       1999
                           ----       ----
                          (in thousands)
% Rate Due
7.25   2002 - October 1  $ 56,500   $ 75,000
7.15   2002 - November 1   20,000     20,000
6.80   2003 - May 1        45,000     50,000
6.60   2003 - August 1     40,000     40,000
6.10   2003 - November 1   20,000     20,000
6.55   2004 - March 1      50,000     50,000
6.75   2004 - May 1        50,000     50,000
8.70   2022 - July 1       35,000     35,000
8.40   2022 - August 1     15,000     15,000
8.55   2022 - August 1     15,000     15,000
8.40   2022 - August 15    25,500     25,500
8.40   2022 - October 15   13,000     15,000
7.90   2023 - May 1        50,000     50,000
7.75   2023 - August 1     33,000     33,000
7.45   2024 - March 1      30,000     30,000
7.60   2024 - May 1        41,000     41,000
Unamortized Discount       (1,881)    (2,173)
                         --------   --------
  Total                  $537,119   $562,327
                         ========   ========

         Certain  indentures  relating  to  the  first  mortgage  bonds  contain
improvement,  maintenance  and replacement  provisions  requiring the deposit of
cash or bonds with the trustee,  or in lieu thereof,  certification  of unfunded
property additions.

Installment  purchase  contracts  have been entered into in connection  with the
issuance of pollution control revenue bonds by the Ohio Air Quality  Development
Authority:

                             December 31,
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due
------ -----------------
6-3/8  2020 - December 1  $48,550    $48,550
6-1/4  2020 - December 1   43,695     43,695
Unamortized Discount       (1,079)    (1,133)
                          -------    -------
Total                     $91,166    $91,112
                          =======    =======



         Under  the  terms  of the  installment  purchase  contracts,  CSPCo  is
required to pay amounts  sufficient to enable the payment of interest on and the
principal  (at stated  maturities  and upon  mandatory  redemptions)  of related
pollution  control revenue bonds issued to finance the construction of pollution
control facilities at the Zimmer Plant.

Senior unsecured notes outstanding were as follows:

                            December 31,
                          2000       1999
                          ----       ----
                           (in thousands)
% Rate Due
------ ------------------
6.85   2005 - October 3  $ 48,000  $ 48,000
6.51   2008 - February 1   52,000    52,000
6.55   2008 - June 26      60,000    60,000
Unamortized Discount         (682)     (788)
                         --------  --------
  Total                  $159,318  $159,212
                         ========  ========

Junior debentures outstanding were as follows:

                            December 31,
                         2000         1999
                         ----         ----
                          (in thousands)
% Rate Due
------ ------------------
8-3/8  2025 - September 30 $ 75,000 $ 75,000
7.92   2027 - March 31       40,000   40,000
Unamortized Discount         (2,988)  (3,106)
                           -------- --------
  Total                    $112,012 $111,894
                           ======== ========

         Interest may be deferred  and payment of principal  and interest on the
junior  debentures is subordinated  and subject in right to the prior payment in
full of all senior indebtedness of the Company.

         At December 31, 2000,  future  annual  long-term  debt  payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2001                         $   -
2002                           76,500
2003                          105,000
2004                          100,000
2005                           48,000
Later Years                   576,745
                             --------
  Total Principal Amount      906,245
Unamortized Discount           (6,630)
                             --------
    Total                    $899,615
                             ========



<PAGE>


COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
--------------------------------------------------------------

The notes listed below are combined with the notes to financial  statements  for
AEP and its other subsidiary  registrants.  The combined footnotes begin on page
L-1.

                                                          Combined
                                                          Footnote
                                                          Reference

Significant Accounting Policies                           Note 1

Extraordinary Items                                       Note 2

Rate Matters                                              Note 5

Effects of Regulation                                     Note 6

Industry Restructuring                                    Note 7

Commitments and Contingencies                             Note 8

Staff Reductions                                          Note 11

Benefit Plans                                             Note 12

Business Segments                                         Note 14

Financial Instruments, Credit and Risk Management         Note 15

Income Taxes                                              Note 16

Supplementary Information                                 Note 17

Leases                                                    Note 18

Lines of Credit and Factoring of Receivable               Note 19

Unaudited Quarterly Financial Information                 Note 20

Jointly Owned Electric Utility Plant                      Note 22

Related Party Transactions                                Note 23




<PAGE>


INDEPENDENT AUDITORS' REPORT
--------------------------------------------------


To the Shareholders and Board of Directors
of Columbus Southern Power Company:

         We have  audited  the  accompanying  consolidated  balance  sheets  and
consolidated statements of capitalization of Columbus Southern Power Company and
its subsidiaries as of December 31, 2000 and 1999, and the related  consolidated
statements of income,  retained  earnings,  and cash flows for each of the three
years in the period ended December 31, 2000. These financial  statements are the
responsibility of the Company's management.  Our responsibility is to express an
opinion on these financial statements based on our audits.

         We conducted our audits in accordance with auditing standards generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

         In our opinion, such consolidated  financial statements present fairly,
in all material  respects,  the financial  position of Columbus  Southern  Power
Company and its  subsidiaries  as of December 31, 2000 and 1999, and the results
of their  operations  and their  cash  flows for each of the three  years in the
period  ended  December  31,  2000  in  conformity  with  accounting  principles
generally accepted in the United States of America.



Deloitte & Touche LLP
Columbus, Ohio
February 26, 2001




<PAGE>



















                 INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES



<PAGE>
<TABLE>
<CAPTION>


                                      F-14
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial
Data
------------------------------------------------------------------------------------------------------------------------------

                                             Year Ended December 31,
                         -----------------------------------------------------------------
                            2000         1999          1998         1997          1996
                            ----         ----          ----         ----          ----
                                                  (in thousands)
INCOME STATEMENTS DATA:

<S>                      <C>          <C>           <C>           <C>           <C>
  Operating Revenues     $1,548,476   $1,394,119    $1,405,794    $1,339,232    $1,328,493
  Operating Expenses      1,583,178    1,285,467     1,239,787     1,131,444     1,108,076
                         ----------   ----------    ----------    ----------    ----------
  Operating Income (Loss)   (34,702)     108,652       166,007       207,788       220,417
  Nonoperating Income
   (Loss)                     9,933        4,530          (839)        4,415         2,729
                         ----------   ----------    ----------    ----------    ----------
  Income (Loss) Before
   Interest Charges         (24,769)     113,182       165,168       212,203       223,146
  Interest Charges          107,263       80,406        68,540        65,463        65,993
                         ----------   ----------    ----------    ----------    ----------
  Net Income (Loss)        (132,032)      32,776        96,628       146,740       157,153
  Preferred Stock
   Dividend Requirements      4,624        4,885         4,824         5,736        10,681
                         ----------   ----------    ----------    ----------    ----------
  Earnings (Loss)
   Applicable to
   Common Stock          $ (136,656)  $   27,891    $   91,804    $  141,004    $  146,472
                         ==========   ==========    ==========    ==========    ==========



                                                    December 31,
                         -----------------------------------------------------------------
                            2000         1999          1998         1997          1996
                            ----         ----          ----         ----          ----
                                                  (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant $4,871,473   $4,770,027    $4,631,848    $4,514,497    $4,377,669
  Accumulated
   Depreciation and
   Amortization           2,280,521    2,194,397     2,081,355     1,973,937     1,861,893
                         ----------   ----------    ----------    ----------    ----------
  Net Electric Utility
   Plant                 $2,590,952   $2,575,630    $2,550,493    $2,540,560    $2,515,776
                         ==========   ==========    ==========    ==========    ==========

  Total Assets           $5,818,547   $4,576,696    $4,148,523    $3,967,798    $3,897,484
                         ==========   ==========    ==========    ==========    ==========

  Common Stock and
   Paid-in Capital       $  789,656   $  789,323    $  789,189    $  789,056    $  787,856
  Retained Earnings           3,443      166,389       253,154       278,814       269,071
                         ----------   ----------    ----------    ----------    ----------
  Total Common
   Shareholder's Equity  $  793,099   $  955,712    $1,042,343    $1,067,870    $1,056,927
                         ==========   ==========    ==========    ==========    ==========

  Cumulative Preferred Stock:
    Not Subject to
     Mandatory
     Redemption          $    8,736   $    9,248    $    9,273    $    9,435    $   21,977
    Subject to Mandatory
      Redemption (a)         64,945       64,945        68,445        68,445       135,000
                         ----------   ----------    ----------    ----------    ----------
      Total Cumulative
        Preferred Stock  $   73,681   $   74,193    $   77,718    $   77,880    $  156,977
                         ==========   ==========    ==========    ==========    ==========

  Long-term Debt (a)     $1,388,939   $1,324,326    $1,175,789    $1,049,237    $1,042,104
                         ==========   ==========    ==========    ==========    ==========

  Obligations Under
   Capital Leases (a)    $  163,173   $  187,965    $  186,427    $  195,227    $  130,965
                         ==========   ==========    ==========    ==========    ==========

  Total Capitalization
    and Liabilities      $5,818,547   $4,576,696    $4,148,523    $3,967,798    $3,897,484
                         ==========   ==========    ==========    ==========    ==========



(a)      Including portion due within one year.
</TABLE>
<PAGE>





INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis
of Results of Operations
------------------------------------------------



<PAGE>


       I&M is a  public  utility  engaged  in the  generation,  purchase,  sale,
transmission  and  distribution of electric power to 565,000 retail customers in
its  service  territory  in  northern  and  eastern  Indiana  and a  portion  of
southwestern  Michigan.  As a member  of the AEP  Power  Pool,  I&M  shares  the
revenues and the costs of the AEP Power Pool's  wholesale  sales to  neighboring
utilities and power marketers.  I&M also sells wholesale power to municipalities
and electric cooperatives.

       The cost of the AEP System's  generating  capacity is allocated among the
AEP Power Pool  members  based on their  relative  peak  demands and  generating
reserves  through  the  payment of  capacity  charges or the receipt of capacity
credits. AEP Power Pool members are also compensated for the out-of-pocket costs
of energy  delivered to the AEP Power Pool and charged for energy  received from
the AEP Power Pool.

       The AEP Power Pool  calculates  each  company's  prior  twelve month peak
demand relative to the total peak demand of all member  companies as a basis for
sharing  revenues and costs.  The result of this  calculation  is each company's
member load ratio (MLR) which  determines  each  company's  percentage  share of
revenues or costs.  I&M 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.  Revenues from forward  electricity
trades in AEP's traditional  marketing area (up to two transmission systems from
the AEP service  territory) are recorded net of purchases as operating  revenues
and as nonoperating income for trades beyond two transmission  systems from AEP.
The AEP Power Pool also  enters into power  trading  transactions  for  options,
futures and swaps. I&M's share of these transactions is recorded in nonoperating
income.

       I&M is committed  under unit power  agreements to purchase all of AEGCo's
50% share of the 2,600 MW  Rockport  Plant  capacity  unless it is sold to other
utilities.  AEGCo is an affiliate  that is not a member of the AEP Power Pool. A
long-term unit power agreement with an  unaffiliated  utility expired at the end
of 1999 for the sale of 455 MW of AEGCo's Rockport Plant capacity.  An agreement
between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant
capacity to KPCo through 2004.  Therefore,  effective January 1, 2000, I&M began
purchasing 910 MW of AEGCo's 50% share of Rockport Plant capacity.

Results of Operations

       During  2000  both of the Cook  Plant  nuclear  units  were  successfully
restarted after being shutdown in September 1997 due to questions  regarding the
operability  of  certain  safety  systems  which  arose  during a NRC  architect
engineer  design  inspection.   See  discussion  in  Note  4  of  the  Notes  to
Consolidated Financial Statements.

       In February  2001 the U.S.  District  Court for the Southern  District of
Ohio ruled against AEP and certain of its subsidiaries, including I&M, in a suit
over  deductibility of interest claimed in AEP's consolidated tax return related
to a corporate owned life insurance  (COLI)  program.  In 1998 and 1999 I&M paid
the disputed taxes and interest attributable to the COLI interest deductions for
the taxable years  1991-98.  The payments  were  included in Other  Property and
Investments  pending the  resolution of this matter.  As a result of the Court's
decision, I&M's net income was reduced by $66 million in 2000.

       As a result of the  costs  incurred  in 2000 to  restart  the Cook  Plant
nuclear  units and the  disallowance  of COLI  interest  deductions,  net income
declined  $165  million in 2000.  In 1999 net income  declined  $64  million due
primarily to the cost of efforts to restart the Cook Plant units.

Operating Revenues

       Operating  revenues  increased 11% in 2000 and decreased 1% in 1999.  The
increase in operating revenues in 2000 was primarily due to increased  wholesale
sales to the AEP Power Pool. The decrease in 1999 was primarily due to a decline
in margins on wholesale sales and net power trading  transactions within the AEP
Power Pool's  traditional  marketing area. The following analyzes the changes in
operating revenues:

                    Increase (Decrease)
                    From Previous Year
(dollars in millions)
---------------------
                     2000           1999
               ------------------------------
               Amount    %    Amount     %
Retail:
   Residential $(37.3)        $  3.4
   Commercial   (16.2)           0.7
   Industrial   (30.0)          (5.7)
   Other         (5.0)          (0.2)
               ------         ------
                (88.5)  (9)     (1.8)    -

Wholesale       253.7   84     (18.2)   (6)
Transmission
 and Other      (10.8) (21)      8.3    20
               ------         ------
     Total     $154.4   11    $(11.7)   (1)
               ======         ======

       The increase in operating  revenues in 2000 is primarily due to increased
wholesale  sales to the AEP Power  Pool.  With the return to service of the Cook
Plant  units and  purchasing  more  power from  AEGCo due to the  expiration  of
AEGCo's  contract  to  sell  power  to an  unaffiliated  entity,  I&M  had  more
electricity  available  to sell to the AEP Power Pool. A decline in retail sales
and retail  price which led to a decrease in retail  operating  revenues  partly
offset the increase in wholesale revenues.

       Operating  revenues  decreased  slightly in 1999 primarily due to reduced
margins on I&M's MLR share of wholesale  sales and net revenues  from  regulated
power trading  transactions in the AEP Power Pool's traditional  marketing area.
The decline in margins  reflects the  moderation  in 1999 of extreme  weather in
1998 and capacity shortages experienced in the summer of 1998.

Operating Expenses Increase

       Total operating  expenses  increased 23% in 2000 and 4% in 1999 primarily
due to costs  related to the  extended  Cook Plant outage and efforts to restart
the Cook Plant units. Also contributing to the increase in operating expenses in
2000 was the unfavorable  COLI tax ruling and the additional  purchases of power
due to the  expiration  of an AEGCo  unit  power  agreement  to sell part of its
Rockport  Plant  generation  to an  unaffiliated  utility.  The  changes  in the
components of operating expenses were:

                     Increase (Decrease)
                      From Previous Year
(dollars in millions)
---------------------
                       2000           1999
                -----------------------------
                Amount     %    Amount    %

Fuel            $ 25.5    14    $ 12.8    7
Purchased Power   60.4    22     (21.1)  (7)
Other Operation  137.5    30     114.3   33
Maintenance       84.5    62     (22.3) (14)
Depreciation and
 Amortization      4.9     3       4.9    3
Taxes Other Than
 Federal Income
 Taxes            11.0    19      (8.8) (13)
Federal Income
 Taxes           (26.1) (149)    (34.1) (66)
                ------          ------
    Total       $297.7    23    $ 45.7    4
                ======          ======

       The  increase  in fuel  expense in 2000  reflects  an increase in nuclear
generation  as the Cook Plant units  returned to service  following  an extended
outage.  Fuel  expense  increased  in  1999  primarily  due  to an  increase  in
coal-fired generation replacing power purchases from the AEP Power Pool.

       Purchased power expense increased in 2000 due to increased purchases from
AEGCo.  As a result of the  expiration  of AEGCo's  power sale  contract with an
unaffiliated  utility on December  31,  1999,  I&M was  obligated to buy more of
AEGCo's share of Rockport Plant power.  The decrease in purchased  power expense
in 1999 reflects the purchase of less power in 1999 at lower prices from the AEP
Power Pool, AEGCo and unaffiliated entities.

       The increases in other operation  expense in 2000 and 1999 were primarily
due to expenditures to prepare the Cook Plant nuclear units for restart.


       Maintenance  expense  increased in 2000 primarily due to  expenditures to
prepare the Cook Plant units for restart.  The decline in maintenance expense in
1999 was due to cost  containment  efforts  including staff  reductions at I&M's
fossil-fired  power plants,  in the  engineering  and  maintenance  staff of AEP
Service Corporation and in I&M's transmission and distribution operations.

       In 1999 the IURC and MPSC approved  settlement  agreements  which allowed
the  deferral  of  $200  million  of  Cook  Plant  restart  costs  in  1999  for
amortization  over  five  years  from 1999  through  2003.  As a  result,  other
operation  and  maintenance  expense in 1999  reflected  a net  deferral of $160
million.  See  discussion  in  Note 4 of the  Notes  to  Consolidated  Financial
Statements.

       The increase in taxes other than federal  income tax in 2000 is primarily
attributable  to an increase in Indiana  supplemental  net income tax reflecting
the COLI  decision  related  interest  deduction  disallowance  and a  favorable
accrual  adjustment  recorded in December 1999 related to the filing of the 1998
tax return.  The decrease in taxes other than  federal  income taxes in 1999 was
primarily due to a decline in estimated taxable income for Indiana  supplemental
income tax.

       Federal  income taxes  attributable  to operations  decreased in 2000 and
1999 due to  decreases  in pre-tax  operating  income.  In 2000 the decrease was
partially offset by an increase in tax expense related to the unfavorable ruling
in the  suit  against  the IRS over  interest  deductions  claimed  for the COLI
program.

Nonoperating Income

       The increase in nonoperating  income in 2000 and 1999 is primarily due to
the effect of net gains on non-regulated  electricity trading transactions.  The
AEP Power Pool enters into non-regulated  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.  I&M's
share of the AEP Power Pool's non-regulated trading transactions are included in
nonoperating income.

Interest Charges

       Interest charges  increased in 2000 and 1999 due to increased  borrowings
to support  expenditures  for the Cook Plant restart effort and in 2000 also due
to the  recognition  of deferred  interest  payments to the IRS on the  disputed
taxes.



<PAGE>
<TABLE>
<CAPTION>

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of
Income
------------------------------------------------------------------------------------------------------------------------------------

                                                           Year Ended December 31,
                                                   ---------------------------------------
                                                      2000           1999         1998
                                                      ----           ----         ----
                                                                (in thousands)

<S>                                                <C>            <C>          <C>
OPERATING REVENUES                                 $1,548,476     $1,394,119   $1,405,794
                                                   ----------     ----------   ----------

OPERATING EXPENSES:
  Fuel                                                210,870        185,419      172,592
  Purchased Power                                     337,376        276,962      298,046
  Other Operation                                     599,012        461,494      347,207
  Maintenance                                         219,854        135,331      157,593
  Depreciation and Amortization                       154,920        149,988      145,112
  Taxes Other Than Federal Income Taxes                69,761         58,713       67,592
  Federal Income Tax Expense (Credit)                  (8,615)        17,560       51,645
                                                   ----------     ----------   ----------
           Total Operating Expenses                 1,583,178      1,285,467    1,239,787
                                                   ----------     ----------   ----------

OPERATING INCOME (LOSS)                               (34,702)       108,652      166,007

NONOPERATING INCOME (LOSS)                              9,933          4,530         (839)
                                                   ----------     ----------   ----------

INCOME (LOSS) BEFORE INTEREST CHARGES                 (24,769)       113,182      165,168

INTEREST CHARGES                                      107,263         80,406       68,540
                                                   ----------     ----------   ----------

NET INCOME (LOSS)                                    (132,032)        32,776       96,628

PREFERRED STOCK DIVIDEND REQUIREMENTS                   4,624          4,885        4,824
                                                   ----------     ----------   ----------

EARNINGS (LOSS) APPLICABLE TO COMMON STOCK         $ (136,656)    $   27,891   $   91,804
                                                   ==========-    ==========   ==========

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

</TABLE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance
Sheets
------------------------------------------------------------------------

                                                                      December 31,
                                                                  2000            1999
                                                                     (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                            <C>             <C>
 Production                                                    $2,708,436      $2,587,288
 Transmission                                                     945,709         928,758
 Distribution                                                     863,736         818,697
 General (including nuclear fuel)                                 257,152         244,981
 Construction Work in Progress                                     96,440         190,303
                                                               ----------      ----------
         Total Electric Utility Plant                           4,871,473       4,770,027
 Accumulated Depreciation and Amortization                      2,280,521       2,194,397
                                                               ----------      ----------
         NET ELECTRIC UTILITY PLANT                             2,590,952       2,575,630
                                                               ----------      ----------


NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
 FUEL DISPOSAL TRUST FUNDS                                        778,720         707,967
                                                               ----------      ----------

LONG-TERM ENERGY TRADING CONTRACTS                                194,947          23,131
                                                               ----------      ----------

OTHER PROPERTY AND INVESTMENTS                                    131,417         190,527
                                                               ----------      ----------



CURRENT ASSETS:
 Cash and Cash Equivalents                                         14,835           3,863
 Accounts Receivable:
  Customers                                                       106,832          91,268
  Affiliated Companies                                             48,706          48,901
  Miscellaneous                                                    27,491          18,644
  Allowance for Uncollectible Accounts                               (759)         (1,848)
 Fuel - at average cost                                            16,532          27,597
 Materials and Supplies - at average cost                          84,471          84,149
 Accrued Utility Revenues                                            -             44,428
 Energy Trading Contracts                                       1,229,683          97,946
 Prepayments                                                        6,424           7,631
                                                               ----------      ----------
         TOTAL CURRENT ASSETS                                   1,534,215         422,579
                                                               ----------      ----------


REGULATORY ASSETS                                                 552,140         624,810
                                                               ----------      ----------


DEFERRED CHARGES                                                   36,156          32,052
                                                               ----------      ----------


           TOTAL                                               $5,818,547      $4,576,696
                                                               ==========      ==========

See Notes to Consolidated Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
---------------------------------------------------------------------------------------------------------

                                                                     December 31,
                                                              ---------------------------
                                                                 2000            1999
                                                                 ----            ----
                                                                    (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
 Common Stock - No Par Value:
   Authorized - 2,500,000 Shares
<S>                                                           <C>             <C>
   Outstanding - 1,400,000 Shares                             $   56,584      $   56,584
   Paid-in Capital                                               733,072         732,739
   Retained Earnings                                               3,443         166,389
                                                              ----------      ----------
           Total Common Shareholder's Equity                     793,099         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                                              1,298,939       1,126,326
                                                              ----------      ----------
           TOTAL CAPITALIZATION                                2,165,719       2,156,231
                                                              ----------      ----------

OTHER NONCURRENT LIABILITIES:
 Nuclear Decommissioning                                         560,628         501,185
 Other                                                           108,600         242,522
                                                              ----------      ----------
           TOTAL OTHER NONCURRENT LIABILITIES                    669,228         743,707
                                                              ----------      ----------

CURRENT LIABILITIES:
 Long-term Debt Due Within One Year                               90,000         198,000
 Short-term Debt                                                    -            224,262
 Advances from Affiliates                                        253,582            -
 Accounts Payable - General                                      119,472          78,784
 Accounts Payable - Affiliated Companies                          75,486          31,118
 Taxes Accrued                                                    68,416          48,970
 Interest Accrued                                                 21,639          13,955
 Obligations Under Capital Leases                                100,848          11,072
 Energy Trading Contracts                                      1,275,097          95,564
 Other                                                            97,070          91,684
                                                              ----------      ----------
           TOTAL CURRENT LIABILITIES                           2,101,610         793,409
                                                              ----------      ----------

DEFERRED INCOME TAXES                                            487,945         622,157
                                                              ----------      ----------

DEFERRED INVESTMENT TAX CREDITS                                  113,773         121,627
                                                              ----------      ----------

DEFERRED GAIN ON SALE AND LEASEBACK -
  ROCKPORT PLANT UNIT 2                                           81,299          85,005
                                                              ----------      ----------

LONG-TERM ENERGY TRADING CONTRACTS                               156,736          17,887
                                                              ----------      ----------

DEFERRED CREDITS                                                  42,237          36,673
                                                              ----------      ----------

COMMITMENTS AND CONTINGENCIES (Note 8)

             TOTAL                                            $5,818,547      $4,576,696
                                                              ==========      ==========

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

</TABLE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
------------------------------------------

                            Year Ended December 31,
                                                     2000          1999          1998
                                                     ----          ----          ----
                                                              (in thousands)
OPERATING ACTIVITIES:
<S>                                                <C>           <C>           <C>
  Net Income (Loss)                                $(132,032)    $  32,776     $  96,628
  Adjustments for Noncash Items:
   Depreciation and Amortization                     163,391       153,921       149,209
   Amortization of Incremental Nuclear
    Refueling Outage Expenses (net)                    5,737         8,480        14,142
   Amortization (Deferral) of Nuclear
    Outage Costs (net)                                40,000      (160,000)         -
   Deferred Federal Income Taxes                    (125,179)       85,727        17,905
   Deferred Investment Tax Credits                    (7,854)       (8,152)       (8,266)
   Unrecovered Fuel and Purchased Power Costs         37,501       (84,696)      (46,846)
  Changes in Certain Current Assets and Liabilities:
   Accounts Receivable (net)                         (25,305)      (19,178)        1,462
   Fuel, Materials and Supplies                       10,743       (12,880)       (2,983)
   Accrued Utility Revenues                           44,428        (7,151)       (6,756)
   Accounts Payable                                   85,056        19,068        22,440
   Taxes Accrued                                      19,446        13,809       (11,689)
  Disputed Tax and Interest Related to COLI           56,856        (3,228)      (53,628)
  Other (net)                                        (41,900)       12,831        (8,176)
                                                   ---------     ---------     ---------
     Net Cash Flows From Operating Activities        130,888        31,327       163,442
                                                   ---------     ---------     ---------

INVESTING ACTIVITIES:
  Construction Expenditures                         (171,071)     (165,331)     (147,627)
  Proceeds from Sales of Property and Other              587         2,501         4,419
                                                   ---------     ---------     ---------
    Net Cash Flows Used For Investing Activities    (170,484)     (162,830)     (143,208)
                                                   ---------     ---------     ---------

FINANCING ACTIVITIES:
 Issuance of Long-term Debt                          199,220       247,989       170,675
 Retirement of Cumulative Preferred Stock               (314)       (3,597)         (120)
 Retirement of Long-term Debt                       (148,000)     (109,500)      (55,000)
 Changes in Advances from Affiliates (net)           253,582          -             -
 Change in Short-term Debt (net)                    (224,262)      115,562       (10,900)
 Dividends Paid on Common Stock                      (26,290)     (114,656)     (117,464)
 Dividends Paid on Cumulative Preferred Stock         (3,368)       (5,856)       (4,734)
                                                   ---------     ---------     ---------
    Net Cash Flows From (Used For)
     Financing Activities                             50,568       129,942       (17,543)
                                                   ---------     ---------     ---------

Net Increase (Decrease) in Cash and
 Cash Equivalents                                     10,972        (1,561)        2,691
Cash and Cash Equivalents January 1                    3,863         5,424         2,733
                                                   ---------     ---------     ---------
Cash and Cash Equivalents December 31              $  14,835     $   3,863     $   5,424
                                                   =========     =========     =========

Supplemental Disclosure:
  Cash paid (received) for interest net of capitalized  amounts was $82,511,000,
  $78,703,000   and   $66,313,000   and  for  income   taxes  was   $73,254,000,
  $(71,395,000)  and $36,413,000 in 2000, 1999 and 1998,  respectively.  Noncash
  acquisitions under capital leases were $22,218,000, $10,852,000 and $9,658,000
  in 2000, 1999 and 1998, respectively.

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


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
-------------------------------------

                            Year Ended December 31,
                                                   2000            1999            1998
                                                   ----            ----            ----
                                                              (in thousands)

<S>                                              <C>             <C>             <C>
Retained Earnings January 1                      $ 166,389       $253,154        $278,814
Net Income (Loss)                                 (132,032)        32,776          96,628
                                                 ---------       --------        --------
                                                    34,357        285,930         375,442
                                                 ---------       --------        --------
Deductions:
 Cash Dividends Declared:
   Common Stock                                     26,290        114,656         117,464
   Cumulative Preferred Stock:
     4-1/8% Series                                     230            244             247
     4.56%  Series                                      66             66              67
     4.12%  Series                                      74             78              79
     5.90%  Series                                     897            963             985
     6-1/4% Series                                   1,203          1,250           1,266
     6.30%  Series                                     834            834             834
     6-7/8% Series                                   1,186          1,238           1,255
                                                 ---------       --------        --------
           Total Cash Dividends Declared            30,780        119,329         122,197
  Capital Stock Expense                                134            212              91
                                                 ---------       --------        --------
            Total Deductions                        30,914        119,541         122,288
                                                 ---------       --------        --------

Retained Earnings December 31                    $   3,443       $166,389        $253,154
                                                 =========       ========        ========

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

INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of
Capitalization
-------------------------------------------------------------------------------

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

<S>                                                                                <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                        $  793,099        $  955,712
                                                                                   ----------        ----------

PREFERRED STOCK:
$100 Par Value - Authorized 2,250,000 shares
$25 Par Value - Authorized 11,200,000 shares

              Call Price       Number of Shares Redeemed       Shares
              December 31,      Year Ended December 31,        Outstanding
Series           2000           2000     1999     1998         December 31, 2000
--------------------------------------------------------------------------------
Not Subject to Mandatory Redemption:
    4-1/8%     106.125          3,750      97      771              55,389              5,539             5,914
    4.56%      102               -        150      650              14,412              1,441             1,441
    4.12%      102.728          1,375      -       200              17,556              1,756             1,893
                                                                                   ----------        ----------
                                                                                        8,736             9,248
                                                                                   ----------        ----------
Subject to Mandatory Redemption:
    5.90%  (a,b)                 -     15,000       -              152,000             15,200            15,200
    6-1/4% (a,b)                 -     10,000       -              192,500             19,250            19,250
    6.30%  (a,b)                 -       -          -              132,450             13,245            13,245
    6-7/8% (a,c)                 -     10,000       -              172,500             17,250            17,250
                                                                                   ----------        ----------
                                                                                       64,945            64,945
                                                                                   ----------        ----------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                  308,976           356,820
Installment Purchase Contracts                                                        309,717           309,568
Senior Unsecured Notes                                                                397,435           297,282
Other Long-term Debt                                                                  211,307           199,259
Junior Debentures                                                                     161,504           161,397
Less Portion Due Within One Year                                                      (90,000)         (198,000)
                                                                                   ----------        ----------

    Long-term Debt Excluding Portion Due Within One Year                            1,298,939         1,126,326
                                                                                   ----------        ----------

    TOTAL CAPITALIZATION                                                           $2,165,719        $2,156,231
                                                                                   ==========        ==========

(a)  Not  callable  until  after  2002.  There  are no  aggregate  sinking  fund
     provisions  through 2002. Sinking fund provisions require the redemption of
     15,000 shares in 2003 and 67,500 shares in each 2004 and 2005.
(b)  Commencing in 2004 and continuing  through 2008 the Company may redeem,  at
     $100 per share,  20,000  shares of the 5.90%  series,  15,000 shares of the
     6-1/4%  series  and 17,500  shares of the 6.30%  series  outstanding  under
     sinking fund provisions at its option and all remaining  outstanding shares
     must be redeemed not later than 2009.  Shares redeemed in 1999 and 1997 may
     be applied to meet the sinking fund requirement.
(c)  Commencing  in 2003 and  continuing  through the year 2007,  a sinking fund
     will require the  redemption of 15,000 shares each year and the  redemption
     of the remaining shares  outstanding on April 1, 2008, in each case at $100
     per  share.  Shares  redeemed  in 1999 and 1997 may be  applied to meet the
     sinking fund requirement.


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





INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
-----------------------------------------------------



<PAGE>



First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due
6.40   2000 - March 1    $   -      $ 48,000
7.63   2001 - June 1       40,000     40,000
7.60   2002 - November 1   50,000     50,000
7.70   2002 - December 15  40,000     40,000
6.10   2003 - November 1   30,000     30,000
8.50   2022 - December 15  75,000     75,000
7.35   2023 - October 1    20,000     20,000
7.20   2024 - February 1   30,000     30,000
7.50   2024 - March 1      25,000     25,000
Unamortized Discount       (1,024)    (1,180)
                         --------   --------
                         $308,976   $356,820

         Certain  indentures  relating  to  the  first  mortgage  bonds  contain
improvement,  maintenance  and replacement  provisions  requiring the deposit of
cash or bonds with the trustee,  or in lieu thereof,  certification  of unfunded
property additions.

Installment  purchase  contracts have been entered into, in connection  with the
issuance of pollution  control  revenue  bonds by  governmental  authorities  as
follows:

                             December 31,
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due
------ -----------------
City of Lawrenceburg, Indiana:
7.00   2015 - April 1    $ 25,000   $ 25,000
5.90   2019 - November 1   52,000     52,000

City of Rockport, Indiana:
 (a)   2014 - August 1     50,000     50,000
7.60   2016 - March 1      40,000     40,000
6.55   2025 - June 1       50,000     50,000
 (b)   2025 - June 1       50,000     50,000

City of Sullivan, Indiana:
5.95   2009 - May 1        45,000     45,000
Unamortized Discount       (2,283)    (2,432)
                         --------   --------
                         $309,717   $309,568

(a)      A variable interest rate is determined weekly.  The average weighted
         interest rate was 4.5% for 2000 and 3.2% for 1999.
(b)      An adjustable  interest  rate can be a daily,  weekly,  commercial
         paper or term rate as designated by I&M. A weekly rate was
         selected  which  ranged  from 2.9% to 5.9% in 2000 and from 2.2% to
         5.6% in 1999 and averaged 4.2% and 3.2% during 2000 and 1999,
         respectively.


         Under the terms of the installment purchase contracts,  I&M is required
to pay  amounts  sufficient  to enable  the  cities to pay  interest  on and the
principal  (at stated  maturities  and upon  mandatory  redemptions)  of related
pollution  control revenue bonds issued to finance the construction of pollution
control facilities at certain generating plants. On the two variable rate series
the  principal  is  payable  at the  stated  maturities  or on the demand of the
bondholders  at periodic  interest  adjustment  dates which  occur  weekly.  The
variable  rate bonds due in 2014 are  supported by a bank letter of credit which
expires in 2002.  I&M has  agreements  that  provide for brokers to remarket the
adjustable rate bonds due in 2025 tendered at interest  adjustment dates. In the
event  certain  bonds  cannot be  remarketed,  I&M has a standby  bond  purchase
agreement  with a bank  that  provides  for the bank to  purchase  any bonds not
remarketed.  The purchase agreement expires in 2001.  Accordingly,  the variable
and adjustable  rate  installment  purchase  contracts have been  classified for
repayment  purposes  based  on the  expiration  dates  of the  standby  purchase
agreement and the letter of credit.

Senior unsecured notes outstanding were as follows:
                             December 31,
                        ---------------------
                           2000       1999
                           ----       ----
                           (in thousands)
% Rate Due
------ ------------------
 (a)   2000 - November 22 $   -     $100,000
 (b)   2002 - September 3  200,000      -
6-7/8  2004 - July 1       150,000   150,000
6.45   2008 - November 10   50,000    50,000
Unamortized Discount        (2,565)   (2,718)
                          --------  --------
                          $397,435  $297,282

(a)      A floating interest  rate  is  determined monthly.
         The rate  on December 31, 1999 was 7.1%.
(b)      A floating  interest  rate is  determined quarterly.
         The rate on December 31, 2000 was 7.31%.


<PAGE>


Junior debentures outstanding were as follows:

                            December 31,
                         2000         1999
                         ----         ----
                          (in thousands)
% Rate Due
------ -----------------
8.00   2026 - March 31 $ 40,000     $ 40,000
7.60   2038 - June 30   125,000      125,000
Unamortized Discount     (3,496)      (3,603)
                       --------     --------
  Total                $161,504     $161,397
                       ========     ========

         Interest may be deferred  and payment of principal  and interest on the
junior  debentures is subordinated  and subject in right to the prior payment in
full of all senior indebtedness of I&M.


         At December 31, 2000,  future  annual  long-term  debt  payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2001                       $   90,000
2002                          340,000
2003                           30,000
2004                          150,000
2005                             -
Later Years                   788,307
                           ----------
  Total Principal Amount    1,398,307
Unamortized Discount           (9,368)
                           ----------
    Total                  $1,388,939
                           ==========



<PAGE>


INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements


The notes listed below are combined with the notes to financial  statements  for
AEP and its other subsidiary  registrants.  The combined footnotes begin on page
L-1.

                                                          Combined
                                                          Footnote
                                                          Reference

Significant Accounting Policies                           Note 1

Merger                                                    Note 3

Nuclear Plant Restart                                     Note 4

Rate Matters                                              Note 5

Effects of Regulation                                     Note 6

Industry Restructuring                                    Note 7

Commitments and Contingencies                             Note 8

Staff Reductions                                          Note 11

Benefit Plans                                             Note 12

Business Segments                                         Note 14

Financial Instruments, Credit and Risk Management         Note 15

Income Taxes                                              Note 16

Supplementary Information                                 Note 17

Leases                                                    Note 18

Lines of Credit and Factoring of Receivables              Note 19

Unaudited Quarterly Financial Information                 Note 20

Related Party Transactions                                Note 23





<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of Indiana Michigan Power Company:

       We  have  audited  the  accompanying   consolidated  balance  sheets  and
consolidated  statements of capitalization of Indiana Michigan Power Company and
its subsidiaries as of December 31, 2000 and 1999, and the related  consolidated
statements of income,  retained  earnings,  and cash flows for each of the three
years in the period ended December 31, 2000. These financial  statements are the
responsibility of the Company's management.  Our responsibility is to express an
opinion on these financial statements based on our audits.

       We conducted our audits in accordance with auditing  standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

       In our opinion, such consolidated financial statements present fairly, in
all material respects,  the financial position of Indiana Michigan Power Company
and its  subsidiaries as of December 31, 2000 and 1999, and the results of their
operations  and their cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001





<PAGE>











                             KENTUCKY POWER COMPANY


<PAGE>
<TABLE>
<CAPTION>


                                      G-11
KENTUCKY POWER COMPANY
Selected Financial Data
-----------------------------------------------------------

                                           Year Ended December 31,
                          ---------------------------------------------------------
                            2000        1999        1998        1997        1996
                            ----        ----        ----        ----        ----
                                               (in thousands)
INCOME STATEMENTS DATA:

<S>                       <C>         <C>         <C>         <C>         <C>
  Operating Revenues      $410,403    $373,982    $362,999    $340,635    $323,321
  Operating Expenses       360,665     319,307     311,106     293,779     281,978
                          --------    --------    --------    --------    --------
  Operating Income          49,738      54,675      51,893      46,856      41,343
  Nonoperating Income
   (Loss)                    2,070        (327)     (1,726)       (464)       (594)
                          --------    --------    --------    --------    --------
  Income Before Interest
   Charges                  51,808      54,348      50,167      46,392      40,749
  Interest Charges          31,045      28,918      28,491      25,646      23,776
                          --------    --------    --------    --------    --------
  Net Income              $ 20,763    $ 25,430    $ 21,676    $ 20,746    $ 16,973
                          ========    ========    ========    ========    ========

                                                 December 31,
                          ---------------------------------------------------------
                            2000        1999        1998        1997        1996
                            ----        ----        ----        ----        ----
                                               (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant  $1,103,064  $1,079,048  $1,043,711  $1,006,955   $951,602
  Accumulated Depreciation
    and Amortization         360,648     340,008     315,546     296,318    286,640
                          ----------  ----------  ----------  ----------   --------
  Net Electric Utility
    Plant                 $  742,416  $  739,040  $  728,165  $  710,637   $664,962
                          ==========  ==========  ==========  ==========   ========

  Total Assets            $1,512,016  $  986,638  $  921,847  $  886,671   $833,579
                          ==========  ==========  ==========  ==========   ========

  Common Stock and
    Paid-in Capital       $  209,200  $  209,200  $  199,200  $  179,200   $159,200
  Retained Earnings           57,513      67,110      71,452      78,076     84,090
                          ----------  ----------  ----------  ----------   --------
  Total Common
   Shareholder's Equity   $  266,713  $  276,310  $  270,652  $  257,276   $243,290
                          ==========  ==========  ==========  ==========   ========

  Long-term Debt(a)       $  330,880  $  365,782  $  368,838  $  341,051   $293,198
                          ==========  ==========  ==========  ==========   ========

  Obligations Under
    Capital leases (a)    $   14,184  $   15,141  $   18,977  $   18,725   $ 12,850
                          ==========  ==========  ==========  ==========   ========

  Total Capitalization
   and Liabilities        $1,512,016  $  986,638  $  921,847  $  886,671   $833,579
                          ==========  ==========  ==========  ==========   ========



(a)  Including portion due within one year.
</TABLE>
<PAGE>



KENTUCKY POWER COMPANY
Management's Narrative Analysis
of Results of Operations
----------------------------------------------------




<PAGE>


       KPCo is a public  utility  engaged  in the  generation,  purchase,  sale,
transmission and distribution of electric power serving 172,000 retail customers
in eastern  Kentucky.  KPCo as a member of the AEP System  Power Pool (AEP Power
Pool) shares in the revenues and costs of the AEP Power Pool's  wholesale  sales
to neighboring  utility systems and power  marketers.  KPCo also sells wholesale
power to municipalities.

       The cost of the AEP System's  generating  capacity is allocated among the
AEP Power Pool  members  based on their  relative  peak  demands and  generating
reserves through the payment of capacity charges or the receipt of credits.  AEP
Power Pool members are also compensated for their  out-of-pocket costs of energy
delivered  to the AEP Power Pool and  charged for energy  received  from the AEP
Power Pool.

       The AEP Power Pool  calculates  each  company's  prior  twelve month peak
demand relative to the total peak demand of all member  companies as a basis for
sharing AEP Power Pool revenues and costs. The result of this calculation is the
member load ratio (MLR) which determines each company's  percentage share of AEP
Power Pool  revenues or costs.  KPCo 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.  Revenues from
forward  electricity  trades are recorded net of purchases as operating revenues
for  transactions in AEP's  traditional  marketing area (up to two  transmission
systems  from  the  AEP  service  territory)  and  as  nonoperating  income  for
transactions  beyond two transmission  systems from AEP. The AEP Power Pool also
enters into power trading  transactions for options,  futures and swaps.  KPCo's
share of these transactions is recorded in nonoperating income.


       In February 2001 the U.S. District Court for the Southern District of
Ohio ruled against AEP and certain of its subsidiaries, including KPCo, in a
suit over deductibility of interest  claimed in AEP's  consolidated tax return
related to a corporate owned life insurance (COLI) program. In 1998 and 1999
KPCo paid the disputed taxes and interest attributable to the COLI interest
deductions for taxable years 1992-98. The  payments  were  included  in Other
Property  and  Investments  pending the resolution of this matter. As a result
of the Court's  decision,  net income was reduced by $8 million in 2000.

Net Income Decreases

       Net income  decreased  $4.7 million or 18% in 2000  primarily  due to the
COLI decision and an increase in maintenance expense.

Operating Revenues Increase

       Operating  revenues  increased  $36  million  or  10%  in  2000  due to a
significant  increase in AEP Power Pool transactions.  Changes in the components
of operating revenues were as follows:

                         Increase (Decrease)
(dollars in millions)   From Previous Year
                         Amount           %
Retail:
  Residential            $ 6.1           5.7
  Commercial              (0.2)         (0.3)
  Industrial              (3.5)         (3.7)
                         -----
                           2.4           0.9

Wholesale                 37.2          49.0
Transmission               2.8          62.6
Other                     (6.0)        (22.3)
                         -----
  Total                  $36.4           9.7
                         =====

       The  increase  in  operating  revenues is due to  increased  KWH sales to
residential  customers as a result of colder weather and a significant  increase
in AEP Power Pool wholesale transactions. 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  contributing  to the increase in the company's  revenue.  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 8% more KWH in the year 2000 than in the year
1999.  In 2000  other  revenues  decreased  substantially  due to the  effect of
favorable  adjustment to rental income in 1999 reflecting  agreed to retroactive
revisions  to  the  billings  for  pole  attachments   with   telecommunications
companies.

Operating Expenses Increase

       Operating  expenses  increased  $41.4 million  primarily due to increased
purchased  power,  maintenance  costs and federal  income taxes.  Changes in the
components of operating expenses were as follows:

                        Increase (Decrease)
(dollars in millions)   From Previous Year
                         Amount           %

Fuel                     $(9.7)        (11.5)
Purchased Power           41.6          38.6
Other Operation            0.8           1.6
Maintenance                4.4          20.6
Depreciation and
 Amortization              1.8           6.2
Taxes Other Than Federal
 Income Taxes             (1.1)        (10.6)
Federal Income Taxes       3.6          27.1
                         -----

     Total               $41.4          13.0
                         =====

        Fuel  expense  decreased  due to a decline in internal  generation  as a
result of  planned  outages  in 2000 at the  company's  Big Sandy  Plant Unit 2.
Purchased  Power expense  increased  due to a significant  increase in AEP Power
Pool wholesale  transactions  and affiliated  power purchases under a unit power
agreement.

        The  planned   outages  at  Big  Sandy  Plant  caused  the  increase  in
maintenance  expense.  Comparing  2000 to 1999,  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 compared to 4.6 weeks in 1999.



        An  increase  in  transmission  plant  investment  and  improvements  to
distribution facilities accounted for the increase in depreciation expense.

        Taxes  other  than  federal  income  taxes  decreased  due to  decreased
Kentucky state income taxes as a result of lower pre-tax operating income partly
offset by the  unfavorable  ruling in AEP's suit  against  the  government  over
interest deductions claimed in prior years related to a COLI program.

        The  increase in federal  income tax expense  was  primarily  due to the
unfavorable ruling in AEP's suit against the government over interest deductions
claimed in prior years related to a COLI program.

Nonoperating Income Increase

        Nonoperating   income   increased  due  to  the   favorable   effect  of
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 the AEP Power Pool's  non-regulated  trading transactions are
included in nonoperating income.

Interest Charges Increase

      The increase in interest charges  resulted from the U.S.  District Court's
unfavorable  decision  denying  Federal  income tax deductions for COLI interest
resulting in the incurrance of interest on taxes owed for prior years.



<PAGE>
<TABLE>
<CAPTION>


KENTUCKY POWER COMPANY
Statements of Income
---------------------------------------------------------------------------------------

                            Year Ended December 31,
                                                 2000          1999          1998
                                                 ----          ----          ----
                                                          (in thousands)

<S>                                            <C>           <C>           <C>
OPERATING REVENUES                             $410,403      $373,982      $362,999
                                               --------      --------      --------

OPERATING EXPENSES:
  Fuel                                           74,638        84,369        83,303
  Purchased Power                               149,345       107,763       100,620
  Other Operation                                53,325        52,468        47,802
  Maintenance                                    25,866        21,452        30,462
  Depreciation and Amortization                  31,028        29,221        28,080
  Taxes Other Than Federal Income Taxes           9,709        10,854         9,687
  Federal Income Taxes                           16,754        13,180        11,152
                                               --------      --------      --------
      TOTAL OPERATING EXPENSES                  360,665       319,307       311,106
                                               --------      --------      --------

OPERATING INCOME                                 49,738        54,675        51,893

NONOPERATING INCOME (LOSS)                        2,070          (327)       (1,726)
                                               --------      --------      --------

INCOME BEFORE INTEREST CHARGES                   51,808        54,348        50,167

INTEREST CHARGES                                 31,045        28,918        28,491
                                               --------      --------      --------

NET INCOME                                     $ 20,763      $ 25,430      $ 21,676
                                               ========      ========      ========


Statements of Retained Earnings
--------------------------------------------------------------------------------------------------------------------------------

                            Year Ended December 31,
                                                  2000          1999          1998
                                                  ----          ----          ----
                                                           (in thousands)

RETAINED EARNINGS JANUARY 1                     $67,110       $71,452       $78,076

NET INCOME                                       20,763        25,430        21,676

CASH DIVIDENDS DECLARED                          30,360        29,772        28,300
                                                -------       -------       -------

RETAINED EARNINGS DECEMBER 31                   $57,513       $67,110       $71,452
                                                =======       =======       =======

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

<PAGE>
<TABLE>
<CAPTION>


KENTUCKY POWER COMPANY
Balance
Sheets
----------------------------------------------------------------------------------------------------------------------------------

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

ELECTRIC UTILITY PLANT:
<S>                                                      <C>             <C>
  Production                                             $  271,107      $  268,618
  Transmission                                              360,563         355,442
  Distribution                                              387,499         372,752
  General                                                    67,476          67,608
  Construction Work in Progress                              16,419          14,628
                                                         ----------      ----------
         Total Electric Utility Plant                     1,103,064       1,079,048
  Accumulated Depreciation and Amortization                 360,648         340,008
                                                         ----------      ----------
         NET ELECTRIC UTILITY PLANT                         742,416         739,040
                                                         ----------      ----------


OTHER PROPERTY AND INVESTMENTS                                6,559          12,406
                                                         ----------      ----------

LONG-TERM ENERGY TRADING CONTRACTS                           76,657           8,010
                                                         ----------      ----------

CURRENT ASSETS:
  Cash and Cash Equivalents                                   2,270             674
  Accounts Receivable:
    Customers                                                34,555          18,952
    Affiliated Companies                                     22,119          15,223
    Miscellaneous                                             6,419           8,343
    Allowance for Uncollectible Accounts                       (282)           (637)
  Fuel - at average cost                                      4,760          10,441
  Materials and Supplies - at average cost                   15,408          18,113
  Accrued Utility Revenues                                    6,500          13,737
  Energy Trading Contracts                                  483,537          33,919
  Prepayments                                                   766           1,450
                                                         ----------      ----------
          TOTAL CURRENT ASSETS                              576,052         120,215
                                                         ----------      ----------


REGULATORY ASSETS                                            98,515          96,296
                                                         ----------      ----------

DEFERRED CHARGES                                             11,817          10,671
                                                         ----------      ----------

          TOTAL                                          $1,512,016      $  986,638
                                                         ==========      ==========

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


KENTUCKY POWER COMPANY
--------------------------------------------------------------------------------------------------------------------

                                                                 December 31,
                                                            -----------------------
                                                              2000         1999
                                                              ----         ----
                                                               (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - Par Value $50:
    Authorized - 2,000,000 Shares
<S>                                                         <C>           <C>
    Outstanding - 1,009,000 Shares                          $   50,450    $ 50,450
  Paid-in Capital                                              158,750     158,750
  Retained Earnings                                             57,513      67,110
                                                            ----------    --------
            Total Common Shareholder's Equity                  266,713     276,310
  Long-term Debt                                               270,880     260,782
                                                            ----------    --------
            TOTAL CAPITALIZATION                               537,593     537,092
                                                            ----------    --------


OTHER NONCURRENT LIABILITIES                                    18,348      23,797
                                                            ----------    --------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                            60,000     105,000
  Short-term Debt                                                 -         39,665
  Advances from Affiliates                                      47,636        -
  Accounts Payable - General                                    32,043       9,923
  Accounts Payable - Affiliated Companies                       37,506      19,743
  Customer Deposits                                              4,389       4,143
  Taxes Accrued                                                 11,885       9,860
  Interest Accrued                                               5,610       4,843
  Energy Trading Contracts                                     496,884      33,094
  Other                                                         14,517      12,020
                                                            ----------    --------
           TOTAL CURRENT LIABILITIES                           710,470     238,291
                                                            ----------    --------

DEFERRED INCOME TAXES                                          165,935     165,007
                                                            ----------    --------

DEFERRED INVESTMENT TAX CREDITS                                 11,656      12,908
                                                            ----------    --------

LONG-TERM ENERGY TRADING CONTRACTS                              61,632       6,194
                                                            ----------    --------

DEFERRED CREDITS                                                 6,382       3,349
                                                            ----------    --------

COMMITMENTS AND CONTINGENCIES (Note 8)

                    TOTAL                                   $1,512,016    $986,638
                                                            ==========    ========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


KENTUCKY POWER COMPANY
Statements of Cash Flows
-----------------------------------------------------------------------------------------------------------------------------------

                            Year Ended December 31,
                                                   2000         1999         1998
                                                   ----         ----         ----
                                                           (in thousands)
OPERATING ACTIVITIES:
<S>                                             <C>          <C>          <C>
  Net Income                                    $  20,763    $ 25,430     $ 21,676
  Adjustments for Noncash Items:
   Depreciation and Amortization                   31,034      29,228       28,092
   Deferred Income Taxes                            3,765       2,596        3,607
   Deferred Investment Tax Credits                 (1,252)     (1,292)      (1,415)
   Deferred Fuel Costs (net)                        2,948         828         (449)
  Changes in Certain Current Assets
    and Liabilities:
    Accounts Receivable (net)                     (20,930)     (6,618)      (6,663)
    Fuel, Materials and Supplies                    8,386      (7,014)       3,199
    Accrued Utility Revenues                        7,237        (177)        (579)
    Accounts Payable                               39,883       4,935          157
    Taxes Accrued                                   2,025       2,604        1,126
  Disputed Tax and Interest Related to COLI         5,943        (567)      (5,376)
  Other (net)                                      (4,559)     (3,019)      (2,215)
                                                ---------    --------     --------
     Net Cash Flows From Operating Activities      95,243      46,934       41,160
                                                ---------    --------     --------

INVESTING ACTIVITIES:
  Construction Expenditures                       (36,209)    (44,339)     (43,769)
  Proceeds from Sales of Property                     266         168         -
                                                ---------    --------     --------
        Net Cash Flows Used For
          Investing Activities                    (35,943)    (44,171)     (43,769)
                                                ---------    --------     --------

FINANCING ACTIVITIES:
  Capital Contributions from Parent Company          -         10,000       20,000
  Issuance of Long-term Debt                       69,685      79,740       29,816
  Retirement of Long-term Debt                   (105,000)    (83,307)      (2,203)
  Change in Short-term Debt (net)                 (39,665)     19,315      (16,150)
  Change in Advances from Affiliates (net)         47,636        -            -
  Dividends Paid                                  (30,360)    (29,772)     (28,300)
                                                ---------    --------     --------
        Net Cash Flows From (Used For)
         Financing Activities                     (57,704)     (4,024)       3,163
                                                ---------    --------     --------

Net Increase (Decrease) in Cash and
  Cash Equivalents                                  1,596      (1,261)         554
Cash and Cash Equivalents January 1                   674       1,935        1,381
                                                ---------    --------     --------
Cash and Cash Equivalents December 31           $   2,270    $    674     $  1,935
                                                =========    ========     ========

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was $28,619,000, $29,845,000
  and  $27,857,000  and  for  income  taxes  was  $7,923,000,   $12,050,000  and
  $8,607,000 in 2000, 1999 and 1998,  respectively.  Noncash  acquisitions under
  capital leases were  $2,817,000,  $2,219,000 and $4,890,000 in 2000,  1999 and
  1998, respectively.

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


KENTUCKY POWER COMPANY
Statements of Capitalization
-----------------------------------------------------------------

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

<S>                                                    <C>                <C>
COMMON SHAREHOLDER'S EQUITY                            $266,713           $276,310
                                                       --------           --------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                    119,341            119,270
Senior Unsecured Notes                                  147,490            157,502
Notes Payable                                            25,000             50,000
Junior Debentures                                        39,049             39,010
Less Portion Due Within One Year                        (60,000)          (105,000)
                                                       --------           --------

  Long-term Debt Excluding Portion Due Within One Year  270,880            260,782
                                                       --------           --------

  TOTAL CAPITALIZATION                                 $537,593           $537,092
                                                       ========           ========


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

</TABLE>
<PAGE>



KENTUCKY POWER COMPANY
Schedule of Long-term Debt
-------------------------------------------------


<PAGE>



First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due
8.95   2001 - May 10     $ 20,000   $ 20,000
8.90   2001 - May 21       40,000     40,000
6.65   2003 - May 1        15,000     15,000
6.70   2003 - June 1       15,000     15,000
6.70   2003 - June 1       15,000     15,000
7.90   2023 - June 1       14,500     14,500
Unamortized Discount         (159)      (230)
                         --------   --------
                         $119,341   $119,270

         Certain  indentures  relating  to  the  first  mortgage  bonds  contain
improvement,  maintenance  and replacement  provisions  requiring the deposit of
cash or bonds with the trustee,  or in lieu thereof,  certification  of unfunded
property additions.

Senior unsecured notes outstanding were as follows:

                             December 31,
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due
------ ------------------
 (a)   2000 - November 2  $  -      $ 80,000
 (b)   2002 - November 19  70,000       -
6.91   2007 - October 1    48,000     48,000
6.45   2008 - November 10  30,000     30,000
Unamortized Discount         (510)      (498)
                         --------   --------
                          147,490    157,502
Less Portion Due Within
 One Year                    -        80,000
                         --------   --------
  Total                  $147,490   $ 77,502
                         ========   ========

(a)      A floating interest rate is determined monthly.
         The rate on December 31, 1999 was 7.23%.
(b)      A floating interest rate is determined monthly.
         The rate on December 31, 2000 was 7.4075%.

Notes Payable to Banks outstandings were as follows:

6.57   2000 - April 1       $  -    $25,000
7.45     2002 - September 20   25,000  25,000
                              ------- -------
    Total                   $25,000 $50,000
                            ======= =======



Junior debentures outstanding were as follows:

                            December 31,
                         2000         1999
                         ----         ----
                          (in thousands)
% Rate Due
------ -----------------
8.72   2025 - June 30   $40,000      $40,000
Unamortized Discount       (951)        (990)
                        -------      -------
  Total                 $39,049      $39,010
                        =======      =======

         Interest may be deferred  and payment of principal  and interest on the
junior  debentures is subordinated  and subject in right to the prior payment in
full of all senior indebtedness of the Company.

         At December 31, 2000,  future  annual  long-term  debt  payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2001                        $ 60,000
2002                          95,000
2003                          45,000
2004                            -
2005                            -
Later Years                  132,500
                            --------
  Total Principal Amount     332,500
Unamortized Discount          (1,620)
                            --------
    Total                   $330,880
                            ========



<PAGE>


KENTUCKY POWER COMPANY
Index to Notes to Financial Statements
------------------------------------------------------------------------------



<PAGE>


The notes listed below are combined with the notes to financial  statements  for
AEP and its other subsidiary  registrants.  The combined footnotes begin on page
L-1.

                                                          Combined
                                                          Footnote
                                                          Reference

Significant Accounting Policies                           Note 1

Merger                                                    Note 3

Rate Matters                                              Note 5

Effects of Regulation                                     Note 6

Commitments and Contingencies                             Note 8

Staff Reductions                                          Note 11

Benefit Plans                                             Note 12

Business Segments                                         Note 14

Financial Instruments, Credit and Risk Management         Note 15

Income Taxes                                              Note 16

Leases                                                    Note 18

Lines of Credit and Factoring of Receivables              Note 19

Unaudited Quarterly Financial Information                 Note 20

Related Party Transactions                                Note 23



<PAGE>


INDEPENDENT AUDITORS' REPORT
-----------------------------------------------


To the Shareholder and Board of
Directors of Kentucky Power Company:

       We have  audited  the  accompanying  balance  sheets  and  statements  of
capitalization  of Kentucky  Power Company as of December 31, 2000 and 1999, and
the related statements of income,  retained earnings, and cash flows for each of
the  three  years  in the  period  ended  December  31,  2000.  These  financial
statements   are  the   responsibility   of  the   Company's   management.   Our
responsibility  is to express an opinion on these financial  statements based on
our audits.

       We conducted our audits in accordance with auditing  standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

       In our opinion, such financial statements present fairly, in all material
respects,  the financial  position of Kentucky  Power Company as of December 31,
2000 and 1999,  and the results of its operations and its cash flows for each of
the three  years in the  period  ended  December  31,  2000 in  conformity  with
accounting principles generally accepted in the United States of America.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001


<PAGE>













                       OHIO POWER COMPANY AND SUBSIDIARIES



<PAGE>
<TABLE>
<CAPTION>


                                      H-14
OHIO POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial
Data
-------------------------------------------------------------------------------------------------------

                                                 Year Ended December 31,
                               ----------------------------------------------------------
                                  2000        1999        1998        1997        1996
                                  ----        ----        ----        ----        ----
                                                      (in thousands)
INCOME STATEMENTS DATA:

<S>                            <C>         <C>         <C>         <C>         <C>
  Operating Revenues           $2,227,902  $2,039,263  $2,105,547  $1,892,110  $1,911,708
  Operating Expenses            2,001,075   1,750,434   1,816,175   1,615,717   1,614,547
                               ----------  ----------  ----------  ----------  ----------
  Operating Income                226,827     288,829     289,372     276,393     297,161
  Nonoperating Income (Loss)       (5,004)      7,000         588      14,822       6,374
                               ----------  ----------  ----------  ----------  ----------
  Income Before Interest
    Charges                       221,823     295,829     289,960     291,215     303,535
  Interest Charges                119,210      83,672      80,035      82,526      85,880
                               ----------  ----------  ----------  ----------  ----------
  Income Before
    Extraordinary Item            102,613     212,157     209,925     208,689     217,655
  Extraordinary Loss              (18,876)        -          -           -           -
                               ----------  ----------  ----------  ----------  ----------
  Net Income                       83,737     212,157     209,925     208,689     217,655
  Preferred Stock
    Dividend Requirements           1,266       1,417       1,474       2,647       8,778
                               ----------  ----------  ----------  ----------  ----------
  Earnings Applicable to
    Common Stock               $   82,471  $  210,740  $  208,451  $  206,042  $  208,877
                               ==========  ==========  ==========  ==========  ==========

                                                       December 31,
                               ----------------------------------------------------------
                                  2000        1999        1998        1997        1996
                                  ----        ----        ----        ----        ----
                                                      (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant       $5,577,631  $5,400,917  $5,257,841  $5,155,797  $4,996,621
  Accumulated Depreciation
     and Amortization           2,764,130   2,621,711   2,461,376   2,349,995   2,216,534
                               ----------  ----------  ----------  ----------  ----------
  Net Electric Utility Plant   $2,813,501  $2,779,206  $2,796,465  $2,805,802  $2,780,087
                               ==========  ==========  ==========  ==========  ==========
  Total Assets                 $6,252,436  $4,677,209  $4,344,680  $4,163,202  $4,092,166
                               ==========  ==========  ==========  ==========  ==========

  Common Stock and
    Paid-in Capital            $  783,684  $  783,577  $  783,536  $  783,497  $  781,863
  Retained Earnings               398,086     587,424     587,500     590,151     584,015
                               ----------  ----------  ----------  ----------  ----------
  Total Common Shareholder's
    Equity                     $1,181,770  $1,371,001  $1,371,036  $1,373,648  $1,365,878
                               ==========  ==========  ==========  ==========  ==========

  Cumulative Preferred Stock:

    Not Subject to Mandatory
      Redemption               $   16,648  $   16,937  $   17,370  $   17,542  $   38,532
    Subject to Mandatory
      Redemption (a)                8,850       8,850      11,850      11,850     109,900
                               ----------  ----------  ----------  ----------  ----------
      Total Cumulative
        Preferred Stock        $   25,498  $   25,787  $   29,220  $   29,392  $  148,432
                               ==========  ==========  ==========  ==========  ==========

  Long-term Debt (a)           $1,195,493  $1,151,511  $1,084,928  $1,095,226  $1,069,729
                               ==========  ==========  ==========  ==========  ==========
  Obligations Under Capital
    Leases (a)                 $  116,581  $  136,543  $  142,635  $  157,487  $  131,285
                               ==========  ==========  ==========  ==========  ==========
  Total Capitalization and
    Liabilities                $6,252,436  $4,677,209  $4,344,680  $4,163,202  $4,092,166
                               ==========  ==========  ==========  ==========  ==========


(a) Including portion due within one year.

</TABLE>
<PAGE>


OHIO POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis
of Results of Operations



<PAGE>



       OPCo is a public  utility  engaged  in the  generation,  purchase,  sale,
transmission  and  distribution of electric power to 696,000 retail customers in
northwestern, east central, eastern and southern sections of Ohio. OPCo supplies
electric  power to the AEP Power Pool and shares the  revenues  and costs of the
AEP Power  Pool's  wholesale  sales to  neighboring  utility  systems  and power
marketers. OPCo also sells wholesale power to municipalities and cooperatives.

       The cost of the AEP System's  generating  capacity is allocated among the
AEP Power Pool  members  based on their  relative  peak  demands and  generating
reserves  through  the  payment of  capacity  charges or the receipt of capacity
credits.  AEP Power Pool members are also  compensated  for their  out-of-pocket
costs of energy  delivered to the AEP Power Pool and charged for energy received
from the AEP Power Pool.

       The AEP Power Pool  calculates  each  company's  prior  twelve month peak
demand relative to the total peak demand of all member  companies as a basis for
sharing  revenues and costs.  The result of this  calculation is the member load
ratio (MLR) which  determines each company's  percentage share of AEP Power Pool
revenues or costs. OPCo 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.  Revenues from forward  electricity
trades are recorded net of purchases as operating  revenues for  transactions in
AEP's



traditional  marketing area (up to two transmission systems from the AEP service
territory) and as nonoperating  income for transactions  beyond two transmission
systems from AEP. The AEP Power Pool also enters into power trading transactions
for options,  futures and swaps.  OPCo's share of these transactions is recorded
in nonoperating income.

Results of Operations

       In February  2001 the U.S.  District  Court for the Southern  District of
Ohio ruled  against AEP and certain of its  subsidiaries,  including  OPCo, in a
suit over  deductibility of interest  claimed in AEP's  consolidated tax returns
related to a corporate  owned life insurance  (COLI)  program.  In 1998 and 1999
OPCo paid the disputed  taxes and  interest  attributable  to the COLI  interest
deductions  for taxable  years  1991-98.  The  payments  were  included in Other
Property and Investments  pending the resolution of this matter.  As a result of
the Court's decision, net income was reduced by $118 million in 2000.

       Income before  extraordinary  item  decreased $110 million or 52% in 2000
due  predominantly  to the  disallowance  of COLI  related  tax  deductions.  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 PUCO's  approval  of a plan to  transition  OPCo's
generation  business  from cost based rate  regulation  to  customer  choice and
market pricing.




       Net income  increased $2 million or 1% in 1999 primarily due to a decline
in operation and maintenance costs reflecting cost containment efforts.

Operating Revenues and Energy Sales

       Operating  revenues  increased  9% in 2000  following a decrease of 3% in
1999. The changes in the components of revenues were as follows:

                        Increase (Decrease)
                        From Previous Year
(Dollars in Millions)
                      2000          1999
                -----------------------------
                Amount    %   Amount    %
Retail:
   Residential  $  (4.2)      $  7.5
   Commercial       1.7          0.4
   Industrial    (126.0)        (5.0)
   Other            0.2           -
                -------       ------
                 (128.3) (9)     2.9    -

Wholesale         322.1  56    (71.9) (11)

Transmission
 and Other         (5.2) (6)     2.7    3
                -------       ------

     Total      $ 188.6   9   $(66.3)  (3)
                =======       ======

       The  increase in  operating  revenues  in 2000  resulted  from  increased
wholesale sales to the AEP Power Pool and 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.  As a  result  of one of  OPCo's  major
industrial customers deciding not to continue its power purchase agreement, OPCo
was able to deliver  additional  power to the 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 of an  affiliate's  nuclear  units in June  2000 and
improved generating unit outage management.

       Operating  revenues  declined  3% in 1999  primarily  due to a decline in
margins on wholesale  sales and net power  trading  transactions  and  decreased
sales to the AEP Power Pool.

Operating Expenses

       Operating  expenses  increased  by 14% in 2000 mostly due to increases in
fuel expense,  purchased  power  expense,  other  operation  expense and federal
income taxes.

       Operating expenses decreased 4% in 1999 from cost containment efforts and
lower fuel costs due mainly to a decrease in generation  reflecting lower demand
for wholesale  energy.  Changes in the components of operating  expenses were as
follows:

                      Increase (Decrease)
                      From Previous Year

                     (dollars in millions)
                     ---------------------

                   2000          1999
                  Amount    %    Amount    %
                 ----------------------------
                  ------   ---   ------   ----

Fuel             $ 84.3    12   $(50.8)   (7)
Purchased Power    20.9    13     12.4     8
Other Operation    80.2    25    (26.1)   (7)
Maintenance         3.4     3    (18.3)  (13)
Depreciation
 and Amortization   6.9     5      4.6     3
Taxes Other Than
  Federal Income
  Taxes            (0.3)    -     (3.5)   (2)
Federal Income
  Taxes            55.2    41     16.0    13
                 ------         ------
  Total Operating
   Expenses      $250.6    14   $(65.7)   (4)
                 ======         ======

       Fuel expense  increased in 2000 due to  increases in  generation  and the
average cost of fuel consumed  reflecting shutdown costs included in the cost of
coal delivered from affiliated mining operations. Fuel expense decreased in 1999
due to a 6% decrease in generation reflecting the decline in wholesale sales.

       The increase in purchased power expense was due to a significant increase
in AEP Power Pool transactions.
       Other operation  expense  increased in 2000 mainly due to increased power
generation costs.  Increased emission allowance consumption and allowance prices
and  increased  costs of AEP's growing  power  marketing and trading  operation,
including  incentive  compensation,  accounted  for the  increase in  generation
costs.  The increase in emission  allowance  usage and prices  resulted from the
stricter air quality  standards of Phase II of the 1990 Clean Air Act Amendments
which  became  effective  on January 1, 2000.  The  decrease in other  operation
expense in 1999 was due to lower coal-fired power plant expenses reflecting cost
containment  efforts,  and an increase in gains on emission allowance sales. The
cost   containment   efforts  included  staff  reductions  in  transmission  and
distribution  operations,  at the power  plants and within the  engineering  and
maintenance  group of AEP Service  Corporation  which bills OPCo for  operations
support services. These cost containment efforts were the primary reason for the
decrease in maintenance expense in 1999.

       The increase in federal  income tax expense in 2000 was  primarily due to
the  unfavorable  ruling  relating to AEP's COLI program.  Federal  income taxes
attributable to operations  increased in 1999 due to changes in certain book/tax
differences  accounted for on a flow-through basis for rate-making  purposes and
an increase in pre-tax operating income.


Nonoperating Income

       The decrease in nonoperating income in 2000 is due to the disallowance of
COLI-related  tax  deductions  for  coal-mining  operations  that are no  longer
operating.

Extraordinary Loss

       An extraordinary loss was recorded in the third quarter of 2000 when OPCo
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 OPCo's generation business to customer choice and market pricing.



<PAGE>
<TABLE>
<CAPTION>


OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements  of Income
---------------------------------------------

                                                         Year Ended December 31,
                                               ------------------------------------------
                                                    2000           1999           1998
                                                    ----           ----           ----
                                                              (in thousands)

<S>                                            <C>            <C>            <C>
OPERATING REVENUES                             $2,227,902     $2,039,263     $2,105,547
                                               ----------     ----------     ----------

OPERATING EXPENSES:
   Fuel                                           771,969        687,672        738,522
   Purchased Power                                184,004        163,143        150,733
   Other Operation                                407,375        327,132        353,194
   Maintenance                                    124,735        121,299        139,611
   Depreciation and Amortization                  155,944        149,055        144,493
   Taxes Other Than Federal Income Taxes          165,552        165,891        169,353
   Federal Income Taxes                           191,496        136,242        120,269
                                               ----------     ----------     ----------
                Total Operating Expenses        2,001,075      1,750,434      1,816,175
                                               ----------     ----------     ----------

OPERATING INCOME                                  226,827        288,829        289,372

NONOPERATING INCOME (LOSS)                         (5,004)         7,000            588
                                               ----------     ----------     ----------

INCOME BEFORE INTEREST CHARGES                    221,823        295,829        289,960

INTEREST CHARGES                                  119,210         83,672         80,035
                                               ----------     ----------     ----------

INCOME BEFORE EXTRAORDINARY ITEM                  102,613        212,157        209,925

EXTRAORDINARY LOSS - Discontinuance of
  Regulatory Accounting for Generation
  (inclusive of Tax Benefit of $21,281,000)       (18,876)          -              -
                                               ----------     ----------     -----------

NET INCOME                                         83,737        212,157        209,925

PREFERRED STOCK DIVIDEND REQUIREMENTS               1,266          1,417          1,474
                                               ----------     ----------     ----------

EARNINGS APPLICABLE TO COMMON STOCK            $   82,471     $  210,740     $  208,451
                                               ==========     ==========     ==========

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

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


OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Balance
Sheets
--------------------------------------------------------------------------------------------------

                                                                     December 31,
                                                                 2000            1999
                                                                    (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                           <C>             <C>
   Production                                                 $2,764,155      $2,713,421
   Transmission                                                  870,033         857,420
   Distribution                                                1,040,940         999,679
   General (including mining assets)                             707,417         713,882
   Construction Work in Progress                                 195,086         116,515
                                                              ----------     -----------
                 Total Electric Utility Plant                  5,577,631       5,400,917
   Accumulated Depreciation and Amortization                   2,764,130       2,621,711
                                                              ----------     -----------
                 NET ELECTRIC UTILITY PLANT                    2,813,501       2,779,206
                                                              ----------     -----------


OTHER PROPERTY AND INVESTMENTS                                   109,124         221,756
                                                              ----------     -----------

LONG-TERM ENERGY TRADING CONTRACTS                               256,455          31,912
                                                              ----------     -----------


CURRENT ASSETS:
   Cash and Cash Equivalents                                      31,393         157,138
   Advances to Affiliates                                         92,486            -
   Accounts Receivable:
      Customers                                                  139,732         246,310
      Affiliated Companies                                       126,203          89,215
      Miscellaneous                                               39,046          22,055
      Allowance for Uncollectible Accounts                        (1,054)         (2,223)
   Fuel - at average cost                                         82,291         129,022
   Materials and Supplies - at average cost                       96,053          95,967
   Accrued Utility Revenues                                          264          45,575
   Energy Trading Contracts                                    1,617,660         134,567
   Prepayments and Other                                          32,882          38,472
                                                              ----------     -----------
                 TOTAL CURRENT ASSETS                          2,256,956         956,098
                                                              ----------     -----------

REGULATORY ASSETS                                                714,710         594,385
                                                              ----------     -----------

DEFERRED CHARGES                                                 101,690          93,852
                                                              ----------     -----------


                     TOTAL                                    $6,252,436     $ 4,677,209
                                                              ==========     ===========

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

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


OHIO POWER COMPANY AND SUBSIDIARIES
--------------------------------------------------------------------------------------------------------------------

                                                                     December 31,
                                                                 2000            1999
                                                                    (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
   Common Stock - No Par Value:
      Authorized - 40,000,000 Shares
<S>                                                           <C>             <C>
      Outstanding - 27,952,473 Shares                         $  321,201      $  321,201
   Paid-in Capital                                               462,483         462,376
   Retained Earnings                                             398,086         587,424
                                                              ----------      ----------
                Total Common Shareholder's Equity              1,181,770       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                                              1,077,987       1,139,834
                                                              ----------      ----------
                TOTAL CAPITALIZATION                           2,285,255       2,536,622
                                                              ----------      ----------

OTHER NONCURRENT LIABILITIES                                     542,017         414,837
                                                              ----------      ----------

CURRENT LIABILITIES:
   Long-term Debt Due Within One Year                            117,506          11,677
   Short-term Debt                                                  -            194,918
   Accounts Payable - General                                    179,691         180,383
   Accounts Payable - Affiliated Companies                       121,360          64,599
   Customer Deposits                                              39,736           8,196
   Taxes Accrued                                                 223,101         179,112
   Interest Accrued                                               20,458          16,863
   Obligations Under Capital Leases                               32,716          34,284
   Energy Trading Contracts                                    1,662,315         131,844
   Other                                                         151,934          88,249
                                                              ----------      ----------
                TOTAL CURRENT LIABILITIES                      2,548,817         910,125
                                                              ----------      ----------

DEFERRED INCOME TAXES                                            621,941         676,460
                                                              ----------      ----------

DEFERRED INVESTMENT TAX CREDITS                                   25,214          35,838
                                                              ----------      ----------

LONG-TERM ENERGY TRADING CONTRACTS                               206,187          24,677
                                                              ----------      ----------

DEFERRED CREDITS                                                  23,005          78,650
                                                              ----------      ----------

COMMITMENTS AND CONTINGENCIES (Note 8)


                    TOTAL                                     $6,252,436      $4,677,209
                                                              ==========      ==========

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

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


OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash
Flows
--------------------------------------------------------------------------------------------------------------------------

                                                           Year Ended December 31,
                                                     2000           1999           1998
                                                     ----           ----           ----
                                                               (in thousands)

OPERATING ACTIVITIES:
<S>                                               <C>            <C>            <C>
   Net Income                                     $  83,737      $ 212,157      $ 209,925
   Adjustments for Noncash Items:
     Depreciation, Depletion and Amortization       200,350        193,780        172,085
     Deferred Income Taxes                          (65,956)         3,666          3,042
     Deferred Investment Tax Credits                 (3,399)        (3,458)        (3,525)
     Deferred Fuel Costs (net)                      (56,869)       (76,978)       (44,694)
     Extraordinary Loss - Discontinuance of SFAS 71  18,876           -              -
   Changes in Certain Current Assets and Liabilities:
     Accounts Receivable (net)                       51,430        (49,309)       (12,376)
     Fuel, Materials and Supplies                    46,645        (60,500)        18,612
     Accrued Utility Revenues                        45,311         (2,074)        (5,915)
     Accounts Payable                                56,069          9,195         51,040
   Disputed Tax and Interest Related to COLI        110,494         (6,272)      (104,222)
   Change in Operating Reserves                     145,573         66,573         77,811
   Other (net)                                        6,232         48,718         42,981
                                                  ---------      ---------      ---------
       Net Cash Flows From Operating Activities     638,493        335,498        404,764
                                                  ---------      ---------      ---------

INVESTING ACTIVITIES:
   Construction Expenditures                       (254,016)      (193,870)      (185,036)
   Proceeds from Sales of Property and Other          6,354          5,900          5,910
                                                  ---------      ---------      ---------
       Net Cash Flows Used For
         Investing Activities                      (247,662)      (187,970)      (179,126)
                                                  ---------      ---------      ---------

FINANCING ACTIVITIES:
   Issuance of Long-term Debt                        74,748        222,308        186,126
   Changes in Advances to Affiliates (net)          (92,486)          -              -
   Retirement of Cumulative Preferred Stock            (182)        (3,392)          (133)
   Retirement of Long-term Debt                     (30,663)      (158,638)      (197,911)
   Change in Short-term Debt (net)                 (194,918)        71,913         44,305
   Dividends Paid on Common Stock                  (271,813)      (210,813)      (211,101)
   Dividends Paid on Cumulative Preferred Stock      (1,262)        (1,420)        (1,475)
                                                  ---------      ---------      ---------
       Net Cash Flows Used For
         Financing Activities                      (516,576)       (80,042)      (180,189)
                                                  ---------      ---------      ---------

Net Increase (Decrease) in Cash and
  Cash Equivalents                                 (125,745)        67,486         45,449
Cash and Cash Equivalents January 1                 157,138         89,652         44,203
                                                  ---------      ---------      ---------
Cash and Cash Equivalents December 31             $  31,393      $ 157,138      $  89,652
                                                  =========      =========      =========

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was $87,120,000, $78,739,000
  and  $79,667,000  and for  income  taxes  was  $142,710,000,  $94,606,000  and
  $118,548,000 in 2000, 1999 and 1998, respectively.  Noncash acquisitions under
  capital leases were $17,005,000, $28,561,000 and $29,938,000 in 2000, 1999 and
  1998, respectively.


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

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


OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statement of Retained Earnings
----------------------------------------------------------------------------------------------------------------------------------

                                                            Year Ended December 31,
                                                     2000           1999           1998
                                                     ----           ----           ----
                                                               (in thousands)

<S>                                               <C>            <C>            <C>
Retained Earnings January 1                       $587,424       $587,500       $590,151
Net Income                                          83,737        212,157        209,925
                                                  --------       --------       --------
                                                   671,161        799,657        800,076
                                                  --------       --------       --------
Deductions:
  Cash Dividends Declared:
    Common Stock                                   271,813        210,813        211,101
    Cumulative Preferred Stock:
       4.08%    Series                                  59             61             63
       4.20%    Series                                  96             97             97
       4.40%    Series                                 139            142            143
       4-1/2%   Series                                 442            460            467
       5.90%    Series                                 428            472            487
       6.02%    Series                                  66            156            186
       6.35%    Series                                  32             32             32
                                                  --------       --------       --------
                Total Dividends                    273,075        212,233        212,576
                                                  --------       --------       --------

Retained Earnings December 31                     $398,086       $587,424       $587,500
                                                  ========       ========       ========

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


OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
------------------------------------------------------------------------------------------------------------------------------------

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

<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $1,181,770        $1,371,001
                                                                                 ----------        ----------

PREFERRED STOCK - authorized shares 3,762,403 $100 par value
                  authorized shares 4,000,000 $25 par value

            Call Price                                                 Shares
           December 31,    Par   Number of Shares Redeemed          Outstanding
Series(a)      2000       Value     Year Ended December 31,       December 31, 2000
------     ------------   -----  ----------------------------     -----------------
                                  2000      1999      1998
                                  ----      ----      ----

Not Subject to Mandatory Redemption:

4.08%          $103        $100   -          373       425              14,595        1,460             1,460
4.20%           103.20      100    276      -         -                 22,824        2,282             2,310
4.40%           104         100    432       330       200              31,512        3,151             3,194
4-1/2%          110.00      100  2,181     3,631     1,096              97,546        9,755             9,973
                                                                                     ------            ------

                                                                                     16,648            16,937
                                                                                     ------            ------
Subject to Mandatory Redemption:

5.90% (b)         -        $100   -       10,000      -                 72,500        7,250             7,250
6.02% (c)         -         100   -       20,000      -                 11,000        1,100             1,100
6.35% (c)         -         100   -         -         -                  5,000          500               500
                                                                                     ------            ------

                                                                                      8,850             8,850
                                                                                     ------            ------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                316,294           323,772
Installment Purchase Contracts                                                      233,130           233,025
Senior Unsecured Notes                                                              471,583           408,671
Notes Payable                                                                        30,000            30,000
Junior Debentures                                                                   131,980           131,860
Other Long-term Debt                                                                 12,506            24,183
Less Portion Due Within One Year                                                   (117,506)          (11,677)
                                                                                 ----------        ----------

  Long-term Debt Excluding Portion Due Within One Year                            1,077,987         1,139,834
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $2,285,255        $2,536,622
                                                                                 ==========        ==========

(a)  The series  subject to mandatory  redemption  are not callable  until after
     2002.  The sinking  fund  provisions  of each series  subject to  mandatory
     redemption have been met by purchase of shares in advance of the due date.
(b)  Commencing in 2004 and continuing through the year 2008, a sinking fund for
     the 5.90% cumulative  preferred stock will require the redemption of 22,500
     shares each year and the redemption of the remaining shares  outstanding on
     January 1, 2009, in each case at $100 per share. Shares previously redeemed
     may be applied to meet sinking fund requirements.
(c)  Commencing in 2003 and continuing  through 2007 cumulative  preferred stock
     sinking funds will require the redemption of 20,000 shares each year of the
     6.02% series and 15,000 shares each year of the 6.35% series,  in each case
     at $100 per share.  All  remaining  outstanding  shares must be redeemed in
     2008.  Shares  previously  redeemed may be applied to meet the sinking fund
     requirements.


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


OHIO POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
------------------------------------------------------



<PAGE>


First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2000       1999
                           ----       ----
                          (in thousands)
% Rate Due
6.75   2003 - April 1    $ 38,850   $ 40,000
6.55   2003 - October 1    32,135     32,135
6.00   2003 - November 1   25,000     25,000
6.15   2003 - December 1   50,000     50,000
8.80   2022 - February 10  50,000     50,000
7.75   2023 - April 1      40,000     40,000
7.375  2023 - October 1    40,000     40,000
7.10   2023 - November 1   20,000     23,000
7.30   2024 - April 1      21,500     25,000
Unamortized Discount       (1,191)    (1,363)
                         --------   --------
  Total                  $316,294   $323,772
                         ========   ========

         Certain  indentures  relating  to  the  first  mortgage  bonds  contain
improvement,  maintenance  and replacement  provisions  requiring the deposit of
cash or bonds with the trustee,  or in lieu thereof,  certification  of unfunded
property additions.

         Installment  purchase  contracts  have been entered into in  connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:

                             December 31,
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due

Mason County, West
 Virginia:
5.45%  2016 - December 1  $ 50,000  $ 50,000
Marshall County, West
 Virginia:
5.45%  2014 - July 1        50,000    50,000
5.90%  2022 - April 1       35,000    35,000
6.85%  2022 - June 1        50,000    50,000
Ohio Air Quality
 Development
5.15%  2026 - May 1         50,000    50,000
Unamortized Discount        (1,870)   (1,975)
                          --------  --------
  Total                   $233,130  $233,025
                          ========  ========


         Under the terms of the installment purchase contracts, OPCo is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated  maturities  and upon  mandatory  redemptions)  of related  pollution
control revenue bonds issued to finance the  construction  of pollution  control
facilities at certain plants.

Senior unsecured notes outstanding were as follows:
                            December 31,
                        --------------------
                          2000       1999
                          ----       ----
                           (in thousands)
% Rate Due
------ ------------------
 (a)   2001 - May 16    $ 75,000   $   -
6.75   2004 - July 1     100,000    100,000
7.00   2004 - July 1      75,000     75,000
6.73   2004 - November 1  48,000     48,000
6.24   2008 - December 4  37,225     50,000
7-3/8  2038 - June 30    140,000    140,000
Unamortized Discount      (3,642)    (4,329)
                        --------   --------
  Total                 $471,583   $408,671
                        ========   ========

(a)      A floating interest rate is determined monthly.
         The rate on December 31, 2000 was 7.26%.

Notes payable outstanding were as follows:

                              December 31,
                             2000      1999
                             ----      ----
                             (in thousands)
% Rate Due
6.20   2001 - January 31   $ 5,000   $ 5,000
6.20   2001 - January 31     7,000     7,000
6.20   2001 - January 31    18,000    18,000
                           -------   -------
  Total                    $30,000   $30,000
                           =======   =======

Junior debentures outstanding were as follows:
                            December 31,
                         2000         1999
                         ----         ----
                          (in thousands)
% Rate Due
------ -----------------
8.16   2025 - September 30 $ 85,000 $ 85,000
7.92   2027 - March 31       50,000   50,000
Unamortized Discount         (3,020)  (3,140)
                           -------- --------
  Total                    $131,980 $131,860
                           ======== ========

         Interest may be deferred  and payment of principal  and interest on the
junior  debentures is subordinated  and subject in right to the prior payment in
full of all senior indebtedness of the Company.


<PAGE>


         Finance  obligations  were  entered into by the  Company's  coal mining
subsidiaries  for mining  facilities  and  equipment  through sale and leaseback
transactions.  In accordance with SFAS 98, the  transactions  did not qualify as
sales and leasebacks  for  accounting  purposes and therefore are shown as other
long-term debt. The terms on the remaining  long-term debt obligation  including
renewals  end on  December  24, 2001 and  contain a bargain  purchase  option at
expiration of the agreement. At December 31, 2000, the interest rate was 6.98%.


         At December 31, 2000,  future  annual  long-term  debt  payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2001                       $  117,506
2002                             -
2003                          145,985
2004                          223,000
2005                             -
Later Years                   718,725
                           ----------
  Total Principal Amount    1,205,216
Unamortized Discount           (9,723)
                           ----------
    Total                  $1,195,493
                           ==========




<PAGE>





OHIO POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements


The notes listed below are combined with the notes to financial  statements  for
AEP and its other subsidiary  registrants.  The combined footnotes begin on page
L-1.

                                                     Combined
                                                     Footnote
                                                     Reference

Significant Accounting Policies                      Note 1

Extraordinary Items                                  Note 2

Rate Matters                                         Note 5

Effects of Regulation                                Note 6

Industry Restructuring                               Note 7

Commitments and Contingencies                        Note 8

Staff Reductions                                     Note 11

Benefit Plans                                        Note 12

Business Segments                                    Note 14

Financial Instruments, Credit and Risk Management    Note 15

Income Taxes                                         Note 16

Supplementary Information                            Note 17

Leases                                               Note 18

Lines of Credit and Factoring of Receivables         Note 19

Unaudited Quarterly Financial Information            Note 20

Related Party Transactions                           Note 23




<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of Ohio Power Company:

     We  have  audited  the   accompanying   consolidated   balance  sheets  and
consolidated  statements  of  capitalization  of  Ohio  Power  Company  and  its
subsidiaries  as of  December  31, 2000 and 1999,  and the related  consolidated
statements of income,  retained  earnings,  and cash flows for each of the three
years in the period ended December 31, 2000. These financial  statements are the
responsibility of the Company's management.  Our responsibility is to express an
opinion on these financial statements based on our audits.

     We conducted our audits in accordance  with  auditing  standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.

     In our opinion,  such consolidated  financial statements present fairly, in
all material  respects,  the  financial  position of Ohio Power  Company and its
subsidiaries  as of  December  31,  2000  and  1999,  and the  results  of their
operations  and their cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001



<PAGE>




                       PUBLIC SERVICE COMPANY OF OKLAHOMA
                                AND SUBSIDIARIES

<PAGE>
<TABLE>
<CAPTION>


                                      I-11
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Selected Consolidated Financial Data


                                                 Year Ended December 31,
                               -----------------------------------------------------------
                                  2000         1999        1998        1997        1996
                                  ----         ----        ----        ----        ----
                                                      (in thousands)
INCOME STATEMENTS DATA:

<S>                            <C>           <C>         <C>         <C>         <C>
  Operating Revenues           $  962,609    $749,390    $780,159    $712,690    $735,265
  Operating Expenses              865,940     650,677     665,085     630,666     635,527
                               ----------    --------    --------    --------    --------
  Operating Income                 96,669      98,713     115,074      82,024      99,738
  Nonoperating Income (Loss)        8,974         946         (91)      1,649     (35,511)
                               ----------    --------    --------    --------    --------
  Income Before Interest
    Charges                       105,643      99,659     114,983      83,673      64,227
  Interest Charges                 38,980      38,151      38,074      37,218      34,748
                               ----------    --------    --------    --------    --------
  Net Income                       66,663      61,508      76,909      46,455      29,479
  Preferred Stock Dividend
    Requirements                      212         212         213         364         816
  Gain On Reacquired
    Preferred Stock                  -           -           -          4,211        -
                               ----------    --------    --------    --------    --------
  Earnings Applicable to
    Common Stock               $   66,451    $ 61,296    $ 76,696    $ 50,302    $ 28,663
                               ==========    ========    ========    ========    ========

                                                       December 31,
                               -----------------------------------------------------------
                                  2000        1999        1998        1997        1996
                                  ----        ----        ----        ----        ----
                                                     (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant       $2,604,670  $2,459,705  $2,391,722  $2,339,908  $2,290,175
  Accumulated Depreciation
    and Amortization            1,150,253   1,114,255   1,082,081   1,031,322     987,283
                               ----------  ----------  ----------  ----------  ----------
  Net Electric Utility Plant   $1,454,417  $1,345,450  $1,309,641  $1,308,586  $1,302,892
                               ==========  ==========  ==========  ==========  ==========

  Total Assets                 $2,142,156  $1,524,726  $1,470,939  $1,464,562  $1,447,107
                               ==========  ==========  ==========  ==========  ==========

  Common Stock and Paid-in
    Capital                    $  337,230  $  337,230  $  337,230  $  337,230  $  337,230
  Retained Earnings               137,688     139,237     142,941     135,245     143,944
                               ----------  ----------  ----------  ----------  ----------
  Total Common Shareholder's
    Equity                     $  474,918  $  476,467  $  480,171  $  472,475  $  481,174
                               ==========  ==========  ==========  ==========  ==========

  Cumulative Preferred Stock:
    Not Subject to Mandatory
      Redemption               $    5,283  $    5,286  $    5,287  $    5,287  $   19,826
                               ==========  ==========  ==========  ==========  ==========

  Preferred Securities of
    Subsidiary Trust           $   75,000  $   75,000  $   75,000  $   75,000  $     -
                               ==========  ==========  ==========  ==========  ===========

  Long-term Debt (a)           $  470,822  $  384,516  $  384,064  $  438,703  $  438,369
                               ==========  ==========  ==========  ==========  ==========

  Total Capitalization
    and Liabilities            $2,142,156  $1,524,726  $1,470,939  $1,464,562  $1,447,107
                               ==========  ==========  ==========  ==========  ==========



(a) Including portion due within one year.
</TABLE>

<PAGE>


PUBLIC SERVICE COMPANY OF OKLAHOMA
Management's Narrative Analysis
of Results of Operations




<PAGE>



       PSO is a  public  utility  engaged  in the  generation,  purchase,  sale,
transmission and distribution of electric power to approximately  499,000 retail
customers in eastern and southwestern Oklahoma. PSO also sells electric power at
wholesale to other utilities,  municipalities  and rural electric  cooperatives.
PSO  participates  in power  marketing and trading  activities  conducted on its
behalf by the AEP System.

       PSO  shares in the  revenues  and costs of the AEP Power  Pool  wholesale
sales to and net forward trades with other utility systems and power  marketers.
Revenues from trading of electricity  are recorded net of purchases as operating
revenues.

Results of Operations Rise

         Net income  increased $5.2 million or 8.4% in 2000 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.

Operating Revenues

        Operating  revenues  rose 28% due to an increase  in fuel and  purchased
power revenues, reflecting price increases in fuel and purchased power expenses,
and an increase in power sales to  neighboring  utilities  and power  marketers.
Changes in the components of operating revenues were as follows:



                              Increase
                         From Previous Year
(dollars in millions)      Amount       %
----------------------     ------       -

Retail:
  Residential              $ 65.8      22
  Commercial                 52.2      23
  Industrial                 37.4      23
  Other                       1.9      20
                           ------
                            157.3
Wholesale                    54.8     140
Transmission and Other        1.1       6
                           ------     ---
     Total                 $213.2      28
                           ======     ===

         Revenues from retail customers  increased as a result of an increase in
fuel-related  revenues  that  reflect  rising  prices for  natural  gas used for
generation and higher purchased power prices.  The Oklahoma fuel clause recovery
mechanism  provides for the accrual of fuel-related  revenues until reviewed and
approved for billing to customers by the Oklahoma  Corporation  Commission.  The
accrual of additional  fuel and purchased  power revenues is offset by increases
in fuel and purchased power expenses. As a result, accrued fuel-related revenues
do not impact results of operations.

         The increase in wholesale  revenues is  attributable to increased sales
volumes to other utilities and prices  reflecting the increase in gas prices and
PSO's  participation in the AEP System's power marketing and trading operations.
The  volume  of  electricity  sales  to other  utilities,  both  affiliated  and
unaffiliated,  increased as demand for energy rose in response to warmer  summer
weather.  Since  PSO  became a  subsidiary  of AEP in June 2000 as a result of a
merger with CSW,  PSO shares in the AEP  System's  power  marketing  and trading
transactions  with other  entities.  Trading  involves  the purchase and sale of
substantial  amounts of  electricity  at  wholesale to  non-affiliated  parties.
Revenues from trading are recorded net of purchases.


<PAGE>


Operating Expenses Increase

        Operating expenses were $215.3 million more in 2000 than in 1999 largely
as a result of  increased  fuel and  purchased  power  expenses.  Changes in the
components of operating expenses were as follows:

                         Increase (Decrease)
                         From Previous Year
(dollars in millions)      Amount       %
----------------------     ------       -

Fuel Expense               $133.6      50
Purchased Power Expense      80.2     107
Other Operation              (0.2)    N.M.
Depreciation and
 Amortization                 1.7       2
Taxes Other Than Federal
 Income Taxes                (1.7)     (5)
Federal Income Taxes          1.7       6
                           ------
     Total                 $215.3      33
                           ======
N.M. = Not Meaningful

        The increases in fuel and  purchased  power 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.  As discussed  above,  changes in
fuel and  purchased  power  expenses are  generally  reflected in revenues on an
accrual basis and as such did not impact results of operations.

Nonoperating Income

         Nonoperating income increased $8 million primarily due to the gain from
the sale of PSO's minority interest in Scientech, Inc. in 2000.





<PAGE>
<TABLE>
<CAPTION>


PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of
Income
-----------------------------------------------------------------------------------------------

                                                           Year Ended December 31,
                                                   ---------------------------------------
                                                      2000           1999         1998
                                                      ----           ----         ----
                                                                (in thousands)

<S>                                                 <C>            <C>          <C>
OPERATING REVENUES                                  $962,609       $749,390     $780,159
                                                    --------       --------     --------

OPERATING EXPENSES:
  Fuel                                               402,933        269,316      309,969
  Purchased Power                                    155,087         74,893       57,222
  Other Operation                                    121,697        121,896      109,285
  Maintenance                                         45,858         45,809       36,981
  Depreciation and Amortization                       76,418         74,736       72,671
  Taxes Other Than Federal Income Taxes               33,235         34,970       36,733
  Federal Income Taxes                                30,712         29,057       42,224
                                                    --------       --------     --------
           Total Operating Expenses                  865,940        650,677      665,085
                                                    --------       --------     --------

OPERATING INCOME                                      96,669         98,713      115,074

NONOPERATING INCOME (LOSS)                             8,974            946          (91)
                                                    --------       --------     --------

INCOME BEFORE INTEREST CHARGES                       105,643         99,659      114,983

INTEREST CHARGES                                      38,980         38,151       38,074
                                                    --------       --------     --------

NET INCOME                                            66,663         61,508       76,909

PREFERRED STOCK DIVIDEND REQUIREMENTS                    212            212          213
                                                    --------       --------     --------

EARNINGS APPLICABLE TO COMMON STOCK                 $ 66,451       $ 61,296     $ 76,696
                                                    ========       ========     ========

Consolidated Statements of Retained Earnings
-------------------------------------------------------------------------------------------------------------------------------

                                                           Year Ended December 31,
                                                   ---------------------------------------
                                                      2000           1999         1998
                                                      ----           ----         ----
                                                                (in thousands)
BALANCE AT BEGINNING OF PERIOD AS
 PREVIOUSLY REPORTED                                $142,019       $144,626     $136,996
CONFORMING CHANGE IN ACCOUNTING POLICY                (2,782)        (1,685)      (1,751)
                                                    --------       --------     --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD              139,237        142,941      135,245
NET INCOME                                            66,663         61,508       76,909
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                                      68,000         65,000       69,000
    Preferred Stock                                      212            212          213
                                                    --------       --------     --------

BALANCE AT END OF PERIOD                            $137,688       $139,237     $142,941
                                                    ========       ========     ========

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


<PAGE>
<TABLE>
<CAPTION>

PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Balance
Sheets
-----------------------------------------------------------------------------

                                                                     December 31,
                                                                 2000            1999
                                                                    (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                           <C>             <C>
 Production                                                   $  914,096      $  916,889
 Transmission                                                    396,695         392,029
 Distribution                                                    938,053         897,516
 General                                                         206,731         217,368
 Construction Work in Progress                                   149,095          35,903
                                                              ----------      ----------
         Total Electric Utility Plant                          2,604,670       2,459,705
 Accumulated Depreciation and Amortization                     1,150,253       1,114,255
                                                              ----------      ----------
         NET ELECTRIC UTILITY PLANT                            1,454,417       1,345,450
                                                              ----------      ----------


OTHER PROPERTY AND INVESTMENTS                                    38,211          46,205
                                                              ----------      ----------

LONG-TERM ENERGY TRADING CONTRACTS                                52,629            -
                                                              ----------      -----------


CURRENT ASSETS:
 Cash and Cash Equivalents                                        11,301           3,173
 Accounts Receivable:
  Customers                                                       60,424          32,301
  Affiliated Companies                                             3,453           2,283
  Allowance for Uncollectible Accounts                              (467)           -
 Fuel - at LIFO cost                                              28,113          24,143
 Materials and Supplies - at average cost                         29,642          34,289
 Under-recovered Fuel Costs                                       43,267           6,469
 Energy Trading Contracts                                        382,380            -
 Prepayments                                                       1,559           1,572
                                                              ----------      ----------
         TOTAL CURRENT ASSETS                                    559,672         104,230
                                                              ----------      ----------


REGULATORY ASSETS                                                 29,338          16,717
                                                              ----------      ----------


DEFERRED CHARGES                                                   7,889          12,124
                                                              ----------      ----------


           TOTAL                                              $2,142,156      $1,524,726
                                                              ==========      ==========

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

<PAGE>
<TABLE>
<CAPTION>


PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
---------------------------------------------------------------------------------------------------

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

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
  Common Stock - $15 Par Value:
    Authorized Shares: 11,000,000
    Issued Shares: 10,482,000
<S>                                                            <C>            <C>
    Outstanding Shares: 9,013,000                              $  157,230     $  157,230
  Paid-in Capital                                                 180,000        180,000
  Retained Earnings                                               137,688        139,237
                                                               ----------     ----------
          Total Common Shareholder's Equity                       474,918        476,467
                                                               ----------     ----------

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                                                    450,822        364,516
                                                               ----------     ----------

          TOTAL CAPITALIZATION                                  1,006,023        921,269
                                                               ----------     ----------

CURRENT LIABILITIES:
  Long-term Debt Due Within One Year                               20,000         20,000
  Advances from Affiliates                                         81,120         79,169
  Accounts Payable - General                                      104,379         44,088
  Accounts Payable - Affiliated Companies                          64,556         35,517
  Customer Deposits                                                19,294         17,751
  Taxes Accrued                                                     1,659         18,480
  Interest Accrued                                                  8,336          5,420
  Energy Trading Contracts                                        389,279           -
  Other                                                            12,137          8,059
                                                               ----------     ----------

          TOTAL CURRENT LIABILITIES                               700,760        228,484
                                                               ----------     ----------

DEFERRED INCOME TAXES                                             312,060        281,916
                                                               ----------     ----------

DEFERRED INVESTMENT TAX CREDITS                                    35,783         37,574
                                                               ----------     ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                        35,292         55,483
                                                               ----------     ----------

LONG-TERM ENERGY TRADING CONTRACTS                                 52,238           -
                                                               ----------     -----------

CONTINGENCIES (Note 8)

            TOTAL                                              $2,142,156     $1,524,726
                                                               ==========     ==========

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

</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of Cash
Flows
------------------------------------------------------------------------------------------------------------------------

                                                             Year Ended December 31,
                                                    -------------------------------------
                                                      2000          1999          1998
                                                      ----          ----          ----
                                                               (in thousands)

OPERATING ACTIVITIES:
<S>                                                 <C>           <C>           <C>
  Net Income                                        $  66,663     $  61,508     $  76,909
  Adjustments for Noncash Items:
   Depreciation and Amortization                       76,418        74,736        72,671
   Deferred Income Taxes                               25,453        14,521        (1,651)
   Deferred Investment Tax Credits                     (1,791)       (1,791)       (1,795)
  Changes in Certain Assets and Liabilities:
   Accounts Receivable (net)                          (28,826)       (1,668)      (13,308)
   Fuel, Materials and Supplies                           677        (8,985)       (5,809)
   Other Property and Investments                       7,994        (2,108)       (2,835)
   Accounts Payable                                    89,330        (8,000)        2,196
   Taxes Accrued                                      (16,821)       (4,615)       23,095
   Fuel Recovery                                      (36,798)      (21,709)       30,605
  Transmission Coordination Agreement Settlement      (15,063)       15,063          -
  Other (net)                                          (1,621)       (5,509)       13,035
                                                    ---------     ---------     ---------
     Net Cash Flows From Operating Activities         165,615       111,443       193,113
                                                    ---------     ---------     ---------

INVESTING ACTIVITIES:
  Construction Expenditures                          (176,851)     (103,122)      (68,897)
  Proceeds from Sales of Property and Other Items        -           (8,659)       (8,271)
                                                    ---------     ---------     ---------
    Net Cash Flows Used For Investing Activities     (176,851)     (111,781)      (77,168)
                                                    ---------     ---------     ---------

FINANCING ACTIVITIES:
 Issuance of Long-term Debt                           105,625        33,232          -
 Retirement of Long-term Debt                         (20,000)      (33,700)      (55,231)
 Change in Advances from Affiliates (net)               1,951        63,277        11,018
 Dividends Paid on Common Stock                       (68,000)      (65,000)      (69,000)
 Dividends Paid on Cumulative Preferred Stock            (212)         (212)         (213)
                                                    ---------     ---------     ---------
    Net Cash Flows From (Used For)
      Financing Activities                             19,364        (2,403)     (113,426)
                                                    ---------     ---------     ---------

Net Increase (Decrease) in Cash and Cash Equivalents    8,128        (2,741)        2,519
Cash and Cash Equivalents January 1                     3,173         5,914         3,395
                                                    ---------     ---------     ---------
Cash and Cash Equivalents December 31               $  11,301     $   3,173     $   5,914
                                                    =========     =========     =========

Supplemental Disclosure:
 Cash paid for interest net of capitalized amounts was $33,732,000,  $37,081,000
 and  $37,772,000  and  for  income  taxes  was  $25,786,000,   $23,871,000  and
 $37,712,000 in 2000, 1999, and 1998, respectively.

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

<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of
Capitalization
----------------------------------------------------------------------------------------------------------------------------

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

<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $  474,918        $  476,467
                                                                                 ----------        ----------

PREFERRED  STOCK  -  authorized  shares  700,000,   cumulative  $100  par  value
redeemable at the option of PSO upon 30 days notice.

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2000            Year Ended December 31,       December 31, 2000
------     ------------     ----------------------------     -----------------
                              2000      1999      1998
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4.00%        $105.75          25         9         -                44,606            4,460             4,463
4.24%         103.19           -         -         -                 8,069              807               807
Premium                                                                                  16                16
                                                                                 ----------        ----------
                                                                                      5,283             5,286
                                                                                 ----------        ----------

TRUST PREFERRED SECURITIES
  PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust
   holding solely Junior Subordinated Debentures of PSO, 8.00%,
   due April 30, 2037                                                                75,000            75,000
                                                                                 ----------        ----------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                317,465           337,160
Installment Purchase Contracts                                                       47,357            47,356
Senior Unsecured Notes                                                              106,000              -
Less Portion Due Within One Year                                                    (20,000)          (20,000)
                                                                                 ----------        ----------

Long-term Debt Excluding Portion Due Within One Year                                450,822           364,516
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $1,006,023        $  921,269
                                                                                 ==========        ==========


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

</TABLE>
<PAGE>





PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Schedule of Long-term Debt
-------------------------------------------------------



<PAGE>



First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2000       1999
                           ----       ----
                          (in thousands)
% Rate Due
6.43   2000 - March 30   $   -      $ 10,000
5.89   2000 - December 15    -        10,000
5.91   2001 - March 1       6,000      6,000
6.02   2001 - March 1       5,000      5,000
6.02   2001 - March 1       9,000      9,000
6.25   2003 - April 1      35,000     35,000
7.25   2003 - July 1       65,000     65,000
7.38   2004 - December 1   50,000     50,000
6.50   2005 - June 1       50,000     50,000
7.38   2023 - April 1     100,000    100,000
Unamortized Discount       (2,535)    (2,840)
                         --------   --------
                         $317,465   $337,160

         Certain  indentures  relating  to  the  first  mortgage  bonds  contain
improvement,  maintenance  and replacement  provisions  requiring the deposit of
cash or bonds with the trustee,  or in lieu thereof,  certification  of unfunded
property additions.

         Installment  purchase  contracts  have been entered into in  connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:

                             December 31,
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due
Oklahoma Environmental
 Finance Authority (OEFA):

5.90   2007 - December 1  $ 1,000    $ 1,000

Oklahoma Development
 Finance Authority (ODFA):
4.875  2014 - June 1       33,700     33,700

Red River Authority
  of Texas:
6.00   2020 - June 1       12,660     12,660
Unamortized Discount           (3)        (4)
                          -------    -------
  Total                   $47,357    $47,356
                          =======    =======



         Under the terms of the installment purchase contracts,  PSO is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated  maturities  and upon  mandatory  redemptions)  of related  pollution
control revenue bonds issued to finance the  construction  of pollution  control
facilities at certain plants.

Senior unsecured notes outstanding were as follows:

                            December 31,
                          2000       1999
                          ----       ----
                           (in thousands)
% Rate Due
------ ------------------
 (a)   2002 - November 21 $106,000 $   -
                          ======== =========

 (a) A floating interest rate is determined monthly.
     The rate on December 31, 2000 was 7.376%.

     At December 31, 2000, future annual long-term debt payments are as follows:

                             Amount
                             ------
                         (in thousands)

2001                        $ 20,000
2002                         106,000
2003                         100,000
2004                          50,000
2005                          50,000
Later Years                  147,360
                            --------
  Total Principal Amount     473,360
Unamortized Discount          (2,538)
                            --------

    Total                   $470,822
                            ========





<PAGE>


PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements


The notes listed below are combined with the notes to financial  statements  for
AEP and its other subsidiary  registrants.  The combined footnotes begin on page
L-1.

                                    Combined
                                    Footnote
                                                                  Reference


Significant Accounting Policies                                   Note 1

Merger                                                            Note 3

Effects of Regulation                                             Note 6

Industry Restructuring                                            Note 7

Commitments and Contingencies                                     Note 8

Benefit Plans                                                     Note 12

Business Segments                                                 Note 14

Financial Instruments, Credit and Risk Management                 Note 15

Income Taxes                                                      Note 16

Lines of Credit and Factoring of Receivables                      Note 19

Unaudited Quarterly Financial Information                         Note 20

Trust Preferred Securities                                        Note 21

Jointly Owned Electric Utility Plant                              Note 22

Related Party Transactions                                        Note 23


<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of Public Service Company of Oklahoma:

       We  have  audited  the  accompanying   consolidated   balance  sheet  and
consolidated  statement of  capitalization of Public Service Company of Oklahoma
and  subsidiaries  as  of  December  31,  2000,  and  the  related  consolidated
statements of income, retained earnings, and cash flows for the year then ended.
These financial  statements are the responsibility of the Company's  management.
Our responsibility is to express an opinion on these financial  statements based
on our audit. The consolidated financial statements of the Company for the years
ended December 31, 1999 and 1998, before the restatement  described in Note 3 to
the  consolidated  financial  statements,  were audited by other  auditors whose
report,  dated  February 25, 2000,  expressed  an  unqualified  opinion on those
statements.

       We conducted our audits in accordance with auditing  standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial statement presentation. We believe that our audit provide a reasonable
basis for our opinion.

       In our  opinion,  the  2000  consolidated  financial  statements  present
fairly,  in all material  respects,  the  financial  position of Public  Service
Company of Oklahoma and subsidiaries as of December 31, 2000, and the results of
their operations and their cash flows for the year then ended in conformity with
accounting principles generally accepted in the United States of America.

       We also audited the adjustments  described in Note 3 that were applied to
restate the 1999 and 1998 consolidated  financial statements to give retroactive
effect to the  conforming  change in the method of  accounting  for vacation pay
accruals.  In our  opinion,  such  adjustments  are  appropriate  and have  been
properly applied.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001




<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors of
Public Service Company Oklahoma:

We have audited the  accompanying  consolidated  balance sheets and consolidated
statements of  capitalization of Public Service Company of Oklahoma (an Oklahoma
corporation and a wholly owned subsidiary of Central and South West Corporation)
and subsidiary  companies as of December 31, 1999, and the related  consolidated
statements  of income,  retained  earnings  and cash flows,  for each of the two
years in the period  ended  December  31,  1999 prior to the  restatement  (and,
therefore,  are  not  presented  herein)  for  the  retroactive  effect  of  the
conforming  change in the method of  accounting  for  vacation  pay accruals and
certain conforming  reclassifications  to the historical financial statements as
described in Note 3 to the restated  consolidated  financial  statements.  These
financial  statements  are the  responsibility  of  Public  Service  Company  of
Oklahoma's  management.  Our  responsibility  is to  express an opinion on these
consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable  assurance about whether the financial  statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting  the amounts and  disclosures in the financial  statements.  An audit
also includes assessing the accounting principles used and significant estimates
made by  management,  as well as  evaluating  the  overall  financial  statement
presentation.  We believe  that our audits  provide a  reasonable  basis for our
opinion.

In our opinion,  the consolidated  financial statements prior to the restatement
referred to above  present  fairly,  in all  material  respects,  the  financial
position of Public Service  Company of Oklahoma and  subsidiary  companies as of
December 31, 1999, and results of their operations and their cash flows for each
of the two years in the period  ended  December  31, 1999,  in  conformity  with
accounting principles generally accepted in the United States.






Arthur Andersen LLP

Dallas, Texas
February 25, 2000

<PAGE>



















                       SOUTHWESTERN ELECTRIC POWER COMPANY
                                AND SUBSIDIARIES

<PAGE>
<TABLE>
<CAPTION>


                                      J-12
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial
Data
------------------------------------------------------------------------------------------------------------------------------

                                                Year Ended December 31,
                               -----------------------------------------------------------
                                  2000         1999        1998        1997        1996
                                  ----         ----        ----        ----        ----
                                                      (in thousands)
INCOME STATEMENTS DATA:

<S>                            <C>           <C>         <C>         <C>         <C>
  Operating Revenues           $1,124,210    $971,527    $952,952    $939,869    $920,786
  Operating Expenses              995,932     824,465     802,274     800,396     786,669
                               ----------    --------    --------    --------    --------
  Operating Income                128,278     147,062     150,678     139,473     134,117
  Nonoperating Income (Loss)        3,851      (1,965)      2,451       4,029     (21,178)
                               ----------    --------    --------    --------    --------
  Income Before Interest
    Charges                       132,129     145,097     153,129     143,502     112,939
  Interest Charges                 59,457      58,892      55,135      50,536      50,349
                               ----------    --------    --------    --------    --------
  Income Before Extraordinary
    Item                           72,672      86,205      97,994      92,966      62,590
  Extraordinary Loss                 -         (3,011)       -           -           -
                               ----------    --------    --------    --------    --------
  Net Income                       72,672      83,194      97,994      92,966      62,590
  Preferred Stock Dividend
    Requirements                      229         229         705       2,467       3,053
  Gain (Loss) on Reacquired
    Preferred Stock                  -           -           (856)      1,819        -
                               ----------    --------    --------    --------    ---------
  Earnings Applicable to
    Common Stock               $   72,443    $ 82,965    $ 96,433    $ 92,318    $ 59,537
                               ==========    ========    ========    ========    ========

                                                       December 31,
                               -----------------------------------------------------------
                                  2000        1999        1998        1997        1996
                                  ----        ----        ----        ----        ----
                                                     (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant       $3,319,024  $3,231,431  $3,157,911  $3,081,443  $3,044,314
  Accumulated Depreciation
    and Amortization            1,457,005   1,384,242   1,317,057   1,225,865   1,192,356
                               ----------  ----------  ----------  ----------  ----------
  Net Electric Utility Plant   $1,862,019  $1,847,189  $1,840,854  $1,855,578  $1,851,958
                               ==========  ==========  ==========  ==========  ==========

  Total Assets                 $2,662,534  $2,106,215  $2,081,454  $2,134,618  $2,141,999
                               ==========  ==========  ==========  ==========  ==========

  Common Stock and Paid-in
    Capital                    $  380,660  $  380,660  $  380,660  $  380,660  $  380,660
  Retained Earnings               293,989     283,546     296,581     320,148     317,835
                               ----------  ----------  ----------  ----------  ----------
  Total Common Shareholder's
    Equity                     $  674,649  $  664,206  $  677,241  $  700,808  $  698,495
                               ==========  ==========  ==========  ==========  ==========

  Preferred Stock              $    4,704  $    4,706  $    4,707  $   30,639  $   48,496
                               ==========  ==========  ==========  ==========  ==========

  Trust Preferred Securities   $  110,000  $  110,000  $  110,000  $  110,000  $     -
                               ==========  ==========  ==========  ==========  ==========

  Long-term Debt (a)           $  645,963  $  541,568  $  587,673  $  589,980  $  642,555
                               ==========  ==========  ==========  ==========  ==========

  Total Capitalization
    and Liabilities            $2,662,534  $2,106,215  $2,081,454  $2,134,618  $2,141,999
                               ==========  ==========  ==========  ==========  ==========

(a) Including portion due within one year.

</TABLE>
<PAGE>


SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations

<PAGE>


       SWEPCo is a public utility  engaged in the  generation,  purchase,  sale,
transmission and distribution of electric power to approximately  428,000 retail
customers in northeastern Texas,  northwestern Louisiana,  and western Arkansas.
SWEPCo also sells electric power at wholesale to other utilities, municipalities
and rural electric  cooperatives.  SWEPCo  participates  in power  marketing and
trading activities conducted on its behalf by the AEP System.

       SWEPCo 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.
Revenues from trading of electricity  are recorded net of purchases as operating
revenues.

Results of Operations

         The  $10.5  million  or 13%  decrease  in net  income in 2000 is due to
increased operating expenses. While the $14.8 million or 15% decrease in 1999 is
primarily the result of increased other operation and maintenance expenses,  the
write-off of acquisition  expenses  attributable to CSW's efforts to acquire the
non-nuclear  assets of Cajun Power  Cooperative,  increased interest charges and
the effect of an extraordinary loss from the discontinued  regulatory accounting
for SWEPCo's Texas and Arkansas generating business.

Operating Revenues

       Operating revenues  significantly  increased in 2000 from higher fuel and
purchased  power  revenues due to increased  fuel and purchased  power  expense,
increased  retail energy sales,  the post merger favorable impact of AEP's power
marketing and trading operations,  which added new wholesale  revenues,  and the
effect  of an  unfavorable  revenue  adjustment  in 1999 as a result  of  FERC's
approval of a transmission coordination agreement. The transmission coordination
agreement provides the means by which the AEP West electric operating  companies
plan,  operate  and  maintain  their  separate  transmission  assets as a single
system.  The  agreement  also  establishes  the method by which these  companies
allocate  transmission revenues received under open access transmission tariffs.
In 1999 the AEP West electric operating  companies filed a revised  transmission
coordination  agreement which included 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
to 1997 which  caused  SWEPCo to record a  reduction  to  revenues  in the third
quarter of 1999.

       The following analyzes the changes in operating revenues:

                    Increase (Decrease)
                    From Previous Year
(dollars in millions)
---------------------
                     2000           1999
               ------------------------------
               Amount    %    Amount     %

Retail:
  Residential  $ 32.7         $(19.9)
  Commercial     21.1            0.5
  Industrial     18.4            1.6
  Other           3.3            1.0
               ------         ------
                 75.5    10    (16.8)   (2)

Wholesale        68.7    40     32.2    23
Transmission     32.1   N.M.    (5.3) N.M.
Other           (23.6)  (86)     8.5    44
               ------         ------
     Total     $152.7    16   $ 18.6     2
               ======         ======

N.M. = Not Meaningful

       Revenues  from  retail  customers  increased  in 2000 as a  result  of an
increase in fuel and purchased  power revenues and a rise in sales volume caused
by warmer summer temperatures. The increase in fuel and purchased power revenues
reflects  rising prices for natural gas used for  generation  and related higher
costs  for  purchased  power.  The  Texas  and  Arkansas  fuel  clause  recovery
mechanisms  provide for the accrual of fuel-related  revenues until reviewed and
approved for billing to customers by the  regulator.  The accrual of  additional
fuel-related  revenues is generally  offset by  increases in fuel and  purchased
power  expenses.  As a result  fuel-related  revenues  do not impact  results of
operations.

       The significant increase in wholesale revenues in 2000 is attributable to
increased sales to other utilities and SWEPCo's initial participation in the AEP
System's power marketing and trading operations after the merger of CSW and AEP.
The volume of wholesale  electricity  sales to other utilities,  both affiliated
and  unaffiliated,  increased  as demand for energy  rose in  response to warmer
summer  weather.  Since  SWEPCo  became a  subsidiary  of AEP as a result of the
merger in June 2000,  SWEPCo  shares in the AEP  System's  power  marketing  and
trading  transactions  with other  entities.  Trading  transactions  involve the
purchase and sale of substantial  amounts of electricity which are accounted for
as revenues net of purchases.

       Wholesale  revenues  increased  23% in 1999 due mainly to an  increase in
sales to other utilities as a result of increased demand.

Operating Expenses Increase

       Total  operating   expenses  increased  21%  in  2000  primarily  due  to
significant  increases  in the cost of fuel  and  purchased  power.  In 1999 the
operating expenses increased 3% primarily due to increased  maintenance expense.
The changes in the components of operating expenses were:

                    Increase (Decrease)
                    From Previous Year
                   (dollars in millions)
                   ---------------------
                     2000           1999
               ------------------------------
                Amount    %    Amount     %

Fuel            $119.2   31    $ 8.2      2
Purchased Power   40.4  108      1.9      5
Other Operation   17.1   12      1.8      1
Maintenance       10.9   17     13.0     25
Depreciation and
 Amortization     (4.2)  (4)    10.3     11
Taxes Other Than
 Federal Income
 Taxes            (2.2)  (4)    (3.7)    (6)
Federal Income
 Taxes            (9.8) (29)    (9.3)   (22)
                ------         -----
     Total      $171.4   21    $22.2      3
                ======         =====

       Fuel expense increased in 2000 and 1999 due to an increase in the average
unit  cost of fuel as a result  of an  increase  in the spot  market  price  for
natural  gas and an  increase  in  generation  to meet  the rise in  retail  and
wholesale  demand for  electricity.  The modest increase in fuel expense in 1999
resulted from an increase in the  generation of  electricity  to meet the rising
wholesale demand for electricity.

       The major  increase  in  purchased  power  expense in 2000 was  primarily
caused by an increase  in firm energy  contract  purchases,  increased  capacity
charges and increased economy energy purchases. Purchased power expense for 1999
increased due primarily to an increase in economy energy purchases.

       Other  operation  expense  increased  in 2000 due  primarily to increased
regulatory and consulting expenses.

       Maintenance  expense  increased  in 2000 as a result of costs to  restore
service and make repairs following a severe ice storm in December.  The increase
in 1999  can be  attributed  to  higher  power  station  maintenance,  increased
tree-trimming and additional overhead line maintenance.


<PAGE>


       The increase in  depreciation  and  amortization in 1999 is the result of
increased  depreciable  plant and a  provision  for excess  earnings.  The Texas
Legislation  provides  that each year during the 1999  through  2001 rate freeze
period,  electric  utilities are subject to an earnings test. See description of
earnings test in Note 7 of the Notes to Consolidated Financial Statements.

       A decline in franchise  taxes in 2000 and ad valorem taxes in 1999 led to
the reduction in taxes other than federal income taxes in 2000 and 1999.

       The decreases in federal income tax expense attributable to operations in
2000 and 1999 were primarily due to decreases in pre-tax operating income and an
unfavorable tax accrual adjustment made in 1998.

Nonoperating Income

       The  increase in  nonoperating  income in 2000 was due to the effect of a
1999  write  off  of  Cajun  Electric  Power  Cooperative  acquisition  expenses
following  CSW's  decision  not to continue to pursue the  acquisition  of Cajun
Electric Power Cooperative non-nuclear assets. SWEPCo had deferred approximately
$13  million in  acquisition  costs  related to its  attempt to acquire  Cajun's
non-nuclear assets.

Interest Charges

       Interest charges for 1999 increased  primarily due to increased levels of
short-term  borrowings  and  additional  interest  expenses in  connection  with
changes to the transmission coordination agreements.

Extraordinary Loss

       An extraordinary  loss of $3 million net of tax was recorded in the third
quarter of 1999 when SWEPCo  discontinued  the application of SFAS 71 regulatory
accounting for the generation portion of its business in Texas and Arkansas as a
result of  legislation  passed in those states  providing for a transition  from
cost based rate regulation for SWEPCo's  generation  business to customer choice
market pricing.




<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of  Income
-----------------------------------------------------------

                            Year Ended December 31,
                                                      2000           1999         1998
                                                      ----           ----         ----
                                                                (in thousands)

<S>                                                <C>             <C>          <C>
OPERATING REVENUES                                 $1,124,210      $971,527     $952,952
                                                   ----------      --------     --------

OPERATING EXPENSES:
  Fuel                                                498,805       379,597      371,414
  Purchased Power                                      77,792        37,371       35,483
  Other Operation                                     159,459       142,385      140,627
  Maintenance                                          75,123        64,241       51,219
  Depreciation and Amortization                       104,679       108,831       98,479
  Taxes Other Than Federal Income Taxes                56,283        58,458       62,207
  Federal Income Taxes                                 23,791        33,582       42,845
                                                   ----------      --------     --------
           Total Operating Expenses                   995,932       824,465      802,274
                                                   ----------      --------     --------

OPERATING INCOME                                      128,278       147,062      150,678

NONOPERATING INCOME (LOSS)                              3,851        (1,965)       2,451
                                                   ----------      --------     --------

INCOME BEFORE INTEREST CHARGES                        132,129       145,097      153,129

INTEREST CHARGES                                       59,457        58,892       55,135
                                                   ----------      --------     --------

INCOME BEFORE EXTRAORDINARY ITEM                       72,672        86,205       97,994

EXTRAORDINARY LOSS (net of tax of $1,621,000)            -           (3,011)        -
                                                   ----------      --------     ---------

NET INCOME                                             72,672        83,194       97,994

PREFERRED STOCK DIVIDEND REQUIREMENTS                     229           229          705

LOSS ON REACQUIRED PREFERRED STOCK                       -             -            (856)
                                                   ----------      --------     --------

EARNINGS APPLICABLE TO COMMON STOCK                $   72,443      $ 82,965     $ 96,433
                                                   ==========      ========     ========


Consolidated Statements of Retained Earnings

BALANCE AT BEGINNING OF PERIOD AS
  PREVIOUSLY REPORTED                                $288,019      $300,592     $324,050
  Conforming Change in Accounting Policy               (4,473)       (4,011)      (3,902)
                                                     --------      --------     --------

ADJUSTED BALANCE AT BEGINNING OF PERIOD               283,546       296,581      320,148
NET INCOME                                             72,672        83,194       97,994
LOSS ON REACQUIRED PREFERRED STOCK                       -             -            (856)

DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                                       62,000        96,000      120,000
    Preferred Stock                                       229           229          705
                                                     --------      --------     --------

BALANCE AT END OF PERIOD                             $293,989      $283,546     $296,581
                                                     ========      ========     ========

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

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
----------------------------------------------------------------------------------------


                                                                      December 31,
                                                                  2000            1999
                                                                     (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                            <C>             <C>
 Production                                                    $1,414,527      $1,402,062
 Transmission                                                     519,317         484,327
 Distribution                                                   1,001,237         958,318
 General                                                          325,948         333,949
 Construction Work in Progress                                     57,995          52,775
                                                               ----------      ----------
         Total Electric Utility Plant                           3,319,024       3,231,431
 Accumulated Depreciation and Amortization                      1,457,005       1,384,242
                                                               ----------      ----------
         NET ELECTRIC UTILITY PLANT                             1,862,019       1,847,189
                                                               ----------      ----------


OTHER PROPERTY AND INVESTMENTS                                     39,627          37,080
                                                               ----------      ----------

LONG-TERM ENERGY TRADING CONTRACTS                                 63,028            -
                                                               ----------      -----------

CURRENT ASSETS:
 Cash and Cash Equivalents                                          1,907           3,043
 Accounts Receivable:
  Customers                                                        42,310          49,939
  Affiliated Companies                                             11,419           6,053
  Allowance for Uncollectible Accounts                               (911)         (4,428)
 Fuel Inventory - at average cost                                  40,024          60,844
 Materials and Supplies - at average cost                          25,137          26,420
 Under-recovered Fuel Costs                                        35,469            -
 Energy Trading Contracts                                         457,936            -
 Prepayments                                                       16,780          15,953
                                                               ----------      ----------
         TOTAL CURRENT ASSETS                                     630,071         157,824
                                                               ----------      ----------


REGULATORY ASSETS                                                  57,082          47,180
                                                               ----------      ----------


DEFERRED CHARGES                                                   10,707          16,942
                                                               ----------      ----------


           TOTAL                                               $2,662,534      $2,106,215
                                                               ==========      ==========

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


SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES

                                                                     December 31,
                                                              ---------------------------
                                                                 2000            1999
                                                                 ----            ----
                                                                    (in thousands)
CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
 Common Stock - $18 Par Value:
   Authorized - 7,600,000 Shares
<S>                                                           <C>             <C>
   Outstanding - 7,536,640 Shares                             $  135,660      $  135,660
 Paid-in Capital                                                 245,000         245,000
 Retained Earnings                                               293,989         283,546
                                                              ----------      ----------
           Total Common Shareholder's Equity                     674,649         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                                                  645,368         495,973
                                                              ----------      ----------
           TOTAL CAPITALIZATION                                1,434,721       1,274,885
                                                              ----------      ----------

OTHER NONCURRENT LIABILITIES                                      11,290           9,255
                                                              ----------      ----------

CURRENT LIABILITIES:
 Long-term Debt Due Within One Year                                  595          45,595
 Advances from Affiliates                                         16,823         140,897
 Accounts Payable - General                                      107,747          60,689
 Accounts Payable - Affiliated Companies                          36,021          39,117
 Customer Deposits                                                16,433          14,236
 Taxes Accrued                                                    11,224          24,374
 Interest Accrued                                                 13,198           9,792
 Energy Trading Contracts                                        466,198            -
 Other                                                            15,064          12,623
                                                              ----------      ----------
           TOTAL CURRENT LIABILITIES                             683,303         347,323
                                                              ----------      ----------

DEFERRED INCOME TAXES                                            399,204         376,504
                                                              ----------      ----------

DEFERRED INVESTMENT TAX CREDITS                                   53,167          57,649
                                                              ----------      ----------

REGULATORY LIABILITIES AND DEFERRED CREDITS                       18,288          40,599
                                                              ----------      ----------

LONG-TERM ENERGY TRADING CONTRACTS                                62,561            -
                                                              ----------      -----------

COMMITMENTS AND CONTINGENCIES (Note 8)

             TOTAL                                            $2,662,534      $2,106,215
                                                              ==========      ==========

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

<PAGE>
<TABLE>
<CAPTION>


SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
--------------------------------------------

                                                             Year Ended December 31,
                                                    -------------------------------------
                                                      2000          1999          1998
                                                      ----          ----          ----
                                                               (in thousands)

OPERATING ACTIVITIES:
<S>                                                 <C>           <C>           <C>
  Net Income                                        $  72,672     $  83,194     $  97,994
  Adjustments for Noncash Items:
   Depreciation and Amortization                      104,679       108,831        98,479
   Deferred Income Taxes                               14,653       (17,347)      (11,909)
   Deferred Investment Tax Credits                     (4,482)       (4,565)       (4,631)
  Changes in Certain Assets and Liabilities:
   Accounts Receivable (net)                           (1,254)      (11,134)       41,077
   Fuel, Materials and Supplies                        22,103       (21,891)      (14,436)
   Accounts Payable                                    43,962       (12,953)      (25,852)
   Taxes Accrued                                      (13,150)        1,185        10,305
   Transmission Coordination Agreement Settlement     (24,406)       24,406          -
   Fuel Recovery                                      (38,357)       (2,490)       18,391
  Other (net)                                          25,208         8,731        17,045
                                                    ---------     ---------     ---------
    Net Cash Flows From Operating Activities          201,628       155,967       226,463
                                                    ---------     ---------     ---------

INVESTING ACTIVITIES:
  Construction Expenditures                          (120,671)     (111,019)      (83,120)
  Other                                                   446        (4,167)       (5,202)
                                                    ---------     ---------     ---------
    Net Cash Flows Used For Investing Activities     (120,225)     (115,186)      (88,322)
                                                    ---------     ---------     ---------

FINANCING ACTIVITIES:
  Issuance of Long-term Debt                          149,360          -             -
  Retirement of Cumulative Preferred Stock                 (1)           (1)      (27,988)
  Retirement of Long-term Debt                        (45,595)      (46,144)       (2,354)
  Change in Advances from Affiliates (net)           (124,074)      100,192        15,530
  Dividends Paid on Common Stock                      (62,000)      (96,000)     (120,000)
  Dividends Paid on Cumulative Preferred Stock           (229)         (229)       (1,183)
                                                    ---------     ---------     ---------
    Net Cash Flows Used For Financing Activities      (82,539)      (42,182)     (135,995)
                                                    ---------     ---------     ---------

Net Increase (Decrease) in Cash and
  Cash Equivalents                                     (1,136)       (1,401)        2,146
Cash and Cash Equivalents January 1                     3,043         4,444         2,298
                                                    ---------     ---------     ---------
Cash and Cash Equivalents December 31               $   1,907     $   3,043     $   4,444
                                                    =========     =========     =========

Supplemental Disclosure:
  Cash paid for interest net of capitalized amounts was $51,110,611, $55,254,000
  and  $50,341,000  and  for  income  taxes  was  $27,993,879,  $55,677,000  and
  $57,977,000 in 2000, 1999, and 1998, respectively.

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

SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of
Capitalization
------------------------------------------------------------------------------------------------

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

<S>                                                                              <C>               <C>
COMMON SHAREHOLDER'S EQUITY                                                      $  674,649        $  664,206
                                                                                 ----------        ----------

PREFERRED STOCK - authorized 1,860,000 shares $100 par value

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2000            Year Ended December 31,       December 31, 2000
------     ------------     ----------------------------     -----------------
                              2000      1999      1998
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4.28%        $103.90              -        -         -              7,386               739               739
4.65%        $102.75              -        1         -              1,907               190               191
5.00%        $109.00             12        2        20             37,715             3,771             3,772
Premium                                                                                   4                 4
                                                                                 ----------        ----------

                                                                                      4,704             4,706
                                                                                 ----------        ----------

TRUST PREFERRED SECURITIES
  SWEPCo-obligated,  mandatorily  redeemable  preferred securities of subsidiary
   trust holding solely Junior Subordinated Debentures of SWEPCo, 7.875%,
   due April 30, 2037                                                               110,000           110,000
                                                                                 ----------        ----------

LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                                315,477           360,430
Installment Purchase Contracts                                                      180,486           181,138
Senior Unsecured Notes                                                              150,000              -
Less Portion Due Within One Year                                                       (595)          (45,595)
                                                                                 ----------        ----------

  Long-term Debt Excluding Portion Due Within One Year                              645,368           495,973
                                                                                 ----------        ----------

  TOTAL CAPITALIZATION                                                           $1,434,721        $1,274,885
                                                                                 ==========        ==========


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

<PAGE>





SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
------------------------



<PAGE>



First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2000       1999
                           ----       ----
                          (in thousands)
% Rate Due
5-1/4  2000 - April 1    $   -      $ 45,000
6-5/8  2003 - February 1   55,000     55,000
7-3/4  2004 - June 1       40,000     40,000
6.20   2006 - November 1    5,795      5,940
6.20   2006 - November 1    1,000      1,000
7.00   2007 - September 1  90,000     90,000
7-1/4  2023 - July 1       45,000     45,000
6-7/8  2025 - October 1    80,000     80,000
Unamortized Discount       (1,318)    (1,510)
                         --------   --------
                         $315,477   $360,430

         Certain  indentures  relating  to  the  first  mortgage  bonds  contain
improvement,  maintenance  and replacement  provisions  requiring the deposit of
cash or bonds with the trustee,  or in lieu thereof,  certification  of unfunded
property additions.

         Installment  purchase  contracts  have been entered into in  connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:

                             December 31,
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due
------ -----------------
DeSoto:

7.60   2019 - January 1  $ 53,500   $ 53,500

Sabine:

6.10   2018 - April 1      81,700     81,700

Titus County:

6.90   2004 - November 1   12,290     12,290
6.00   2008 - January 1    13,520     13,970
8.20   2011 - August 1     17,125     17,125
Unamortized Premium         2,351      2,553
                         --------   --------
                         $180,486   $181,138




         Under  the  terms of the  installment  purchase  contracts,  SWEPCo  is
required to pay amounts  sufficient to enable the payment of interest on and the
principal  (at stated  maturities  and upon  mandatory  redemptions)  of related
pollution  control revenue bonds issued to finance the construction of pollution
control facilities at certain plants.

Senior unsecured notes outstanding were as follows:

                            December 31,
                          2000       1999
                          ----       ----
                           (in thousands)
% Rate Due
------ ------------------
 (a)   2002 - March 1   $150,000   $   -
                        ========   ========

(a)      A floating interest rate is determined monthly.
         The rate on December 31, 2000 was 6.97%.

At December 31, 2000, future annual long-term debt payments are as follows:

                             Amount
                             ------
                         (in thousands)
2001                        $    595
2002                         150,595
2003                          55,595
2004                          52,885
2005                             595
Later Years                  384,665
                            --------
  Total Principal Amount     644,930
Unamortized Premium            1,033
                            --------
    Total                   $645,963
                            ========



<PAGE>



SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements


The notes listed below are combined with the notes to financial  statements  for
AEP and its other subsidiary  registrants.  The combined footnotes begin on page
L-1.

                                                          Combined
                                                          Footnote
                                                          Reference

Significant Accounting Policies                           Note 1

Extraordinary Items                                       Note 2

Merger                                                    Note 3

Rate Matters                                              Note 5

Effects of Regulation                                     Note 6

Industry Restructuring                                    Note 7

Commitments and Contingencies                             Note 8

Benefit Plans                                             Note 12

Business Segments                                         Note 14

Financial Instruments, Credit and Risk Management         Note 15

Income Taxes                                              Note 16

Lines of Credit and Factoring of Receivables              Note 19

Unaudited Quarterly Financial Information                 Note 20

Trust Preferred Securities                                Note 21

Jointly Owned Electric Utility Plant                      Note 22

Related Party Transactions                                Note 23



<PAGE>


INDEPENDENT AUDITORS' REPORT



To the Shareholders and Board of
Directors of Southwestern Electric Power Company:

       We  have  audited  the  accompanying   consolidated   balance  sheet  and
consolidated  statement of capitalization of Southwestern Electric Power Company
and  subsidiaries  as  of  December  31,  2000,  and  the  related  consolidated
statements of income, retained earnings, and cash flows for the year then ended.
These financial  statements are the responsibility of the Company's  management.
Our responsibility is to express an opinion on these financial  statements based
on our audit. The consolidated financial statements of the Company for the years
ended December 31, 1999 and 1998, before the restatement  described in Note 3 to
the  consolidated  financial  statements,  were audited by other  auditors whose
report,  dated  February 25, 2000,  expressed  an  unqualified  opinion on those
statements.

       We conducted our audit in accordance  with auditing  standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audit  provides  a
reasonable basis for our opinion.

       In our  opinion,  the  2000  consolidated  financial  statements  present
fairly,  in all  material  respects,  the  financial  position  of  Southwestern
Electric  Power Company and  subsidiary as of December 31, 2000, and the results
of their  operations  and their cash flows for the year then ended in conformity
with accounting principles generally accepted in the United States of America.

       We also audited the adjustments  described in Note 3 that were applied to
restate the 1999 and 1998 consolidated  financial statements to give retroactive
effect to the  conforming  change in the method of  accounting  for vacation pay
accruals.  In our  opinion,  such  adjustments  are  appropriate  and have  been
properly applied.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001



<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors of
 Southwestern Electric Power Company:

We have audited the  accompanying  consolidated  balance sheets and consolidated
statements of capitalization of Southwestern  Electric Power Company (a Delaware
corporation and a wholly owned subsidiary of Central and South West Corporation)
and  subsidiary  company as of December 31, 1999,  and the related  consolidated
statements  of income,  retained  earnings  and cash flows,  for each of the two
years in the period  ended  December  31,  1999 prior to the  restatement  (and,
therefore,  are  not  presented  herein)  for  the  retroactive  effect  of  the
conforming  change in the method of  accounting  for  vacation  pay accruals and
certain conforming  reclassifications  to the historical financial statements as
described in Note 3 to the restated  consolidated  financial  statements.  These
financial  statements  are the  responsibility  of  Southwestern  Electric Power
Company's  management.  Our  responsibility  is to  express  an opinion on these
consolidated financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable  assurance about whether the financial  statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting  the amounts and  disclosures in the financial  statements.  An audit
also includes assessing the accounting principles used and significant estimates
made by  management,  as well as  evaluating  the  overall  financial  statement
presentation.  We believe  that our audits  provide a  reasonable  basis for our
opinion.

In our opinion,  the consolidated  financial statements prior to the restatement
referred to above  present  fairly,  in all  material  respects,  the  financial
position of  Southwestern  Electric Power Company and  subsidiary  company as of
December 31, 1999, and results of their operations and their cash flows for each
of the two years in the period  ended  December  31, 1999,  in  conformity  with
accounting principles generally accepted in the United States.







Arthur Andersen LLP

Dallas, Texas
February 25, 2000


<PAGE>













                          WEST TEXAS UTILITIES COMPANY

<PAGE>
<TABLE>
<CAPTION>


                                      K-11
WEST TEXAS UTILITIES COMPANY
Selected Financial
Data
----------------------------------------------------------------------------------------------------

                                               Year Ended December 31,
                              -----------------------------------------------------------
                                 2000        1999        1998        1997        1996
                                 ----        ----        ----        ----        ----
                                                    (in thousands)
INCOME STATEMENTS DATA:

<S>                           <C>         <C>         <C>         <C>         <C>
  Operating Revenues          $  572,794  $  445,709  $  424,953  $  397,779  $  377,057
  Operating Expenses             520,453     391,910     365,677     353,195     327,499
                              ----------  ----------  ----------  ----------  ----------
  Operating Income                52,341      53,799      59,276      44,584      49,558
  Nonoperating Income (Loss)      (1,675)      2,488       2,712       1,463      (9,922)
                              ----------  ----------  ----------  ----------  ----------
  Income Before Interest
    Charges                       50,666      56,287      61,988      46,047      39,636
  Interest Charges                23,216      24,420      24,263      24,570      25,241
                              ----------  ----------  ----------  ----------  ----------
  Income Before
    Extraordinary Item            27,450      31,867      37,725      21,477      14,395
  Extraordinary Loss                -         (5,461)       -           -           -
                              ----------  ----------  ----------  ----------  -----------
  Net Income                      27,450      26,406      37,725      21,477      14,395
  Preferred Stock Dividend
    Requirements                     104         104         104         144         264
                              ----------  ----------  ----------  ----------  ----------
  Gain on Reacquired
    Preferred Stock                 -           -           -          1,085        -
                              ----------  ----------  ----------  ----------  ----------
  Earnings Applicable to
    Common Stock              $   27,346  $   26,302  $   37,621  $   22,418  $   14,131
                              ==========  ==========  ==========  ==========  ==========

                                                       December 31,
                              ------------------------------------------------------------
                                 2000        1999        1998        1997        1996
                                 ----        ----        ----        ----        ----
                                                    (in thousands)
BALANCE SHEETS DATA:

  Electric Utility Plant      $1,229,339  $1,182,544  $1,146,582  $1,108,845  $1,088,141
  Accumulated Depreciation
    and Amortization             515,041     495,847     473,503     441,281     414,777
                              ----------  ----------  ----------  ----------  ----------
  Net Electric Utility Plant  $  714,298  $  686,697  $  673,079  $  667,564  $  673,364
                              ==========  ==========  ==========  ==========  ==========

  Total Assets                $1,088,932  $  861,205  $  819,446  $  826,858  $  837,412
                              ==========  ==========  ==========  ==========  ==========

  Common Stock and Paid-in
    Capital                   $  139,450  $  139,450  $  139,450  $  139,450  $  139,450
  Retained Earnings              122,588     113,242     114,940     117,319     120,901
                              ----------  ----------  ----------  ----------  ----------
  Total Common Shareholder's
    Equity                    $  262,038  $  252,692  $  254,390  $  256,769  $  260,351
                              ==========  ==========  ==========  ==========  ==========

  Cumulative Preferred Stock:
    Not Subject to Mandatory
      Redemption              $    2,482  $    2,482  $    2,482  $    2,483  $    6,291
                              ==========  ==========  ==========  ==========  ==========
  Long-term Debt (a)          $  255,843  $  303,686  $  303,518  $  303,351  $  303,182
                              ==========  ==========  ==========  ==========  ==========

Total Capitalization
    and Liabilities           $1,088,932  $  861,205  $  819,446  $  826,858  $  837,412
                              ==========  ==========  ==========  ==========  ==========



(a) Including portion due within one year.
</TABLE>
<PAGE>


WEST TEXAS UTILITIES COMPANY
Management's Narrative Analysis
of Results of
Operations
------------------------------------------------------



<PAGE>


       WTU is a  public  utility  engaged  in the  generation,  purchase,  sale,
transmission and  distribution of electric power and provides  electric power to
approximately 190,000 retail customers in west and central Texas. WTU also sells
electric  power  at  wholesale  to other  utilities,  municipalities  and  rural
electric   cooperatives.   WTU  participates  in  power  marketing  and  trading
activities conducted on its behalf by the AEP System.

         WTU 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.
Revenues from trading of electricity  are recorded net of purchases as operating
revenues.

Results of Operations

       Income  before  extraordinary  items  decreased  $4.4 million or 14%. The
decrease was primarily due to a decrease in nonoperating  income, as a result of
the termination of merchandise sales and the cost of phasing out the merchandise
sales  program.  The decrease in  nonoperating  income is partially  offset by a
decrease in interest charges.

       An extraordinary loss related to the discontinuance of SFAS 71 regulatory
accounting for WTU's generation  business of $5.5 million after tax was recorded
in September 1999.

Operating Revenues

       A 29%  increase  in  operating  revenues  was due to  increased  fuel and
purchases power revenues,  reflecting  higher fuel and purchased power expenses,
and an increase in weather-related  demand for electricity.  Under the operation
of a fuel and purchase power clause mechanism in Texas,  revenues are accrued to
reflect  fuel and  purchased  power cost  increases.  The accrued  revenues  are
subsequently reviewed and approved for recovery by the PUCT. As a result changes
in  fuel  and  purchase  power  revenues  do not  generally  impact  results  of
operations.

       Changes in the components of operating revenues were as follows:

                         Increase (Decrease)
                         From Previous Year
(dollars in millions)      Amount       %
----------------------     ------       -

Retail:
  Residential              $ 31.7      24
  Commercial                 18.9      24
  Industrial                 13.3      26
  Other                       9.3      25
                           ------
                             73.2
Wholesale                    47.8      46
Transmission                  3.7      11
Other                         2.4     128
                           ------
     Total                 $127.1      29
                           ======

       Revenues from retail customers increased  significantly as a result of an
increase in fuel and purchase power related  revenues  reflecting  rising prices
for natural gas used for generation and related higher  purchased  power prices.
Since the Texas fuel and purchase power clause recovery  mechanism  provides for
the accrual of revenues to recover  fuel and purchase  power cost changes  until
reviewed and  approved  for billing to customers by the PUCT,  increases in fuel
and  purchased  power  expenses and related  accrued  revenues do not  adversely
effect results of operations.

       The  significant  increase  in  wholesale  revenues  is  attributable  to
increased sales to other utilities and WTU's  participation  in the AEP System's
power marketing and trading operations. The volume of electricity sales to other
utilities, both affiliated and unaffiliated, increased as demand for energy rose
in response to warmer summer weather.  Since WTU became a subsidiary of AEP as a
result  of the  merger  in June  2000,  WTU  shares  in the AEP  System's  power
marketing and trading transactions with other non-affiliated  entities.  Trading
involves  the  purchase  and  sale of  substantial  amounts  of  electricity  to
non-affiliated parties. Revenues from trading are recorded net of purchases.
Operating Expenses

         Operating expenses were $520.5 million or 33% more than in 1999 largely
as a result of  increased  fuel and  purchased  power  expenses.  Changes in the
components of operating expenses were as follows:

                         Increase (Decrease)
                         From Previous Year
(dollars in millions)      Amount       %
----------------------     ------       -

Fuel                       $ 59.8      48
Purchased Power              66.1     107
Other Operation              (1.2)     (1)
Maintenance                   1.6       8
Depreciation and
 Amortization                 4.4       9
Taxes Other Than Federal
 Income                      (2.9)    (10)
Federal Income Taxes          0.8       6
                           ------
     Total                 $128.6      33
                           ======

       The  substantial  increase in fuel expense was primarily due to a rise in
the average  cost of fuel  resulting  from an increase in spot market  prices of
natural gas. WTU uses  natural gas as fuel for 72% of its  generating  capacity.
The nature of the natural gas market is such that both  long-term and short-term
contracts  are generally  based on the current spot market price.  Consequently,
changes in natural gas prices affect WTU's fuel expense.  However,  as explained
above they generally do not impact results of operations.

       Purchased  power  expense  increased  due primarily to an increase in the
cost per MWH  purchased to replace  generation at a power plant which was out of
service for 90 days as a result of a control room fire and to the adverse impact
of natural gas prices on wholesale purchased power prices.

       The increase in maintenance expense was due to an increase in power plant
maintenance  and  overhead  line  maintenance.   The  increase  in  power  plant
maintenance was partly due to repair of the fire damaged control room.

       Depreciation and amortization expense increased due to the recordation of
increased accruals for estimated excess earnings under the Texas Legislation.

       The decrease in taxes other than federal  income taxes was  primarily due
to lower ad valorem and state franchise taxes.

Nonoperating Income

       Nonoperating   income  decreased  $4.2  million   primarily  due  to  the
termination  of  merchandise  sales and the cost of phasing out the  merchandise
sales program.

Interest Charges

       The decrease in interest  charges of $1.2  million or 5% resulted  from a
reduction in long-term borrowings.

Extraordinary Loss

       The extraordinary  loss of $5.5 million 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 Texas  Jurisdictional
Legislation  which provides for a transition from cost based rate regulation for
WTU's  generation  business to customer  choice and market based pricing for the
supply of electricity at retail.



<PAGE>
<TABLE>
<CAPTION>


WEST TEXAS UTILITIES COMPANY
Statements of Income
---------------------------------------------------------------

                                                           Year Ended December 31,
                                                   ---------------------------------------
                                                      2000           1999         1998
                                                      ----           ----         ----
                                                                (in thousands)

<S>                                                <C>            <C>          <C>
OPERATING REVENUES                                 $  572,794     $  445,709   $  424,953
                                                   ----------     ----------   ----------

OPERATING EXPENSES:
  Fuel                                                183,154        123,348      122,836
  Purchased Power                                     127,583         61,532       48,131
  Other Operation                                      93,078         94,290       90,061
  Maintenance                                          21,241         19,604       16,666
  Depreciation and Amortization                        55,172         50,789       42,750
  Taxes Other Than Federal Income Taxes                25,321         28,267       24,638
  Federal Income Taxes                                 14,904         14,080       20,595
                                                   ----------     ----------   ----------
           Total Operating Expenses                   520,453        391,910      365,677
                                                   ----------     ----------   ----------

OPERATING INCOME                                       52,341         53,799       59,276

NONOPERATING INCOME (LOSS)                             (1,675)         2,488        2,712
                                                   ----------     ----------   ----------

INCOME BEFORE INTEREST CHARGES                         50,666         56,287       61,988

INTEREST CHARGES                                       23,216         24,420       24,263
                                                   ----------     ----------   -----------

INCOME BEFORE EXTRAORDINARY ITEMS                      27,450         31,867       37,725

EXTRAORDINARY LOSS - (net of tax of $2,941,000)          -            (5,461)        -
                                                   ----------     ----------   -----------

NET INCOME                                             27,450         26,406       37,725

PREFERRED STOCK DIVIDEND REQUIREMENTS                     104            104          104
                                                   ----------     ----------   ----------

EARNINGS APPLICABLE TO COMMON STOCK                $   27,346     $   26,302   $   37,621
                                                   ==========     ==========   ==========


Statements of Retained
Earnings
-----------------------------------------------------------------------------------------------------------------

                            Year Ended December 31,
                                                      2000           1999         1998
                                                      ----           ----         ----
                                                                (in thousands)

BALANCE AT BEGINNING OF PERIOD AS
 PREVIOUSLY REPORTED                                $115,856       $117,189     $119,479
CONFORMING CHANGE IN ACCOUNTING POLICY                (2,614)        (2,249)      (2,160)
                                                    --------       --------     --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD              113,242        114,940      117,319
NET INCOME                                            27,450         26,406       37,725
DEDUCTIONS:
  Cash Dividends Declared:
    Common Stock                                      18,000         28,000       40,000
    Preferred Stock                                      104            104          104
                                                    --------       --------     --------

BALANCE AT END OF PERIOD                            $122,588       $113,242     $114,940
                                                    ========       ========     ========

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

WEST TEXAS UTILITIES COMPANY
Balance Sheets
-----------------------------------------------------------------------------------------------------------------

                                                                       December 31,
                                                                   2000            1999
                                                                      (in thousands)
ASSETS

ELECTRIC UTILITY PLANT:
<S>                                                             <C>            <C>
 Production                                                     $  431,793     $  429,783
 Transmission                                                      235,303        220,479
 Distribution                                                      416,587        403,206
 General (including nuclear fuel)                                  110,832        113,945
 Construction Work in Progress                                      34,824         15,131
                                                                ----------     ----------
         Total Electric Utility Plant                            1,229,339      1,182,544
 Accumulated Depreciation and Amortization                         515,041        495,847
                                                                ----------     ----------
         NET ELECTRIC UTILITY PLANT                                714,298        686,697
                                                                ----------     ----------


OTHER PROPERTY AND INVESTMENTS                                      23,154         21,570
                                                                ----------     ----------

ENERGY TRADING CONTRACTS - LONG-TERM                                20,944           -
                                                                ----------     -----------

CURRENT ASSETS:
 Cash and Cash Equivalents                                           6,941          6,074
 Accounts Receivable:
  Customers                                                         36,217         45,928
  Affiliated Companies                                              16,095          4,837
  Allowance for Uncollectible Accounts                                (288)          (186)
 Fuel - at average cost                                             12,174         17,133
 Materials and Supplies - at average cost                           10,510         14,029
 Underrecovered Fuel Costs                                          67,655         14,652
 Energy Trading Contracts                                          152,174           -
 Prepayments                                                           851            619
                                                                ----------     ----------
         TOTAL CURRENT ASSETS                                      302,329        103,086
                                                                ----------     ----------


REGULATORY ASSETS                                                   24,808         29,745
                                                                ----------     ----------


DEFERRED CHARGES                                                     3,399         20,107
                                                                ----------     ----------


           TOTAL                                                $1,088,932     $  861,205
                                                                ==========     ==========

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


WEST TEXAS UTILITIES COMPANY
-------------------------------------------------------------------------------------------------------------------------------

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

CAPITALIZATION AND LIABILITIES

CAPITALIZATION:
 Common Stock - $25 Par Value:
<S>                                                            <C>               <C>
   Authorized - 7,800,000 Shares
   Outstanding - 5,488,560 Shares                              $  137,214        $137,214
 Paid-in Capital                                                    2,236           2,236
 Retained Earnings                                                122,588         113,242
                                                               ----------        --------
           Total Common Shareholder's Equity                      262,038         252,692
 Cumulative Preferred Stock:
     Not Subject to Mandatory Redemption                            2,482           2,482
 Long-term Debt                                                   255,843         263,686
                                                               ----------        --------
           TOTAL CAPITALIZATION                                   520,363         518,860
                                                               ----------        --------

CURRENT LIABILITIES:
 Long-term Debt Due Within One Year                                  -             40,000
 Advances from Affiliates                                          58,578          21,408
 Accounts Payable - General                                        45,562          39,611
 Accounts Payable - Affiliated Companies                           42,212          19,770
 Customer Deposits                                                  2,659           2,396
 Taxes Accrued                                                     18,901          12,458
 Interest Accrued                                                   3,717           4,165
 Energy Trading Contracts                                         154,919            -
 Other                                                              7,906           5,510
                                                               ----------        --------
           TOTAL CURRENT LIABILITIES                              334,454         145,318
                                                               ----------        --------

DEFERRED INCOME TAXES                                             157,038         148,992
                                                               ----------        --------

DEFERRED INVESTMENT TAX CREDITS                                    24,052          25,323
                                                               ----------        --------

REGULATORY LIABILITIES AND DEFERRED CREDITS                        32,236          22,712
                                                               ----------        --------

ENERGY TRADING CONTRACTS - LONG-TERM                               20,789            -
                                                               ----------        ---------

COMMITMENTS AND CONTINGENCIES (Note 8)

             TOTAL                                             $1,088,932        $861,205
                                                               ==========        ========

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

</TABLE>
<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
Statements of Cash Flows
----------------------------------------


                                                             Year Ended December 31,
                                                    --------------------------------------
                                                      2000          1999          1998
                                                      ----          ----          ----
                                                               (in thousands)

OPERATING ACTIVITIES:
<S>                                                 <C>           <C>           <C>
  Net Income                                        $  27,450     $  26,406     $  37,725
  Adjustments for Noncash Items:
    Depreciation and Amortization                      55,172        50,789        42,750
    Deferred Federal Income Taxes                       8,164        12,026        (6,626)
    Deferred Investment Tax Credits                    (1,271)       (1,275)       (1,321)
    Extraordinary Loss - Discontinuance of SFAS 71       -            5,461          -
CHANGES IN CERTAIN ASSETS AND LIABILITIES:
    Accounts Receivable (net)                          (1,445)      (18,890)      (21,119)
    Fuel, Materials and Supplies                        8,478        (3,785)         (660)
    Accounts Payable                                   28,393         7,229           305
    Taxes Accrued                                       6,443         2,427        (1,344)
    Fuel Recovery                                     (53,003)      (10,672)        7,988
  Other Property and Investments                       (1,584)       (2,057)       (1,344)
  Transmission Coordination Agreement Settlement       15,465       (15,465)         -
  Other (net)                                           2,016        10,448         4,972
                                                    ---------     ---------     ---------
    Net Cash Flows From Operating Activities           94,278        62,642        61,326
                                                    ---------     ---------     ---------

INVESTING ACTIVITIES:
  Construction Expenditures                           (64,477)      (49,443)      (36,867)
  Other                                                  -           (3,832)       (5,782)
                                                    ---------     ---------     ---------
    Net Cash Flows Used For Investing Activities      (64,477)      (53,275)      (42,649)
                                                    ---------     ---------     ---------

FINANCING ACTIVITIES:
 Retirement of Long-term Debt                         (48,000)         -             -
 Change in Advances from Affiliates (net)              37,170        16,835         4,573
 Dividends Paid on Common Stock                       (18,000)      (28,000)      (40,000)
 Dividends Paid on Cumulative Preferred Stock            (104)         (105)         (104)
                                                    ---------     ---------     ---------
    Net Cash Flows From (Used For)
      Financing Activities                            (28,934)      (11,270)      (35,531)
                                                    ---------     ---------     ---------

Net Increase (Decrease) in Cash and Cash Equivalents      867        (1,903)      (16,854)
Cash and Cash Equivalents at Beginning of Period        6,074         7,977        24,831
                                                    ---------     ---------     ---------
Cash and Cash Equivalents at End of Period          $   6,941     $   6,074     $   7,977
                                                    =========     =========     =========

Supplemental Disclosure:
  Cash paid (received) for interest net of capitalized  amounts was $19,088,000,
  $17,577,000 and  $17,250,000  and for income taxes was $(906,000),  $3,309,000
  and $29,533,000 in 2000, 1999 and 1998, respectively.

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

<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
Statements of
Capitalization
---------------------------------------------------------------------------

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

<S>                                                                              <C>                <C>
COMMON SHAREHOLDER'S EQUITY                                                      $262,038           $252,692
                                                                                 --------           --------

PREFERRED STOCK - authorized 810,000 shares $100 par value

            Call Price                                             Shares
           December 31,      Number of Shares Redeemed          Outstanding
Series         2000            Year Ended December 31,       December 31, 2000
------     ------------     ----------------------------     -----------------
                              2000      1999      1998
                              ----      ----      ----

Not Subject to Mandatory Redemption:

4.40%        $107.00              1        2         -             23,672           2,367             2,367
Premium                                                                               115               115
                                                                                 --------          --------
                                                                                    2,482             2,482
                                                                                 --------          --------


LONG-TERM DEBT (See Schedule of Long-term Debt):

First Mortgage Bonds                                                              211,533           259,376
Installment Purchase Contracts                                                     44,310            44,310
Less Portion Due Within One Year                                                     -              (40,000)
                                                                                 --------          --------

Long-term Debt Excluding Portion Due Within One Year                              255,843           263,686
                                                                                 --------          --------

  TOTAL CAPITALIZATION                                                           $520,363          $518,860
                                                                                 ========          ========


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

</TABLE>
<PAGE>


WEST TEXAS UTILITIES COMPANY
Schedule of Long-term Debt
--------------------------------------------------



<PAGE>



First mortgage bonds outstanding were as follows:
                             December 31,
                         --------------------
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due
7-3/4  2007 - June 1     $ 25,000   $ 25,000
6-7/8  2002 - October 1    35,000     35,000
7      2004 - October 1    40,000     40,000
6-1/8  2004 - February 1   40,000     40,000
7-1/2  2000 - April 1        -        40,000
6-3/8  2005 - October 1    72,000     80,000
Unamortized Discount         (467)      (624)
                         --------   --------
                         $211,533   $259,376

         Certain  indentures  relating  to  the  first  mortgage  bonds  contain
improvement,  maintenance  and replacement  provisions  requiring the deposit of
cash or bonds with the trustee,  or in lieu thereof,  certification  of unfunded
property additions.

         Installment  purchase  contracts  have been entered into, in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:

                             December 31,
                           2000       1999
                           ----       ----
                            (in thousands)
% Rate Due
Red River Authority
 of Texas:
6      2020 - June 1      $44,310    $44,310
                          =======    =======




         Under the terms of the installment purchase contracts,  WTU is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated  maturities  and upon  mandatory  redemptions)  of related  pollution
control revenue bonds issued to finance the  construction  of pollution  control
facilities at certain plants.

         At December 31, 2000,  future  annual  long-term  debt  payments are as
follows:

                             Amount
                             ------
                         (in thousands)
2001                        $   -
2002                          35,000
2003                            -
2004                          80,000
2005                          72,000
Later Years                   69,310
                            --------
   Total                    $256,310
                            ========



<PAGE>




WEST TEXAS UTILITIES COMPANY
Index to Notes to Financial Statements
-----------------------------------------

The notes listed below are combined with the notes to financial  statements  for
AEP and its other subsidiary  registrants.  The combined footnotes begin on page
L-1.

                                                               Combined
                                                               Footnote
                                                               Reference


Significant Accounting Policies                                 Note 1

Extraordinary Items                                             Note 2

Merger                                                          Note 3

Rate Matters                                                    Note 5

Effects of Regulation                                           Note 6

Industry Restructuring                                          Note 7

Commitments and Contingencies                                   Note 8

Benefit Plans                                                   Note 12

Business Segments                                               Note 14

Financial Instrument, Credit and Risk Management                Note 15

Income Taxes                                                    Note 16

Lines of Credit and Factoring of Receivables                    Note 19

Unaudited Quarterly Financial Information                       Note 20

Jointly Owned Electric Utility Plant                            Note 22

Related Party Transactions                                      Note 23



<PAGE>


INDEPENDENT AUDITORS' REPORT
-----------------------------------------------


To the Shareholders and Board of
Directors of West Texas Utilities Company:

       We  have  audited  the  accompanying   balance  sheet  and  statement  of
capitalization  of West Texas Utilities Company as of December 31, 2000, and the
related  statements of income,  retained  earnings,  and cash flows for the year
then ended.  These financial  statements are the responsibility of the Company's
management.  Our  responsibility  is to express  an  opinion on these  financial
statements based on our audit.  The financial  statements of the Company for the
years ended December 31, 1999 and 1998, before the restatement described in Note
3 to the  financial  statements,  were audited by other  auditors  whose report,
dated February 25, 2000, expressed an unqualified opinion on those statements.

       We conducted our audit in accordance  with auditing  standards  generally
accepted in the United States of America.  Those standards  require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.   We  believe  that  our  audit  provides  a
reasonable basis for our opinion.

       In our opinion,  the 2000 financial  statements  present  fairly,  in all
material respects,  the financial position of West Texas Utilities Company as of
December 31, 2000,  and the results of its operations and its cash flows for the
year then ended in conformity with accounting  principles  generally accepted in
the United States of America.

       We also audited the adjustments  described in Note 3 that were applied to
restate the 1999 and 1998 financial statements to give retroactive effect to the
conforming change in the method of accounting for vacation pay accruals.  In our
opinion, such adjustments are appropriate and have been properly applied.



DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001

<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders and Board of Directors of
West Texas Utilities Company:

We have audited the accompanying balance sheets and statements of capitalization
of West  Texas  Utilities  Company  (a  Texas  corporation  and a  wholly  owned
subsidiary of Central and South West  Corporation)  as of December 31, 1999, and
the related  statement of income,  retained earnings and cash flows, for each of
the two years in the period  ended  December  31, 1999 prior to the  restatement
(and,  therefore,  are not presented  herein) for the retroactive  effect of the
conforming  change in the method of  accounting  for  vacation  pay accruals and
certain conforming  reclassifications  to the historical financial statements as
described  in  Note 3 to the  restated  financial  statements.  These  financial
statements are the responsibility of West Texas Utilities Company's  management.
Our responsibility is to express an opinion on these financial  statements based
on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable  assurance about whether the financial  statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting  the amounts and  disclosures in the financial  statements.  An audit
also includes assessing the accounting principles used and significant estimates
made by  management,  as well as  evaluating  the  overall  financial  statement
presentation.  We believe  that our audits  provide a  reasonable  basis for our
opinion.

In our opinion,  the financial  statements prior to the restatement  referred to
above present fairly, in all material  respects,  the financial position of West
Texas  Utilities  Company as of December 31, 1999, and results of its operations
and its cash flows for each of the two years in the period  ended  December  31,
1999, in conformity with accounting  principles generally accepted in the United
States.









Arthur Andersen LLP

Dallas, Texas
February 25, 2000

<PAGE>


                                      L-48
NOTES TO FINANCIAL STATEMENTS
-----------------------------------------------------------------------------

The notes to financial  statements that follow are a combined  presentation  for
AEP and its subsidiary  registrants.  The following list of footnotes  shows the
registrant to which they apply:

 1. Significant Accounting Policies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo,  PSO, SWEPCo, WTU

 2. Extraordinary Items             AEP, APCo, CPL, CSPCo, OPCo, SWEPCo, WTU

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

 4. Nuclear Plant Restart           AEP, I&M

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

 6. Effects of Regulation           AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    KPCo, OPCo, PSO, SWEPCo, WTU

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

 8. Commitments and Contingencies   AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo, PSO, SWEPCo, WTU

 9. Acquisitions                    AEP

10. International Investments       AEP

11. Staff Reductions                AEP, APCo, CSPCo, I&M, KPCo, OPCo

12. Benefit Plans                   AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo,
                                    PSO, SWEPCo, WTU

13. Stock Based Compensation        AEP

14. Business Segments               AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo, PSO, SWEPCo, WTU

15. Financial Instruments, Credit   AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
     and Risk Management            OPCo, PSO, SWEPCo, WTU

16. Income Taxes                    AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    KPCo, OPCo, PSO, SWEPCo, WTU

17. Supplementary Information       AEP, APCo, CSPCo, I&M, OPCo

18. Leases                          AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo

19. Lines of Credit                 AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
     and Commitment Fees            OPCo, PSO, SWEPCo, WTU

20. Unaudited Quarterly             AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
     Financial Information          OPCo, PSO, SWEPCo, WTU

21. Trust Preferred Securities      AEP, CPL, PSO, SWEPCo,


22. Jointly Owned Electric
     Utility Plant                  CPL, CSPCo, PSO, SWEPCo, WTU

23. Related Party Transactions      AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
                                    OPCo, PSO, SWEPCo, WTU



<PAGE>





1. Significant Accounting Policies:

Business  Operations - AEP's principal business conducted by its eleven domestic
electric  utility  operating  companies  is  the  generation,  transmission  and
distribution of electric power.  Nine of AEP's eleven domestic  electric utility
operating  companies,  APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,  WTU, are
SEC registrants. AEGCo is a domestic generating company wholly-owned by AEP that
is an SEC  registrant.  These  companies  are subject to  regulation by the FERC
under the Federal Power Act and follow the Uniform System of Accounts prescribed
by FERC.  They are subject to further  regulation with regard to rates and other
matters by state regulatory commissions.

Wholesale  marketing  and trading of  electricity  and gas is  conducted  in the
United  States and  Europe.  In  addition  AEP's  domestic  operations  includes
non-regulated  independent power and cogeneration  facilities and an intra-state
midstream natural gas operation in Louisiana.

AEP's  international  operations  include  regulated  supply and distribution of
electricity  and other  non-regulated  power  generation  projects in the United
Kingdom, Australia, Mexico, South America and China.

In addition to the above  energy  related  operations,  AEP is also  involved in
domestic  factoring of accounts  receivable,  investing in leveraged  leases and
providing  energy  services  worldwide  and   communications   related  services
domestically.

Rate  Regulation - The AEP System is subject to  regulation by the SEC under the
PUHCA.  The rates charged by the domestic  utility  subsidiaries are approved by
the FERC and the state utility commissions. The FERC regulates wholesale

electricity operations and transmission rates and the state commissions regulate
retail  generation  and  distribution  rates.  The  prices  charged  by  foreign
subsidiaries  located  in the  UK,  Australia,  China,  Mexico  and  Brazil  are
regulated by the


authorities of that country and are generally subject to price controls.

Principles of Consolidation - AEP's  consolidated  financial  statements include
AEP Co., Inc. and its wholly-owned and majority-owned  subsidiaries consolidated
with their wholly-owned subsidiaries.  The consolidated financial statements for
APCo,  CPL,  CSPCo,  I&M,  OPCo,  PSO and SWEPCo  include the registrant and its
wholly-owned  subsidiaries.  Significant  intercompany  items are  eliminated in
consolidation.  Equity  investments that are 50% or less owned are accounted for
using the equity method with their equity earnings included in Other Income, net
for AEP and nonoperating income for the registrant subsidiaries.

Basis of  Accounting - As  cost-based  rate-regulated  electric  public  utility
companies,  the  financial  statements  for  AEP  and  each  of  the  registrant
subsidiaries reflect the actions of regulators that result in the recognition of
revenues and expenses in different  time periods than  enterprises  that are not
rate  regulated.  In  accordance  with SFAS 71,  "Accounting  for the Effects of
Certain  Types  of  Regulation,"   regulatory  assets  (deferred  expenses)  and
regulatory  liabilities (deferred revenues) are recorded to reflect the economic
effects of regulation by matching expenses with their recovery through regulated
revenues.  Application of SFAS 71 for the generation portion of the business was
discontinued  as  follows:  in Ohio by OPCo and  CSPCo  in  September  2000,  in
Virginia  and West  Virginia  by APCo in June 2000,  in Texas by CPL,  WTU,  and
SWEPCo in September  1999 and in Arkansas by SWEPCo in September  1999. See Note
7, "Industry Restructuring" for additional information.

Use of Estimates - The preparation of these  financial  statements in conformity
with generally accepted accounting  principles requires in certain instances the
use of estimates and assumptions  that affect the reported amounts of assets and
liabilities  along with the disclosure of contingent  liabilities at the date of
financial  statements and the reported  amounts of revenues and expenses  during
the reporting period. Actual results could differ from those estimates.

Property,  Plant and Equipment - Domestic electric utility  property,  plant and
equipment are stated at original cost of the acquirer.  The property,  plant and
equipment of SEEBOARD,  CitiPower  and LIG are stated at their fair market value
at acquisition plus the original cost of property  acquired or constructed since
the acquisition,  less disposals.  Additions, major replacements and betterments
are  added to the plant  accounts.  For  cost-based  rate  regulated  operations
retirements  from the  plant  accounts  and  associated  removal  costs,  net of
salvage,  are  deducted  from  accumulated  depreciation.  The  costs of  labor,
materials and overheads  incurred to operate and maintain  plant are included in
operating expenses.

Allowance  for  Funds  Used  During  Construction  (AFUDC)  - AFUDC is a noncash
nonoperating income item that is capitalized and recovered through  depreciation
over the service life of domestic regulated electric utility plant. For domestic
regulated  electric  utility plant, it represents the estimated cost of borrowed
and equity funds used to finance construction projects. The amounts of AFUDC for
2000, 1999 and 1998 were not significant.  Effective with the  discontinuance of
the application of SFAS 71 regulatory  accounting for domestic generating assets
in  Arkansas,  Ohio,  Texas,  Virginia  and West  Virginia  and for AEP's  other
nonregulated   operations   interest  is  capitalized  during   construction  in
accordance  with SFAS 34,  "Capitalization  of  Interest  Costs." The amounts of
interest capitalized was not material in 2000, 1999, and 1998.

Depreciation,  Depletion and Amortization - Depreciation of property,  plant and
equipment is provided on a straight-line  basis over the estimated  useful lives
of property,  other than coal-mining property, and is calculated largely through
the use of composite rates by functional class as follows:

Functional Class           Annual Composite
of Property            Depreciation Rates Ranges
                                2000
Production:
  Steam-Nuclear            2.8% to  3.4%
  Steam-Fossil-Fired       2.3% to  4.5%
  Hydroelectric-
   Conventional
    and Pumped Storage     2.7% to  3.4%
Transmission               1.7% to  3.1%
Distribution               3.3% to  4.2%
Other                      2.5% to 20.0%

Functional Class           Annual Composite
of Property            Depreciation Rates Ranges
                                1999
Production:
  Steam-Nuclear            2.8% to  3.4%
  Steam-Fossil-Fired       3.2% to  5.0%
  Hydroelectric-
   Conventional
    and Pumped Storage     2.7% to  3.4%
Transmission               1.7% to  2.7%
Distribution               2.8% to  4.2%
Other                      2.0% to 20.0%

Functional Class           Annual Composite
of Property            Depreciation Rates Ranges
                                1998
Production:
  Steam-Nuclear            2.8% to  3.4%
  Steam-Fossil-Fired       3.2% to  4.4%
  Hydroelectric-
   Conventional
    and Pumped Storage     2.7% to  3.4%
Transmission               1.7% to  2.7%
Distribution               3.3% to  4.2%
Other                      2.5% to 20.0%



<PAGE>


The following table provides the annual composite  depreciation  rates generally
used by the AEP registrant  subsidiaries for the years 2000, 1999 and 1998 which
were as follows:

                    Nuclear  Steam  Hydro  Transmission  Distribution  General

AEGCo                - %     3.5%    - %       - %           - %       2.8%
APCo                 -       3.4    2.9       2.2           3.3        3.2
CPL                 2.8      2.3     -        2.3           3.5        4.2
CSPCo                -       3.2     -        2.3           3.6        3.3
I&M                 3.4      4.5    3.4       1.9           4.2        3.8
KPCo                 -       3.8     -        1.7           3.5        2.5
OPCo                 -       3.4    2.7       2.3           4.0        2.7
PSO                  -       2.7     -        2.3           3.4        6.4
SWEPCo               -       3.3     -        2.7           3.6        4.6
WTU                  -       2.7     -        3.1           3.3        6.8



<PAGE>


Depreciation,  depletion  and  amortization  of  OPCo's  coal-mining  assets  is
provided over each asset's  estimated  useful life or the estimated  life of the
mine, whichever is shorter, and is calculated using the straight-line method for
mining  structures  and  equipment.  The  units-of-production  method is used to
amortize coal rights and mine development  costs based on estimated  recoverable
tonnages at a current  average  rate of $5.07 per ton in 2000,  $2.32 per ton in
1999 and $1.85 per ton in 1998.  These  costs are  included  in the cost of coal
charged to fuel  expense.  See Note 5 "Rate  Matters"  regarding the closure and
possible sale of affiliated mines.

Cash and Cash  Equivalents - Cash and cash  equivalents  include  temporary cash
investments with original maturities of three months or less.

Inventory - Except for CPL, PSO and WTU, the domestic  utility  companies  value
fossil fuel inventories using a weighted average cost method.  CPL, PSO and WTU,
utilize the LIFO method to value fossil fuel  inventories.  SWEPCo  continues to
use the  weighted  average  cost method  pending  approval of its request to the
Arkansas Commission to utilize the LIFO method.  Natural gas inventories held by
LIG are marked-to-market.

Accounts Receivable - AEP Credit Inc. (formerly CSW Credit) factors accounts
receivable for the domestic utility  subsidiaries,  except
APCo, and unaffiliated companies.


Foreign Currency  Translation - The financial statements of subsidiaries outside
the U.S.  which are  included in AEP's  consolidated  financial  statements  are
measured using the local currency as the functional currency and translated into
U.S. dollars in accordance with SFAS 52 "Foreign Currency  Translation".  Assets
and liabilities are translated to U.S. dollars at year-end rates of exchange and
revenues  and  expenses  are  translated  at  monthly  average   exchange  rates
throughout the year. Currency translation gain and loss adjustments are recorded
in shareholders'  equity as "Accumulated Other Comprehensive Income (Loss)". The
non-cash  impact of the changes in exchange  rates on cash,  resulting  from the
translation of items at different  exchange rates is shown on AEP's Consolidated
Statement  of Cash Flows in "Effect of  Exchange  Rate  Change on Cash."  Actual
currency transaction gains and losses are recorded in income.

Energy Marketing and Trading  Transactions - The AEP System engages in wholesale
electricity  and  natural  gas  marketing  and  trading  transactions   (trading
activities).  Trading  activities  involve  the sale of  energy  under  physical
forward  contracts  at fixed  and  variable  prices  and the  trading  of energy
contracts  including  exchange  traded  futures  and  options,  over-the-counter
options and swaps. The majority of these transactions represent physical forward
electricity   contracts  in  AEP's   traditional   marketing  area  (up  to  two
transmission  systems from AEP's service territory) and are typically settled by
entering into offsetting contracts.  The net revenues from these transactions in
AEP's traditional marketing area are included in revenues from domestic electric
utility operations on AEP's consolidated statements of income.

The AEP System also purchases and sells electricity and gas options, futures and
swaps,  and enters into forward  purchase  and sale  contracts  for  electricity
(outside its traditional  marketing area) and gas. These transactions  represent
non-regulated  trading  activities  that are included in revenues from worldwide
electric and gas operations on AEP's consolidated statements of income.

All of the registrant  subsidiaries except AEGCo participate in the AEP System's
wholesale marketing and trading of electricity.  APCo, CSPCo, I&M, KPCo and OPCo
record  revenues  from  trading of  electricity  net of  purchases  as operating
revenues for forward electricity trades in AEP's traditional  marketing area and
as nonoperating  income for forward  electricity  trades beyond two transmission
systems from AEP and for speculative financial  transactions  (options,  futures
and swaps). CPL, PSO, SWEPCo and WTU record revenues from trading of electricity
net of purchases as operating revenues.

The AEP System  follows  EITF 98-10 and EITF 00-17,  "Accounting  for  Contracts
Involved in Energy Trading and Risk  Management  Activities"  and "Measuring the
Fair Value of Energy-Related  Contracts in Applying Issue 98-10",  respectively.
EITF 98-10 requires that all energy trading contracts be  marked-to-market.  The
effect  on AEP's  consolidated  statements  of income of  marking  open  trading
contracts to market in the  regulated  jurisdictions  are deferred as regulatory
assets or liabilities for those open  electricity  trading  transactions  within
AEP's marketing area that are included in cost of service on a settlement  basis
for  ratemaking  purposes.  Non-regulated  jurisdictions  with open  electricity
trading  transactions  within  AEP's  marketing  area are  marked-to-market  and
included in domestic electric utility operations  revenues on AEP's consolidated
statements of income. Non-regulated and regulated jurisdictions open electricity
trading contracts outside the traditional  marketing area are accounted for on a
mark-to-market  basis and  included in  worldwide  electric  and gas  operations
revenues on AEP's consolidated  statements of income. Open gas trading contracts
are accounted for on a mark-to-market  basis and included in worldwide  electric
and gas operations on AEP's consolidated statements of income.

APCo, CSPCo and OPCo account for open forward electricity trading contracts on a
mark-to-market basis and include the mark-to-market  change in revenues for open
contracts in AEP's  traditional  marketing area and in  nonoperating  income for
open contracts beyond AEP's traditional marketing area.

I&M and KPCo  account  for  open  forward  electricity  trading  contracts  on a
mark-to-market basis and defer the mark-to-market change as regulatory assets or
liabilities  for those open  contracts in AEP's  traditional  marketing area and
include the  mark-to-market  change in  nonoperating  income for open  contracts
beyond AEP's traditional marketing area.

CPL, PSO, SWEPCo and WTU account for open forward  electricity trading contracts
on a  mark-to-market  basis.  CPL  includes the  mark-to-market  change for open
electricity  trading  contracts in revenues.  PSO defers as regulatory assets or
liabilities  the  mark-to-market  change for open  forward  electricity  trading
contracts  that are  included  in cost of  service  on a  settlement  basis  for
ratemaking  purposes.  SWEPCo and WTU  include the  jurisdictional  share of the
mark-to-market  change in revenues for open  electricity  trading  contracts for
those  jurisdictions  that are not subject to SFAS 71 cost based rate regulation
and defer as regulatory  assets or liabilities the  jurisdictional  share of the
mark-to-market change for open contracts that are included in cost of service on
a settlement basis for ratemaking purposes.

Unrealized  mark-to-market  gains  and  losses  from all  trading  activity  are
reported as assets and liabilities, respectively.


Hedging and Related  Activities - In order to mitigate the risks of market price
and  interest  rate  fluctuations,  AEP's  foreign  subsidiaries,  SEEBOARD  and
CitiPower, utilize interest swaps, currency swaps and forward contracts to hedge
such  market  fluctuations.  Changes  in the  market  value of these  swaps  and
contracts  are  deferred  until the gain or loss is realized  on the  underlying
hedged asset, liability or commodity.  To qualify as a hedge, these transactions
must be  designated  as a hedge and  changes in their fair value must  correlate
with changes in the price and interest  rate movement of the  underlying  asset,
liability or commodity.  This in effect reduces AEP's exposure to the effects of
market fluctuations related to price and interest rates.

AEP, APCo,  CSPCo,  I&M, and OPCo enter into contracts to manage the exposure to
unfavorable  changes in the cost of debt to be issued.  These  anticipatory debt
instruments  are entered  into in order to manage the change in  interest  rates
between  the time a debt  offering  is  initiated  and the  issuance of the debt
(usually  a period of 60 days).  Gains or losses  from  these  transactions  are
deferred and amortized over the life of the debt issuance with the  amortization
included in interest charges.  There were no such forward contracts  outstanding
at December 31, 2000 or 1999. See Note 15 - "Financial  Instruments,  Credit and
Risk  Management"  for further  discussion of the accounting for risk management
transactions.

Revenues  and Fuel  Costs - Domestic  revenues  include  the  accrual of service
provided but un-billed at month-end as well as billed revenues. The cost of fuel
consumed  is  charged  to  expense  as  incurred.   Under  governing  regulatory
com-mission retail rate orders, any resulting fuel cost over or under-recoveries
are deferred as regula-tory  liabilities or regulatory assets in accordance with
SFAS 71. These deferrals  generally are billed or refunded to customers in later
months with the regulator's review and approval.  Wholesale  jurisdictional fuel
cost  increases and decreases  over amounts  included in base rates are expensed
and  billed  as  incurred.  See  Note 5  "Rate  Matters"  and  Note 7  "Industry
Restruct-uring"  for further  information  about fuel recovery.  Levelization of
Nuclear  Refueling  Outage  Costs - In  order  to  match  costs  with  regulated
revenues,  which  include  outage  costs  on  a  normalized  basis,  incremental
operation and maintenance  costs associated with periodic  refueling  outages at
I&M's Cook Plant are deferred and amortized  over the period  beginning with the
commencement of an outage and ending with the beginning of the next outage.

Amortization  of Cook Plant  Deferred  Restart  Costs - Pursuant  to  settlement
agreements approved by the IURC and the MPSC to resolve all issues related to an
extended  outage of the Cook Plant,  I&M deferred  $200  million of  incremental
operation  and  maintenance  costs  during 1999.  The  deferred  amount is being
amortized  to expense on a  straight-line  basis over five years from January 1,
1999 to December 31, 2003.  I&M amortized $40 million in 1999 and 2000,  leaving
$120  million  as an  SFAS 71  regulatory  asset  at  December  31,  2000 on the
Consolidated Balance Sheets of AEP and I&M.

Income Taxes - The AEP System  follows the liability  method of  accounting  for
income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the
liability  method,   deferred  income  taxes  are  provided  for  all  temporary
differences  between the book cost and tax basis of assets and liabilities which
will  result  in a future  tax  consequence.  Where the  flow-through  method of
accounting for temporary  differences  is reflected in regulated  revenues (that
is,  deferred  taxes are not  included  in the cost of service  for  determining
regulated rates for electricity), deferred income taxes are recorded and related
regulatory  assets and liabilities are established in accordance with SFAS 71 to
match the regulated revenues and tax expense.

Investment  Tax Credits - Investment  tax credits have been  accounted for under
the  flow-through  method except where  regulatory  commissions  have  reflected
investment  tax  credits  in  the  rate-making  process  on  a  deferral  basis.
Investment tax credits that have been deferred are being amortized over the life
of the regulated plant investment.

Debt  and  Preferred  Stock  - Where  appropriate  gains  and  losses  from  the
reacquisition of debt used to finance domestic  regulated electric utility plant
are generally  deferred and amortized  over the remaining term of the reacquired
debt in accordance with their rate-making treatment.  If the debt is refinanced,
the  reacquisition  costs  attributable to the portions of the business that are
subject to cost based regulatory accounting under SFAS 71 are generally deferred
and amortized  over the term of the  replacement  debt  commensurate  with their
recovery in rates.  Gains and losses on the reacquisition of debt for operations
not subject to SFAS 71 are reported as a component of net income.

Debt discount or premium and debt issuances  expenses are deferred and amortized
over the term of the related debt,  with the  amortization  included in interest
charges.

Where rates are regulated  redemption premiums paid to reacquire preferred stock
of the  domestic  utility  subsidiaries  are  included  in paid-in  capital  and
amortized to retained  earnings  commensurate  with their recovery in rates. The
excess of par value over costs of  preferred  stock  reacquired  is  credited to
paid-in capital and amortized to retained earnings consistent with the timing of
its recovery in rates in accordance with SFAS 71.

Goodwill - The amount of acquisition  cost in excess of the fair value allocated
to tangible assets obtained  through an acquisition  accounted for as a purchase
combination  is  recorded  as  goodwill  on AEP's  consolidated  balance  sheet.
Amortization  of goodwill is on a  straight-line  basis  generally over 40 years
except for the portion of  goodwill  associated  with gas trading and  marketing
activities which is being amortized on a straight-line  basis over 10 years. The
recoverability  of  goodwill  (evaluated  on  undiscounted  operating  cash flow
analysis) is reviewed when events or changes in circumstances  indicate that the
carrying amount may exceed fair value.

Other Assets - Other assets on AEP's  consolidated  balance  sheet are comprised
primarily of nuclear decommissioning and spent nuclear fuel disposal trust funds
and licenses for CitiPower operating franchises.  Securities held in trust funds
for  decommissioning  nuclear  facilities  and for the disposal of spent nuclear
fuel are included in Other Assets at market value in  accordance  with SFAS 115,
"Accounting for Certain Investments in Debt and Equity  Securities."  Securities
in the trust  funds  have been  classified  as  available-for-sale  due to their
long-term purpose.  Under the provisions of SFAS 71, unrealized gains and losses
from  securities  in these trust funds are not  reported in equity but result in
adjustments to the liability account for the nuclear decommissioning trust funds
and to  regulatory  assets or  liabilities  for the spent  nuclear fuel disposal
trust funds in accordance with their treatment in rates.

Comprehensive  Income - Comprehensive  income is defined as the change in equity
(net  assets) of a business  enterprise  during a period from  transactions  and
other events and circumstances from non-owner  sources.  It includes all changes
in equity during a period except those resulting from  investments by owners and
distributions to owners.  There were no material  differences between net income
and  comprehensive  income for AEGCo,  APCo, CPL, CSPCo,  I&M, KPCo,  OPCo, PSO,
SWEPCo, and WTU.

Components  of Other  Comprehensive  Income - The following  table  provides the
components  that  comprise  the  balance  sheet  amount  in  Accumulated   Other
Comprehensive Income for AEP.

                               December 31,
   Components               2000    1999   1998
-------------------------------------------------
                                 (millions)
Foreign Currency
 Adjustments               $ (99)   $ 20   $ 33
Unrealized Losses
 on Securities               -       (20)   (20)
Minimum Pension
 Liability                    (4)     (4)    (6)
                           -----    ----   ----
                           $(103)   $ (4)  $  7
                           =====    ====   ====





Segment  Reporting - The AEP System has adopted  SFAS No.  131,  which  requires
disclosure of selected  financial  information by business  segment as viewed by
the chief operating decision-maker.  See Note 14 "Business Segments" for further
discussion and details regarding segments.

Common Stock  Options - AEP follows  Accounting  Principles  Board Opinion 25 to
account for stock options. Compensation expense is not recognized at the date of
grant,  because the  exercise  price of stock  options  awarded  under the stock
option  plan  equals the  market  price of the  underlying  stock on the date of
grant.

EPS - AEP's  basic  earnings  per share is  determined  based upon the  weighted
average number of common shares outstanding during the years presented.  Diluted
earnings per share for AEP is based upon the weighted  average  number of common
shares  and stock  options  outstanding  during the years  presented.  Basic and
diluted are the same in 2000, 1999 and 1998.

AEGCo,  APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, and WTU are wholly-owned
subsidiaries of AEP and are not required to report EPS.

Reclassification  - Certain  prior  year  financial  statement  items  have been
reclassified to conform to current year presentation.  Such reclassification had
no impact on previously reported net income.

2. Extraordinary Items:

Extraordinary  Items - Extraordinary  items were recorded for the discontinuance
of  regulatory  accounting  under  SFAS 71 for  the  generation  portion  of the
business  in the  Ohio,  Virginia,  West  Virginia,  Texas  and  Arkansas  state
jurisdictions.  See Note 7  "Industry  Restructuring"  for  descriptions  of the
restructuring  plans and related accounting  effects.  The following table shows
the  components  of the  extraordinary  items  reported  on  AEP's  consolidated
statements of income:

                                  Year Ended
                                  December 31,
                                 2000     1999
                                 ----     ----
                                 (in millions)
Extraordinary Items:
 Discontinuance of Regulatory
 Accounting for Generation:
  Ohio Jurisdiction
  (Net of Tax of $35 Million)   $(44)    $  -
  Virginia and West Virginia
   Jurisdictions (Inclusive of
   Tax Benefit of $8 Million)      9        -
  Texas and Arkansas
   Jurisdictions (Net of Tax
   of $5 Million)                 -         (8)
 Loss on Reacquired Debt
 (Net of Tax of $3 Million)       -         (6)
                                ----      ----

  Extraordinary Items           $(35)     $(14)
                                ====      ====

There were no extraordinary items in 1998.

3. Merger:

On June  15,  2000,  AEP  merged  with CSW so that  CSW  became  a  wholly-owned
subsidiary of AEP. Under the terms of the merger agreement,  approximately 127.9
million  shares  of AEP  Common  Stock  were  issued  in  exchange  for  all the
outstanding shares of CSW Common Stock based upon an exchange ratio of 0.6 share
of AEP Common Stock for each share of CSW Common Stock.  Following the exchange,
former  shareholders of AEP owned approximately 61.4 percent of the corporation,
while  former  CSW  shareholders   owned   approximately  38.6  percent  of  the
corporation.

The  merger was  accounted  for as a pooling of  interests.  Accordingly,  AEP's
consolidated  financial  statements give retroactive effect to the merger,  with
all  periods  presented  as if AEP and CSW had  always  been  combined.  Certain
reclassifications  have been made to conform the historical  financial statement
presentation of AEP and CSW.

The  following  table sets forth  revenues,  extraordinary  items and net income
previously  reported  by AEP  and  CSW and the  combined  amounts  shown  in the
accompanying financial statements for 1999 and 1998:

                     Year Ended December 31,
                   1999                   1998
                   ----                   ----
                          (in millions)
Revenues:
  AEP             $ 6,870               $ 6,358
  CSW               5,537                 5,482
                  -------               -------
  AEP After
   Pooling        $12,407               $11,840
                  =======               =======




                     Year Ended December 31,
                   1999                   1998
                   ----                   ----
                          (in millions)

Extraordinary Items:
  AEP                $ -                    $ -
  CSW                 (14)                    -
                     ----                   ---
  AEP After
   Pooling           $(14)                  $ -
                     ====                   ===

Net Income:
  AEP                $520                  $536
  CSW                 455                   440
  Conforming
   Adjustment          (3)                   (1)
                     ----                  ----
  AEP After Pooling  $972                  $975
                     ====                  ====

The  combined  financial  statements  include an  adjustment  to  conform  CSW's
accounting  for vacation pay accruals with AEP's  accounting.  The effect of the
conforming  adjustment  was to reduce net assets by $16 million at December  31,
1999 and  reduce net income by $3  million  and $1 million  for the years  ended
December 31, 1999 and 1998, respectively.

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

       Net Asset         Net Income Reductions
                                              -
      Reduction At      Year Ended December 31,
                        -----------------------
    December 31, 1999     1999           1998
    -----------------    ------         ------
      (in millions)         (in millions)

  CPL     $5.3            $0.7           $0.1
  PSO      2.8             1.1             -
  SWEPCo   4.5             0.5            0.1
  WTU      2.6             0.4            0.1

  In  connection  with the merger,  $203  million  ($180  million  after tax) of
  non-recoverable  merger costs were expensed by AEP through  December 31, 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 $45 million
  recoverable from ratepayers were deferred pursuant to state regulator approved
  settlement agreements. The deferred merger costs are being amortized over five
  to  eight  year  recovery  periods  depending  on the  specific  terms  of the
  settlement agreements,  with the amortization ($4 million for AEP for the year
  2000) included in depreciation and amortization expense.


The following table shows the deferred merger cost and  amortization  expense of
the applicable subsidiary registrants:

                                Amortization
                                Expense for the
        Merger Cost Deferral    Year Ended
        at December 31, 2000     December 31, 2000
        --------------------     -----------------
                       (in millions)

CPL           $15.7                   $1.3
I&M             7.6                    0.7
KPCo            2.7                    0.3
PSO             8.3                    0.5
SWEPCo          6.6                    0.5
WTU             4.6                    0.4

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 state settlement agreements provide for, among other things, a
sharing of net merger savings with certain  regulated  customers over periods of
up to eight years  through rate  reductions  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  settlement  agreement  results  in  rate
reductions  for Texas  customers  totaling  $221 million over a six-year  period
commencing  with the merger's  consummation.  The rate reduction was composed of
$84 million of net merger savings and $137 million to resolve issues  associated
with  CPL's,  SWEPCo's  and WTU's rate and fuel  reconciliation  proceedings  in
Texas.  Under  the  terms of the  settlement  agreement,  base  rates  cannot be
increased until three years after consummation of the merger.

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 Indiana  settlement extends the base rate freeze
in the Cook Plant extended outage settlement agreement until January 1, 2005 and
requires additional annual deposits of $6 million to the nuclear decommissioning
trust fund for the Indiana  jurisdiction  for the years 2001 through  2003. As a
result of an appeal of the Indiana settlement agreement by a consumer group, I&M
has not reflected the  reductions in Indiana  jurisdictional  customers'  bills.
Instead,  pending the result of the appeal, I&M recorded a liability ($1 million
at December 31, 2000) for the reduction due to its Indiana  customers  under the
settlement.

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 and prohibits a general increase in base rates or
other charges for three years following consummation of the merger. 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, prohibits an increase in Oklahoma base rates prior to January 1, 2003
and  requires an  application  to join an RTO be filed with FERC by December 31,
2001.

The Arkansas 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 and  prohibits a base rate increase
being effective prior to January 1, 2002.

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.  In addition,  the order capped base rates
for five  years  after the  consummation  of the  merger  (until  June 2005) and
required that benefits from off-system sales be shared with ratepayers.

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.
Most of the merger settlement agreements approved by the regulatory  commissions
require  the  electric  operating   companies  to  join  regional   transmission
organizations.  APCo,  CSPCo,  I&M,  KPCo,  OPCo and several other  unaffiliated
utilities  formed the Alliance RTO before the  consummation of the merger.  As a
condition  of FERC's  approval  of the  merger,  CPL,  PSO,  SWEPCo and WTU were
required to join an RTO prior to December 31, 2000 and to transfer the operation
and control of their  transmission  facilities to that RTO by December 15, 2001.
CPL and WTU are members of ERCOT.  PSO and SWEPCo are members of SPP.  ERCOT and
SPP are transmission  pooling  organizations in certain  geographic areas of the
U.S. whose goals include enhancement of bulk electric transmission  reliability.
The SPP has filed with FERC to be approved as an RTO. Due to the FERC's inaction
on  approving  the SPP RTO, in December  2000 PSO and SWEPCo filed with the FERC
requesting  an  extension  of time to join an RTO  until 75 days  following  the
FERC's approval of an RTO for the SPP service area. Initial filings to gain FERC
approval for the Alliance RTO were made and conditional  approval was granted by
the FERC. The Alliance RTO made compliance  filings as requested by the FERC and
these were  accepted  in January  2001.  Final FERC  approval  of the SPP RTO is
pending.

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 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.  In February 2001, AEP
announced the sale of Frontera, one of the plants required to be divested by the
settlement  agreements  approved by the FERC. 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 Texas  divestiture  cannot 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 for the years  ended
December 31, 1999 and 1998.

  4. Nuclear Plant Restart:

The restart of both units of I&M's Cook Plant was completed with Unit 2 reaching
100% power on July 5, 2000 and Unit 1  achieving  100% power on January 3, 2001.
Cook Plant is a 2,110 MW two-unit plant owned and operated by I&M under licenses
granted by the NRC. I&M shut down both units of the Cook Plant in September 1997
due to questions  regarding the operability of certain safety systems that arose
during a NRC architect engineer design inspection.

Settlement  agreements  in the Indiana and Michigan  retail  jurisdictions  that
address  recovery of Cook Plant related  outage costs were approved in 1999. The
IURC  approved a settlement  agreement  in March 1999 that  resolved all matters
related to the recovery of replacement  energy fuel costs and all outage/restart
costs and related  issues  during the  extended  outage of the Cook  Plant.  The
settlement   agreement  provided  for,  among  other  things,  the  deferral  of
unrecovered  fuel revenues  accrued  between  September 9, 1997 and December 31,
1999; the deferral of up to $150 million of restart  related  nuclear  operation
and  maintenance  costs in 1999 above the amount  included  in base  rates;  the
amortization   of  the  deferred  fuel  revenues  and  non-fuel   operation  and
maintenance  cost deferrals over a five-year  period ending December 31, 2003; a
freeze in base rates through December 31, 2003; and a fixed fuel recovery charge
through March 1, 2004. The regulatory  approved  deferrals were recorded in 1999
as a regulatory asset in accordance with SFAS 71.

In December 1999 the MPSC approved a settlement  agreement for two open Michigan
power supply cost recovery reconciliation cases that resolves all issues related
to the Cook Plant extended outage. The settlement agreement limits I&M's ability
to increase base rates and freezes the power supply cost  recovery  factor until
January  1,  2004;  permits  the  deferral  of up to  $50  million  in  1999  of
jurisdictional  non-fuel nuclear operation and maintenance expenses;  authorizes
the  amortization of power supply cost recovery  revenues accrued from September
9, 1997 to December 31, 1999 and non-fuel nuclear operation and maintenance cost
deferrals  over a five-year  period  ending  December 31, 2003.  The  regulatory
approved deferrals were recorded in the fourth quarter of 1999.

The amounts of restart costs charged to other operation and maintenance expenses
were as follows:

                          Year Ended December 31,
                          2000     1999      1998
                          ----     ----      ----

Costs Incurred            $297    $ 289       $78
Deferred Pursuant to
 Settlement Agreements      -      (200)        -
Amortization of Deferrals   40       40         -
                          ----    -----       ---

Charged to O&M Expense    $337    $ 129       $78
                          ====    =====       ===

At December 31, 2000 and 1999,  deferred  restart costs of $120 million and $160
million,  respectively,  remained in regulatory  assets to be amortized  through
2003. Also pursuant to the settlement agreements,  accrued fuel-related revenues
of $38 million and $37 million in 2000 and 1999,  respectively,  were amortized.
At December  31, 2000 and 1999,  fuel-related  revenues of $113 million and $150
million, respectively,  were included in regulatory assets and will be amortized
through December 31, 2003 for both jurisdictions.

The  amortization  of restart costs and  fuel-related  revenues  deferred  under
Indiana and Michigan retail jurisdictional  settlement agreements will adversely
affect  results of operations  through  December 31, 2003 when the  amortization
period ends. The annual  amortization of restart cost and  fuel-related  revenue
deferrals is $78 million.

5. Rate Matters:

Texas  Jurisdictional  Fuel Filings - AEP's Texas electric  operating  companies
(CPL, SWEPCo and WTU) have been experiencing  significant 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 these under-recoveries.

CPL Fuel  Filings  - In July  2000 CPL  filed  with the PUCT an  application  to
implement an increase in fuel factor revenues  effective with the September 2000
billing month. Additionally, CPL proposed to implement an interim fuel surcharge
to collect its under-recovered fuel costs, including accumu-lated interest, over
a twelve-month period begin-ing in October 2000.

In September 2000 the PUCT approved a settlement. The settlement provided for an
increase in fuel factor  revenues of $173.5 million  annually and provided for a
two-phase  surcharge  totaling  $86.4  million.  The recovery of the first phase
surcharge of $21.3 million for previously  under-recovered  fuel costs including
accumulated  interest for the period from  December 1, 1999 through May 31, 2000
was  authorized to be collected in September  through  December 2000. The second
surcharge was not to exceed $65.1 million for projected under-recoveries for the
period from June 2000  through  August 2000 and was  authorized  to be collected
January through  September  2001. A September 2000 compliance  filing showed the
actual under-recovery for June 2000 through August 2000 to be $93.7 million. The
remaining under-recovery amount of $28.6 was carried forward into a January 2001
filing.

In January 2001 CPL filed with the PUCT an  application to implement an increase
in fuel factors of $175.9  million,  effective with the March 2001 billing month
over the ten months March 2001 through December 2001. Additionally, CPL proposed
to implement an interim fuel surcharge of $51.8 million,  including  accumulated
interest,  over a  nine-month  period  beginning  in April 2001 to  collect  its
under-recovered fuel costs. Approval by the PUCT is pending.

SWEPCo Fuel Filings - In November 2000 SWEPCo filed with the PUCT an application
for authority to implement an increase in fuel factor  revenues  effective  with
the January 2001  billing  month.  SWEPCo also  proposed to implement an interim
fuel surcharge to collect its under-recovered fuel costs,  including accumulated
interest, over a six-month period beginning in January 2001.

In January  2001 the PUCT  approved  SWEPCo's  application.  The order allows an
increase in fuel factors of $12 million on an annual basis including accumulated
interest  beginning  in January  2001 and a surcharge  of $11.8  million for the
billing months of February through July 2001.

In June  2000  SWEPCo  filed  with  the PUCT an  application  for  authority  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.

On December 27, 2000, SWEPCo reached a settlement.  The settlement resulted in a
reduction of $2.25 million of eligible Texas jurisdictional fuel expense,  which
was prorated equally over thirty-six months of the  reconciliation  period.  The
settlement also provides that depreciation and lease expense associated with new
aluminum  railcars  will  qualify for  treatment  as eligible  fuel expense from
January  1, 2000  forward.  Parties to the  settlement  will  support  SWEPCo in
seeking  to amend its 1999  excess  earnings  report  to  include  1999  railcar
depreciation  expense  in the  depreciation  component  of the  calculation.  In
February 2001, the PUCT approved the  settlement,  which did not have a material
effect on SWEPCo's results of operations.

WTU Fuel  Filings - 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 from August 1, 1999 through June 30, 2000
including  accumulated  interest,  over a six-month period beginning in November
2000.

In December  2000,  the PUCT  approved  WTU's  application.  The order allows an
increase  in  fuel  factors  of  $42.6  million  on an  annual  basis  including
accumulated  interest  and  provides  for  a  surcharge  of  $19.6  million  for
previously under-recovered fuel costs.

In  January  2001 WTU  filed  with  the PUCT an  application  for  authority  to
implement an increase in fuel factor  revenues of $46.5 million  effective  with
the March 2001 billing. Approval by the PUCT is pending.

In  December  2000 WTU  filed  with the PUCT an  application  for  authority  to
reconcile fuel costs.  During the reconciliation  period of July 1, 1997 through
June 30, 2000, WTU incurred $348 million of Texas jurisdiction eligible fuel and
fuel-related expenses. Approval by the PUCT is pending.

OPCo's  Recovery  of  Fuel  Costs -  Pursuant  to  PUCO -  approved  stipulation
agreements  the cost of coal  burned at the Gavin Plant was subject to a 15-year
predetermined  price of $1.575  per  million  Btu's  with  quarterly  escalation
adjustments  through November 2009. To the extent the actual cost of coal burned
at the Gavin Plant was below the predetermined prices, the stipulation agreement
provided  OPCo  with  the   opportunity  to  recover  over  its  term  the  Ohio
jurisdictional  share of OPCo's  investment  in and the  liabilities  and future
shutdown costs of its affiliated  mines as well as any fuel costs incurred above
the  pre-determined  rate and deferred for future recovery under the agreements.
As a result of the Ohio Act  introducing  customer  choice and a  transition  to
market  based  pricing  for  electricity   supply  in  Ohio,  these  stipulation
agreements  were  superseded  effective  January 1, 2001.  OPCo filed  under the
provisions  of the  Ohio  Act  for  recovery  of all of its  generation  related
regulatory assets including fuel costs deferred under these  predetermined price
stipulation  agreements.  Under  the terms of  OPCo's  PUCO-approved  stipulated
transition plan,  recovery of  generation-related  regulatory assets at December
31, 2000, which were $518 million, over seven years was approved.

The Muskingum  coal strip mine and Windsor deep coal mine which  supplied all of
their  output to OPCo have been  closed.  Efforts  are  underway  to reclaim the
properties,  sell or scrap all mining  equipment,  terminate  both  capital  and
operating  leases and perform other  activities  necessary to reclaim the mines.
Mine  reclamation  activities  should be  completed  within two to three  years;
postremediation  monitoring  is  anticipated  to  continue  for five years after
completion of reclamation.

OPCo currently plans to close the Meigs deep coal mine by the end of 2001 unless
ongoing efforts to sell it are successful.  Currently  efforts are being made to
sell the active Meigs and shutdown Windsor and Muskingum mines.

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

On July 9, 1996,  the AEP System  companies  filed an Open  Access  Transmission
Tariff conforming with the FERC's pro-forma  transmission tariff, subject to the
resolution of certain pricing issues. The 1996 tariff incorporated  transmission
rates which were the result of a settlement  of a pending  rate case,  but which
were being  collected  subject to refund from certain  customers who opposed the
settlement and continued to litigate the  reasonableness  of AEP's  transmission
rates.  On July 30, 1999,  the FERC issued an order in the  litigated  rate case
that would reduce AEP's rates for the affected  customers  below the  settlement
rate.  AEP  and  certain  of the  affected  customers  sought  rehearing  of the
Commission's Order.

On December 10, 1999,  AEP filed a settlement  agreement with the FERC resolving
the issues on rehearing of the July 30, 1999 order.  On March 16, 2000, the FERC
approved the settlement agreement. Under terms of the settlement, the AEP System
is  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. APCo,  CSPCo,  I&M, KPCo, and
OPCo  recorded  provisions  in 1999  and  2000 for the  earnings  impact  of the
required refunds including interest.

The settlement agreement also reduced the rates for transmission  service. 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. Since the rate has
been reduced the volume of  transmission  usage has  increased on the AEP System
mainly due to increased competition in the wholesale electricity market.

West Virginia

On May 12, 1999,  APCo, an AEP  subsidiary  doing business in WV, filed with the
WVPSC for a base rate  increase of $50 million  annually and a reduction in ENEC
rates of $38 million  annually.  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 continued
suspension  of annual  ENEC  recovery  proceedings  and  cessation  of  existing
deferral  accounting for all over or under recovery of fuel and purchased  power
costs net of system sales  effective  January 1, 2000; and the  retention,  as a
regulatory   liability,   on  the  books  of  a  net  cumulative  deferred  ENEC
overrecovery  balance of $66 million as established by a WVPSC order on December
27,  1996.  The  Joint  Stipulation  also  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  restructuring  and deregulation of APCo's
generation business 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 through 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 generation 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 overrecovery 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  adjustment  provisions in
the  Joint  Stipulation  and  the  0.5  mills  per KWH  wires  charge  in the WV
Restructuring  Plan (see Note 7 "Industry  Restructuring"  for  discussion of WV
Restructuring  Plan).  On June 2, 2000, the WVPSC issued an order  approving the
Joint Stipulation.  Management  expects that the stipulation  agreement plus the
provisions of pending restructuring legislation will, if the legislation becomes
effective,  provide  for the  recovery  of  existing  regulatory  assets,  other
stranded costs and the cost of such deregulation in WV.

6. Effects of Regulation:

In  accordance  with  SFAS  71 the  consolidated  financial  statements  include
regulatory  assets  (deferred  expenses) and  regulatory  liabilities  (deferred
revenues)  recorded  in  accordance  with  regulatory  actions in order to match
expenses and  revenues  from  cost-based  rates in the same  accounting  period.
Regulatory  assets are expected to be recovered  in future  periods  through the
rate-making  process and  regulatory  liabilities  are expected to reduce future
cost  recoveries.  Among other things,  application of SFAS 71 requires that the
AEP System's regulated rates be cost-based and the recovery of regulatory assets
probable.  Management  has  reviewed all the evidence  currently  available  and
concluded  that the  requirements  to apply SFAS 71  continue  to be met for all
electric  operations in Indiana,  Kentucky,  Louisiana,  Michigan,  Oklahoma and
Tennessee.

When the generation portion of the business in Arkansas,  Ohio, Texas,  Virginia
and WV no longer met the  requirements  to apply SFAS 71, net regulatory  assets
were written off for that portion of the business unless they were determined to
be recoverable as a stranded cost through regulated  distribution  rates or wire
charges in accordance with SFAS 101 "Regulated  Enterprises - Accounting for the
Discontinuation  of FASB  Statement No. 71" and EITF 97-4  "Deregulation  of the
Pricing  of  Electricity  - Issues  Related to the  Application  of FASB No. 71,
Accounting  for the  Effects  of  Certain  Types  of  Regulation,  and No.  101,
Regulated Enterprises - Accounting for the Discontinuation of the Application of
FASB  Statement  No.  71."  In  the  Ohio,  Virginia  and WV  jurisdictions  the
generation-related  regulated  assets that are  recoverable  through  transition
rates have been transferred to the distribution  portion of the business and are
being amortized as they are recovered through charges to regulated  distribution
customers. In the Texas jurisdiction  generation-related  regulatory assets that
have been  tentatively  approved for recovery through  securitization  have been
classified as "regulatory  assets  designated for  securitization."  (See Note 7
"Industry Restructuring" for further details.)

AEP's  recognized  regulatory  assets  and  liabilities  are  comprised  of  the
following at:

                                December 31,
                              2000       1999
                               (in millions)
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes   $  914    $1,450
  Transition - Regulatory
   Assets                       963      -
  Regulatory Assets
  Designated for
   Securitization               953       953
  Deferred Fuel Costs           407       477
  Unamortized Loss on
   Reacquired Debt              113       154
  Cook Plant Restart Costs      120       160
  DOE Decontamination and
   Decommissioning
    Assessment                   35        39
  Other                         193       231
                             ------    ------
Total Regulatory Assets      $3,698    $3,464
                             ======    ======

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                 $528      $580
  Other                         208       315
                               ----      ----
Total Regulatory Liabilities   $736      $895
                               ====      ====



<PAGE>


The recognized regulatory assets and liabilities for the registrant
subsidiaries are comprised of the following at:
<TABLE>
<CAPTION>

                                  AEGCo      APCo         CPL         CSPCo       I&M
                                ---------------------------------------------------------
December 31, 2000                                   (in thousands)
Regulatory Assets:
  Amounts Due From Customers
<S>                                        <C>         <C>          <C>         <C>
   For Future Income Taxes                 $217,540    $  206,930   $ 31,853    $229,466
  Transition - Regulatory Assets            191,469                  247,852
  Excess Earnings                                         (39,700)
  Regulatory Assets Designated
   For Securitization                                     953,249
  Deferred Fuel Costs                        14,669       127,295                112,503
  Unamortized Loss on
   Reacquired Debt                $5,504     11,676        12,773      8,340      17,740
  Deferred Storm Damage                       1,244
  Cook Plant Restart Costs                                                       120,000
  DOE Decontamination and
   Decommissioning Assessment                               3,622                 31,744
  Other                                      11,152        18,815      3,508      40,687
                                  ------   --------    ----------   --------    --------
Total Regulatory Assets           $5,504   $447,750    $1,282,984   $291,553    $552,140
                                  ======   ========    ==========   ========    ========

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                   $59,718   $ 43,093      $128,100    $41,234    $113,773
  Amounts Due To Customers
   For Future Income Taxes        23,996
  WV Rate Stabilization                      75,601
  Other                                       2,614                   11,510       9,930
                                 -------   --------      --------    -------    --------
Total Regulatory Liabilities     $83,714   $121,308      $128,100    $52,744    $123,703
                                 =======   ========      ========    =======    ========


                                  KPCo      OPCo        PSO        SWEPCo       WTU
                                ------------------------------------------------------
December 31, 2000                                (in thousands)
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes      $85,926   $180,602                $14,558
  Transition - Regulatory Assets           517,851
  Deferred Fuel Costs                                 $43,267      35,469     $67,655
  Unamortized Loss on
   Reacquired Debt                  459      6,106     13,600      22,626      11,204
  Other                          12,130     10,151     15,738      19,898      13,604
                                -------   --------    -------     -------     -------
Total Regulatory Assets         $98,515   $714,710    $72,605     $92,551     $92,463
                                =======   ========    =======     =======     =======

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                  $11,656    $25,214    $35,783     $53,167     $24,052
  Excess Earnings                                                     500      15,100
  Amounts Due To Customers
   For Future Income Taxes                             28,652                  13,493
  Other                           3,172     10,994      2,015       8,140
                                -------    -------    -------     -------     --------
Total Regulatory Liabilities    $14,828    $36,208    $66,450     $61,807     $52,645
                                =======    =======    =======     =======     =======



<PAGE>


                                  AEGCo     APCo          CPL        CSPCo       I&M
                                 ------------------------------------------------------
December 31, 1999                                  (in thousands)
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes                $389,922     $212,364    $243,031   $236,783
  Excess Earnings                                       (18,400)
  Regulatory Assets -
   Designated For Securitization                        953,249
  Deferred Fuel Costs                                    30,423                150,004
  Unamortized Loss on
   Reacquired Debt                $5,744    20,828       13,983      23,307     14,780
  Deferred Zimmer Plant
   Carrying Charges                                                  42,826
  Deferred Storm Damage                      6,619
  Cook Plant Restart Costs                                                     160,000
  DOE Decontamination and
   Decommissioning Assessment                             4,022                 35,238
  Other                                     19,525       11,390      29,939     28,005
                                  ------  --------   ----------    --------   --------
Total Regulatory Assets           $5,744  $436,894   $1,207,031    $339,103   $624,810
                                  ======  ========   ==========    ========   ========

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                   $63,114  $ 57,259   $  133,306    $ 44,716   $121,627
  Amounts Due To Customers
   For Future Income Taxes        26,266
  50% Share - Net WV ENEC                   36,589
  Over Recovery - Fuel Costs                34,676
  Deferred Gains From Emission
    Allowance Sales                          1,867                   13,539
  Other                                      7,180                   24,082     17,238
                                 -------  --------    ---------    --------   --------
Total Regulatory Liabilities     $89,380  $137,571    $ 133,306    $ 82,337   $138,865
                                 =======  ========    =========    ========   ========


                                 KPCo       OPCo        PSO        SWEPCo       WTU
                                -----------------------------------------------------
December 31, 1999                                (in thousands)
Regulatory Assets:
  Amounts Due From Customers
   For Future Income Taxes      $88,764   $331,164                $ 7,128
  Deferred Fuel Costs                      197,631     $6,469                 $14,652
  Unamortized Loss on
   Reacquired Debt                  711     15,666     14,880      25,539      14,700
  Other                           6,821     49,924      1,837      14,513      15,045
                                -------   --------    -------     -------     -------
Total Regulatory Assets         $96,296   $594,385    $23,186     $47,180     $44,397
                                =======   ========    =======     =======     =======

Regulatory Liabilities:
  Deferred Investment
   Tax Credits                  $12,908   $ 35,838    $37,574     $57,649     $25,323
  Excess Earnings                                                   6,500       6,000
  Amounts Due To Customers
   For Future Income Taxes                             32,826                  13,146
  Deferred Gains From Emission
   Allowance Sales                          53,738
  Other                           2,792     13,043                  2,480
                                -------   --------    -------     -------     -------
Total Regulatory Liabilities    $15,700   $102,619    $70,400     $66,629     $44,469
                                =======   ========    =======     =======     =======

</TABLE>

<PAGE>




7. Industry Restructuring:

Restructuring  legislation  has been enacted in seven of the eleven state retail
jurisdictions in which AEP's domestic  electric utility companies  operate.  The
legislation  provides for a transition  from  cost-based  regulation  of bundled
electric  service to unbundled  cost-based rate  regulation of transmission  and
distribution  service  and  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 APCo, CPL, CSPCo, OPCo, SWEPCo
and WTU to discontinue regulatory accounting for the generation portion of their
business in those  jurisdictions.  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 to account for the difference  between  regulatory  accounting and
GAAP 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
the deregulated operations,  unless recovery of such amounts is provided through
cost-based  regulated  rates to be collected in the 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.  If there is
any accounting impairment, it would be recorded on a discounted basis.

As  legislative  and  regulatory  proceedings  evolve,  the  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  the  restructuring
legislation,  the status of the transition  plans and the status of the electric
utility  operating  companies'  accounting to comply with the changes in each of
the seven state regulatory jurisdictions affected by restructuring legislation.

Ohio Restructuring - Affecting AEP, CSPCo and OPCo

Effective January 1, 2001,  customer choice of electricity  supplier began under
the Ohio Act. In February 2001, one supplier announced its plan to offer service
to CSPCo's residential  customers.  Currently for residential customers of OPCo,
no alternative  suppliers have  registered with the PUCO as required by the Ohio
Act. Two  alternative  suppliers  have been  approved to compete for CSPCo's and
OPCo's commercial and industrial customers.  Presently, customers continue to be
served  by  CSPCo  and  OPCo  with a  legislatively  required  residential  rate
reduction of 5% for the generation portion of rates and a freezing of generation
rates including fuel rates starting on January 1, 2001.

The Ohio Act provides for a five-year  transition period to move from cost based
rates to market  pricing  for  generation  services.  It granted  the PUCO broad
oversight  responsibility  for  promul-gation  of rules for  competitive  retail
electric  generation  service,  approval of a transition  plan for each electric
utility  company  and  addressing  certain  major  transition  issues  including
unbund-ling  of rates and the recovery of stranded  costs  including  regulatory
assets and transition costs.



The Ohio Act also  provides  for a reduction in property  tax  assessments,  the
imposition of replacement  franchise and income taxes,  and the replacement of a
gross  receipts tax with a KWH based  excise tax.  The  property tax  assessment
percentage  on  generation  property  was  lowered  from  100%  to 25% of  value
effective January 1, 2001 and Ohio electric utilities will become subject to the
Ohio Corporate  Franchise Tax and municipal income taxes on January 1, 2002. The
last year for which  Ohio  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
(May 1),  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.  As a result a duplicate  tax will be  expensed  from May 1,
2001 through  April 30, 2002 adding  approximately  $90 million ($40 million for
CSPCo and $50 million for OPCo) to tax expense during that period.  Unless CSPCo
and OPCo can recover the duplicate  amount from  ratepayers  it will  negatively
impact results of operations.

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  regarding  transition plans filed by CSPCo
and OPCo. The key provisions of this stipulation agreement are:

o    Recovery of generation-related  regulatory assets at December 31, 2000 over
     seven  years for OPCo ($518  million)  and over eight years for CSPCo ($248
     million)  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 five year transition period.
o    CSPCo's and OPCo's  request for a $90 million  gross  receipts tax rider to
     recover  the  duplicate  gross  receipts  KWH  based  excise  tax  would be
     considered separately by the PUCO.

The  approved  stipulation  agreement  also  accepted the  following  provisions
contained in CSPCo's and OPCo's filed transition plans:

o  a  corporate  separation  plan  to  segregate  generation,  transmission  and
distribution  assets into separate legal entities,  and o a plan for independent
operation of transmission facilities.

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 $90 million gross  receipts tax rider.  CSPCo's and OPCo's request
for  rehearing  of the gross  receipts  tax issue was denied.  An appeal of this
issue to the Ohio Supreme Court has been filed. Unless this issue is resolved in
CSPCo's and OPCo's favor,  it will have an adverse  effect on future  results of
operations and financial position.

One of the intervenors at the hearings for approval of the settlement  agreement
(whose  request  for  rehearing  was denied by the PUCO) has filed with the Ohio
Supreme  Court for review of the  settlement  agreement  including  recovery  of
regulatory assets. Management is unable to predict the outcome of litigation but
the resolution of this matter could negatively impact results of operation.

Beginning January 1, 2001,  CSPCo's and OPCo's fuel costs will not be subject to
PUCO fuel recovery  proceedings.  Deferred fuel costs at December 31, 2000 which
represent  under or over recoveries were one of the items included in the PUCO's
final determination of net regulatory assets to be collected  (recovered) 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 their future results of operations and cash flows.

CSPCo and OPCo Discontinue Application of SFAS 71 Regulatory Accounting 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 the Ohio 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 of the remaining net  regulatory  assets  related to the Ohio
generation business will be recovered under the PUCO's September 28, 2000 order.
Therefore,   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  transition  rates  to  customers.  CSPCo  and OPCo
performed an accounting  impairment  analysis on their  generating  assets under
SFAS 121 as required when discontinuing the application of SFAS 71 and concluded
there was no impairment of generation assets.
Virginia - Affecting AEP and APCo

In  Virginia,  a  restructuring  law  provides  for a  transition  to  choice of
electricity  supplier  for retail  customers  beginning  on January 1, 2002.  In
February 2001  restructuring  revision  legislation was approved by the Virginia
Legislature  which  could  modify  the terms of  restructuring.  Presently,  the
transition  period is to be completed,  subject to a finding by the Virginia SCC
that an effective competitive market exists by January 1, 2004 but no later than
January 1, 2005.

The  restructuring  law also  provides an  opportunity  for recovery of just and
reasonable net stranded generation costs. The mechanisms in the Virginia law for
net  stranded  cost  recovery  are: a capping of rates  until as late as July 1,
2007,  and the  application  of a wires  charge  upon  customers  who depart the
incumbent  utility in favor of an alternative  supplier prior to the termination
of the rate cap. The  restructuring law provides for the establishment of capped
rates prior to January 1, 2001 based either on a request by APCo for a change in
rates  prior to  January 1, 2001 or on the rates in effect at July 1, 1999 if no
rate  change  request  is made and the  establishment  of a wires  charge by the
fourth quarter of 2001. APCo did not request new rates;  therefore,  its current
rates are 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 to
review the  reasonableness of APCo's capped rates. The cost of service study was
filed on January 3, 2001. In the opinion of APCo's Virginia counsel,  Virginia's
restructuring  law does not  permit  the  Virginia  SCC to change  rates for the
transition period except for changes in the fuel factor,  changes in state gross
receipts taxes, or to address the utility's financial distress.  However, if the
Virginia SCC were to reduce  APCo's  capped rates or deny recovery of regulatory
assets,  it would  adversely  affect  results of  operations  if such  action is
ultimately determined to be legal.

The Virginia restructuring law also requires filings to be made that outline the
functional  separation of generation from  transmission  and  distribution and a
rate unbundling  plan. On January 3, 2001,  APCo filed its corporate  separation
plan and rate  unbundling  plan with the Virginia SCC which is based on the most
recent rate case test year (1996). See the heading "Structural Separation" below
in this footnote for a discussion of AEP's corporate  separation plan filed with
the SEC.

West Virginia - Affecting AEP and APCo

On  January  28,  2000,  the WVPSC  issued  an order  approving  an  electricity
restructuring  plan for WV. 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.  The Joint
Committee on Government and Finance of the WV Legislature  hired a consultant to
study and issue a report  on the tax  changes  required  to  implement  electric
restructuring.  Moreover,  the  committee  also hired a consultant  to study and
issue a report on the electric  restructuring  plan in light of events occurring
in  California.  The WV  Legislature  is not expected to consider  these reports
until the 2002 Legislative  Session since the 2001  Legislative  Session ends in
April 2001.  Since the WV  Legislature  has not yet passed the  required tax law
changes, the restructuring plan has not become effective. AEP subsidiaries, APCo
and WPCo, provide electric service in WV.

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 on the starting date; functional separation of the generation,
transmission  and  distribution  businesses on the starting date and their legal
corporate 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
a 10-year  period  commencing  with the  starting  date  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 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 are 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 5 "Rate Matters", 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 Regulatory Accounting

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 made  possible  by the June 2, 2000
approval of the Joint  Stipulation which  established  rates,  wires charges and
regulatory asset recovery  procedures for the transition  period to market rates
which  was  determined  to be  probable.  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  expected   probable  passage  of  required   enabling  tax
legislation in 2001 supported  management's decision in 2000 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  after  tax
extraordinary  gain, in the second  quarter of 2000,  of $9 million.  Management
believes  that it is  probable  that  substantially  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.  As  required  by SFAS  101  when  discontinuing  SFAS 71  regulatory
accounting,  APCo performed an accounting  impairment analysis on its generating
assets under SFAS 121 and concluded  that there was no accounting  impairment of
generation assets.

The studies  requested by the WV Legislature,  discussed above,  could result in
the WV  Legislature  deciding not to enact the  required  tax changes,  thereby,
effectively  continuing  cost based rate regulation in West Virginia or it could
modify the restructuring  plan.  Modifications in the  restructuring  plan could
adversely affect future results of operations if they were to occur.  Management
is carefully  monitoring  the  situation in West  Virginia and continues to work
with all concerned  parties to get approval to  successfully  transition  APCo's
generation business in West Virginia.  Failure to pass the required enabling tax
changes  could  ultimately  require  APCo  to  reinstate  regulatory  accounting
principles under SFAS 71 for its generation operations in West Virginia.

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 an annual  progress  report to the
Arkansas  General Assembly on the development of competition in electric markets
and its
     impact on retail customers is required.

In November 2000 the Arkansas  Commission  filed its annual progress report with
the Arkansas General  Assembly  recommending a delay in the start date of retail
competition  to a date between  October 1, 2003 and October 1, 2005.  The report
also asks the Arkansas  General  Assembly to delegate  authority to the Arkansas
Commission to determine the appropriate retail competition start date within the
approved  time frame.  In February  2001 the Arkansas  General  Assembly  passed
legislation  that was signed into law by the  Governor  that changes the date of
electric  retail  competition  to October 1, 2003,  and  provided  the  Arkansas
Commission with the authority to delay that date for up to two years.

Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU

In June 1999 Texas  restructuring  legislation was signed into law which,  among
other things:

o    gives Texas customers of investor-owned  utilities the opportunity to
     choose their electricity  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 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)  which  will  reduce   stranded  cost
     recoveries  or if there is no stranded  cost provides for a refund or their
     use to fund  certain  capital  expenditures  in the  amount  of the  excess
     earnings;
o    requires  each  utility  to  structurally  unbundle  into a  retail
     electric  provider,  a  power  generation  company  and a
     transmission and distribution utility;
o    provides for certain  limits for ownership and control of generating
     capacity by  companies;
o    provides  for  elimination  of the fuel clause  reconciliation
     process beginning January 1, 2002; and
o    provides for a 2004 true-up  proceeding to determine  recovery of stranded
     costs including final fuel recovery balances, net regulatory assets,
     certain environmental costs, accumulated excess earnings and other issues.

Under the Texas  Legislation,  delivery of  electricity  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,  and a  transmission  and  distribution
utility.  In May 2000 CPL,  SWEPCo and WTU filed a revised  business  separation
plan that the PUCT  approved  on July 7, 2000 in an interim  order.  The revised
business separation plans provided for CPL and WTU, which operate in Texas only,
to establish  separate  companies and divide their integrated utility operations
and assets into a power  generation  company,  a transmission  and  distribution
utility  and  a  retail  electric  provider.  SWEPCo  will  separate  its  Texas
jurisdictional  transmission and  distribution  assets and operations into a new
Texas regulated transmission and distribution subsidiary.  In addition, a retail
electric provider will be formed by SWEPCo to provide retail electric service to
SWEPCo's Texas jurisdictional customers.

Under the Texas Legislation,  electric utilities are allowed,  with the approval
of the PUCT, to recover stranded  generation costs including  generation-related
regulatory  assets that may not be recoverable in a future  competitive  market.
The approved stranded costs can be refinanced through securitization, which is a
financing structure designed to provide lower financing costs than are available
through conventional financings.  Lower financing costs are achieved through the
issuance of securitization bonds at a lower interest rate to finance 100% of the
costs  pursuant to a state pledge to ensure  recovery of the bond  principal and
financing  costs  through  a  non-bypassable  rate  surcharge  by the  regulated
transmission and distribution utility over the life of the securitization bonds.

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 March 27, 2000,  the PUCT
issued an order permitting 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
generation-related  regulatory  assets  and  $33  million  for  other  qualified
refinancing  costs.  The $764  million for  recovery  of net  generation-related
regulatory  assets  reflects the recovery of $949 million of  generation-related
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.  On April 11,  2000,  four  parties  appealed  the PUCT's
securitization  order to the  Travis  County  District  Court.  In July 2000 the
Travis  County  District  Court  upheld the  PUCT's  securitization  order.  The
securitization  order is being  appealed to the Supreme  Court of Texas.  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 remaining  regulatory assets of $206 million  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 property, plant and equipment-electric on AEP's
Consolidated  Balance Sheets and in electric utility  plant-production  on CPL's
Consolidated  Balance Sheets.  These STP costs had previously been identified as
excess  cost over market  (ECOM) by the PUCT for  regulatory  purposes  and were
earning a lower  return and were being  amortized  on an  accelerated  basis for
rate-making  purposes in Texas. The March 2000 filing will determine the initial
amount of stranded costs in addition to the securitized  regulatory assets to be
recovered beginning January 1, 2002.

CPL  submitted a revised  estimate  of  stranded  costs on October 2, 2000 using
assumptions  developed in generic  proceedings by the PUCT and an administrative
model  developed  by the PUCT  staff  that  reduced  the  amount of the  initial
stranded cost  estimate to $361 million from the $1.1 billion  requested by CPL.
CPL  subsequently  agreed to accept  adjustments  proposed by  intervenors  that
reduced ECOM to  approximately  $230 million.  Hearings on CPL's  requested ECOM
were held in October 2000. In February 2001 the PUCT issued an interim  decision
determining  an initial  amount of CPL ECOM or stranded  costs of negative  $580
million.  The  decision  indicated  that CPL's  costs were  below  market  after
securitization of regulatory assets. Management does not agree with the critical
inputs to this  model.  Management  believes  CPL has a positive  stranded  cost
exclusive of securitized  regulatory  assets. The final amount of CPL's stranded
costs  including  regulatory  assets and ECOM will be established by the PUCT in
the  legislatively  required 2004 true-up  proceeding.  If CPL's total  stranded
costs  determined  in the 2004  true-up are less than the amount of  securitized
regulatory  assets,  the PUCT can implement an offsetting credit to transmission
and distribution rates.

The PUCT ruled that prior to the 2004 true-up  proceeding,  no adjustments would
be  made  to the  amount  of  regulatory  costs  authorized  by the  PUCT  to be
securitized.  However,  the PUCT also ruled that excess  earnings for the period
1999-2001 should be refunded through  transmission and distribution rates to the
extent of any over-mitigation of stranded costs represented by negative ECOM. In
the event that CPL will be  required  to refund  excess  earnings  in the future
instead of applying them to reduce ECOM or regulatory  assets, it will adversely
affect future cash flow but not results of operations  since excess earnings for
1999 and 2000 were accrued and expensed in 1999 and 2000. The Texas  Legislation
allows for several alternative methods to be used to value stranded costs in the
final 2004  true-up  proceeding  including  the sale or exchange  of  generation
assets,  the issuance of power generation company stock to the public or the use
of PUCT staff's ECOM model. To the extent that the final 2004 true-up proceeding
determines that CPL should recover  additional  stranded costs, the total amount
recoverable can be securitized.

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 annual earnings
test calculation.

The 1999  earnings  test  reports  filed by CPL,  SWEPCo and WTU  showed  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.  The Office of Public Utility
Counsel also filed exceptions to the companies' earnings reports. Several issues
were resolved via settlement and the remaining open issues were submitted to the
PUCT. A final order was issued by the PUCT in February 2001 and  adjustments  to
the accrued 1999 and 2000 excess earnings were recorded in results of operations
in the fourth quarter of 2000.  After  adjustments  the accruals for 1999 excess
earnings for CPL and WTU were $24 million and $1 million,  respectively. CPL and
WTU also recorded an estimated provision for excess 2000 earnings of $16 million
and $14 million, respectively.

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  and
financial  reporting  purposes,  STP ECOM plant  assets will be  depreciated  in
accordance  with GAAP, on a systematic and rational basis unless  impaired.  CPL
will establish a regulatory liability or reduce regulatory assets by a charge to
earnings to the extent excess earnings exceed $20 million in 2000 and 2001.

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 to  reconcile  their fuel costs  through the
period ending  December 31, 2001. Fuel costs have been reconciled by CPL, SWEPCo
and  WTU  through  June  30,  1998,   December  31,  1999  and  June  30,  1997,
respectively.  WTU is currently  reconciling  its fuel  through  June 2000.  See
discussion in Note 5 "Rate Matters".  At December 31, 2000, CPL's,  SWEPCo's and
WTU's Texas jurisdictional unrecovered deferred fuel balances were $127 million,
$20 million and $59  million,  respectively.  Final  unrecovered  deferred  fuel
balances at December  31, 2001 will be included in each  company's  2004 true-up
proceeding.  If the final  fuel  balances  or any  amount  incurred  but not yet
reconciled  were not recovered,  they could have a negative impact on results of
operations.  The elimination of the fuel clause recoveries in 2002 in Texas will
subject AEP, CPL, SWEPCo and WTU to greater risks of fuel market price increases
and could adversely affect future results of operations beginning in 2002.

The affiliated  retail electric provider of CPL, SWEPCo and WTU will be required
to offer  residential and small commercial  customers (with a peak usage of less
than 1000 KW) a rate 6% below  rates in effect on January 1, 1999  adjusted  for
any changes in fuel cost recovery factors since January 1, 1999 (price to beat).
The price to beat must be offered to residential and small commercial  customers
until  January  1,  2007.  Customers  with a peak usage of more than 1000 KW are
subject to market rates. The Texas  restructuring  legislation  provides for the
price to beat to be  adjusted up to two times  annually  to reflect  significant
changes in fuel and purchased energy costs.

Discontinuance of the Application of SFAS 71 Regulatory Accounting in 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  wires  charges  to  customers.   Management   believes  that
substantially  all  of  CPL's  generation-related   regulatory  assets  will  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 through  securitization
of CPL's  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 Arkansas and Texas jurisdictional  generation-related  net regulatory assets
were written off as non-recoverable in 1999 when SWEPCo and WTU discontinued the
application of SFAS 71 regulatory accounting.  As required by SFAS 101 when SFAS
71 is  discontinued,  an accounting  impairment  analysis for generation  assets
under SFAS 121 was completed for CPL,  SWEPCo and WTU. The analysis  showed that
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 if circumstances change.  Management believes that
on a discounted  basis CPL's  generation  business net cash flows will likely 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 the balance  sheet at December  31, 2000,  $953 million of
generation-related  regulatory  assets already approved for  securitization  and
$195 million of net  generation-related  regulatory  assets pending approval for
securitization  in  Texas.  A  final  determination  of  whether  they  will  be
securitized and recovered will be made as part of the 2004 true-up proceeding.

CPL, SWEPCo, and WTU continue to analyze the impact of electric utility industry
restructuring  legislation  on their  Arkansas  and 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  regulatory  process is complete  following the 2004
true-up proceeding in Texas and a determination by the Arkansas  Commission.  In
the event CPL, SWEPCo,  and WTU are unable after the 2004 true-up proceeding and
after the Arkansas  Commission  proceedings 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.

Although  Arkansas' delay of retail  competition may be having a negative effect
on the  progress of efforts to  transition  SWEPCo's  generation  in Arkansas to
market based pricing of electricity,  it appears that Texas is moving forward as
planned.  Management  is carefully  monitoring  the situation in Arkansas and is
working  with  all  concerned  parties  to  prudently  quicken  the  pace of the
transition.  However,  changes  could  occur due to concerns  stemming  from the
California  energy crisis and other events which could  adversely  affect future
results of operations in Arkansas and possibly Texas.

Michigan Restructuring - Affecting AEP and I&M

On June 5, 2000,  the Michigan  Legislation  became law.  Its major  provisions,
which were effective  immediately,  applied only to electric  utilities with one
million or more retail customers. I&M, AEP's electric operating subsidiary doing
business  in  Michigan,  has  less  than  one  million  customers  in  Michigan.
Consequently,  I&M was not  immediately  required  to comply  with the  Michigan
Legislation.

The Michigan Legislation gives the MPSC broad power to issue orders to implement
retail  customer  choice of  electric  supplier  no later  than  January 1, 2002
including  recovery of regulatory assets and stranded costs. 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.  The plan contains a
proposed  methodology to determine stranded costs and  implementation  costs and
requests   the   continuation   of  a  wires  charge  for  recovery  of  nuclear
decommissioning  costs.  Approval of the  restructuring  implementation  plan is
pending before the MPSC.

Management has concluded that as of December 31, 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 of EITF 97-4 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 and record its
unrecorded Michigan jurisdictional  liability for decommissioning the Cook Plant
to the extent that they cannot be recovered under the transition rates and wires
charges.  As  required  by  SFAS  101  when  discontinuing  SFAS  71  regulatory
accounting,  I&M will have to perform an accounting  impairment  analysis  under
SFAS 121 to determine if the Michigan  jurisdictional  portion of its generating
assets are impaired for accounting purposes.

The amount of  regulatory  assets  recorded  on the books at  December  31, 2000
applicable  to I&M's  Michigan  retail  jurisdictional  generation  business  is
approximately $45 million before related tax effects.  The estimated  unrecorded
liability for the Michigan  jurisdiction to  decommission  the Cook Plant ranges
from $114  million to $215  million in 2000  non-discounted  dollars  based upon
studies  completed  during  2000.  For  the  Michigan   jurisdiction,   I&M  has
accumulated  approximately  $100 million in trust funds to decommission the Cook
Plant.  Based  on  the  current  information  available,   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 restructuring proceedings.


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,
de-commissioning obligations and 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,  unrecorded  decommissioning  obligation,
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  open  access by July 1, 2002.  That  legislation  called for a number of
studies to be  completed  on a variety of  restructuring  issues,  including  an
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.

The 2001 Oklahoma  legislative  session  convened in early February.  No further
electric  restructuring  legislation  has passed and proposals have been made to
delay the  implementation  of the transition to customer choice and market based
pricing under the restructuring legislation. If the necessary legislation is not
passed,  PSO's  generation  and retail  electric  supply  business  will  remain
regulated in Oklahoma. If implementation legislation were to modify the original
restructuring  legislation in Oklahoma it could have a adverse effect on results
of operations.

Management has concluded that as of December 31, 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.

When PSO discontinues  application of SFAS 71, it will be necessary to write off
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 and/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.






Structural Separation

On November 1, 2000, AEP, AEPSC,  APCo, CPL, CSPCo,  OPCo,  SWEPCo and WTU filed
with  the  SEC  for  approval  to  form  two  separate  legal  holding   company
subsidiaries  of AEP, the parent  company.  The purpose of these  entities is to
legally and functionally separate the competitive market business activities and
the  subsidiaries  performing  those  competitive  activities  from the business
activities  which are  cost-based  regulated and the  subsidiaries  that perform
those regulated activities. Corporate separation plans have also been filed with
regulatory  commissions  in  Arkansas,  Ohio,  Texas and Virginia to comply with
requirements specified in their restructuring legislation. The Texas Legislation
requires  separate  legal entities for  generation  and  distribution  assets by
January 1, 2002. AEP, APCo, CPL, CSPCo,  OPCo, SWEPCo and WTU will need approval
from the SEC under PUHCA, FERC and certain state regulatory  commissions to make
these organization changes.

8. Commitments and Contingencies:

Construction and Other Commitments - The AEP System has substantial construction
commitments to support its operations.  Aggregate construction  expenditures for
2001-2003 for consolidated  domestic and foreign  operations are estimated to be
$7 billion.

The  following  table  shows  the  estimated  construction  expenditures  of the
subsidiary registrants for 2001 - 2003:

                      (in millions)

AEGCo                   $    9.1
APCo                     1,164.3
CPL                        770.2
CSPCo                      422.2
I&M                        439.6
KPCo                       215.6
OPCo                     1,085.2
PSO                        310.8
SWEPCo                     413.1
WTU                        259.3




Long-term  contracts to acquire fuel for electric  generation  have been entered
into for various  terms,  the longest of which  extends to the year 2014 for the
AEP System.  The expiration  date of the longest fuel contract for APCo is 2006,
CSPCo is 2007, I&M is 2014, KPCo is 2003,  OPCo is 2012, PSO is 2014,  SWEPCo is
2006 and WTU is 2006. The contracts  provide for periodic price  adjustments and
contain  various  clauses  that  would  release  the  subsidiaries   from  their
obligations under certain force majeure conditions.

The AEP  System  has  contracted  to sell  approximately  1,174  MW of  capacity
domestically on a long-term basis to  unaffiliated  utilities.  Certain of these
contracts  totaling 250 mw of capacity are unit power  agreements  requiring the
delivery  of energy  only if the unit  capacity  is  available.  The power sales
contracts expire from 2001 to 2010.

Nuclear Plants - Affecting AEP, CPL and I&M

I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by
the NRC. CPL owns 25.2% of the  two-unit  2,500 MW STP.  STPNOC  operates STP on
behalf of the joint owners under licenses granted by the NRC. The operation of a
nuclear facility  involves special risks,  potential  liabilities,  and specific
regulatory  and  safety  requirements.  Should a nuclear  incident  occur at any
nuclear  power plant  facility in the U.S.,  the  resultant  liability  could be
substantial.  By agreement  I&M and CPL are partially  liable  together with all
other electric utility companies that own nuclear generating units for a nuclear
power  plant  incident at any  nuclear  plant in the U.S.  In the event  nuclear
losses or liabilities are underinsured or exceed  accumulated funds and recovery
in rates is not  possible,  results  of  operations,  cash  flows and  financial
condition would be adversely affected.

Nuclear Incident Liability - Affecting AEP, CPL and I&M

The  Price-Anderson  Act establishes  insurance  protection for public liability
arising  from a nuclear  incident at $9.5  billion and covers any  incident at a
licensed  reactor in the U.S.  Commercially  available  insurance  provides $200
million of coverage.  In the event of a nuclear incident at any nuclear plant in
the U.S. the remainder of the liability would be provided by a deferred  premium
assessment of $88 million on each licensed reactor in the U.S. payable in annual
installments of $10 million. As a result, I&M could be assessed $176 million per
nuclear  incident  payable in annual  installments of $20 million.  CPL could be
assessed $44 million per nuclear incident  payable in annual  installments of $5
million as its share of a STPNOC  assessment.  The number of incidents for which
payments could be required is not limited.

Insurance coverage for property damage,  decommissioning  and decontamination at
the Cook  Plant  and STP is  carried  by I&M and  STPNOC  in the  amount of $1.8
billion  each.  Cook  Plant and  STPNOC  jointly  purchase  $1 billion of excess
coverage for property damage,  de-commissioning and decontamination.  Additional
insurance   provides  coverage  for  extra  costs  resulting  from  a  prolonged
accidental outage.

SNF Disposal - Affecting AEP, CPL, and I&M

Federal law provides for  government  responsibility  for permanent SNF disposal
and assesses  nuclear plant owners fees for SNF disposal.  A fee of one mill per
KWH for  fuel  consumed  after  April  6,  1983 at Cook  Plant  and STP is being
collected  from  customers and remitted to the U.S.  Treasury.  Fees and related
interest of $211 million for fuel consumed  prior to April 7, 1983 at Cook Plant
have been recorded as long-term  debt.  I&M has not paid the government the Cook
Plant  related  pre-April  1983 fees due to continued  delays and  uncertainties
related to the federal disposal  program.  At December 31, 2000, funds collected
from customers  towards  payment of the pre-April 1983 fee and related  earnings
thereon are in external funds and approximate  the liability.  CPL is not liable
for any  assessments  for nuclear fuel consumed prior to April 7, 1983 since the
STP units began operation in 1988 and 1989.


Decommissioning and Low Level Waste Accumulation Disposal - Affecting AEP, CPL
 and I&M

Decommissioning  costs are accrued over the service  lives of the Cook Plant and
STP. The licenses to operate the two nuclear  units at Cook Plant expire in 2014
and 2017.  After  expiration  of the  licenses,  Cook  Plant is  expected  to be
decommissioned through dismantlement.  The estimated cost of decommissioning and
low level  radioactive waste  accumulation  disposal costs for Cook Plant ranges
from $783  million to $1,481  million in 2000  nondiscounted  dollars.  The wide
range is caused by variables in  assumptions  including the estimated  length of
time  SNF may  need  to be  stored  at the  plant  site  subsequent  to  ceasing
operations.  This,  in turn,  depends  on  future  developments  in the  federal
government's SNF disposal program. Continued delays in the federal fuel disposal
program  can  result in  increased  decommissioning  costs.  I&M is  re-covering
estimated   Cook   Plant   decommissioning   costs  in  its  three   rate-making
jurisdictions  based on at least the  lower end of the range in the most  recent
decommissioning  study at the  time of the  last  rate  proceeding.  The  amount
recovered  in rates for  decommissioning  the Cook  Plant and  deposited  in the
external  fund was $28  million in 2000,  $28 million in 1999 and $29 million in
1998.

The  licenses to operate  the two nuclear  units at STP expire in 2027 and 2028.
After expiration of the licenses, STP is expected to be decommissioned using the
decontamination   method.   CPL   estimates   its   portion   of  the  costs  of
decommissioning  STP to be $289 million in 1999  nondiscounted  dollars.  CPL is
accruing and recovering these  decommissioning  costs through rates based on the
service life of STP at a rate of $8 million per year.

Decommissioning costs recovered from customers are deposited in external trusts.
In 2000 and 1999 I&M  deposited in its  decommissioning  trust an  additional $6
million and $4 million,  respectively,  related to special regulatory commission
approved  funding for  decommissioning  of the Cook Plant.  Trust fund  earnings
increase  the fund assets and the  recorded  liability  and  decrease the amount
needed  to  be  recovered  from  ratepayers.   Decommissioning  costs  including
interest,  unrealized  gains and  losses  and  expenses  of the trust  funds are
recorded  in  other  operation   expense  for  Cook  Plant.   For  STP,  nuclear
decommissioning  costs are recorded in other operation expense,  interest income
of the trusts are recorded in  nonoperating  income and interest  expense of the
trust funds are included in interest charges.  During 1999 and 1998 I&M withdrew
$8  million   and  $3   million,   respectively,   from  the  trust   funds  for
decommissioning of the original steam generators removed from Cook Plant Unit 2.

On the AEP Consolidated Balance Sheets, nuclear decommissioning trust assets are
included in other assets and a corresponding nuclear  decommissioning  liability
is  included in other  noncurrent  liabilities.  On CPL's  balance  sheets,  the
nuclear   decommissioning    liability   is   included   in   electric   utility
plant-accumulated  depreciation and amortization. At December 31, 2000 and 1999,
the  decommissioning  liability  for Cook  Plant and STP  combined  totals  $654
million and $587 million, respectively.

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  filed a consolidated  complaint  pursuant to this court order.  This
case has been transferred to the U.S.  District Court for the Southern  District
of Ohio.  Although  management  believes these  shareholder  actions are without
merit and  intends to oppose  them  vigorously,  management  cannot  predict the
outcome of this litigation or its impact on results of operations, cash flows or
financial condition.

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 any 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 with an additional  annual  reduction of $13
million commencing 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 service  billings from an affiliate,  CSW Services.  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  service billing 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  the PUCT's 1997 order 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 service billings.

Lignite Mining Agreement Litigation - Affecting AEP and 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  has been  extended  from  December 31, 2000 to March 31,  2001.  The
litigation  has  been  stayed  until  April  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,
and OPCo

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.

AEP,  APCo,  CSPCo,  I&M, and OPCo have been  involved in  litigation  regarding
generating plant emissions under the Clean Air Act. In 1999 Notices of Violation
were issued and  complaints  were filed by Federal EPA in various U.S.  District
Courts alleging APCo,  CSPCo,  I&M, OPCo and a number of 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  generating units previously named only in the Notices of
Violation in the complaint.

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 certain AEP System  operating  companies
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  companies  filed  motions  to dismiss  all or
portions of the complaints. Briefing on these motions was completed on August 2,
2000. On February 23, 2001,  the government  filed a motion for partial  summary
judgement  seeking a  determination  that four  projects  undertaken on units at
Sporn,  Cardinal and Clinch River plants do not constitute "routine maintenance,
repair and  replacement" as used in the Clean Air Act.  Management  believes its
maintenance, repair and replacement activities were in conformity with the Clean
Air Act and intends to vigorously pursue its defense.

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

In December 2000 Cinergy Corp., an unaffiliated utility,  which operates certain
plants jointly owned by CSPCo reached a tentative agreement with Federal EPA and
other parties to settle  litigation  regarding  generating plant emissions under
the Clean Air Act. Negotiations are continuing between the parties in an attempt
to reach final settlement terms. Cinergy's settlement could impact the operation
of Zimmer  Plant and W.C.  Beckjord  Generating  Station  Unit 6 which are owned
25.4% and 12.5%,  respectively,  by CSPCo.  Until a final settlement is reached,
CSPCo will be unable to determine the  settlement's  impact on its jointly owned
facilities and its future earnings and cash flows.

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

Federal  EPA  issued a NOx rule  that  required  substantial  reductions  in NOx
emissions in a number of eastern states,  including  certain states in which the
AEP System's  generating  plants are located.  A number of utilities,  including
several 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, which was denied.

In December 2000 Federal EPA ruled that eleven states, including states in which
AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located,
failed  to submit  plans to  comply  with the  mandates  of the NOx  rule.  This
determination  means that those states could face stringent sanctions within the
next 24 months including limits on construction of new sources of air emissions,
loss of federal highway  funding and possible  Federal EPA takeover of state air
quality management programs.

In January 2000 Federal EPA adopted a revised rule granting  petitions  filed by
certain  northeastern  states  under  Section  126 of the Clean Air Act  seeking
significant  reductions in nitrogen oxide  emissions from utility and industrial
sources. The rule imposes emissions reduction requirements comparable to the NOx
rule  beginning  May 1, 2003,  for most of AEP's  coal-fired  generating  units.
Certain AEP operating  companies and other  utilities filed petitions for review
in the D.C.  Circuit  Court.  Briefing has been  completed and oral argument was
held in December 2000.

In a related matter, on April 19, 2000, the Texas Natural Resource  Conservation
Commission 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 May 2005 for SWEPCo.

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.  Construction  of
selective catalytic reduction  technology on Amos Plant Unit 3, which is jointly
owned by OPCo and APCo,  and APCo's  Mountaineer  Plant is scheduled to begin in
2001. The Amos and Mountaineer  projects  (expected to be completed in 2002) are
estimated to cost a total of $230 million ($145 million for APCo and $85 million
for OPCo).



<PAGE>


Preliminary  estimates  indicate that compliance with the NOx rule upheld by the
D.C.  Circuit  Court as well as  compliance  with  the  Texas  Natural  Resource
Conservation  Commission  rule and the Section  126  petitions  could  result in
required  capital  expenditures  of  approximately  $1.6 billion,  including the
amounts discussed in the previous  paragraph,  for AEP  Consolidated.  Estimated
compliance costs by registrant subsidiaries are as follows:
                        (in millions)
AEGCo                       $125
APCo                         365
CPL                           57
CSPCo                        106
I&M                          202
KPCo                         140
OPCo                         606
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.

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

On February 20, 2001, the U.S.  District Court for the Southern District of Ohio
ruled  against the AEP System  companies in their suit against the United States
over deductibility of interest claimed in their consolidated  federal income tax
return  related  to a COLI  program.  The suit was  filed  to  resolve  the IRS'
assertion  that interest  deductions for the COLI program should not be allowed.
In 1998 and 1999 APCo,  CSPCo,  I&M,  KPCo and OPCo paid the disputed  taxes and
interest  attributable to COLI interest deductions for taxable years 1991-98 for
APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the potential assessment
by the IRS of  additional  interest on the  contested  tax.  The  payments  were
included  in other  assets  on AEP's  Consolidated  Balance  Sheet  and in Other
Property  and  Investment  on  the  subsidiaries'  balance  sheets  pending  the
resolution of this matter.  As a result of the U.S. District Court's decision to
deny the COLI interest  deductions,  net income was reduced for AEP Consolidated
by $319 million in 2000. The appeal of this decision is planned.
The earnings reductions for affected registrant subsidiaries are as follows:

                        (in millions)
APCo                        $ 82
CSPCo                         41
I&M                           66
KPCo                           8
OPCo                         118

Other - AEP and its  registrant  subsidiaries  are involved in a number of other
legal proceedings and claims. While management is unable to predict the ultimate
outcome of these matters,  it is not expected that their  resolution will have a
material  adverse  effect on results  of  operations,  cash  flows or  financial
condition.

9. Acquisitions:

AEP  completed  two energy  related  acquisitions  in 1998 through a subsidiary,
AEPR. Both  acquisitions  have been accounted for using the purchase method.  On
December 31, 1998 CitiPower,  an Australian  distribution  utility,  that serves
approximately  250,000  customers in Melbourne with 3,100 miles of  distribution
lines in a service area of approximately  100 square miles was acquired.  All of
the  stock of  CitiPower  was  acquired  for  approximately  $1.1  billion.  The
acquisition of CitiPower had no effect on the results of operations for 1998 and
a  full  year  of  CitiPower's   results  of  operations  are  included  in  the
consolidated  statements  of  income  for 1999 and  2000.  Assets  acquired  and
liabilities  assumed  have  been  recorded  at their  fair  values.  Based on an
independent  appraisal,  $616  million of the  purchase  price was  allocated to
retail  and  wholesale  distribution  licenses  which are being  amortized  on a
straight-line basis over 20 years and 40 years, respectively. The excess of cost
over fair value of the net assets acquired was  approximately $34 million and is
recorded as goodwill  and is being  amortized on a  straight-line  basis over 40
years.  On December 1, 1998 AEPR acquired  Louisiana  Intrastate  Gas (LIG) with
midstream gas operations that include a fully integrated  natural gas gathering,
processing,  storage and transportation operation in Louisiana and a gas trading
and  marketing  operation.  LIG was acquired  for  approximately  $340  million,
including  working  capital funds with one month of earnings  reflected in AEP's
consolidated  results of operations for the year ended December 31, 1998. A full
year of LIG's results of operations is included in AEP's consolidated statements
of income for 1999 and 2000.  Assets acquired and liabilities  assumed have been
recorded  at their  fair  values.  The excess of cost over fair value of the net
assets  acquired was  approximately  $158 million for the  midstream gas storage
operations  and $17 million for the gas trading  and  marketing  operation.  The
goodwill is being amortized on a straight-line basis over 40 years and 10 years,
respectively.

10. International 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 December 31, 2000 is approximately  $33 million,  net of tax, and
$49 million, net of tax,  respectively.  Pursuant to the put option arrangement,
these  losses  have not been  applied to reduce the  carrying  value of the Vale
investment.  As a  result,  CSW  International  will not  recognize  any  future
earnings from Vale until the operating  losses are recovered.  In December 2000,
CSW  International  sold its  investment in a Chilean  electric  company for $67
million.  A net  loss on the  sale of $13  million  ($9  million  after  tax) is
included in  worldwide  electric  and gas expenses and includes $26 million ($17
million net of tax) of losses  from  foreign  exchange  rate  changes  that were
previously  reflected in other  comprehensive  income.  In the second quarter of
2000 management determined that the then existing decline in market value of the
shares was other than temporary.  As a result the investment was written down by
$33 million ($21 million  after tax) in June 2000.  The total loss from both the
write down of the Chilean  investment  to market in the second  quarter and from
the sale in the fourth quarter was $46 million ($30 million net of tax).

In December 2000 AEPR entered into  negotiations  to sell its 50%  investment in
Yorkshire,  a U.K. electricity supply and distribution  company. On February 26,
2001 an  agreement to sell AEPR's 50%  interest in  Yorkshire  was signed.  As a
result a $43 million  impairment  writedown ($30 million after tax) was recorded
in the fourth  quarter of 2000 to reflect the net loss from the expected sale in
the first quarter of 2001. The impairment  writedown is included in other income
(net) on AEP's Consolidated Statements of Income.

11. Staff Reductions:

During 1998 an internal  evaluation  of the power  generation  organization  was
conducted  with a goal of developing an optimum  organizational  structure for a
competitive  generation  market.  The study was  completed  in October  1998 and
called for the elimination of approximately 450 positions across the AEP System.
In addition,  a review of energy delivery  staffing levels in 1998 identified 65
AEP System positions for elimination.

A provision  for severance  costs  totaling $26 million was recorded in December
1998 for  reductions  in power  generation  and energy  delivery  staffs and was
charged to maintenance and other  operation  expense.  The power  generation and
energy  delivery  staff  reductions  were made in the first quarter of 1999. The
amount of  severance  benefits  paid was not  significantly  different  from the
amount accrued.

The following  table shows the staff  reductions  information for the applicable
registrant companies:

              Total Number   Severance Accrual
Company       of Employees        Amount
-------       -------------  ------------------
                              (in millions)
APCo                180            $7.6
CSPCo                70             3.4
I&M                  80             3.7
KPCo                 35             1.9
OPCo                150             8.6

12. Benefit Plans:

In the  U.S.  the AEP  System  sponsors  two  qualified  pension  plans  and two
nonqualified  pension plans. All employees in the U.S.,  except  participants in
the UMWA  pension  plans are covered by one or both of the pension  plans.  OPEB
plans are sponsored by the AEP System to provide  medical and death benefits for
retired employees in the U.S.


The  foreign  pension  plans  are for  employees  of  SEEBOARD  in the U.K.  and
CitiPower in Australia.  The majority of SEEBOARD's  employees  joined a pension
plan that is administered  for the U.K.'s  electricity  industry.  The assets of
this  plan  are  actuarially   valued  every  three  years.   SEEBOARD  and  its
participating employees both contribute to the plan. Subsequent to July 1, 1995,
new  employees  were no  longer  able to  participate  in that  plan and two new
pension  plans were made  available  to new  employees  of  SEEBOARD.  CitiPower
sponsors a defined benefit pension plan that covers all employees.

The  following  tables  provide a  reconciliation  of the  changes in the plans'
benefit  obligations  and fair value of assets over the two-year  period  ending
December  31, 2000,  and a statement of the funded  status as of December 31 for
both years:

<PAGE>
<TABLE>
<CAPTION>




                                     U.S.                  Foreign                U.S.
                                  Pension Plans          Pension Plans          OPEB Plans
                               ------------------       ----------------    -------------------
                                2000        1999        2000        1999     2000       1999
                                ----        ----        ----        ----     ----       ----
                                                          (in millions)
Reconciliation of benefit
 obligation:
<S>                            <C>         <C>          <C>       <C>       <C>        <C>
Obligation at January 1        $2,934      $3,117       $1,176    $1,147    $1,365     $1,297
Service Cost                       60          71           13        15        29         33
Interest Cost                     227         211           64        59       106         90
Participant Contributions        -           -               5         4         7          9
Plan Amendments                   (71)(a)       7 (b)     -            7 (c)   (67) (d)  -
Foreign Currency Translation
 Adjustment                      -           -             (95)      (26)     -          -
Actuarial (Gain) Loss             218        (300)          80        37       262       -
Benefit Payments                 (207)       (172)         (64)      (67)      (85)       (74)
Curtailments                     -           -            -         -           51  (e)    10 (e)
                               ------      ------       ------    ------    ------     ------
Obligation at December 31      $3,161      $2,934       $1,179    $1,176    $1,668     $1,365
                               ======      ======       ======    ======    ======     ======

Reconciliation of fair value
 of plan assets:
Fair value of plan assets at
 January 1                     $3,866      $3,665       $1,405    $1,338      $668       $560
Actual Return on Plan Assets      250         370           55       156         2         71
Company Contributions               2           2         -            7       112        103
Participant Contributions        -           -               5         4         7          9
Foreign Currency Translation
 Adjustment                      -           -            (111)      (33)       -          -
Benefit Payments                 (207)       (172)         (64)      (67)      (85)       (74)
                               ------      ------       ------    ------      ----       ----
Fair value of plan assets at
 December 31                   $3,911      $3,865       $1,290    $1,405      $704       $669
                               ======      ======       ======    ======      ====       ====

Funded status:
Funded status at December 31    $ 750       $ 931         $111     $ 229     $(964)     $(696)
Unrecognized Net Transition
 (Asset) Obligation               (23)        (31)          -         -        298        434
Unrecognized Prior-Service Cost   (12)         71           10        11        -          -
Unrecognized Actuarial
 (Gain) Loss                     (628)       (954)         (67)     (177)      448        135
                                -----       -----         ----     -----     -----      -----
Prepaid Benefit (Accrued
 Liability)                     $  87       $  17         $ 54     $  63     $(218)     $(127)
                                =====       =====         ====     =====     =====      =====

(a) One of the  qualified  pension plans  converted to the cash balance  pension
formula from a final average pay formula.  (b) Early retirement  factors for one
of  the  pension  plans  was  changed  to  provide  more  generous  benefits  to
participants retiring between ages 55 and 60.
(c) SEEBOARD made a one-time payment to all retired participants.
(d) Change to a  service-related  formula for retirement health care costs and a
50% of pay life insurance benefit for retiree life insurance. (e) Related to the
shutdown of OPCo's affiliated coal mine operations.
</TABLE>

<PAGE>
<TABLE>
<CAPTION>



The following table provides the amounts recognized in AEP's consolidated balance sheets as of December 31 of both years:
                                      U.S.                  Foreign                  U.S.
                                  Pension Plan           Pension Plans            OPEB Plans
                               -------------------      ----------------      -------------------
                                2000        1999        2000        1999       2000        1999
                                ----        ----        ----        ----       ----        ----
                                                          (in millions)

<S>                             <C>         <C>         <C>          <C>      <C>         <C>
Prepaid Benefit Costs           $ 159       $ 145       $54          $63      $  -        $  -
Accrued Benefit Liability         (72)       (128)       -            -        (218)       (127)
Additional Minimum Liability      (24)        (14)       -            -         N/A         N/A
Intangible Asset                   14           8        -            -         N/A         N/A
Accumulated Other
 Comprehensive Income              10           6        -            -         N/A         N/A
                                -----       -----       ---          ---      -----       ------
Net Amount Recognized           $  87       $  17       $54          $63      $(218)      $(127)
                                =====       =====       ===          ===      =====       =====

Other Comprehensive (Income)
 Expense Attributable to
 Change in Additional Pension
 Liability Recognition             $4         $(2)       -             -        N/A         N/A
                                   ==         ====      ===           ===       ===         ====

N/A = Not Applicable

</TABLE>

<PAGE>
<TABLE>
<CAPTION>


The AEP System's  nonqualified pension plans had accumulated benefit obligations
in excess of plan assets of $41 million and $26 million at December 31, 2000 and
$29 million and $23 million at December  31,  1999.  There are no plan assets in
the nonqualified plans.

The AEP System's OPEB plans had  accumulated  benefit  obligations  in excess of
plan  assets of $964  million and $696  million at  December  31, 2000 and 1999,
respectively.

The following table provides the components of AEP's net periodic benefit cost for the plans for fiscal years 2000, 1999 and 1998:
                                        U.S.                 Foreign                  U.S.
                                   Pension Plans           Pension Plans          OPEB Plans
                                --------------------   --------------------   -------------------
                                2000    1999    1998   2000    1999    1998   2000   1999   1998
                                ----    ----    ----   ----    ----    ----   ----   ----   ----
                                                         (in millions)
<S>                             <C>    <C>     <C>     <C>     <C>     <C>    <C>    <C>    <C>
Service cost                    $  60  $  71   $  67   $ 13    $ 15    $ 14   $ 29   $ 33   $ 26
Interest cost                     227    211     202     64      59      68    106     90     76
Expected return on plan assets   (321)  (299)   (269)   (75)    (71)    (77)   (57)   (49)   (40)
Amortization of
 transition (asset) obligation     (8)    (8)     (8)    -      -        -      41     43     41
Amortization of prior-service
 cost                              13     12       9      1     -        -      -      -      -
Amortization of net actuarial
 (gain) loss                      (39)   (15)     (3)    -      -        -       4      5     (2)
                                 ----  -----   -----   ----    ----    ----   ----   ----   ----
Net periodic benefit cost         (68)   (28)     (2)     3       3       5    123    122    101
Curtailment loss(a)                -      -      -       -      -        -      79     18     24
                                 ----  -----   -----   ----    ----    ----   ----   ----   -----
Net periodic benefit
 cost after curtailments         $(68) $ (28)  $  (2)  $  3    $  3    $  5   $202   $140   $125
                                 ====  =====   =====   ====    ====    ====   ====   ====   ====

(a)  Curtailment  charges were  recognized  during  2000,  1999 and 1998 for the
shutdown of affiliated coal mine operations.
</TABLE>
<TABLE>
<CAPTION>

The  following  table  provides the net periodic  benefit cost  (credit) for the
plans by the following AEP registrant  subsidiaries  for fiscal years 2000, 1999
and 1998:

                                           U.S.                           U.S
                                       Pension Plans                   OPEB Plans
                                ----------------------------   ---------------------------
                                   2000      1999      1998      2000      1999    1998
                                   ----      ----      ----      ----      ----    ----
                                                       (in thousands)

<S>                             <C>        <C>       <C>       <C>       <C>      <C>
APCo                            $(14,047)  $(3,925)  $   778   $ 22,139  $19,431  $16,569
CPL                               (2,986)   (4,270)   (2,850)     6,656    7,595    6,599
CSPCo                            (10,905)   (4,893)   (1,410)     9,643    8,623    7,467
I&M                               (8,565)   (1,259)    2,104     14,155   13,664   11,994
KPCo                              (2,075)     (393)      322      2,364    2,652    2,113
OPCo                             (15,041)   (4,979)       26    116,205   52,518   54,578
PSO                               (2,196)   (3,129)   (2,190)     4,277    5,516    4,369
SWEPCo                            (2,606)   (3,734)   (2,581)     4,152    4,913    3,673
WTU                               (1,585)   (2,221)   (1,478)     2,929    3,377    3,002
</TABLE>
<TABLE>
<CAPTION>

The assumptions used in the measurement of the AEP System's benefit  obligations
are shown in the following tables:
                                 U.S.                    Foreign
                             Pension Plans             Pension Plans               U.S. OPEB Plans
                        -----------------------   -------------------------     --------------------
                        2000    1999       1998   2000      1999       1998     2000    1999    1998
                        ----    ----       ----   ----      ----       ----     ----    ----    ----
                          %       %          %      %         %          %        %       %       %
Weighted-average assumptions as of December 31:
<S>                     <C>     <C>        <C>      <C>      <C> <C>  <C>       <C>     <C>     <C>
 Discount rate          7.50    8.00       6.75     5-5.5    5.5-6    5-5.5     7.50    8.00    6.75
 Expected return on
  plan assets           9.00    9.00       9.00     6-7.5  6.5-7.5   6.25-7     8.75    8.75    8.75
 Rate of compensation
  increase               3.2     3.8       3.8    3.5-4.0    4-4.5    3.5-4      N/A     N/A     N/A
</TABLE>
<PAGE>





For measurement  purposes, a 6.0% annual rate of increase in the per capita cost
of covered  health care  benefits was assumed for 2001.  The rate was assumed to
decrease  gradually  each year to a rate of 5.1% through 2005 and remain at that
level thereafter.

Assumed  health care cost trend rates have a  significant  effect on the amounts
reported for the OPEB health care plans. A 1% change in assumed health care cost
trend rates would have the following effects:

                          1% Increase  1% Decrease
                          -----------  ------------
                               (in millions)
Effect on total
 service and interest
 cost components of
 net periodic
 postretirement
 health care benefit cost    $ 15         $ (13)

Effect on the health care
 component of the
 accumulated
 postretirement
 benefit obligation           197          (162)

AEP System Savings Plans - The AEP System Savings Plans are defined contribution
plans offered to non-UMWA U.S.  employees.  The cost for  contributions to these
plans totaled $37 million in 2000,  $36 million in 1999 and $35 million in 1998.
Beginning in 2001 AEP's  contributions to the plans will increase to 4.5% of the
initial 6% of employee pay contributed  from the current 3% of the initial 6% of
employee base pay contributed.

The following table provides the cost for  contributions to the savings plans by
the following AEP registrant subsidiaries for fiscal years 2000, 1999 and 1998:

          2000     1999     1998
          ----     ----     ----
              (in thousands)

APCo     $3,988   $4,091   $4,276
CPL       3,161    3,284    3,078
CSPCo     1,638    1,679    1,830
I&M       4,231    3,996    4,017
KPCo        544      561      714
OPCo      3,713    3,744    3,978
PSO       2,306    2,435    2,230
SWEPCo    2,880    2,961    2,728
WTU       1,708    1,766    1,594


Other UMWA  Benefits - AEP and OPCo  provide  UMWA  pension,  health and welfare
benefits for certain unionized mining employees,  retirees,  and their survivors
who  meet  eligibility  requirements.  The  benefits  are  administered  by UMWA
trustees  and  contributions  are made to their trust funds.  Contributions  are
based on hours  worked  and are  expensed  as paid as part of the cost of active
mining operations and were not material in 2000, 1999 and 1998.

13. Stock-Based Compensation:

In 2000,  AEP  adopted a  Long-term  Incentive  Plan  under  which a maximum  of
15,700,000  shares of common  stock  can be issued to key  employees.  Under the
plan, the exercise price of each option granted equals the market price of AEP's
common stock on the date of grant.  These options will vest in equal increments,
annually,  over a three-year  period beginning on January 1, 2002 with a maximum
exercise term of ten years.

CSW maintained a stock option plan prior to the merger with AEP.  Effective with
the merger,  all CSW stock options  outstanding  were  converted  into AEP stock
options  at an  exchange  ratio of one CSW stock  option for 0.6 of an AEP stock
option.  The  exercise  price for each CSW stock  option  was  adjusted  for the
exchange  ratio.  The  provisions  of the CSW stock option plan will continue in
effect  until all  options  expire or there are no longer  options  outstanding.
Under the CSW stock  option  plan,  the option  exercise  price was equal to the
stock's  market  price on the date of grant.  The grant vested over three years,
one-third on each of the first three anniversary dates of the grant, and expires
10 years after the original  grant date. All CSW stock options were fully vested
at December 31, 2000.



<PAGE>
<TABLE>
<CAPTION>




The  following  table  summarizes  share  activity in the above  plans,  and the
weighted-average exercise price:


                           2000                    1999                   1998
                           ----                    ----                   ----
                               Weighted                Weighted               Weighted
                               Average                 Average                Average
                    Options    Exercise     Options    Exercise     Options   Exercise
                (in thousands) Price    (in thousands) Price    (in thousands) Price
                -------------- -----    -------------- -----    -------------- ------
Outstanding at
<S>                    <C>     <C>             <C>     <C>           <C>       <C>
 beginning of year     825     $40             866     $40           1,141     $40
  Granted            6,046     $36              -      $ -            -        $ -
  Exercised            (26)    $36             (22)    $38            (202)    $40
  Forfeited           (235)    $39             (19)    $43             (73)    $40
                     -----                     ---                   -----
Outstanding at
 end of year         6,610     $36             825     $40             866     $40
                     =====                     ===                   =====

Options Exercisable
 at end of year        588     $41             707     $42             606     $43
                       ===                     ===                     ===
</TABLE>
<PAGE>





The weighted-average  fair value of options granted in 2000 is $36 per share. No
options were granted in 1999 or 1998. Shares  outstanding under the stock option
plan  have  exercise  prices  ranging  from  $35 to $49  and a  weighted-average
remaining contractual life of 9.2 years.

If compensation  expense for stock options had been determined based on the fair
value at the grant date,  net income and  earnings per share would have been the
pro forma amounts shown below:

                           2000    1999    1998
                           ----    ----    ----
Pro forma net income
(in millions)              $264    $972    $975

Pro forma earnings per
share (basic and diluted)  $0.82  $3.03    $3.06

The pro forma  amounts are not  representative  of the  effects on reported  net
income for future years.

The fair value of each option  award is estimated on the date of grant using the
Black-Scholes  option-pricing  model  with  the  following  assumptions  used to
estimate  the fair value of options  granted in 2000:  dividend  yield of 6.02%;
expected stock price volatility of 24.75%;  risk-free interest rate of 5.02% and
expected life of option of 7 years.



14.      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 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.

The  AEP  consolidated  income  statement  caption  "Revenues-Domestic  Electric
Utility Operations"  includes both the retail and wholesale domestic electricity
supply  businesses  which are cost-based  rate regulated on a bundled basis with
transmission  and  distribution   services  in  Kentucky,   Indiana,   Michigan,
Louisiana,  Oklahoma and  Tennessee and are in the process of  transitioning  to
customer choice market based pricing in Arkansas,  Ohio, Texas, WV and Virginia.
Since the domestic  electric  utility  companies  have not yet  functionally  or
structurally  separated their retail and wholesale  electricity  supply business
from their regulated  transmission and 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.   Therefore  all  registrant   subsidiaries  have  one
reportable segment, a regulated vertically integrated electricity generation and
energy delivery business. All other activities for these registrant subsidiaries
are  insignificant.  In 2000,  1999 and  1998  all the  registrant  subsidiaries
revenues are derived from the  generation,  sale and delivery of  electricity in
the U.S.

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 in Florida, Texas, Colorado,  Brazil and Mexico, and natural
gas pipeline, storage and other natural gas services in the U.S.

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

In the fourth quarter of 2000,  management  announced its intent to functionally
and  structurally  separate its operations  into two main business  segments,  a
non-regulated  business and a regulated business.  Separation of AEP's regulated
bundled generation,  distribution and transmission  businesses into an unbundled
non-regulated  generation  business and  regulated  unbundled  distribution  and
transmission  business  will not be  completed  until  the  required  regulatory
approvals  are  obtained and the electric  operating  subsidiaries  operating in
states that are deregulating the generation business are structurally  separated
and the remaining subsidiaries  functionally separated and the necessary changes
are made to their accounting software, books, and records. Management expects to
begin reporting  certain  segmented  information by the new business segments in
the near future.


<PAGE>
<TABLE>
<CAPTION>





                             Domestic*  Foreign   Worldwide
                             Electric   Energy    Energy              Reconciling      AEP
Year                         Utilities  Delivery  Investments  Other  Adjustments  Consolidated
----                         ---------  --------  -----------  -----  -----------  ------------
                                                     (in millions)
2000
  Revenues from:
    External unaffiliated
<S>                            <C>       <C>        <C>       <C>                      <C>
     customers                 $10,827   $1,934     $  836    $    97       -          $13,694
    Transactions with other
     operating segments           -        -           147        391    $(538)           -
  Interest expense                 734      163        129         91      (60)          1,057
  Depreciation, depletion and
    amortization expense         1,062      149         25         13     (187)          1,062
  Income tax expense (benefit)     641      (16)       (19)        (9)      -              597
  Segment net income (loss)        211      125        (56)       (13)      -              267
  Total assets                  35,741    4,446      2,089     12,272       -           54,548
  Investments in equity method
    subsidiaries                  -         427        360         77       -              864
  Gross property additions       1,386      177        149         61       -            1,773

1999
  Revenues from:
    External unaffiliated
     customers                $ 9,838    $2,023     $  583     $  (37)       -         $12,407
    Transactions with other
     operating segments          -         -            70        246     $(316)          -
  Interest expense                688       172        109         55       (47)           977
  Depreciation, depletion and
    amortization expense        1,011       166         26          9      (201)         1,011
  Income tax expense (benefit)    490        18        (10)       (16)       -             482
  Segment net income (loss)       794       170         34        (26)       -             972
  Total assets                 27,288     4,739      1,669      2,023        -          35,719
  Investments in equity method
    subsidiaries                 -          412        420         57        -             889
  Gross property additions      1,215       206        205         54        -           1,680

1998
  Revenues from:
    External unaffiliated
     customers                $ 9,834    $1,769     $  183     $   54        -         $11,840
    Transactions with other
     operating segments          -         -          -            49     $ (49)          -
  Interest expense                682       116         68         51       (38)           879
  Depreciation, depletion and
    amortization expense          989        95         13          7      (115)           989
  Income tax expense (benefit)    532         4        (14)       (20)       -             502
  Segment net income (loss)       884       155        (26)       (38)       -             975
  Total assets                 25,546     4,504      1,672      1,543        -          33,265
  Investments in equity method
    subsidiaries                 -          352        287         59        -             698
  Gross property additions        729     1,259        712         90        -           2,790

*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>
<TABLE>
<CAPTION>

Geographic Areas                                       Revenues
----------------         ----------------------------------------------------------------------
                                               United                                  AEP
                         United States        Kingdom        Other Foreign        Consolidated
                         ---------------------------------------------------------------------
                                                    (in millions)

<S>                        <C>                 <C>                <C>               <C>
2000                       $11,663             $1,632             $399              $13,694
1999                        10,353              1,705              349               12,407
1998                        10,063              1,769                8               11,840


                                                     Long-Lived Assets
                         ----------------------------------------------------------------------
                                               United                                  AEP
                         United States        Kingdom        Other Foreign        Consolidated
                         ---------------------------------------------------------------------
                                                    (in millions)

2000                       $20,463             $1,220             $710              $22,393
1999                        19,958              1,124              783               21,865
1998                        19,752              1,102              665               21,519



</TABLE>
<PAGE>



15. Financial Instruments, Credit and
  Risk Management:

AEP and its  subsidiaries  are  subject to market risk as a result of changes in
commodity  prices,  foreign currency exchange rates, and interest rates. AEP has
wholesale  electricity and gas trading and marketing  operations that manage the
exposure to commodity price movements using physical  forward  purchase and sale
contracts at fixed and variable  prices,  and financial  derivative  instruments
including exchange traded futures and options,  over-the-counter  options, swaps
and other financial derivative contracts at both fixed and variable prices.

In the first  quarter of 1999 AEP adopted  the  Financial  Accounting  Standards
Board's EITF 98-10,  "Accounting  for Contracts  Involved in Energy  Trading and
Risk  Management  Activities".  The EITF requires  that all open energy  trading
contracts be  marked-to-market.  The effect on the  Consolidated  Statements  of
Income of marking open trading contracts to market in the AEP System's regulated
jurisdictions  are deferred as regulatory  assets or  liabilities  in accordance
with SFAS 71 for the  portion of those  open  electricity  trading  transactions
within AEP's marketing area that are included in cost of service on a settlement
basis for ratemaking  purposes.  Open electricity  trading  transactions  within
AEP's   marketing   area   allocated   to   non-regulated    jurisdictions   are
marked-to-market  and  included  in  revenues  from  domestic  electric  utility
operations.  Open electricity trading contracts outside AEP's marketing area are
accounted for on a mark-to-market  basis and included in revenues from worldwide
electric and gas operations.  Open gas trading  contracts are accounted for on a
mark-to-market  basis and included in revenues from  worldwide  electric and gas
operations. Unrealized mark-to-market gains and losses from trading of financial
instruments are reported as assets and liabilities, respectively.

The  amounts of net  revenues  recorded  in 2000 and 1999 for  electric  and gas
trading activities were:

Revenues - Net Gain (Loss)     2000      1999
--------------------------     ----      ----
                               (in millions)
Domestic Electric Utility
  Operations                   $ 43      $27
Worldwide Electric and
  Gas Operations                213       14

The  amounts  of net  revenues  recorded  in 2000 and  1999  for the  registrant
subsidiaries were:
                              2000        1999
                              ----        ----
                           (in thousands)

APCo                     $23,712    $14,640
CPL                       (3,809)      -
CSPCo                     22,032      5,819
I&M                       29,344      6,384
KPCo                      11,792      2,182
OPCo                      34,582     10,921
PSO                        3,553       -
SWEPCo                      (441)      -
WTU                         (453)      -

Investment  in foreign  energy  companies  and  projects  exposes AEP to risk of
foreign currency fluctuations.  AEP is also exposed to changes in interest rates
primarily  due to short-  and  long-term  borrowings  used to fund its  business
operations.  AEP does not presently utilize  derivatives to manage its exposures
to foreign currency exchange rate movements.

Market  Valuation  - The book  values  of cash and  cash  equivalents,  accounts
receivable,  short-term debt and accounts payable approximate fair value because
of the short-term maturity of these instruments. The book value of the pre-April
1983 spent  nuclear  fuel  disposal  liability  approximates  AEP and I&M's best
estimate of its fair value.

The book  values  and fair  values  of AEP's  and the  registrant  subsidiaries'
significant  financial  instruments at December 31, 2000 and 1999 are summarized
in the following  table.  The fair values of long-term debt and preferred  stock
subject to mandatory  redemption  are based on quoted market prices for the same
or similar  issues and the  current  dividend  or  interest  rates  offered  for
instruments of the

<PAGE>


same remaining  maturities.  The fair value of those financial  instruments that
are   marked-to-market   are  based  on   management's   best  estimates   using
over-the-counter quotations, exchange prices, volatility factors and a

valuation  methodology.  The  estimates  presented  herein  are not  necessarily
indicative of the amounts that AEP and the registrant subsidiaries could realize
in a current market exchange.



<PAGE>
<TABLE>
<CAPTION>





                                                 2000                      1999
                                        Book Value  Fair Value    Book Value  Fair Value
                                        ----------  ----------    ----------  ----------
                                            (in thousands)            (in thousands)
             Non-Derivatives

             AEP Consolidated

             <S>                        <C>         <C>           <C>         <C>
             Long-term Debt             $10,754,000 $10,812,000   $11,524,000 $11,037,000
             Preferred Stock                100,000      98,000       119,000     117,000
             Trust Preferred Securities     334,000     326,000       335,000     290,000

             AEGCo

             Long-term Debt                     $45         $45           $45         $45

             APCo

             Long-term Debt              $1,605,818  $1,601,313    $1,665,307  $1,580,600
             Preferred Stock                 10,860      10,725        20,310      19,700

             CPL

             Long-term Debt              $1,454,559  $1,463,690    $1,454,541  $1,435,083
             Trust Preferred Securities     148,500     147,431       150,000     129,360

             CSPCo

             Long-term Debt                $899,615    $908,620      $925,000    $889,000
             Preferred Stock                 15,000      14,892        25,000      25,438

             I&M

             Long-term Debt              $1,388,939  $1,377,230    $1,324,326  $1,283,300
             Preferred Stock                 64,945      63,941        64,945      63,500

             KPCo

             Long-term Debt                $330,880    $335,408      $365,782    $359,100

             OPCo

             Long-term Debt              $1,195,493  $1,176,367    $1,151,511  $1,027,000
             Preferred Stock                  8,850       8,780         8,850       8,500

             PSO

             Long-term Debt                $470,822    $476,964      $384,516    $378,437
             Trust Preferred Securities      75,000      72,180        75,000      63,390

             SWEPCo

             Long-term Debt                $645,963    $651,586      $541,568    $537,354
             Trust Preferred Securities     110,000     106,700       110,000      97,372

             WTU

             Long-term Debt                $255,843    $261,315      $303,686    $298,220

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


                                                         Derivatives
                                              2000                         1999
                                  ---------------------------  ----------------------------
                                  Notional  Fair    Average    Notional  Fair    Average
                                   Amount   Value  Fair Value   Amount   Value  Fair Value
                                  --------  -----  ----------  --------  -----  ----------
                                    GWH       (in millions)      GWH       (in millions)
             AEP Consolidated
             Trading Assets

             Electric
               Futures and
<S>                                        <C>      <C>            <C>   <C>       <C>
                Options-NYMEX (net)  -     $ -      $ -            224   $  2      $  1
               Physicals          247,330   8,845    2,758      69,509    577       517
               Options - OTC        8,981     215       99       6,203     39        62
               Swaps               11,575     164       60         177      1         1

                                   MMMBTU                      MMMBTU
             Gas
               Futures and
                Options-NYMEX (net)  -     $  -     $  -          -      $ -      $  -
               Physicals          597,251     455       97     345,830     37        39
               Options - OTC      698,392   1,266      355     192,593     54        40
               Swaps            4,677,142   7,328    1,730   2,682,033    410       312


             Trading Liabilities

                                    GWH       (in millions)      GWH       (in millions)

             Electric
               Futures and
                Options-NYMEX (net)  -     $  -      $  -         -      $ -      $ -
               Physicals          246,729   (8,906)   (2,712)   74,764   (536)     (498)
               Options - OTC       10,368     (133)      (69)    8,907    (43)      (56)
               Swaps               11,289     (144)      (47)      180     (2)       (2)

                                   MMMBTU                      MMMBTU
             Gas
               Futures and
                Options-
                NYMEX (net)        23,110  $   (81) $   (11)    69,840   $ (8)    $  (5)
               Physicals          442,309     (420)     (91)   301,271    (32)      (26)
               Options - OTC      666,304     (934)    (306)   227,225    (55)      (37)
               Swaps            4,616,178   (7,592)  (1,762) 2,601,644   (379)     (303)


                                              2000                         1999
                                  ---------------------------  ----------------------------
                                  Notional  Fair    Average    Notional  Fair    Average
                                   Amount   Value  Fair Value   Amount   Value  Fair Value
                                  --------  -----  ----------  --------  -----  ----------
                                    GWH       (in thousands)     GWH       (in thousands)
             APCo
             Trading Assets

             Electric
               Futures and
                Options-NYMEX (net)  -    $     -    $   -           64  $    535 $    254
               Physicals           45,406  2,246,952  757,757    19,953   165,624  150,377
               Options - OTC        1,924     59,814   25,015     1,781    11,766   18,461
               Swaps                3,652     51,470   18,387        51       112       90

             Trading Liabilities

             Electric
               Futures and
                Options-NYMEX (net)  -    $  -        $  -         -     $   -    $   -
               Physicals          45,994  (2,271,026) (747,567)  21,461  (154,364)(144,876)
               Options - OTC       3,130     (35,955)  (18,872)   2,557   (12,375) (16,811)
               Swaps               3,562     (44,855)  (14,103)      52      (103)     (85)

             KPCo
             Trading Assets

             Electric
               Futures and
                Options-NYMEX (net)  -     $    -    $   -           15  $   114  $    49
               Physicals           10,779   533,781   179,999     4,707   39,074   35,477
               Options - OTC          456    14,207     5,938       420    2,773    4,353
               Swaps                  867    12,227     4,368        12       26       21

             Trading Liabilities

             Electric
               Futures and
                Options-NYMEX (net)  -    $  -        $  -        -      $  -      $ -
               Physicals          10,919  (539,465)   (177,581)  5,063     (36,422)(34,180)
               Options - OTC         743    (8,521)     (4,461)    603      (2,900) (3,949)
               Swaps                 846   (10,656)     (3,350)     12         (24)    (20)

                                              2000                         1999
                                  ---------------------------  ----------------------------
                                  Notional  Fair    Average    Notional  Fair    Average
                                   Amount   Value  Fair Value   Amount   Value  Fair Value
                                  --------  -----  ----------  --------  -----  ----------
                                    GWH       (in thousands)     GWH       (in thousands)
             I&M
             Trading Assets

             Electric
               Futures and
                Options-NYMEX (net)  -     $    -    $   -           43 $    340  $   171
               Physicals           27,431   1,357,459 466,140    13,592  112,830   99,621
               Options - OTC        1,162      36,139  15,464     1,213    8,010   12,125
               Swaps                2,206      31,095  11,144        35       76       61

             Trading Liabilities

             Electric
               Futures and
                Options-NYMEX (net)  -    $  -        $  -        -      $  -      $ -
               Physicals          27,786  (1,379,302) (460,348) 14,620    (105,169)(95,948)
               Options - OTC       1,891     (25,807)  (13,031)  1,742      (8,391)(11,010)
               Swaps               2,152     (27,099)   (8,552)     35         (70)    (58)


             OPCo
             Trading Assets

             Electric
               Futures and
                Options-NYMEX (net)  -    $     -    $   -           61 $    583  $    286
               Physicals           36,080  1,786,137  639,632    18,753  155,507   146,395
               Options - OTC        1,529     46,731   20,403     1,673    9,672     9,936
               Swaps                2,902     41,788   16,172        48      987       967

             Trading Liabilities

             Electric
               Futures and
                Options-NYMEX (net)  -    $  -        $  -        -     $  -      $ -
               Physicals          36,547  (1,802,295) (627,137) 20,171   (143,440)(135,015)
               Options - OTC       2,487     (29,350)  (16,571)  2,403    (11,506)  (7,084)
               Swaps               2,830     (37,398)  (13,447)     49     (1,846)  (1,829)


             CSPCo
             Trading Assets

             Electric
               Futures and
                Options-NYMEX (net)  -     $    -    $   -           40 $    312  $   159
               Physicals           24,221   1,198,835 420,090    12,503  103,794   91,570
               Options - OTC        1,026      31,918  13,961     1,116    7,369   11,140
               Swaps                1,948      27,461   9,914        32       70       56

             Trading Liabilities

             Electric
               Futures and
                Options-NYMEX (net)  -    $  -        $  -        -      $  -      $ -
               Physicals          24,535  (1,211,580) (414,198) 13,449     (96,748)(88,194)
               Options - OTC       1,669     (19,220)  (10,629)  1,602      (7,717)(10,114)
               Swaps               1,900     (23,932)   (7,599)     32         (64)    (53)


</TABLE>
<PAGE>




                            2000
                Notional  Fair    Average
                 Amount   Value  Fair Value
                --------  -----  ----------
                  GWH       (in thousands)
CPL
Trading Assets

Electric
  Physicals      31,040  $547,437  $ 210,189

Trading
Liabilities
  Electric
   Physicals     31,442  (555,628)  (211,482)


PSO
Trading Assets

Electric
  Physicals      24,670   435,009    232,198


Trading
Liabilities
  Electric
   Physicals     24,990  (441,517)  (234,082)


SWEPCo
Trading Assets
Electric
  Physicals      29,538   520,964    217,444

Trading
Liabilities
  Electric
   Physicals     29,920  (528,759)  (220,171)


WTU
Trading Assets

Electric
  Physicals       9,821   173,118     58,048


Trading
Liabilities
  Electric
   Physicals      9,948  (175,708)   (58,071)

There were no trading  activities  for CPL,  PSO,  SWEPCo,  and WTU for the year
ended 1999.

AEP routinely  enters into exchange traded futures and options  transactions for
electricity and natural gas as part of its wholesale trading  operations.  These
transactions  are  executed  through  brokerage  accounts  with  brokers who are
registered with the Commodity Futures Trading  Commission.  Brokers require cash
or cash related  instruments  to be deposited on these  accounts as margin calls
against the customer's  open position.  The amount of these deposits at December
31, 2000 and 1999 was $95 million and $25 million, respectively.

Credit and Risk  Management - In addition to market risk  associated  with price
movements,  AEP is  also  subject  to  the  credit  risk  inherent  in its  risk
management  activities.  Credit risk refers to the  financial  risk arising from
commercial  transactions  and/or the intrinsic  financial  value of  contractual
agreements with trading counter parties,  by which there exists a potential risk
of non-performance.  The AEP System has established and enforced credit policies
that  minimize  or  eliminate  this risk.  AEP  accepts  as  counter  parties to
forwards,  futures, and other derivative contracts primarily those entities that
are classified as Investment  Grade, or those that can be considered as such due
to the effective placement of credit enhancements and/or collateral  agreements.
Investment  Grade  is the  designation  given to the four  highest  debt  rating
categories (i.e., AAA, AA, A, BBB) of the major rating services,  e.g.,  ratings
BBB- and above at Standard & Poor's and Baa3 and above at Moody's.  When adverse
market  conditions  have the  potential to negatively  affect a counter  party's
credit position,  AEP will require further  enhancements to mitigate risk. Since
the formation of the trading business in July of 1997, AEP has not experienced a
significant  loss due to the credit risk;  furthermore,  AEP does not anticipate
any future material effect on its results of operations,  cash flow or financial
condition as a result of counter party non-performance.

Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The
trust  investments for decommission and SNF disposal,  reported in other assets,
are recorded at market  value.  At December 31, 2000 and 1999 the fair values of
the trust investments were $873 million and $795 million,  respectively, and had
a cost  basis of $768  million  and $696  million,  respectively.  The change in
market value in 2000,  1999,  and 1998 was a net  unrealized  holding gain of $6
million, $18 million, and $32 million, respectively.

At  December  31, 2000 and 1999 the fair value of CPL's  trust  investments  for
decommissioning were $94 million and $86 million,  respectively,  and had a cost
basis of $70 million and $60 million,  respectively.  The change in market value
for CPL  was a net  unrealized  holding  loss of $3  million  in 2000  and a net
unrealized  holding  gain  of $10  million  and $8  million  in 1999  and  1998,
respectively.  At  December  31,  2000 and 1999  the fair  value of I&M's  trust
investments  for  decommissioning  and SNF  disposal  were $779 million and $708
million,  respectively,  and had a cost basis of $698 million and $636  million,
respectively.  The change in market value for I&M in 2000,  1999, and 1998 was a
net  unrealized  holding  gain  of $9  million,  $8  million  and  $24  million,
respectively.

CitiPower entered into several interest rate swap agreements for $425 million of
borrowings under a credit facility.  The swap agreements involve the exchange of
floating-rate for fixed-rate interest payments. Interest is recognized currently
based on the fixed rate of interest resulting from use of these swap agreements.
Market risks arise from the movements in interest  rates.  If counter parties to
an  interest  rate swap  agreement  were to  default  on  contractual  payments,
CitiPower  could be exposed to increased costs related to replacing the original
agreement. However, CitiPower does not anticipate non-performance by any counter
party to any  interest  rate swap in  effect  as of  December  31,  2000.  As of
December  31,  2000,  CitiPower  was a party to  interest  rate swaps  having an
aggregate  notional  amount of $626  million,  with  $224  million  maturing  on
December 31, 2003, and $201 million  maturing on December 29, 2003, $201 million
commencing  on December 29, 2003 and maturing on December 30, 2005.  The average
fixed  interest  rate payable on the  aggregate  of the  interest  rate swaps is
5.84%.  The average  floating rate for interest rate swaps was 6.04% at December
31, 2000. The estimated fair value of the interest rate swaps,  which represents
the estimated  amount CitiPower would receive to terminate the swaps at December
31, 2000,  based on quoted  interest  rates,  is a net receivable of less than a
million dollars.

CitiPower  entered into interest rate swap agreement for $112 million in January
2000, for the purpose of hedging a capital markets bond issue. The interest rate
swap agreement exchanges a fixed-rate for a floating interest rate up to January
15, 2007.  The $112 million  interest  rate swap  agreement  was  terminated  on
December 18, 2000.  The gain of $9 million  earned upon  termination of the swap
agreement has been deferred and will be amortized through January 15, 2007.

The CSW UK Holdings  Group  (Group)  entered into two currency  swaps in 1996 in
respect of two  tranches of $200 million  notes  ("Yankee  Bonds")  repayable on
August 1, 2001 and August 1, 2006. The swaps convert fixed rate semi-annual U.S.
Dollar interest payments at 6.95% and 7.45% to fixed rate sterling.  As a result
of the swaps the effective fixed sterling  interest  rates,  including fees, are
7.98% and 8.75%. The estimated fair value of these swaps at December 31, 2000 is
a net payable of $1 million.

The Group also has an interest in two  interest  rate swaps  entered into by its
joint venture  associate  Power Asset  Development  Company Limited in 1998. The
swaps  convert  floating  rate  interest  payable on a $157 million bank project
finance  borrowing,  maturing in 2021, to 6.00% fixed rate.  The estimated  fair
value of these  swaps at  December  31,  2000 is a net  payable of $3 million of
which the Group's interest is $1 million.

In addition,  at December 31, 2000, the Group has an interest in a currency swap
and an interest rate swap entered into by another joint venture associate, South
Coast Power Limited. The estimated fair value of these swaps is a net receivable
of $3 million of which the Group's share is $1 million.

In accordance  with the debt covenants  included in the financing  provisions of
its credit  facility,  CitiPower must hedge at least 80% of its energy  purchase
requirements  through energy trading  derivative  instruments  entered into with
market  participants,   predominantly  generators.  As  of  December  31,  2000,
CitiPower had outstanding  energy trading  derivatives  with a total  contracted
load of 10,144 GWH's. The maturities for these contracts range from three months
to six years. Management's estimate of the fair value of these derivatives as of
December 31, 2000 is $7 million in excess of net contract value.
SEEBOARD  manages its energy  purchase costs through  energy trading  derivative
instruments entered into with market  participants.  The Company buys derivative
instruments to hedge purchase costs only and does not enter into any speculative
trades.  As of December  31,  2000,  SEEBOARD  had  outstanding  energy  trading
derivatives  with a total  contracted  volume of 14,059 GWH's  excluding  Medway
Power Limited.  These  contracts have maturities in the range of 1 to 27 months.
In addition SEEBOARD has a 15 year contract with Medway Power Limited which owns
and operates a 675 MW combined cycle gas generating station. SEEBOARD also has a
37.5% equity  interest in Medway Power  Limited.  There are 29,025 GWH remaining
under the contract which has 10 years and 9 months to run.

Management's  estimate of the fair value of these derivatives as of December 31,
2000 is $132 million below net contract value.

16. Income Taxes:

The details of AEP's consolidated income taxes as reported are as follows:

                   Year Ended December 31,
               ------------------------------
                 2000       1999       1998
                 ----       ----       ----
                        (in millions)
Federal:
 Current         $ 766      $308       $492
 Deferred         (237)      129        (43)
                 -----      ----       ----
     Total         529       437        449
                 -----      ----       ----
State:
 Current            50        25         30
 Deferred           (9)       -          -
                 -----      ----       ----
     Total          41        25         30
                 -----      ----       ----
International:
 Current             6         3         14
 Deferred           21        17          9
                 -----      ----       -----
     Total          27        20         23
                 -----      ----       -----

Total Income Tax
  as Reported    $ 597      $482       $502
                 =====      ====       ====


<PAGE>
<TABLE>
<CAPTION>

The details of the  registrant  subsidiaries  income  taxes as  reported  are as
follows:

                                         AEGCo      APCo      CPL       CSPCo      I&M
Year Ended December 31, 2000                             (in thousands)

Charged (Credited) to Operating
 Expenses (net):
<S>                                      <C>       <C>       <C>        <C>       <C>
  Current                                $ 8,746   $129,165  $ 89,403   $120,494  $ 134,796
  Deferred                                (5,842)     3,838    16,263     (7,746)  (126,748)
  Deferred Investment Tax Credits           -        (2,947)   (5,207)    (3,379)    (7,524)
                                         -------   --------  --------   --------  ---------
    Total                                  2,904    130,056   100,459    109,369        524
                                         -------   --------  --------   --------  ---------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                    (44)       327    (5,073)     3,777      2,950
  Deferred                                  -         4,764      -         3,683      1,569
  Deferred Investment Tax Credits         (3,396)    (1,968)     -          (103)      (330)
                                         -------   --------   -------   --------  ---------
    Total                                 (3,440)     3,123    (5,073)     7,357      4,189
                                         -------   --------   -------   --------  ---------

Total Income Tax as Reported             $  (536)  $133,179   $95,386   $116,726  $   4,713
                                         =======   ========   =======   ========  =========


                                          KPCo      OPCo      PSO       SWEPCo     WTU
Year Ended December 31, 2000                             (in thousands)

Charged (Credited) to Operating
 Expenses (net):
  Current                                $17,878   $259,608  $11,597     $16,073   $ 6,774
  Deferred                                 2,521    (70,263)  25,453      14,653     9,401
  Deferred Investment Tax Credits         (1,187)    (1,824)  (1,791)     (4,482)   (1,271)
                                         -------   --------  -------     -------   -------
    Total                                 19,212    187,521   35,259      26,244    14,904
                                         -------   --------  -------     -------   -------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                    (50)    15,426   (1,306)     (1,476)     (222)
  Deferred                                 1,244      4,307     -           -       (1,237)
  Deferred Investment Tax Credits            (65)    (1,575)    -           -         -
                                         -------    -------  -------     -------   --------
    Total                                  1,129     18,158   (1,306)     (1,476)   (1,459)
                                         -------    -------  -------     -------   -------

Total Income Tax as Reported             $20,341   $205,679  $33,953     $24,768   $13,445
                                         =======   ========  =======     =======   =======


                                         AEGCo     APCo       CPL       CSPCo      I&M
Year Ended December 31, 1999                             (in thousands)

Charged (Credited) to Operating
 Expenses (net):
  Current                                $ 7,713   $69,522   $ 89,112    $79,410   $(67,368)
  Deferred                                (5,282)    8,981     19,620      9,737     85,345
  Deferred Investment Tax Credits           -       (2,659)    (5,207)    (3,432)    (7,547)
                                         -------   -------   --------    -------   --------
    Total                                  2,431    75,844    103,525     85,715     10,430
                                         -------   -------   --------    -------   --------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                   (146)   (1,548)    (5,604)    (3,122)     1,529
  Deferred                                  -        4,052        318        744        382
  Deferred Investment Tax Credits         (3,448)   (2,313)      -          (562)      (605)
                                         -------   -------   --------    -------   --------
    Total                                 (3,594)      191     (5,286)    (2,940)     1,306
                                         -------   -------   --------    -------   --------
Total Income Taxes as Reported           $(1,163)  $76,035   $ 98,239    $82,775   $ 11,736
                                         =======   =======   ========    =======   ========


                                           KPCo      OPCo       PSO      SWEPCo     WTU
Year Ended December 31, 1999                               (in thousands)

Charged (Credited) to Operating
 Expenses (net):
  Current                                 $14,897   $135,540   $20,777   $ 60,169   $ 3,328
  Deferred                                  2,239      4,205    14,521    (17,347)   12,026
  Deferred Investment Tax Credits          (1,193)    (1,825)   (1,791)    (4,565)   (1,275)
                                          -------   --------   -------   --------   -------
    Total                                  15,943    137,920    33,507     38,257    14,079
                                          -------   --------   -------   --------   -------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                    (424)    (3,256)   (2,215)    (4,826)      858
  Deferred                                    357       (539)     -          -         -
  Deferred Investment Tax Credits             (99)    (1,633)     -          -         -
                                          -------   --------   -------   --------   -------
    Total                                    (166)    (5,428)   (2,215)    (4,826)      858
                                          -------   --------   -------   --------   -------
Total Income Taxes as Reported            $15,777   $132,492   $31,292   $ 33,431   $14,937
                                          =======   ========   =======   ========   =======
</TABLE>

<PAGE>
<TABLE>
<CAPTION>


                                           AEGCo    APCo     CPL       CSPCo      I&M
Year Ended December 31, 1998                             (in thousands)

Charged (Credited) to Operating
 Expenses (net):
<S>                                       <C>       <C>      <C>        <C>       <C>
  Current                                 $(2,556)  $63,291  $128,942   $62,123   $43,103
  Deferred                                  5,544      (143)   (8,328)   17,612    21,073
  Deferred Investment Tax Credits            -       (2,671)   (3,858)   (3,498)   (7,593)
                                          -------   -------  --------   -------   -------
    Total                                   2,988    60,477   116,756    76,237    56,583
                                          -------   -------  --------   -------   -------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                     (45)   (4,902)   (2,204)   (3,795)     (594)
  Deferred                                   -       (2,195)     -         (511)   (3,168)
  Deferred Investment Tax Credits          (3,454)   (2,594)     -         (726)     (673)
                                          -------   -------  --------   -------   -------
    Total                                  (3,499)   (9,691)   (2,204)   (5,032)   (4,435)
                                          -------   -------  --------   -------   -------
Total Income Taxes as Reported            $  (511)  $50,786  $114,552   $71,205   $52,148
                                          =======   =======  ========   =======   =======


                                           KPCo      OPCo      PSO     SWEPCo    WTU
Year Ended December 31, 1998                              (in thousands)

Charged (Credited) to Operating
 Expenses (net):
  Current                                 $10,788   $120,932  $52,587  $ 64,463  $28,542
  Deferred                                  3,967      3,907   (1,651)  (11,909)  (6,626)
  Deferred Investment Tax Credits          (1,202)    (1,827)  (1,795)   (4,631)  (1,321)
                                          -------   --------  -------  --------  -------
    Total                                  13,553    123,012   49,141    47,923   20,595
                                          -------   --------  -------  --------  -------
Charged (Credited) to
 Nonoperating Income (net):
  Current                                    (794)    (5,619)     (93)   (1,868)    (454)
  Deferred                                   (360)      (865)    -         -        -
  Deferred Investment Tax Credits            (213)    (1,698)    -         -        -
                                          -------   --------  -------  --------  --------
    Total                                  (1,367)    (8,182)     (93)   (1,868)    (454)
                                          -------   --------  -------  --------  -------
Total Income Taxes as Reported            $12,186   $114,830  $49,048  $ 46,055  $20,141
                                          =======   ========  =======  ========  =======

</TABLE>



The following is a reconciliation for AEP Consolidated of the difference between
the amount of federal income taxes  computed by  multiplying  book income before
federal  income taxes by the statutory tax rate,  and the amount of income taxes
reported.

                                                  Year Ended December 31,
                                             ---------------------------------
                                                2000       1999        1998
                                                ----       ----        ----
                                                       (in millions)

Net Income                                      $267      $  972      $  975
Extraordinary Items
 (net of income tax $44 million in 2000 and
 $8 million in 1999)                              35          14        -
Preferred Stock Dividends                         11          19          19
                                                ----      ------      ------
Income Before Preferred Stock Dividends
  of Subsidiaries                                313       1,005         994
Income Taxes                                     597         482         502
                                                ----      ------      ------
Pre-Tax Income                                  $910      $1,487      $1,496
                                                ====      ======      ======

Income Tax on Pre-Tax Income
  at Statutory Rate (35%)                       $319        $520        $524
Increase (Decrease) in Income Tax
  Resulting from the Following Items:
   Depreciation                                   77          71          67
   Corporate Owned Life Insurance                247           2         (16)
   Foreign Tax Credits                           (31)        (63)        (49)
   Investment Tax Credits (net)                  (36)        (38)        (37)
   Merger Transaction Costs                       49          -           -
   State Income Taxes                             26          16          19
   International                                  18          13          15
   Other                                         (72)        (39)        (21)
                                                ----        ----        ----
Total Income Taxes as Reported                  $597        $482        $502
                                                ====        ====        ====

Effective Income Tax Rate                       65.5%       32.5%       33.6%
                                                ====        ====        ====



<PAGE>
<TABLE>
<CAPTION>


Shown  below  is a  reconciliation  for each AEP  registrant  subsidiary  of the
difference  between the amount of federal  income taxes  computed by multiplying
book income before federal income taxes by the statutory rate, and the amount of
income taxes reported.

                                             AEGCo    APCo       CPL       CSPCo      I&M
Year Ended December 31, 2000                              (in thousands)

<S>                                         <C>     <C>       <C>       <C>        <C>
Net Income (Loss)                           $7,984  $ 73,844  $189,567  $ 94,966   $(132,032)
Extraordinary (Gains) Loss                            (1,066)             39,384
Income Tax Benefit                            -       (7,872)     -      (14,148)       -
Income Taxes                                  (536)  133,179    95,386   116,726       4,713
                                            ------  --------  --------  --------   ---------
Pre-Tax Income (Loss)                       $7,448  $198,085  $284,953  $236,928   $(127,319)
                                            ======  ========  ========  ========   =========

Income Tax on Pre-Tax Income (Loss)
 at Statutory Rate (35%)                   $ 2,607  $ 69,330   $99,733  $ 82,925    $(44,561)
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                 452     7,606     7,556    10,529      20,378
  Corporate Owned Life Insurance              -       54,824      -       29,259      42,587
  Nuclear Fuel Disposal Costs                 -         -         -         -         (3,957)
  Allowance for Funds Used
    During  Construction                    (1,070)     -         -         -         (2,211)
  Rockport Plant Unit 2 Investment
    Tax Credit                                 374      -         -         -           -
  Removal Costs                               -       (1,197)     -         -           -
  Investment Tax Credits (net)              (3,396)   (4,915)   (5,207)   (3,482)     (7,854)
  State Income Taxes                           784     9,950     2,296        89       6,004
  Other                                       (287)   (2,419)   (8,992)   (2,594)     (5,673)
                                           -------  --------   -------  --------    --------
Total Income Taxes as Reported             $  (536) $133,179   $95,386  $116,726    $  4,713
                                           =======  ========   =======  ========    ========

Effective Income Tax Rate                     N.M.     67.2%     33.5%     49.3%       N.M.
                                              ====     ====      ====      ====        ====


                                           KPCo      OPCo       PSO      SWEPCo     WTU
Year Ended December 31, 2000                               (in thousands)
Net Income                                $20,763   $ 83,737   $ 66,663   $72,672   $27,450
Extraordinary Loss                                    40,157
Income Tax Benefit                           -       (21,281)      -         -         -
Income Taxes                               20,342    205,679     33,953    24,768    13,445
                                          -------   --------   --------   -------   -------
Pre-Tax Income                            $41,105   $308,292   $100,616   $97,440   $40,895
                                          =======   ========   ========   =======   =======

Income Tax on Pre-Tax Income
 at Statutory Rate (35%)                  $14,387   $107,903    $35,216  $ 34,104   $14,313
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                              1,827     27,577       -         -        1,204
  Corporate Owned Life Insurance            5,149     84,453       -         -         -
  Nuclear Fuel Disposal Costs                -          -          -         -         -
  Allowance for Funds Used
    During Construction                      -          -          -         -         -
  Rockport Plant Unit 2 Investment
    Tax Credit                               -          -          -         -         -
  Removal Costs                              (420)      -          -         -         -
  Investment Tax Credits (net)             (1,252)    (3,398)    (1,791)   (4,482)   (1,271)
  State Income Taxes                        1,597     (1,988)     3,037     1,650      -
  Other                                      (946)    (8,868)    (2,509)   (6,504)     (801)
                                          -------   --------    -------  --------   ------- -
Total Income Taxes as Reported            $20,342   $205,679    $33,953  $ 24,768   $13,445
                                          =======   ========    =======  ========   =======

Effective Income Tax Rate                    49.5%      66.8%      33.8%     25.4%     32.9%
                                             ====       ====       ====      ====      ====


                                            AEGCo      APCo       CPL       CSPCo     I&M
Year Ended December 31, 1999                                 (in thousands)
Net Income                                  $ 6,195   $120,492   $182,201   $150,270   $32,776
Extraordinary Loss                                                  8,488
Income Tax Benefit                             -          -        (2,971)      -         -
Income Taxes                                 (1,163)    76,035     98,239     82,775    11,736
                                            -------   --------   --------   --------   -------
Pre-Tax Income                              $ 5,032   $196,527   $285,957   $233,045   $44,512
                                            =======   ========   ========   ========   =======
Income Tax on Pre-Tax
 Income at Statutory Rate (35%)             $ 1,762   $ 68,785   $100,085    $ 81,566  $15,580
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                                  446     12,593      7,981       8,846   19,966
  Corporate Owned Life Insurance               -          -          -           -         594
  Nuclear Fuel Disposal Costs                  -          -          -           -      (3,347)
  Allowance for Funds Used
   During Construction                       (1,069)      -          -           -      (2,174)
  Rockport Plant Unit 2
   Investment Tax Credit                        374       -          -           -        -
  Removal Costs                                -        (3,220)      -           -        -
  Investment Tax Credits (net)               (3,448)    (4,972)    (5,207)     (3,994)  (8,152)
  State Income Taxes                            467      3,305      6,965          58   (4,635)
Other                                           305       (456)   (11,585)     (3,701)  (6,096)
                                            -------   --------   --------    --------  -------
Total Income Taxes as Reported              $(1,163)  $ 76,035   $ 98,239    $ 82,775  $11,736
                                            =======   ========   ========    ========  =======

Effective Income Tax Rate                      N.M.       38.7%      34.4%       35.6%    26.4%
                                               ====       ====       ====        ====     ====
                                           KPCo      OPCo       PSO       SWEPCo     WTU
Year Ended December 31, 1999                               (in thousands)
Net Income                                $25,430   $212,157    $61,508    $83,194   $26,406
Extraordinary Loss                                                           4,632     8,402
Income Tax Benefit                           -           -         -        (1,621)   (2,941)
Income Taxes                               15,777    132,492     31,292     33,431    14,937
                                          -------   --------    -------   --------   -------
Pre-Tax Income                            $41,207   $344,649    $92,800   $119,636   $46,804
                                          =======   ========    =======   ========   =======
Income Tax on Pre-Tax Income
 at Statutory Rate (35%)                  $14,423   $120,628   $ 32,480   $ 41,873   $16,382
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                              1,843     17,517       -          -        1,120
  Corporate Owned Life Insurance             -           198       -          -         -
  Removal Costs                              (420)      -          -          -         -
  Investment Tax Credits (net)             (1,292)    (3,458)    (1,791)    (4,565)   (1,275)
  State Income Taxes                        1,809      1,090      3,054      2,924      -
Other                                        (586)    (3,483)    (2,451)    (6,801)   (1,290)
                                          -------   --------   --------   --------   -------
Total Income Taxes as Reported            $15,777   $132,492   $ 31,292   $ 33,431   $14,937
                                          =======   ========   ========   ========   =======

Effective Income Tax Rate                    38.3%      38.5%      33.8%      28.0%     32.0%
                                             ====       ====       ====       ====      ====


                                           AEGCo     APCo       CPL       CSPCo      I&M
Year Ended December 31, 1998                               (in thousands)
Net Income                                 $ 8,946  $ 93,330   $161,511   $133,044   $ 96,628
Income Taxes                                  (511)   50,786    114,552     71,205     52,148
                                           -------  --------   --------   --------   --------
Pre-Tax Income                             $ 8,435  $144,116   $276,063   $204,249   $148,776
                                           =======  ========   ========   ========   ========

Income Tax on Pre-Tax Book Income
 at Statutory Rate (35%)                   $ 2,953  $ 50,441   $ 96,623   $ 71,488   $ 52,072
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                               1,105    11,667      8,170      8,604     17,257
  Corporate Owned Life Insurance              -       (4,212)      -          -        (3,263)
  Allowance for Funds Used
   During Construction                      (1,070)     -          -          -        (2,184)
  Rockport Plant Unit 2
   Investment Tax Credits                      374      -          -          -          -
  Nuclear Fuel Disposal Costs                 -         -          -          -        (3,397)
  Removal Costs                               -       (4,200)      -          -          -
  Investment Tax Credits (net)              (3,454)   (5,265)    (3,858)    (4,224)    (8,266)
  State Income Taxes                          (203)    4,449       -             1      3,209
  Mirror CWIP                                 -         -        10,055       -          -
Other                                         (216)   (2,094)     3,562     (4,664)    (3,280)
                                           -------  --------   --------   --------    -------
Total Income Taxes as Reported             $  (511) $ 50,786   $114,552   $ 71,205    $52,148
                                           =======  ========   ========   ========    =======

Effective Income Tax Rate                     N.M.      35.3%      41.5%      34.9%      35.1%
                                              ====      ====       ====       ====       ====


                                           KPCo     OPCo       PSO      SWEPCo      WTU
Year Ended December 31, 1998                              (in thousands)
Net Income                                $21,676  $209,925   $ 76,909   $ 97,994    $37,725
Income Taxes                               12,186   114,830     49,048     46,055     20,141
                                          -------  --------   --------   --------    -------
Pre-Tax Income                            $33,862  $324,755   $125,957   $144,049    $57,866
                                          =======  ========   ========   ========    =======

Income Tax on Pre-Tax Book Income
 at Statutory Rate (35%)                  $11,852  $113,665   $ 44,085   $ 50,418    $20,253
Increase (Decrease) in Income Tax
 Resulting from the Following Items:
  Depreciation                              1,633    16,693       -          -           964
  Corporate Owned Life Insurance             -       (5,238)      -          -          -
  Removal Costs                              (840)     -          -          -          -
  Investment Tax Credits (net)             (1,415)   (3,525)    (1,795)    (4,631)    (1,321)
  State Income Taxes                        1,560     1,782      4,478      3,308       -
Other                                        (604)   (8,547)     2,280     (3,040)       245
                                          -------  --------   --------   --------    -------
Total Income Taxes as Reported            $12,186  $114,830   $ 49,048   $ 46,055    $20,141
                                          =======  ========   ========   ========    =======

Effective Income Tax Rate                    36.0%     35.4%      39.0%      32.0%      34.9%
                                             ====      ====       ====       ====       ====

</TABLE>
<PAGE>


The following tables show the elements of the net deferred tax liability and the
significant  temporary  differences  for AEP  Consolidated  and each  registrant
subsidiary:

                                                           December 31,
                                                   --------------------------
                                                      2000            1999
                                                      ----            ----
                                                          (in millions)
Deferred Tax Assets                                 $ 1,248         $ 1,241
Deferred Tax Liabilities                             (6,123)         (6,391)
                                                    -------         -------
  Net Deferred Tax Liabilities                      $(4,875)        $(5,150)
                                                    =======-        =======

Property Related Temporary Differences              $(3,935)        $(4,109)
Amounts Due From Customers For Future
  Federal Income Taxes                                 (415)           (437)
Deferred State Income Taxes                            (251)           (220)
Regulatory Assets Designated for Securitization        (332)           (332)
All Other (net)                                          58             (52)
                                                    -------         -------
  Net Deferred Tax Liabilities                      $(4,875)        $(5,150)
                                                    =======         =======
<TABLE>
<CAPTION>

                                          AEGCo       APCo         CPL        CSPCo      I&M
December 31, 2000                                            (in thousands)

<S>                                     <C>         <C>        <C>          <C>        <C>
Deferred Tax Assets                     $  81,480   $ 178,487  $    67,184  $  88,198  $ 342,900
Deferred Tax Liabilities                 (114,408)   (860,961)  (1,309,981)  (510,957)  (830,845)
                                        ---------   ---------  -----------  ---------  ---------
  Net Deferred Tax Liabilities          $ (32,928)  $(682,474) $(1,242,797) $(422,759) $(487,945)
                                        =========   =========  ===========  =========  =========

Property Related Temporary Differences  $ (78,113)  $(510,950) $  (773,454) $(343,045) $(324,198)
Amounts Due From Customers For
  Future Federal Income Taxes              10,317     (95,639)     (72,426)   (79,959)   (55,218)
Deferred State Income Taxes                (5,478)    (86,351)        -          -       (69,982)
Net Deferred Gain on Sale and
  Leaseback-Rockport Plant Unit 2          42,766        -            -          -        28,454
Accrued Nuclear Decommissioning Expense      -           -            -          -        34,702
Deferred Fuel and Purchased Power            -           -            -          -       (39,395)
Deferred Cook Plant Restart Costs            -           -            -          -       (42,000)
Nuclear Fuel                                 -           -            -          -       (28,319)
Regulatory Assets Designated
  for Securitization                         -           -        (332,198)      -          -
All Other (net)                            (2,420)     10,466      (64,719)       245      8,011
                                        ---------   ---------  -----------  ---------  ---------
  Net Deferred Tax Liabilities          $ (32,928)  $(682,474) $(1,242,797) $(422,759) $(487,945)
                                        =========   =========  ===========  =========  =========


                                           KPCo        OPCo       PSO       SWEPCo        WTU
December 31, 2000                                           (in thousands)

Deferred Tax Assets                     $  32,807  $ 330,878  $  60,010  $   47,615    $  16,604
Deferred Tax Liabilities                 (198,742)  (952,819)  (372,070)   (446,819)    (173,642)
                                        ---------  ---------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $(165,935) $(621,941) $(312,060)  $(399,204)   $(157,038)
                                        =========  =========  =========   =========    =========

Property Related Temporary Differences  $(116,109) $(586,039) $(313,248)  $(375,427)   $(150,264)
Amounts Due From Customers For
  Future Federal Income Taxes             (19,680)  (110,908)    11,082      (6,015)       4,723
Deferred State Income Taxes               (29,695)   (14,282)   (36,487)       -            -
Deferred Fuel and Purchased Power            -      (116,224)      -           -            -
Provision for Mine Shutdown Costs            -        63,995       -           -            -
Postretirement Benefits                      -        93,306       -           -            -
All Other (net)                              (451)    48,211     26,593     (17,762)     (11,497)
                                        ---------  ---------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $(165,935) $(621,941) $(312,060)  $(399,204)   $(157,038)
                                        =========  =========  =========   =========    =========


                                          AEGCo       APCo         CPL        CSPCo      I&M
December 31, 1999                                            (in thousands)

Deferred Tax Assets                     $  85,392   $ 173,038  $    99,426  $  79,510  $ 231,329
Deferred Tax Liabilities                 (121,892)   (844,955)  (1,334,601)  (527,117)  (853,486)
                                        ---------   ---------  -----------  ---------  ---------
  Net Deferred Tax Liabilities          $ (36,500)  $(671,917) $(1,234,175) $(447,607) $(622,157)
                                        =========   =========  ===========  =========  =========

Property Related Temporary Differences  $ (84,149)  $(510,143) $  (798,381) $(352,805) $(436,162)
Amounts Due From Customers For
  Future Federal Income Taxes              11,283    (109,846)     (74,328)   (85,078)   (61,311)
Deferred State Income Taxes                (5,970)    (76,073)        -          -       (61,700)
Net Deferred Gain on Sale and
  Leaseback-Rockport Plant Unit 2          44,716        -            -          -        29,752
Accrued Nuclear Decommissioning Expense      -           -            -          -        32,097
Deferred Fuel and Purchased Power            -           -            -          -       (52,713)
Deferred Cook Plant Restart Costs            -           -            -          -       (56,000)
Nuclear Fuel                                 -           -            -          -       (27,512)
Regulatory Assets Designated
  for Securitization                         -           -        (332,198)      -          -
All Other (net)                            (2,380)     24,145      (29,268)    (9,724)    11,392
                                        ---------   ---------  -----------  ---------  ---------
  Net Deferred Tax Liabilities          $ (36,500)  $(671,917) $(1,234,175) $(447,607) $(622,157)
                                        =========   =========  ===========  =========  =========

                                           KPCo        OPCo       PSO       SWEPCo        WTU
December 31, 1999                                           (in thousands)

Deferred Tax Assets                     $  32,186  $ 234,826  $  68,488  $   79,056    $  26,916
Deferred Tax Liabilities                 (197,193)  (911,286)  (350,404)   (455,560)    (175,908)
                                        ---------  ---------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $(165,007) $(676,460) $(281,916)  $(376,504)   $(148,992)
                                        =========  =========  =========   =========    =========

Property Related Temporary Differences  $(114,903) $(599,863) $(308,497)  $(389,680)   $(153,027)
Amounts Due From Customers For Future
                                     -
  Federal Income Taxes                    (19,616)  (108,185)    12,697      (3,366)       4,569
Deferred State Income Taxes               (32,715)   (22,124)   (13,001)       -            -
Deferred Fuel and Purchase Power             -       (62,832)      -           -            -
Provision for Mine Shutdown Costs            -        33,105       -           -            -
Postretirement Benefits                      -        44,483       -           -            -
All Other (net)                             2,227     38,956     26,885      16,542         (534)
                                        ---------  ---------  ---------   ---------    ---------
  Net Deferred Tax Liabilities          $(165,007) $(676,460) $(281,916)  $(376,504)   $(148,992)
                                        =========  =========  =========   =========    =========

The AEP  System  has  settled  with the IRS all  issues  from the  audits of its
consolidated federal income tax returns for the years prior to 1991. Returns for
the years 1991 through 1999 are presently  being audited by the IRS.  Management
is not aware of any issues for open tax years  that upon  final  resolution  are
expected to have a material adverse effect on results of operations.
</TABLE>

17.  Supplementary Information:

                             Year Ended December 31,
                                                       2000     1999     1998
                                                       ----     ----     ----
                                                           (in millions)
AEP Consolidated Purchased Power -
 Ohio Valley Electric Corporation                       $86      $64      $43
  (44.2% owned by AEP System)

Cash was paid for:
  Interest (net of capitalized amounts)                $842     $979     $859
  Income Taxes                                         $449     $270     $540

Noncash Investing and Financing Activities:
 Acquisitions under Capital Leases                     $118      $80     $119
 Assumption of Liabilities Related to Acquisitions       -        -      $152

The amounts of power purchased by the registrant  subsidiaries  from Ohio Valley
Electric  Corporation,  which is 44.2%  owned by the AEP  System,  for the years
ended December 31, 2000, 1999, and 1998 were:

               Year Ended
               December 31,      APCo     CSPCo     I&M       OPCo
               ------------      ----     -----     ---       ----
                                          (in thousands)

               2000            $30,998   $8,706   $15,204   $31,134
               1999             21,774    6,006    10,227    25,623
               1998             10,388    5,947    14,271    12,006



<PAGE>

<TABLE>
<CAPTION>

18. Leases:

Leases of  property,  plant and  equipment  are for  periods  up to 35 years and
require payments of related property taxes, maintenance and operating costs. The
majority of the leases have  purchase or renewal  options and will be renewed or
replaced by other leases.

Lease  rentals for both  operating and capital  leases are generally  charged to
operating expenses in accordance with rate-making  treatment.  The components of
rental costs are as follows:

                                   AEP     AEGCo     APCo    CSPCo      I&M     KPCo     OPCo
Year Ended December 31, 2000                            (in thousands)
Lease Payments on
<S>                             <C>       <C>      <C>      <C>      <C>       <C>      <C>
 Operating Leases               $216,000  $73,858  $ 7,128  $ 7,683  $ 81,446  $1,978   $51,981
Amortization of Capital Leases   121,000      281   13,900    7,776    26,341   3,931    37,280
Interest on Capital Leases        38,000       55    3,930    2,690    10,908   1,054     9,584
                                --------  -------  -------  -------  --------  ------   -------
 Total Lease Rental Costs       $375,000  $74,194  $24,958  $18,149  $118,695  $6,963   $98,845
                                ========  =======  =======  =======  ========  ======   =======


                                   AEP     AEGCo     APCo    CSPCo      I&M     KPCo     OPCo
Year Ended December 31, 1999                            (in thousands)
Lease Payments on
 Operating Leases               $247,000  $74,269  $ 5,647  $ 5,687  $ 81,611  $  199  $ 60,026
Amortization of Capital Leases    97,000      364   13,749    7,427    11,320   4,299    35,622
Interest on Capital Leases        35,000       64    4,267    2,720     9,338   1,162     9,552
                                --------  -------  -------  -------  --------  ------  --------
 Total Lease Rental Costs       $379,000  $74,697  $23,663  $15,834  $102,269  $5,660  $105,200
                                ========  =======  =======  =======  ========  ======  ========


                                   AEP     AEGCo     APCo    CSPCo      I&M     KPCo     OPCo
Year Ended December 31, 1998                            (in thousands)
Lease Payments on
 Operating Leases               $257,000  $76,387  $ 7,047  $ 8,107  $ 88,297  $  931  $ 59,141
Amortization of Capital Leases    91,000      560   13,561    6,530    10,717   4,265    36,585
Interest on Capital Leases        37,000       97    3,541    2,626    10,302   1,173    14,309
                                --------  -------  -------  -------  --------  ------  --------
 Total Lease Rental Costs       $385,000  $77,044  $24,149  $17,263  $109,316  $6,369  $110,035
                                ========  =======  =======  =======  ========  ======  ========

CPL, PSO, SWEPCo and WTU do not have any operating leases.
</TABLE>
<TABLE>
<CAPTION>

Property,  plant and  equipment  under  capital  leases and related  obligations
recorded on the Consolidated Balance Sheets are as follows:

                                  AEP     AEGCo      APCo    CSPCo      I&M       KPCo    OPCo
Year Ended December 31, 2000                             (in thousands)
Property, Plant and Equipment
 Under Capital Leases
<S>                             <C>       <C>      <C>      <C>       <C>       <C>     <C>
 Production                     $ 42,000  $2,017   $ 6,276  $     2   $  7,023  $ 1,730 $ 24,709
 Distribution                    151,000                                14,595
 Other:
  Nuclear Fuel
  (net of amortization)           90,000                                89,872
  Mining Assets and Other        619,000     177    93,437  $68,352     97,383   22,072  200,308
                                --------  ------   -------  -------   --------  ------- ---------
   Total Property, Plant
    and Equipment                902,000   2,194    99,713   68,354    208,873   23,802  225,017
 Accumulated Amortization        288,000   1,603    36,553   25,422     45,700    9,618  108,436
                                --------  ------   -------  -------   --------  ------- ---------
  Net Property, Plant and
   Equipment Under
   Capital Leases               $614,000  $  591   $63,160  $42,932   $163,173  $14,184 $116,581
                                ========  ======   =======  =======   ========  ======= ========

Obligations Under Capital Leases:
  Noncurrent Liability          $419,000  $  358   $50,350  $35,199   $ 62,325  $11,091 $ 83,866
  Liability Due Within One Year  195,000     233    12,810    7,733    100,848    3,093   32,715
                                --------  ------   -------  -------   --------  ------- ---------
      Total Obligations Under
       Capital Leases           $614,000  $  591   $63,160  $42,932   $163,173  $14,184 $116,581
                                ========  ======   =======  =======   ========  ======= =========
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


                                  AEP     AEGCo      APCo    CSPCo      I&M     KPCo     OPCo
Year Ended December 31, 1999                             (in thousands)
Property, Plant and Equipment
 Under Capital Leases
<S>                             <C>       <C>     <C>                <C>       <C>     <C>
 Production                     $ 46,000  $2,350  $  8,354           $  8,348  $ 2,022 $ 24,428
 Distribution                    106,000                               14,645
 Other:
  Nuclear Fuel
   (net of amortization)         108,000                              108,140
  Mining Assets and Other        612,000     226    93,053  $63,386    99,367   24,225  205,209
                                --------  ------  --------  -------  --------  ------- --------
   Total Property, Plant
    and Equipment                872,000   2,576   101,407   63,386   230,500   26,247  229,637
 Accumulated Amortization        262,000   1,708    36,762   23,116    42,535   11,106   93,094
                                --------  ------  --------  -------  --------  ------- --------
  Net Property, Plant and
   Equipment Under
   Capital Leases               $610,000  $  868  $ 64,645  $40,270  $187,965  $15,141 $136,543
                                ========  ======  ========  =======  ========  ======= ========

Obligations Under Capital Leases:
  Noncurrent Liability          $510,000  $  592  $ 52,009  $33,031  $176,893  $11,830 $102,259
  Liability Due Within One Year  100,000     276    12,636    7,239    11,072    3,311   34,284
                                --------  ------  --------  -------  --------  ------- --------
      Total Obligations Under
       Capital Leases           $610,000  $  868  $ 64,645  $40,270  $187,965  $15,141 $136,543
                                ========  ======  ========  =======  ========  ======= ========

Properties  under operating  leases and related  obligations are not included in
the Consolidated Balance Sheets.

CPL,  PSO,  SWEPCo  and WTU do not lease  property,  plant and  equipment  under
capital leases.
</TABLE>
<TABLE>
<CAPTION>

Future minimum lease payments consisted of the following at December 31, 2000:

                                   AEP    AEGCo      APCo     CSPCo     I&M     KPCo     OPCo
Capital (a)                                               (in thousands)
-----------
<S>                             <C>        <C>     <C>       <C>      <C>      <C>      <C>
2001                            $129,000   $255    $16,528   $10,480  $ 14,620 $ 3,929  $ 39,733
2002                              99,000    217     15,526     9,426    13,535   3,501    21,332
2003                              81,000    133     12,872     7,677    11,336   2,661    19,004
2004                              63,000     20     10,336     6,331     9,397   2,004    15,445
2005                              48,000      6      7,027     5,397     7,053   1,609    11,746
Later Years                      397,000      1     13,748    15,376    25,427   3,417    38,710
                                --------   ----    -------   -------  -------- -------  ---------
Total Future Minimum
 Lease Payments                  817,000(a) 632     76,037    54,687    81,368  17,121   145,970
Less Estimated Interest Element  293,000     41     12,876    11,755     8,067   2,937    29,389
                                --------   ----    -------   -------  -------- -------  --------
Estimated Present Value of
  Future Minimum Lease Payments  524,000   $591    $63,161   $42,932    73,301 $14,184  $116,581
                                           ====    =======   =======           =======  ========
Unamortized Nuclear Fuel          90,000                                89,872
                                --------                              --------        -
  Total                         $614,000                              $163,173
                                ========                              ========

(a)   Minimum lease payments do not include nuclear fuel payments.  The payments
      are paid in  proportion  to heat  produced  and  carrying  charges  on the
      unamortized  nuclear  fuel  balance.  There are no minimum  lease  payment
      requirements for leased nuclear fuel.
</TABLE>
<TABLE>
<CAPTION>

                                  AEP        AEGCo     APCo     CSPCo      I&M     KPCo    OPCo
                                                           (in thousands)
Noncancellable Operating Leases
<S>                            <C>        <C>         <C>      <C>      <C>        <C>   <C>
2001                           $  244,000 $   73,854  $  726   $ 4,314  $   99,249 $ 29  $ 62,560
2002                              236,000     73,854     425       774      97,551   26    61,787
2003                              235,000     73,854     412       735      97,385   23    61,109
2004                              235,000     73,854     412       735      96,467   21    61,229
2005                              243,000     73,854     412       735      95,201   21    71,304
Later Years                     3,090,000  1,255,518   2,888     2,820   1,434,570  232   386,629
                               ---------- ----------  ------   -------  ---------- ----  ---------
Total Future Minimum
 Lease Payments                $4,283,000 $1,624,788  $5,275   $10,113  $1,920,423 $352  $704,618
                               ========== ==========  ======   =======  ========== ====  =========

</TABLE>
<PAGE>






19.      Lines of Credit and Factoring of
       Receivables:

The AEP  System  uses  short-term  debt,  primarily  commercial  paper,  to meet
fluctuations  in working capital  requirements  and other interim capital needs.
AEP has established a money pool to coordinate short-term borrowings for certain
subsidiaries, including AEGCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU,
and also incurs borrowings outside the money pool for other subsidiaries.  As of
December 31, 2000, AEP had revolving credit facilities  totaling $3.5 billion to
backup its commercial paper program.  At December 31, 2000, AEP had $2.7 billion
outstanding  in short-term  borrowings.  The maximum  amount of such  short-term
borrowings  outstanding  during the year,  which had a weighted average interest
rate for the year of 7.5%, was $2.7 billion during December 2000.

The registrant  subsidiaries incurred interest expense for amounts borrowed from
the AEP money pool as follows

                    Year Ended December 31,
                   2000      1999      1998
                   ----      ----      ----
                         (in millions)

 CPL              $16.9     $14.1      $8.8
 CSPCo              1.4        -         -
 I&M                0.8        -         -
 KPCo                -         -         -
 OPCo               9.2        -         -
 PSO                7.5       2.0       1.0
 SWEPCo             4.2       4.7       1.8
 WTU                2.7       0.6       0.3

Interest  income  earned  from  amounts  advanced  to the AEP money  pool by the
registrant subsidiaries were:

                    Year Ended December 31,
                   2000      1999      1998
                   ----      ----      ----
                         (in millions)

 CSPCo            $ 1.1     $  -       $ -
 I&M                9.0        -         -
 KPCo               1.8        -         -
 OPCo               3.4        -         -
 PSO                 -         -        0.6
 SWEPCo              -        0.1       0.1
 WTU                 -        0.2       0.4


AEP Credit,  which does not  participate  in the money pool,  issues  commercial
paper on a  stand-alone  basis.  At  December  31,  2000,  AEP Credit had a $2.0
billion  unsecured  revolving  credit  agreement to back up its commercial paper
program,  which  had  $1.2  billion  outstanding.  The  maximum  amount  of such
commercial  paper  outstanding  during the year,  which had a  weighted  average
interest rate for the year of 6.6% was $1.5 billion during September 2000.

Outstanding short-term debt for AEP Consolidated consisted of:

                         December 31,
                    2000             1999
                    ----             ----
                        (in millions)
Balance Outstanding:
  Notes Payable    $  193           $  232
  Commercial Paper  4,140            2,780
                   ------           ------
    Total          $4,333           $3,012
                   ======           ======

In 2000 APCo did not  participate  in AEP's money pool. At December 31, 2000 and
1999,  APCo had issued  commercial  paper in the  amounts of $191.5  million and
$123.5  million,  respectively.  At December  31,  2000,  the  weighted  average
interest rate for APCo's  commercial paper borrowings was 8.24%. In January 2001
APCo  became a  participant  in AEP's  money pool and  retired  all  outstanding
short-term debt.

AEP  Credit  factors  electric  customer  accounts   receivable  for  affiliated
operating  companies and unaffiliated  companies.  AEP Credit 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.


Under the factoring arrangement the registrant subsidiaries (excluding AEGCo and
APCo) sell without  recourse certain of their customer  accounts  receivable and
accrued  utility  revenue  balances to AEP Credit and are charged a fee based on
AEP Credit financing costs, uncollectible accounts experience for each company's
receivables and  administrative  costs. The costs of factoring customer accounts
receivable is reported as an operating expense. At December 31, 2000, the amount
of factored accounts receivable and accrued utility revenues for each registrant
subsidiary was as follows:

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

 CPL               $153
 CSPCo              116
 I&M                103
 KPCo                30
 OPCo               104
 PSO                108
 SWEPCo              91
 WTU                 52

The  fees  paid by the  registrant  subsidiaries  to AEP  Credit  for  factoring
customer accounts receivable were:

                   Year Ended December 31,
                   2000      1999      1998
                   ----      ----      ----
                         (in millions)

 CPL              $15.7     $14.7     $12.8
 CSPCo             10.8        -         -
 I&M                6.8        -         -
 KPCo               1.9        -         -
 OPCo               8.4        -         -
 PSO                8.3       6.5       7.7
 SWEPCo             9.2       9.3       9.1
 WTU                4.0       3.5       3.7



<PAGE>



20.  Unaudited Quarterly Financial Information:

The unaudited quarterly financial information for AEP Consolidated follows:

                                    2000 Quarterly Periods Ended
                       -------------------------------------------------------
                        March 31        June 30       Sept. 30       Dec. 31
                       ----------     ----------     ----------     ----------
(In Millions - Except
Per Share Amounts)
-----------------------
Operating Revenues       $3,021          $3,169         $3,915        $3,589
Operating Income            428             308            873           417
Income (Loss) Before
 Extraordinary Items        140             (18)           403          (223)
Net Income (Loss)           140              (9)           359          (223)
Earnings (Loss)
 per Share                 0.43           (0.03)          1.11         (0.68)

Fourth  quarter 2000 earnings  decreased  $415 million from the prior year.  The
decrease was  primarily due to various  unfavorable  items  including:  a ruling
disallowing  interest  deductions claimed by AEP relating to its COLI program of
$319  million;  $35 million of the Cook Plant restart  costs;  and a $30 million
writedown for the proposed sale of Yorkshire.  Additionally,  the fourth quarter
of 1999 includes a $33 million gain on the sale of Sweeney in October.

                                    1999 Quarterly Periods Ended
                       -------------------------------------------------------
                        March 31        June 30       Sept. 30       Dec. 31
                       ----------     ----------     ----------     ----------
(In Millions - Except
Per Share Amounts)
-----------------------

Operating Revenues       $2,902          $2,963         $3,528        $3,014
Operating Income            525             552            802           446
Income Before
 Extraordinary Items        195             190            403           198
Net Income                  195             190            395           192
Earnings per Share         0.61            0.59           1.23          0.60


<PAGE>
<TABLE>
<CAPTION>
The unaudited quarterly financial information for each AEP registrant subsidiary
follows:

     Quarterly Periods
     Ended                                  AEGCo     APCo       CPL      CSPCo      I&M
     -----------------                      -----     ----       ---      -----      ---
                                                           (in thousands)
     2000
     March 31
<S>                                        <C>      <C>       <C>       <C>       <C>
      Operating Revenues                   $56,866  $455,595  $316,328  $298,306  $343,986
      Operating Income                       2,395    78,246    38,650    44,124   (15,251)
      Income (Loss) Before
        Extraordinary Items                  2,445    47,664     8,139    27,471   (36,553)
      Net Income (Loss)                      2,445    47,664     8,139    27,471   (36,553)

     June 30
      Operating Revenues                   $56,928  $430,000  $437,911  $330,914  $362,272
      Operating Income                       1,746    58,208    95,717    50,798   (18,599)
      Income (Loss) Before
        Extraordinary Items                  1,653    30,240    67,553    35,335   (39,181)
      Net Income (Loss)                      1,653    39,178    67,553    35,335   (39,181)

     September 30
      Operating Revenues                   $55,658  $475,092  $601,369  $386,583  $423,217
      Operating Income                       2,209    65,750   120,653    83,562    36,056
      Income Before Extraordinary Items      1,972    36,112    89,974    65,542    15,190
      Net Income                             1,972    36,112    89,974    40,306    15,190

     December 31
      Operating Revenues                   $59,064  $499,478  $415,569  $340,605  $419,001
      Operating Income                       2,074    (1,050)   52,078    17,393   (36,908)
      Income (Loss) Before
        Extraordinary Items                  1,914   (49,110)   23,901    (8,146)  (71,488)
      Net Income (Loss)                      1,914   (49,110)   23,901    (8,146)  (71,488)

     Quarterly Periods
     Ended                                   KPCo     OPCo       PSO     SWEPCo     WTU
     -----------------                       ----     ----       ---     ------     ---
                                                           (in thousands)
     2000
     March 31
      Operating Revenues                  $ 97,204  $545,411  $161,329  $212,156  $ 96,535
      Operating Income                      15,557    65,113    10,860    22,731     9,781
      Income Before Extraordinary Items      8,052    46,216     1,165     7,663     3,833
      Net Income                             8,052    46,216     1,165     7,663     3,833

     June 30
      Operating Revenues                  $ 97,759  $540,321  $209,172  $272,409  $130,742
      Operating Income                       9,456    79,968    24,502    33,296    16,938
      Income Before Extraordinary Items      2,449    58,233    14,700    18,786     8,070
      Net Income                             2,449    58,233    14,700    18,786     8,070

     September 30
      Operating Revenues                  $106,698  $582,702  $358,710  $377,442  $201,191
      Operating Income                      13,790    96,652    56,437    61,312    16,565
      Income Before Extraordinary Items      6,761    77,061    54,329    47,537    10,670
      Net Income                             6,761    58,185    54,329    47,537    10,670

     December 31
      Operating Revenues                  $108,742  $559,468  $233,398  $262,203  $144,326
      Operating Income                      10,935   (14,906)    4,870    10,939     9,057
      Income (Loss) Before
        Extraordinary Items                  3,501   (78,897)   (3,531)   (1,314)    4,877
      Net Income (Loss)                      3,501   (78,897)   (3,531)   (1,314)    4,877

In the fourth  quarter of 2000  earnings  for APCo,  CSPCo,  I&M,  and OPCo were
effected by a ruling disallowing  interest deductions claimed by AEP relating to
its COLI program.  The unfavorable amounts are $82 million for APCo, $41 million
for CSPCo,  $66 million for I&M, $8 million for KPCo and $118  million for OPCo.
Additionally I&M incurred costs in the fourth quarter of 2000 for the Cook Plant
restart of $35 million.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>


     Quarterly Periods
     Ended                                  AEGCo     APCo       CPL      CSPCo      I&M
     -----------------                      -----     ----       ---      -----      ---
                                                           (in thousands)

     1999
     March 31
<S>                                        <C>      <C>       <C>       <C>       <C>
      Operating Revenues                   $52,827  $427,702  $282,278  $279,067  $334,113
      Operating Income                       2,360    71,607    46,091    46,047    38,838
      Income Before Extraordinary Items      2,614    39,261    17,020    27,418    20,070
      Net Income                             2,614    39,261    17,020    27,418    20,070

     June 30
      Operating Revenues                   $51,612  $373,766  $383,783  $301,419  $336,553
      Operating Income                       1,002    43,099    79,679    54,473    26,966
      Income Before Extraordinary Items      1,222    11,036    51,024    34,559     9,745
      Net Income                             1,222    11,036    51,024    34,559     9,745

     September 30
      Operating Revenues                   $57,235  $441,435  $495,653  $368,946  $411,248
      Operating Income                         921    66,309   127,499    83,478    26,085
      Income Before Extraordinary Items        958    35,661   103,989    63,719     8,084
      Net Income                               958    35,661   103,989    63,719     8,084

     December 31
      Operating Revenues                   $55,515  $408,034  $320,761  $280,562  $312,205
      Operating Income                       1,057    60,221    40,716    38,792    16,763
      Income (Loss) Before
        Extraordinary Items                  1,401    34,534    15,685    24,574    (5,123)
      Net Income (Loss)                      1,401    34,534    10,168    24,574    (5,123)

     Quarterly Periods
     Ended                                  KPCo      OPCo       PSO     SWEPCo     WTU
     -----------------                      ----      ----       ---     ------     ---
                                                          (in thousands)

     1999
     March 31
      Operating Revenues                  $ 90,741  $518,221  $151,030  $197,064  $ 81,052
      Operating Income                      15,360    78,956    12,031    25,810     6,922
      Income Before Extraordinary Items      8,209    60,821     2,423    12,095       932
      Net Income                             8,209    60,821     2,423    12,095       932

     June 30
      Operating Revenues                  $ 86,231  $498,587  $178,699  $242,888  $107,782
      Operating Income                      10,233    73,328    23,172    35,269    16,361
      Income Before Extraordinary Items      2,995    51,865    13,955    21,411    10,116
      Net Income                             2,995    51,865    13,955    21,411    10,116

     September 30
      Operating Revenues                  $ 94,939  $544,451  $258,656  $312,035  $164,104
      Operating Income                      14,244    72,858    57,720    61,541    27,030
      Income Before Extraordinary Items      7,197    56,233    50,257    44,908    21,413
      Net Income                             7,197    56,233    50,257    41,897    15,952

     December 31
      Operating Revenues                  $102,071  $478,004  $161,005  $219,540  $ 92,771
      Operating Income                      14,838    63,687     5,790    24,442     3,486
      Income (Loss) Before
        Extraordinary Items                  7,029    43,238    (5,127)    7,791      (594)
      Net Income (Loss)                      7,029    43,238    (5,127)    7,791      (594)
</TABLE>
<TABLE>
<CAPTION>

21.  Trust Preferred Securities:

The following Trust Preferred  Securities  issued by the wholly-owned  statutory
business trusts of CPL, PSO and SWEPCo were outstanding at December 31, 2000 and
December  31,  1999.  They are  classified  on the  balance  sheets  as  certain
subsidiaries   Obligated,   Mandatorily   Redeemable   Preferred  Securities  of
Subsidiary  Trusts  Holding  Solely  Junior  Subordinated   Debentures  of  such
subsidiaries.  The Junior Subordinated  Debentures mature on April 30, 2037. CPL
reacquired 60,000 trust preferred units during 2000.

                                 Units issued/   2000       1999     Description of
                                 outstanding    Amount     Amount    Underlying
Business Trust      Security     at 12/31/00  (millions) (millions)  Debentures of Registrant
---------------------------------------------------------------------------------------------

<S>              <C>               <C>           <C>        <C>      <C>
CPL Capital I    8.00%, Series A   5,940,000     $149       $150     CPL, $153 million,
                                                                     8.00%, Series A
PSO Capital I    8.00%, Series A   3,000,000       75         75     PSO, $77 million,
                                                                     8.00%, Series A
SWEPCo Capital I 7.875%, Series A  4,400,000      110        110     SWEPCO, $113 million,
                                  ----------     ----       ----
                                  13,340,000     $334       $335     7.875%, Series A
                                  ==========     ====       ====

Each of the business  trusts is treated as a subsidiary  of its parent  company.
The only assets of the business trusts are the subordinated debentures issued by
their parent company as specified  above. In addition to the  obligations  under
their subordinated debentures, each of the parent companies has also agreed to a
security  obligation which represents a full and unconditional  guarantee of its
capital trust obligation.
</TABLE>
<TABLE>
<CAPTION>

22.  Jointly Owned Electric Utility Plant:

CPL, CSP, PSO, SWEPCo and WTU have generating  units that are jointly owned with
unaffiliated companies.  Each of the participating companies is obligated to pay
its  share  of the  costs  of any  such  jointly  owned  facilities  in the same
proportion  as  its  ownership  interest.   Each  AEP  registrant   subsidiary's
proportionate  share of the operating  costs  associated with such facilities is
included in its  statements of income and the  investments  are reflected in its
balance sheets under utility plant as follows:

                                Company's Share
                                  December 31,
                                                     2000                        1999
                                          --------------------------  ---------------------------
                                 Percent     Utility    Construction     Utility   Construction
                                   of         Plant         Work          Plant         Work
                                Ownership  in Service   in Progress    in Service   in Progress
                                --------- ------------ -------------  ------------ ------------
                                                   (in thousands)            (in thousands)
CPL:
  Oklaunion Generating Station
<S>         <C>                        <C>     <C>            <C>         <C>           <C>
  (Unit No. 1)                         7.8     $   37,236     $   395     $   37,236    $  -
  South Texas Project Generating
   Station (Units No. 1 and 2)        25.2      2,373,575      19,292      2,351,795     56,021
                                               ----------     -------     ----------    -------
                                               $2,410,811     $19,687     $2,389,031    $56,021
                                               ==========     =======     ==========    ========

CSP:
  W.C. Beckjord Generating Station
   (Unit No. 6)                       12.5     $   14,108     $   178     $   13,919    $   390
  Conesville Generating Station
   (Unit No. 4)                       43.5         80,103         261         80,433         80
  J.M. Stuart Generating Station      26.0        191,875      10,086        184,168      3,620
  Wm. H. Zimmer Generating Station    25.4        706,549       5,265        701,054      6,030
  Transmission                         (a)         61,820         451         60,333      1,210
                                               ----------     -------     ----------    -------
                                               $1,054,455     $16,241     $1,039,907    $11,330
                                               ==========     =======     ==========    =======

PSO:
  Oklaunion Generating Station
   (Unit No. 1)                       15.6     $   81,185     $   817     $   81,185    $  -
                                               ==========     =======     ==========    ========

SWEPCo:
  Dolet Hills Generating Station
   (Unit No. 1)                       40.2     $  231,442     $ 1,984     $  230,971    $ 1,771
  Flint Creek Generating Station
   (Unit No. 1)                       50.0         82,899         852         81,895        286
  Pirkey Generating Station
   (Unit No. 1)                       85.9        437,069         435        434,960      1,777
                                               ----------     -------     ----------    -------
                                               $  751,410     $ 3,271     $  747,826    $ 3,834
                                               ==========     =======     ==========    ========

WTU:
  Oklaunion Generating Station
   (Unit No. 1)                       54.7     $  277,624     $ 3,295     $  281,777    $  -
                                               ==========     =======     ==========    ========


(a)      Varying percentages of ownership.

The accumulated  depreciation  with respect to each AEP registrant  subsidiary's
share of jointly owned facilities is shown below:

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

                                        CPL      $834,722  $758,460
                                        CSPCo     389,558   361,113
                                        PSO        33,669    36,374
                                        SWEPCo    367,558   354,360
                                        WTU        98,045    93,807

</TABLE>
<PAGE>





23.      Related Party Transactions

AEP System Power Pool

APCo, CSPCo, I&M, KEPCo and OPCo are parties to the  Interconnection  Agreement,
dated July 6, 1951,  as amended (the  Interconnection  Agreement),  defining how
they share the costs and benefits  associated with their generating plants. This
sharing is based upon each  company's  "member-load-ratio,"  which is calculated
monthly on the basis of each  company's  maximum  peak demand in relation to the
sum of the maximum peak demands of all five  companies  during the  preceding 12
months.  In addition,  since 1995,  APCo,  CSPCo,  I&M, KEPCo and OPCo have been
parties to the AEP System Interim  Allowance  Agreement  which  provides,  among
other things,  for the transfer of SO2 Allowances  associated with  transactions
under the Interconnection Agreement.

Power marketing and trading  transactions  (trading activities) are conducted by
the AEP Power  Pool and  shared  among  the  parties  under the  Interconnection
Agreement.

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

CPL, PSO, SWEPCo, WTU and AEP Service  Corporation are parties to a Restated and
Amended  Operating  Agreement  originally  dated  as of  January  1,  1997  (CSW
Operating  Agreement).  The  CSW  Operating  Agreement  requires  the  operating
companies of the west zone to maintain specified annual planning reserve margins
and  requires  the  subsidiaries  that have  capacity in excess of the  required
margins to make such capacity  available for sale to other AEP  subsidiaries  as
capacity commitments.  The CSW Operating Agreement also delegates to AEP Service
Corporation the authority to coordinate the acquisition,  disposition, planning,
design and  construction of generating  units and to supervise the operation and
maintenance of a central  control center.  The CSW Operating  Agreement has been
accepted for filing and allowed to become effective by FERC.

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

The  following  table  shows the  revenues  derived  from sales to the Pools and
direct sales to affiliates for years ended December 31, 2000, 1999 and 1998:


<PAGE>
<TABLE>
<CAPTION>



                                          APCo     CSPCo    I&M     KPCo    OPCo    AEGCo
     Related Party Revenues                                (in thousands)

<C>      <S>                            <C>      <C>     <C>      <C>     <C>      <C>
2000     Sales to East System Pool      $ 81,013 $36,884 $200,474 $36,554 $502,140 $   -
         Sales to West System Pool         7,697   4,095    4,614   1,829    6,356     -
         Direct Sales To East Affiliates  59,106    -        -       -      66,487  227,983
         Direct Sales To West Affiliates   4,092   2,262    2,510     972    3,421     -
                                        -------- ------- -------- ------- -------- ---------
            Total Revenues              $151,908 $43,241 $207,598 $39,355 $578,404 $227,983
                                        ======== ======= ======== ======= ======== ========

1999     Sales to East System Pool       $41,869 $15,136  $50,624 $43,157 $337,699 $   -
         Direct Sales To East Affiliates  57,201    -        -       -      50,968  152,559
                                         ------- -------  ------- ------- -------- --------
            Total Revenues               $99,070 $15,136  $50,624 $43,157 $388,667 $152,559
                                         ======= =======  ======= ======= ======== ========

1998     Sales to East System Pool       $36,930 $20,128  $37,561 $43,543 $363,343 $   -
         Direct Sales To East Affiliates  56,753    -        -       -      55,167  153,537
                                         ------- -------  ------- ------- -------- --------
            Total Revenues               $93,683 $20,128  $37,561 $43,543 $418,510 $153,537
                                         ======= =======  ======= ======= ======== ========

</TABLE>



                                         CPL      PSO     SWEPCo   WTU
Related Party Revenues                            (in thousands)

2000     Sales to East System Pool       $  -    $  -     $  -    $  -
         Sales to West System Pool        23,421   7,323    5,546     194
         Direct Sales To East Affiliates  (3,348) (1,990)  (3,008) (1,116)
         Direct Sales To West Affiliates  12,516  21,995   62,178   7,645
                                         ------- -------  ------- -------
            Total Revenues               $32,589 $27,328  $64,716 $ 6,723
                                         ======= =======  ======= =======

1999     Sales to West System Pool       $ 6,124 $ 3,097  $ 4,527  $  401
         Direct Sales To West Affiliates   7,470   7,968   49,542   2,576
                                         ------- -------  -------  ------
             Total Revenues              $13,594 $11,065  $54,069  $2,977
                                         ======= =======  =======  ======

1998     Sales to West System Pool       $ 7,853 $ 3,223  $ 5,660  $  270
         Direct Sales To West Affiliates   9,798  10,196   29,811   2,190
                                         ------- -------  -------  ------
             Total Revenues              $17,651 $13,419  $35,471  $2,460
                                         ======= =======  =======  ======
<TABLE>
<CAPTION>

The following  table shows the purchased  power expense  incurred from purchases
from the Pools and affiliates  for the years ended December 31, 2000,  1999, and
1998:

                                                APCo     CSPCo    I&M      KPCo     OPCo
Related Party Purchases                                      (in thousands)

<C>      <S>                                    <C>      <C>      <C>      <C>       <C>
2000     Purchases from East System Pool       $355,305 $287,482 $106,644 $ 58,150  $50,339
         Purchases from West System Pool            455      260      285      108      390
         Direct Purchases from East Affiliates     -        -     158,537   69,446     -
         Direct Purchases from West Affiliates       14        8        9        3       12
                                               -------- -------- -------- --------  -------
             Total Purchases                   $355,774 $287,750 $265,475 $127,707  $50,741
                                               ======== ======== ======== ========  =======

1999     Purchases from East System Pool       $130,991 $199,574 $112,350  $19,502 $ 20,864
         Direct Purchases from East Affiliates     -        -      88,022   64,498     -
                                               -------- -------- --------  ------- ---------
             Total Purchases                   $130,991 $199,574 $200,372  $84,000 $ 20,864
                                               ======== ======== ========  ======= ========

1998     Purchases from East System Pool       $180,762 $167,619 $125,240  $ 9,673 $ 18,211
         Direct Purchases from East Affiliates     -        -      86,246   67,291     -
                                               -------- -------- --------  ------- ---------
             Total Purchases                   $180,762 $167,619 $211,486  $76,964 $ 18,211
                                               ======== ======== ========  ======= ========

                                                CPL      PSO     SWEPCo    WTU
Related Party Purchases                                  (in thousands)

2000     Purchases from East System Pool        $  -     $20,100  $  -    $  -
         Purchases from West System Pool          1,696    5,386    4,379  18,444
         Direct Purchases from East Affiliates      251    2,117     -         71
         Direct Purchases from West Affiliates   30,644   33,185    8,264  39,258
                                                -------  -------  ------- -------
             Total Purchases                    $32,591  $60,788  $12,643 $57,773
                                                =======  =======  ======= =======

1999     Purchases from West System Pool        $   895  $ 6,992   $1,295 $ 7,266
         Direct Purchases from West Affiliates   15,778   27,627    6,256  19,325
                                                -------  -------   ------ -------
             Total Purchases                    $16,673  $34,619   $7,551 $26,591
                                                =======  =======   ====== =======

1998     Purchases from West System Pool         $1,091  $ 5,022  $ 2,579 $ 8,314
         Direct Purchases from West Affiliates    8,636   15,970    7,576  20,935
                                                 ------  -------  ------- -------
             Total Purchases                     $9,727  $20,992  $10,155 $29,249
                                                 ======  =======  ======= =======

</TABLE>
<PAGE>


AEP System Transmission Pool

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

The  following  table shows the net  (credits)  or charges  allocated  among the
parties to the Transmission  Agreement during the years ended December 31, 1998,
1999 and 2000:

            1998         1999          2000
            ----         ----          ----
                    (in thousands)

APCo     $ (2,400)    $ (8,300)    $ (3,400)
CSPCo      35,600       39,000       38,300
I&M       (44,100)     (43,900)     (43,800)
KEPCo      (6,000)      (4,300)      (6,000)
OPCo       16,900       17,500       14,900

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

Under the TCA,  the west  zone  operating  subsidiaries  have  delegated  to AEP
Service  Corporation the  responsibility  of monitoring the reliability of their
transmission  systems and administering  the OATT on their behalf.  The TCA also
provides  for the  allocation  among the west  zone  operating  subsidiaries  of
revenues  collected for transmission and ancillary  services  provided under the
OATT.  In December  1999,  the FERC approved the TCA filing based on the revised
revenue  allocation ratios effective as of January 1, 1997. In January 2000, the
west zone operating  companies  settled among  themselves,  including  interest,
under the revised TCA.

The  following  table shows the net  (credits) or charges,  excluding  interest,
allocated  among the west  zone  operating  companies  during  the  years  ended
December 31, 1998, 1999 and 2000:

            1998         1999          2000
            ----         ----          ----
                    (in thousands)

CPL       $  -         $  -        $(15,498)
WTU         1,139          (28)     (23,443)
SWEPCo      3,572        1,058       22,115
PSO        (4,711)      (1,030)      16,826

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

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

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

Unit Power Agreements and Other

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

Pursuant  to an  assignment  between I&M and KEPCo,  and a unit power  agreement
between  KEPCo and  AEGCo,  AEGCo  sells  KEPCo 30% of the power (and the energy
associated  therewith) available to AEGCo from both units of the Rockport Plant.
KEPCo has agreed to pay to AEGCo in consideration  for the right to receive such
power the same  amounts  which I&M would have paid AEGCo  under the terms of the
I&M Power Agreement for such entitlement. The KEPCo unit power agreement expires
on December 31, 2004.

APCo and OPCo,  jointly  own two power  plants.  The  costs of  operating  these
facilities are apportioned between the owners based on ownership interests. Each
company's share of these costs is included in the appropriate  expense  accounts
on each company's  consolidated  statements of income. Each company's investment
in these  plants is  included  in  electric  utility  plant on its  consolidated
balance sheets.

I&M provides barging services to AEGCo, APCo and OPCo. I&M records revenues from
barging services as nonoperating income.  AEGCo, APCo and OPCo record costs paid
to I&M for barging services as fuel expense.  The amount of affiliated  revenues
and affiliated expenses were:

                    Year Ended December 31,
                     2000     1999     1998
                     ----     ----     ----
Company                   (in millions)

I&M - revenues      $23.5    $28.1    $24.8
AEGCo - expense       8.8      8.5      8.8
APCo - expense        7.8     10.5      8.5
OPCo - expense        6.9      9.1      7.5

American Electric Power Service  Corporation (AEPSC) provides certain managerial
and professional services to AEP System companies. The costs of the services are
billed to its affiliated companies by AEPSC on a direct-charge  basis,  whenever
possible, and on reasonable bases of proration for shared services. The billings
for services are made at cost and include no compensation  for the use of equity
capital,  which is furnished to AEPSC by AEP Co.,  Inc.  Billings from AEPSC are
capitalized or expensed depending on the nature of the services rendered.  AEPSC
and its billings are subject to the regulation of the SEC under the 1935 Act.



<PAGE>




                                      M-26
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS
----------------------------------------------------------------------------



<PAGE>



        The following is a combined presentation of management's  discussion and
analysis of financial  condition,  contingencies  and other  matters for AEP and
certain of its registrant subsidiaries.  Management's discussion and analysis of
results  of  operations  for  AEP  and  each of its  subsidiary  registrants  is
presented  with  their  financial  statements  earlier  in  this  document.  The
following  is a list of  sections of  management's  discussion  and  analysis of
financial condition, contingencies and other matters and the registrant to which
they apply:

Financial Condition         AEP, APCo, CPL,
                            I&M, OPCo, SWEPCo

Market Risks                AEP, AEGCo, APCo,
                            CPL, CSPCo, I&M,
                            KPCo, OPCo, PSO,
                            SWEPCo, WTU

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

Litigation                  AEP, APCo, CPL,
                            CSPCo, I&M, KPCo,
                            OPCo, SWEPCo, WTU

Environmental Concerns
 and Issues                 AEP, APCo, CPL,
                            CSPCo, I&M, OPCo,
                            SWEPCo

Foreign Energy Delivery,    AEP
 Worldwide Energy
 Investments and Other
 Business Operations

Other Matters               AEP, AEGCo, APCo,
                            CPL, CSPCo, I&M,
                            KPCo, OPCo, PSO,
                            SWEPCo, WTU

Financial Condition - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo

        The  Cook  Plant  extended  outage  and  related  restart   expenditures
negatively affected AEP's 2000 earnings and cash flows and the write-off related
to COLI and non-regulated subsidiaries further depressed earnings.  Although the
2000 dividend  payout ratio was 289%, it is expected that the ratio will improve
significantly as a result of earnings growth in 2001. It has been a




management  objective  to  reduce  the  payout  ratio  by  increasing  earnings.
Management expects to grow future earnings by growing the wholesale business and
by controlling operations and maintenance costs.

        AEP's common equity to total  capitalization,  including  long-term debt
due within one year and  short-term  debt,  decreased from 37% in 1999 to 34% in
2000.  Preferred stock at 1% remained  unchanged.  Long-term debt decreased from
50% to 47%, while  short-term debt increased from 12% to 18%. AEP's intention is
to maintain  flexibility  during  corporate  separation by issuing floating rate
debt.  In  2000,  AEP did not  issue  any  shares  of  common  stock to meet the
requirements of the Dividend Reinvestment and Direct Stock Purchase Plan and the
Employee Savings Plan. Sales of common stock and/or equity linked securities may
be necessary in the future to support AEP's plan to grow the business.

        Expenditures   by  the  AEP  System  for   domestic   electric   utility
construction  are  estimated  to  be  $6  billion  for  the  next  three  years.
Approximately 70% of those construction expenditures are expected to be financed
by internally generated funds.

        Construction  expenditures for the registrant  subsidiaries for the next
three years excluding AFUDC are:

                              Construction
          Projected           Expenditures
          Construction        Financed with
          Expenditures        Internal Funds
         (in millions)

APCo         $1,122.8               79%
I&M             427.2               ALL
OPCo          1,044.5               ALL
CPL             745.1              NONE
SWEPCo          405.6               70%



<PAGE>


        The  year-end  ratings of the  subsidiaries'  first  mortgage  bonds are
listed in the following table:

Company          Moody's    S&P     Fitch

APCo              A3        A       A-
CSPCo             A3        A-      A
I&M               Baa1      A-      BBB+
KPCo              Baa1      A-      BBB+
OPCo              A3        A-      A-
CPL               A3        A-      A
PSO               A1        A       A+
SWEPCo            A1        A       A+
WTU               A2        A-      A

        The ratings at the end of the year for senior  unsecured  debt issued by
the subsidiaries are listed in the following table:

Company          Moody's    S&P     Fitch

AEP Resources*    Baa2      BBB+    BBB+
APCo              Baa1      BBB+    BBB+
CSPCo             Baa1      BBB+    A-
I&M               Baa2      BBB+    BBB
KPCo              Baa2      BBB+    BBB
OPCo              Baa1      BBB+    BBB+
CPL               Baa1      BBB+    A-
PSO               A2        BBB+    A
SWEPCo            A2        BBB+    A
WTU               A3        BBB+    -

o The rating is for a series of senior  notes  issued  with a Support  Agreement
from AEP.

Financing Activity

        Debt  was  issued  in 2000  for the  funding  of  debt  maturities,  for
construction programs and for the growth of the wholesale business.  AEP and its
subsidiaries  issued $1.1 billion  principal amount of long-term  obligations in
2000 at variable  interest  rates with due dates ranging from 2001 to 2007.  The
principal amount of long-term debt retirements,  including  maturities,  totaled
$1.6 billion with interest rates ranging from 5.25% to 9.6%.

        The principal amount of long-term obligations issued and retired in 2000
by the registrant subsidiaries was:

           Issuance           Retirements
                 (in thousands)

APCo       $ 75,000            $136,000
I&M         200,000             148,000
OPCo         75,000              32,102
CPL         150,000             150,000
SWEPCo      150,000              45,595

        The domestic  electric utility  subsidiaries  generally issue short-term
debt to provide  for  interim  financing  of capital  expenditures  that  exceed
internally   generated  funds.  They   periodically   reduce  their  outstanding
short-term  debt  through  issuances of long-term  debt and  additional  capital
contributions  by the parent  company.  The  sources of funds  available  to the
parent  company,  AEP,  are  dividends  from its  subsidiaries,  short-term  and
long-term borrowings and proceeds from the issuance of common stock.

        The   subsidiaries   formed  to  pursue   worldwide   electric  and  gas
opportunities  use  short-term  debt and capital  contributions  from the parent
company for interim  financing of working capital and  acquisitions.  Short-term
debt is replaced  with  long-term  debt when  financial  market  conditions  are
favorable.   Some   acquisitions  of  existing  business  entities  include  the
assumption of their outstanding debt.

        The AEP System uses short-term debt, primarily commercial paper, to meet
fluctuations  in working capital  requirements  and other interim capital needs.
AEP has  established a system money pool to meet the  short-term  borrowings for
certain of its subsidiaries,  including AEGCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and WTU. In January  2001 APCo became a  participant  in AEP's money pool
and retired all  outstanding  short-term  debt. In addition,  AEP also funds the
short-term debt requirements of other  subsidiaries that are not included in the
money pool. As of December 31, 2000, AEP had back up credit facilities  totaling
$3.5 billion to support its commercial paper program.  At December 31, 2000, AEP
had $2.7 billion  outstanding  in short-term  borrowings.  The maximum amount of
short-term borrowings  outstanding during the year, which had a weighted average
interest rate for the year of 7.5%, was $2.7 billion during December 2000.

AEP Credit purchases,  without recourse,  the accounts receivable of most of the
domestic utility operating companies and certain non-affiliated electric utility
companies.  The sale of  accounts  receivable  provides  the  domestic  electric
utility  operating  companies with cash  immediately,  thereby  reducing working
capital  needs and revenue  requirements.  In  addition,  AEP  Credit's  capital
structure  contains greater leverage than that of the domestic  electric utility
operating companies, so cost of capital is lowered. AEP Credit issues commercial
paper to meet its financing  needs.  At December 31, 2000, AEP Credit had a $2.0
billion  unsecured  back up credit  facility  to support  its  commercial  paper
program,  which  had  $1.2  billion  outstanding.  The  maximum  amount  of such
commercial  paper  outstanding  during the year,  which had a  weighted  average
interest rate of 6.6%, was $1.5 billion during September 2000.

Market Risks - Affecting AEP, AEGCo,  APCo, CPL,  CSPCo,  I&M, KPCo,  OPCo, PSO,
SWEPCo and WTU

        AEP as a major power producer and a trader of wholesale  electricity and
natural gas has certain  market risks inherent in its business  activities.  The
trading  of  electricity  and  natural  gas  and  related  financial  derivative
instruments  exposes AEP to market risk. Market risk represents the risk of loss
that may impact due to changes in commodity  market  prices and rates.  Policies
and procedures have been established to identify, assess, and manage market risk
exposures  including the use of a risk measurement  model which calculates Value
at Risk  (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  one-day  holding  period.  Throughout  the year  ending
December 31, 2000 the average,  high, and low VaRs in the wholesale  electricity
and gas  trading  portfolio  were $10  million,  $32  million,  and $1  million,
respectively.  The average,  high, and low VaRs for the year ending December 31,
1999 were $4 million, $8 million,  and $1 million,  respectively.  Based on this
VaR  analysis,  at December  31, 2000 a near term  typical  change in  commodity
prices is not expected to have a material effect on AEP's results of operations,
cash  flows or  financial  condition.  The  following  table  shows the high and
average  U.S.  electricity  market risk as measured by VaR  allocated to the AEP
registrant  subsidiaries  based upon the AEP System's trading  activities in the
U.S. Low VaR is excluded because all companies are under $1 million.

VaR for Registrant Subsidiaries:

                          December 31,
                    2000             1999
                    ----             ----
                 High Average     High Average
                        (in millions)

APCo             $2     $6        $1     $2
CPL               1      4         -      -
CSPCo             1      3         1      1
I&M               1      4         1      2
KPCo              -      1         -      1
OPCo              2      5         1      2
PSO               1      3         -      -
SWEPCo            1      4         -      -
WTU               -      1         -      -

        Investments in foreign  ventures expose AEP to risk of foreign  currency
fluctuations.  AEP's  exposure  to changes in foreign  currency  exchange  rates
related  to  these  foreign  ventures  and  investments  is not  expected  to be
significant for the foreseeable future.

        AEP is exposed to changes in interest  rates  primarily due to short-and
long-term borrowings to fund its business operations. AEP measures interest rate
market risk exposure utilizing a VaR model. The interest rate VaR model is based
on a Monte Carlo  simulation with a 95% confidence  level and a one year holding
period.  The volatilities  and correlations  were based on three years of weekly
prices.  The risk of potential loss in fair value attributable to AEP's exposure
to interest  rates,  primarily  related to  long-term  debt with fixed  interest
rates,  was $998  million at December  31, 2000 and $966 million at December 31,
1999. The following  table shows the potential loss in fair value as measured by
VaR allocated to the AEP registrant subsidiaries based upon debt outstanding:


<PAGE>


VaR for Registrant Subsidiaries:

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

AEGCo               $  4               $  4
APCo                 149                144
CPL                  135                131
CSPCo                 84                 81
I&M                  129                125
KPCo                  31                 30
OPCo                 112                109
PSO                   44                 42
SWEPCo                60                 58
WTU                   24                 23
        AEP and its  registrant  subsidiaries  would not expect to liquidate its
entire debt  portfolio  in a one year  holding  period.  Therefore,  a near term
change in interest rates should not  materially  affect results of operations or
the consolidated financial position of AEP and its registrant subsidiaries.  AEP
is currently  utilizing interest rate swaps as a hedge to manage its exposure to
interest rate fluctuations in the U.K. and Australia.

        AEP has  investments  in debt and  equity  securities  which are held in
nuclear trust funds. The trust investments and their fair value are discussed in
Note 15 of the Notes to Consolidated  Financial  Statements.  Instruments in the
trust funds have not been included in the market risk  calculation  for interest
rates as these instruments are  marked-to-market and changes in market value are
reflected in a corresponding  decommissioning liability. Any differences between
the trust fund assets and the  ultimate  liability  should be  recoverable  from
ratepayers.

        AEGCo  is not  exposed  to  risk  from  changes  in  interest  rates  on
short-term and long-term  borrowings used to finance oper-ations since financing
costs are recovered through the unit power agreements.

        Inflation affects the AEP's System's cost of replacing utility plant and
the cost of operating and maintaining its plant. The rate-making  process limits
recovery to the historical cost of assets, resulting in economic losses when the
effects  of  inflation  are not  recovered  from  customers  on a timely  basis.
However,  economic  gains that result from the repayment of long-term  debt with
inflated dollars partly offset such losses.
Industry Restructuring

        In  2000  California's   deregulated  energy  market  suffered  problems
including high energy prices,  short energy supply,  and financial  difficulties
for retail  energy  suppliers  whose prices to customers  are  controlled.  This
energy  crisis  has  highlighted  the  importance  of  risk  management  and has
contributed  to certain state  regulatory  and  legislative  actions which could
delay the start of customer  choice and the  transition to  competitive,  market
based pricing for retail  electricity  supply in some of the states in which the
AEP System companies operate.  Seven of the eleven state retail jurisdictions in
which the domestic electric utility companies operate have enacted restructuring
legislation.  In  general,  the  legislation  provides  for  a  transition  from
cost-based  regulation of bundled electric service to customer choice and market
pricing for the supply of electricity. As legislative and regulatory proceedings
evolve, six of the electric operating  companies (APCo, CPL, CSPCo, OPCo, SWEPCo
and  WTU)  doing  business  in  five  of  the  seven  states  that  have  passed
restructuring   legislation  have   discontinued  the  application  of  SFAS  71
regulatory  accounting  for  generation.  The seven states in various  stages of
restructuring  to  transition  generation  to market based pricing are Arkansas,
Michigan,  Ohio, Oklahoma,  Texas, Virginia, and West Virginia. PSO and I&M have
not discontinued regulatory accounting for their generation business in Oklahoma
and Michigan,  respectively,  pending the implementation of the legislation. 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.

Ohio Restructuring - Affecting AEP, CSPCo and OPCo

           Effective  January 1, 2001,  customer choice of electricity  supplier
began under the Ohio Act. In February 2001,  one supplier  announced its plan to
offer  service to  CSPCo's  residential  customers.  Currently  for  residential
customers of OPCo, no  alternative  suppliers have  registered  with the PUCO as
required  by the Ohio Act.  Two  alternative  suppliers  have been  approved  to
compete for CSPCo's and OPCo's commercial and industrial  customers.  Presently,
customers continue to be served by CSPCo and OPCo with a legislatively  required
residential  rate  reduction  of 5% for the  generation  portion  of rates and a
freezing of generation rates including fuel rates starting on January 1, 2001.

           The Ohio Act provides for a five-year  transition period to move from
cost based rates to market pricing for generation services.  It granted the PUCO
broad oversight  responsibility for promulgation of rules for competitive retail
electric  generation  service,  approval of a transition  plan for each electric
utility  company  and  addressing  certain  major  transition  issues  including
unbundling  of rates and the  recovery of stranded  costs  including  regulatory
assets and transition costs.

           The  Ohio  Act  also   provides  for  a  reduction  in  property  tax
assessments,  the imposition of replacement  franchise and income taxes, and the
replacement  of a gross  receipts  tax with a KWH based excise tax. The property
tax assessment percentage on generation property was lowered from 100% to 25% of
value effective January 1, 2001 and Ohio electric  utilities will become subject
to the Ohio  Corporate  Franchise Tax and  municipal  income taxes on January 1,
2002.  The last year for which Ohio 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 (May 1),  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.  As a result a duplicate  tax will be  expensed  from May 1,
2001 through April 30, 2002 adding approximately $90 million to AEP consolidated
tax expense ($40 million for CSPCo and $50 million for OPCo) during that period.
Unless the companies can recover the  duplicate  amount from  ratepayers it will
negatively impact results of operations.

        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  regarding  transition plans filed by CSPCo
and OPCo. The key provisions of this stipulation agreement are:

o    Recovery of generation-related  regulatory assets at December 31, 2000 over
     seven  years for OPCo ($518  million)  and over eight years for CSPCo ($248
     million)  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 five year transition period.
o    The  companies'  request for a $90 million  ($40  million for CSPCo and $50
     million for OPCo) gross  receipts tax rider to recover the duplicate  gross
     receipts KWH based excise tax would be considered separately by the PUCO.

        The  approved   stipulation   agreement   also  accepted  the  following
provisions contained in CSPCo's and OPCo's filed transition plans:

o  a  corporate  separation  plan  to  segregate  generation,  transmission  and
distribution  assets into separate legal entities,  and o a plan for independent
operation of transmission facilities.

        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 $90 million  ($40 million for CSPCo and $50 million
for OPCo) gross receipts tax rider.  CSPCo's and OPCo's request for rehearing of
the gross  receipts  tax issue was  denied.  An appeal of this issue to the Ohio
Supreme  Court has been filed.  Unless this issue is resolved in the  companies'
favor,  it will have an  adverse  effect on future  results  of  operations  and
financial position.

        One of the  intervenors  at the hearings for approval of the  settlement
agreement  (whose  request for  rehearing was denied by the PUCO) has filed with
the Ohio Supreme Court for review of the settlement agreement including recovery
of regulatory assets.  Management is unable to predict the outcome of litigation
but the resolution of this matter could negatively impact results of operations.

        Beginning  January 1, 2001,  CSPCo's  and OPCo's  fuel costs will not be
subject to PUCO fuel recovery  proceedings.  Deferred fuel costs at December 31,
2000 which  represent under or over recoveries were one of the items included in
the  PUCO's  final  determination  of  net  regulatory  assets  to be  collected
(recovered)  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  their  future  results of
operations and cash flows.

CSPCo and OPCo Discontinue Application of SFAS 71 Regulatory Accounting 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 the Ohio 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 of the remaining net  regulatory  assets  related to the Ohio
generation business will be recovered under the PUCO's September 28, 2000 order.
Therefore,   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  transition  rates  to  customers.  CSPCo  and OPCo
performed an accounting  impairment  analysis on their  generating  assets under
SFAS 121 as required when discontinuing the application of SFAS 71 and concluded
there was no impairment of generation assets.

Virginia Restructuring - Affecting AEP and APCo

        In Virginia,  a restructuring law provides for a transition to choice of
electricity  supplier  for retail  customers  beginning  on January 1, 2002.  In
February 2001,  restructuring  revision legislation was approved by the Virginia
Legislature  which  could  modify  the terms of  restructuring.  Presently,  the
transition  period is to be completed,  subject to a finding by the Virginia SCC
that an effective competitive market exists by January 1, 2004 but no later than
January 1, 2005.

        The  restructuring law also provides an opportunity for recovery of just
and reasonable net stranded generation costs. The mechanisms in the Virginia law
for net stranded  cost recovery are: a capping of rates until as late as July 1,
2007,  and the  application  of a wires  charge  upon  customers  who depart the
incumbent  utility in favor of an alternative  supplier prior to the termination
of the rate cap. The  restructuring law provides for the establishment of capped
rates prior to January 1, 2001 based either on a request by APCo for a change in
rates  prior to  January 1, 2001 or on the rates in effect at July 1, 1999 if no
rate  change  request  is made and the  establishment  of a wires  charge by the
fourth quarter of 2001. APCo did not request new rates;  therefore,  its current
rates are 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 to
review the  reasonableness of APCo's capped rates. The cost of service study was
filed on January 3, 2001. In the opinion of APCo's Virginia counsel,  Virginia's
restructuring  law does not  permit  the  Virginia  SCC to change  rates for the
transition period except for changes in the fuel factor,  changes in state gross
receipts taxes, or to address the utility's financial distress.  However, if the
Virginia SCC were to reduce  APCo's  capped rates or deny recovery of regulatory
assets,  it would  adversely  affect  results of  operations  if such  action is
ultimately determined to be legal.

        The Virginia  restructuring  law also  requires  filings to be made that
outline  the  functional   separation  of  generation  from   transmission   and
distribution  and a rate  unbundling  plan.  On January 3, 2001,  APCo filed its
corporate  separation  plan and rate unbundling plan with the Virginia SCC which
is based on the most recent rate case test year (1996).  See Note 7 of the Notes
to  Consolidated  Financial  Statements  for a  discussion  of  AEP's  corporate
separation plan filed with the SEC.

West Virginia Restructuring - Affecting AEP and APCo

        On January 28, 2000, the WVPSC issued an order  approving an electricity
restructuring  plan for WV. 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.  The Joint
Committee on Government and Finance of the WV Legislature  hired a consultant to
study and issue a report  on the tax  changes  required  to  implement  electric
restructuring.  Moreover,  the  committee  also hired a consultant  to study and
issue a report on the electric  restructuring  plan in light of events occurring
in  California.  The WV  Legislature  is not expected to consider  these reports
until the 2002 Legislative  Session since the 2001  Legislative  Session ends in
April 2001.  Since the WV  Legislature  has not yet passed the  required tax law
changes, the restructuring plan has not become effective. AEP subsidiaries, APCo
and WPCo, provide electric service in WV.

        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  on  the  starting  date;  functional  separation  of the
generation,  transmission and  distribution  businesses on the starting date and
their legal  corporate  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 a 10-year  period  commencing  with the
starting date  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 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
are 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 5 of the Notes to
Consolidated  Financial  Statements,  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 Regulatory Accounting

        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 made possible by
the June 2, 2000  approval of the Joint  Stipulation  which  established  rates,
wires charges and regulatory asset recovery procedures for the transition period
to market  rates  which was  determined  to be  probable.  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  expected   probable  passage  of  required   enabling  tax
legislation in 2001 supported  management's decision in 2000 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 after tax
extraordinary  gain, in the second  quarter of 2000,  of $9 million.  Management
believes  that it is  probable  that  substantially  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.  As  required  by SFAS  101  when  discontinuing  SFAS 71  regulatory
accounting,  APCo performed an accounting  impairment analysis on its generating
assets under SFAS 121 and concluded  that there was no accounting  impairment of
generation assets.

        The recent energy crisis in California, discussed above, may be having a
chilling effect on efforts to enact the required tax change  legislation in West
Virginia. The WV Legislature could decide not to enact the required tax changes,
thereby,  effectively  continuing cost based rate regulation in West Virginia or
it could modify the restructuring plan.  Modifications in the restructuring plan
could  adversely  affect  future  results of  operations  if they were to occur.
Management is carefully  monitoring the situation in West Virginia and continues
to work with all concerned  parties to get approval to  successfully  transition
our generation business in West Virginia.  Failure to pass the required enabling
tax changes could ultimately  require APCo to re-instate  regulatory  accounting
principles under SFAS 71 for its generation operations in West Virginia.

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 an annual  progress  report to the
Arkansas  General Assembly on the development of competition in electric markets
and its
     impact on retail customers is required.

         In November  2000 the  Arkansas  Commission  filed its annual  progress
report with the Arkansas General Assembly recommending a delay in the start date
of retail competition to a date between October 1, 2003 and October 1, 2005. The
report also asks the  Arkansas  General  Assembly to delegate  authority  to the
Arkansas  Commission to determine the appropriate  retail competition start date
within the approved time frame. In February 2001 the Arkansas  General  Assembly
passed  legislation  that was signed into law by the  Governor  that changes the
date of  electric  retail  competition  to  October 1, 2003,  and  provides  the
Arkansas Commission with the authority to delay that date for up to two years.

Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU

         In June 1999 Texas restructuring legislation was signed into law which,
among other things:

o    gives Texas customers of investor-owned  utilities the opportunity to
     choose their electricity  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 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)  which  will  reduce   stranded  cost
     recoveries  or if there is no stranded  cost provides for a refund or their
     use to fund  certain  capital  expenditures  in the  amount  of the  excess
     earnings;
o    requires  each  utility  to  structurally  unbundle  into a  retail
     electric  provider,  a  power  generation  company  and a transmission and
     distribution utility;
o    provides for certain  limits for ownership and control of generating
     capacity by  companies;
o    provides  for  elimination  of the fuel clause  reconciliation
     process beginning January 1, 2002; and o provides for a 2004 true-up
     proceeding to determine  recovery of stranded costs including final fuel
     recovery balances, net regulatory assets, certain environmental costs,
     accumulated excess earnings and other issues.

         Under the Texas  Legislation,  delivery of electricity 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,   and  a  transmission  and
distribution  utility.  In May 2000 CPL, SWEPCo and WTU filed a revised business
separation plan that the PUCT approved on July 7, 2000 in an interim order.  The
revised  business  separation  plans  provided for CPL and WTU, which operate in
Texas only, to establish  separate companies and divide their integrated utility
operations  and assets  into a power  generation  company,  a  transmission  and
distribution  utility and a retail electric  provider.  SWEPCo will separate its
Texas jurisdictional  transmission and distribution assets and operations into a
new Texas regulated  transmission and distribution  subsidiary.  In addition,  a
retail  electric  provider will be formed by SWEPCo to provide  retail  electric
service to SWEPCo's Texas jurisdictional customers.

         Under the Texas Legislation,  electric utilities are allowed,  with the
approval  of  the  PUCT,  to  recover   stranded   generation   costs  including
generation-related  regulatory  assets that may not be  recoverable  in a future
competitive  market.  The  approved  stranded  costs can be  refinanced  through
securitization,  which  is a  financing  structure  designed  to  provide  lower
financing  costs  than are  available  through  conventional  financings.  Lower
financing costs are achieved through the issuance of  securitization  bonds at a
lower  interest rate to finance 100% of the costs  pursuant to a state pledge to
ensure   recovery  of  the  bond   principal  and  financing   costs  through  a
non-bypassable  rate surcharge by the regulated  transmission  and  distribution
utility over the life of the securitization bonds.

         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 March
27, 2000, the PUCT issued an order  permitting  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  generation-related  regulatory assets and $33 million for other
qualified   refinancing   costs.   The  $764   million   for   recovery  of  net
generation-related  regulatory  assets  reflects the recovery of $949 million of
generation-related 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. On April 11, 2000, four parties  appealed the PUCT's
securitization  order to the  Travis  County  District  Court.  In July 2000 the
Travis  County  District  Court  upheld the  PUCT's  securitization  order.  The
securitization  order is being  appealed to the Supreme  Court of Texas.  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 remaining  regulatory assets of $206 million 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 property, plant and equipment-electric on AEP's
Consolidated  Balance Sheets and in electric utility  plant-production  on CPL's
Consolidated  Balance Sheets.  These STP costs had previously been identified as
excess  cost over market  (ECOM) by the PUCT for  regulatory  purposes  and were
earning a lower  return and were being  amortized  on an  accelerated  basis for
rate-making  purposes in Texas. The March 2000 filing will determine the initial
amount of stranded costs in addition to the securitized  regulatory assets to be
recovered beginning January 1, 2002.

         CPL submitted a revised  estimate of stranded  costs on October 2, 2000
using  assumptions   developed  in  generic  proceedings  by  the  PUCT  and  an
administrative  model developed by the PUCT staff that reduced the amount of the
initial  stranded cost estimate to $361 million from the $1.1 billion  requested
by CPL. CPL subsequently  agreed to accept  adjustments  proposed by intervenors
that reduced ECOM to  approximately  $230 million.  Hearings on CPL's  requested
ECOM were held in October  2000.  In  February  2001 the PUCT  issued an interim
decision determining an initial amount of CPL ECOM or stranded costs of negative
$580 million.  The decision  indicated  that CPL's costs were below market after
securitization of regulatory assets. Management does not agree with the critical
inputs to this  model.  Management  believes  CPL has a positive  stranded  cost
exclusive of securitized  regulatory  assets. The final amount of CPL's stranded
costs  including  regulatory  assets and ECOM will be established by the PUCT in
the  legislatively  required 2004 true-up  proceeding.  If CPL's total  stranded
costs  determined  in the 2004  true-up are less than the amount of  securitized
regulatory  assets,  the PUCT can implement an offsetting credit to transmission
and distribution rates.

         The  PUCT  ruled  that  prior  to  the  2004  true-up  proceeding,   no
adjustments  would be made to the amount of regulatory  costs  authorized by the
PUCT to be  securitized.  However,  the PUCT also ruled that excess earnings for
the period 1999-2001  should be refunded  through  transmission and distribution
rates to the extent of any  over-mitigation  of stranded  costs  represented  by
negative ECOM. In the event that CPL will be required to refund excess  earnings
in the future instead of applying them to reduce ECOM or regulatory  assets,  it
will  adversely  affect  future  cash flow but not results of  operations  since
excess  earnings  for 1999 and 2000 were  accrued and expensed in 1999 and 2000.
The Texas Legislation allows for several alternative methods to be used to value
stranded  costs in the  final  2004  true-up  proceeding  including  the sale or
exchange of generation assets, the issuance of power generation company stock to
the public or the use of PUCT staff's  ECOM model.  To the extent that the final
2004 true-up proceeding  determines that CPL should recover additional  stranded
costs, the total amount recoverable can be securitized.

         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 annual
earnings test calculation.

         The 1999  earnings  test  reports  filed by CPL,  SWEPCo and WTU showed
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.  The Office of Public
Utility  Counsel  also filed  exceptions  to the  companies'  earnings  reports.
Several  issues were resolved via  settlement and the remaining open issues were
submitted to the PUCT. A final order was issued by the PUCT in February 2001 and
adjustments  to the  accrued  1999 and 2000  excess  earnings  were  recorded in
results of  operations  in the fourth  quarter of 2000.  After  adjustments  the
accruals  for 1999  excess  earnings  for CPL and WTU were  $24  million  and $1
million,  respectively.  CPL and WTU also  recorded an estimated  provision  for
excess 2000 earnings of $16 million and $14 million, respectively.

         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 and
financial  reporting  purposes,  STP ECOM plant  assets will be  depreciated  in
accordance  with GAAP, on a systematic and rational basis unless  impaired.  CPL
will establish a regulatory liability or reduce regulatory assets by a charge to
earnings to the extent excess earnings exceed $20 million in 2000 and 2001.

         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 to  reconcile  their fuel costs  through the
period ending  December 31, 2001. Fuel costs have been reconciled by CPL, SWEPCo
and  WTU  through  June  30,  1998,   December  31,  1999  and  June  30,  1997,
respectively.  WTU is currently  reconciling  its fuel  through  June 2000.  See
discussion  in Note 5 of the  Notes to  Consolidated  Financial  Statements.  At
December 31, 2000, CPL's,  SWEPCo's and WTU's Texas  jurisdictional  unrecovered
deferred  fuel  balances  were  $127  million,  $20  million  and  $59  million,
respectively. Final unrecovered deferred fuel balances at December 31, 2001 will
be  included  in each  company's  2004  true-up  proceeding.  If the final  fuel
balances or any amount incurred but not yet reconciled were not recovered,  they
could have a negative  impact on results of operations.  The  elimination of the
fuel clause recoveries in 2002 in Texas will subject AEP, CPL, SWEPCo and WTU to
greater risks of fuel market price increases and could  adversely  affect future
results of operations beginning in 2002.
         The affiliated  retail electric provider of CPL, SWEPCo and WTU will be
required to offer residential and small commercial  customers (with a peak usage
of less  than  1000 KW) a rate 6% below  rates in  effect  on  January  1,  1999
adjusted for any changes in fuel cost  recovery  factors  since  January 1, 1999
(price to beat).  The price to beat must be  offered  to  residential  and small
commercial  customers until January 1, 2007. Customers with a peak usage of more
than 1000 KW are subject to market rates.  The Texas  restructuring  legislation
provides  for the  price to beat to be  adjusted  up to two  times  annually  to
reflect significant changes in fuel and purchased energy costs.

CPL, SWEPCo and WTU Discontinue Application of SFAS 71 Regulatory Accounting in
 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  wires  charges  to  customers.   Management   believes  that
substantially  all  of  CPL's  generation-related   regulatory  assets  will  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 through  securitization
of CPL's  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 Arkansas and Texas  jurisdictional  generation-related  net
regulatory  assets  were  written  off as  non-recoverable  in  1999  when  they
discontinued  application of SFAS 71 regulatory accounting.  As required by SFAS
101  when  SFAS  71 is  discontinued,  an  accounting  impairment  analysis  for
generation  assets  under SFAS 121 was  completed  for CPL,  SWEPCo and WTU. The
analysis  showed that 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 if circumstances  change.
Management  believes that on a discounted  basis CPL's  generation  business net
cash flows will  likely 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 the balance  sheet at December 31,
2000, $953 million of generation-related  regulatory assets already approved for
securitization  and $195  million of net  generation-related  regulatory  assets
pending approval for  securitization in Texas. A final  determination of whether
they will be securitized  and recovered will be made as part of the 2004 true-up
proceeding.

         CPL, SWEPCo, and WTU continue to analyze the impact of electric utility
industry  restructuring   legislation  on  their  Arkansas  and  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  regulatory  process is complete  following the 2004
true-up proceeding in Texas and a determination by the Arkansas  Commission.  In
the event CPL, SWEPCo,  and WTU are unable after the 2004 true-up proceeding and
after the Arkansas  Commission  proceedings 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.

         Although Arkansas' delay of retail competition may be having a negative
effect on the progress of efforts to transition  SWEPCo's generation in Arkansas
to market based pricing of electricity,  it appears that Texas is moving forward
as planned.  Management is carefully monitoring the situation in Arkansas and is
working  with  all  concerned  parties  to  prudently  quicken  the  pace of the
transition.  However,  changes  could  occur due to concerns  stemming  from the
California  energy crisis and other events which could  adversely  affect future
results of operations in Arkansas and possibly Texas.

Michigan Restructuring - Affecting AEP and I&M

        On  June 5,  2000,  the  Michigan  Legislation  became  law.  Its  major
provisions, which were effective immediately, applied only to electric utilities
with one  million  or more  retail  customers.  I&M,  AEP's  electric  operating
subsidiary  doing business in Michigan,  has less than one million  customers in
Michigan.  Consequently,  I&M was not  immediately  required  to comply with the
Michigan Legislation.

         The Michigan  Legislation gives the MPSC broad power to issue orders to
implement  retail customer choice of electric  supplier no later than January 1,
2002 including  recovery of regulatory  assets and stranded costs. 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.  The plan contains a
proposed  methodology to determine stranded costs and  implementation  costs and
requests   the   continuation   of  a  wires  charge  for  recovery  of  nuclear
decommissioning  costs.  Approval of the  restructuring  implementation  plan is
pending before the MPSC.

         Management has concluded that as of December 31, 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 of EITF 97-4 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 and
record its unrecorded Michigan jurisdictional  liability for decommissioning the
Cook Plant to the extent  that they  cannot be  recovered  under the  transition
rates and wires  charges.  As  required by SFAS 101 when  discontinuing  SFAS 71
regulatory  accounting,  I&M  will  have to  perform  an  accounting  impairment
analysis under SFAS 121 to determine if the Michigan  jurisdictional  portion of
its generating assets are impaired for accounting purposes.

         The amount of regulatory  assets  recorded on the books at December 31,
2000 applicable to I&M's Michigan retail  jurisdictional  generation business is
approximately $45 million before related tax effects.  The estimated  unrecorded
liability for the Michigan  jurisdiction to  decommission  the Cook Plant ranges
from $114  million to $215  million in 2000  non-discounted  dollars  based upon
studies  completed  during  2000.  For  the  Michigan   jurisdiction,   I&M  has
accumulated  approximately  $100 million in trust funds to decommission the Cook
Plant.  Based  on  the  current  information  available,   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 restructuring proceedings.

         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,  decommissioning  obligations and 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, unrecorded decommissioning obligation,
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 open access by July 1, 2002. That legislation  called for a
number  of  studies  to be  completed  on a  variety  of  restructuring  issues,
including an 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  supple-mented  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.
         The 2001 Oklahoma  legislative  session convened in early February.  No
further  electric  restructuring  legislation has passed and proposals have been
made to delay the implementation of the transition to customer choice and market
based  pricing  under  the  restructuring  legislation.  These  proposals  are a
reaction to  California's  recent energy crisis.  Management is working with all
concerned  parties to reassure them that what  happened in  California  will not
occur in Oklahoma.  If the necessary legislation is not passed, PSO's generation
and retail  electric  supply  business  will remain  regulated in  Oklahoma.  If
implementation legislation were to modify the original restructuring legislation
in Oklahoma it could have a adverse effect on results of operations.

         Management has concluded that as of December 31, 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.

         When PSO  discontinues  application of SFAS 71, it will be necessary to
write off 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 and/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.

Restructuring In Other Jurisdictions

        The remaining four states (Indiana,  Kentucky,  Louisiana and Tennessee)
making up AEP's  service  territory  have  initiatives  to  implement  or review
customer choice,  although the timing of any implementation is uncertain and may
be further delayed due to the California situation. AEP supports customer choice
and  deregulation  of  generation  and is  proactively  involved in  discussions
regarding the best competitive  market structure and transition method to arrive
at a fair,  competitive  marketplace.  As the  pricing  of  generation  in these
markets evolves from regulated  cost-of-service  rates to market-based  pricing,
the  recovery  of  stranded  costs  including  net  regulatory  assets and other
transition  costs  must be  addressed.  The  amount  of  stranded  costs the AEP
subsidiaries  could experience when and if  restructuring  occurs in their state
jurisdictions  depends  on  the  timing  and  extent  to  which  competition  is
introduced to their  business and the future market prices of  electricity.  The
recovery of stranded cost is dependent on the terms of future  legislation  and,
if required, related regulatory proceedings.

        Customer  choice  and the  transition  to market  based  competition  if
restructuring is implemented in Indiana, Kentucky, Louisiana and Tennessee could
also  ultimately  result in adverse  impacts on results of  operations  and cash
flows  depending on the future market prices of  electricity  and the ability of
the subsidiaries to recover their stranded costs including net regulatory assets
during a  transition  or  subsequent  period  through  a wires  charge  or other
recovery mechanism. Management believes that state restructuring legislation and
the regulatory  process  should provide for full recovery of  generation-related
net regulatory assets and other reasonable stranded costs if these states decide
to  deregulate  generation.  However,  if in  the  future  any  portion  of  the
generation business in these other jurisdictions were to no longer be cost-based
regulated and if it were not possible to demonstrate  probability of recovery of
resultant  stranded costs including  regulatory  assets,  results of operations,
cash flows and financial condition would be adversely affected.

Amortization  of  Transition  Regulatory  Assets  and  Other  Deferred  Costs  -
Affecting AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU

        Future  earnings will be negatively  impacted by amortization of certain
deferred  costs and  regulatory  assets  related to I&M's  Cook  Plant  extended
outage,  transition  plans to  discontinue  SFAS 71  regulatory  accounting  for
generation  with the  beginning  of  customer  choice in certain  states and the
merger of AEP and CSW.

        During 1999,  the IURC and MPSC  approved  settlement  agreements  which
provided  for the  deferral  in 1999  and  amortization  of  restart  costs  and
fuel-related  revenues  from the extended Cook Plant  outage.  The  amortization
period is for five years ending in December  2003.  Annual  amortization  is $78
million for I&M. See Note 4 of the Notes to Consolidated Financial Statements.

        Beginning  in 2001 under the Ohio Act,  CSPCo and OPCo began  amortizing
their transition regulatory assets over eight and seven years, respectively. The
annual  amortization  in 2001 for CSPCo and OPCo is  estimated to be $20 million
and $74  million,  respectively.  The amount of  amortization  is based upon KWH
sold.

        APCo began amortization of its West Virginia  jurisdictional  regulatory
assets over an eleven year period in July 2000.  In the  Virginia  jurisdiction,
APCo started straight line  amortization of regulatory  assets over a seven year
period in July 2000. The annual  amortization  for 2001 is $9 million for APCo's
West Virginia jurisdiction and $9 million for APCo's Virginia jurisdiction.


        In June 2000 AEP merged with CSW. In connection  with securing  approval
for the merger, AEP and certain of its subsidiaries signed agreements,  approved
by regulatory  authorities,  which included rate  reductions to share  estimated
merger savings with  customers.  The agreements  provide for rate reductions for
periods up to eight years beginning in the third quarter of 2000.

        Certain merger related costs  recover-able from ratepayers were deferred
pursuant to the  settlement  agreements and will be amortized over five to eight
years  depending  upon  the  terms  of the  respective  agreements.  The  annual
amortization  of the  deferred  merger  costs for the AEP System is estimated to
total $8 million in 2001. The merger  amortization  will be recorded as follows:
$2.6 million by CPL, $1.7 million by I&M, $600,000 by KPCo, $1.2 million by PSO,
$1.1  million  by SWEPCo and  $800,000  by WTU.  If actual  merger  savings  are
significantly  less than the merger  savings  rate  reductions  required  by the
merger  settlement  agreements and the  amortization of deferred  merger-related
costs, future results of operations, cash flows and possibly financial condition
could be adversely affected.  See Note 3 of the Notes to Consolidated  Financial
Statements for further discussion of the merger.

        Amortization of the above described deferred costs and regulatory assets
could  negatively  affect  future  earnings  to the extent that they exceed cost
savings or revenues growth.

Litigation

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

        On February 20, 2001, the U.S.  District Court for the Southern District
of  Ohio  ruled  against  AEP  in  its  suit  against  the  United  States  over
deductibility of interest claimed by AEP in its consolidated  federal income tax
return  related to its COLI  program.  AEP had filed  suit to  resolve  the IRS'
assertion that interest deductions for AEP's COLI program should not be allowed.
In 1998 and 1999 AEP and the impacted  subsidiaries  paid the disputed taxes and
interest  attributable to COLI interest deductions for taxable years 1991-98 for
APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the potential assessment
by the IRS of  additional  interest on the  contested  tax.  The  payments  were
included in other assets on AEP  Consolidated  Balance Sheet and Other  Property
and  Investments on the  subsidiaries'  balance sheets pending the resolution of
this matter.  As a result of the U.S. District Court's decision to deny the COLI
interest  deductions,  net income was reduced by $319 million for the AEP System
in 2000. Management plans to appeal the decision.

The earnings reductions for affected registrant subsidiaries are as follows:

                                (in millions)
APCo                                $ 82
CSPCo                                 41
I&M                                   66
KPCo                                   8
OPCo                                 118

Shareholders' Litigation - Affecting AEP

        On 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  filed a consolidated  complaint  pursuant to this court order.  This
case has been transferred to the U.S.  District Court for the Southern  District
of Ohio.  Although,  management  believes these shareholder  actions are without
merit and  intends to oppose  them  vigorously,  management  cannot  predict the
outcome of this litigation or its impact on results of operations, cash flows or
financial condition.

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  damages  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 awards a judgement
against CPL for a franchise underpayment, CPL will extend the principles of that
decision, with regard to any 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  counterclaim  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 with an additional  annual  reduction of $13
million commencing 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 service billings from an affiliate, CSW Services.
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  service billing 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  the PUCT's 1997 order 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 related loss of return on equity and the
disallowed affiliated service billings.

Lignite Mining Agreement Litigation - Affecting AEP and 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  has been extended from December 31, 2000 to March 31, 2001. The
litigation  has  been  stayed  until  April  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.

        AEP and its  registrant  subsidiaries  are involved in a number of other
legal proceedings and claims.  While management is unable to predict the outcome
of such  litigation,  it is not expected  that the ultimate  resolution of these
matters will have a material  adverse effect on the results of operations,  cash
flows or financial condition.

Environmental Concerns and Issues

        As 2001 begins,  the U.S.  continues to debate an array of environmental
issues affecting the electric utility  industry.  Most of the policies are aimed
at reducing air emissions  citing  alleged  impacts of such  emissions on public
health, sensitive ecosystems or the global climate.

        AEP and its subsidiaries' policy on the environment  continues to be the
development  and  application  of long-term  economically  feasible  measures to
improve  air and water  quality,  limit  emissions  and  protect  the  health of
employees,  customers,  neighbors and others  impacted by their  operations.  In
support of this policy, AEP and its subsidiaries  continue to invest in research
through groups like the Electric Power Research  Institute and directly  through
demonstration  projects for new technology for the capture and storage of carbon
dioxide, mercury, NOx and other emissions. The AEP System intends to continue in
a leadership role to protect and preserve the environment  while providing vital
energy commodities and services to customers at fair prices.

        AEP and its subsidiaries  have a proven record of efficiently  producing
and  delivering   electricity  and  gas  while  minimizing  the  impact  on  the
environment.  AEP and its  subsidiaries  have spent billions of dollars to equip
their facilities with the latest cost effective clean air and water technologies
and to research new  technologies.  Award winning  efforts to reclaim our mining
properties is a proud accomplishment.

        The  introduction  of  multi-pollutant   control  legislation  is  being
discussed by members of Congress and the Bush  Administration.  The  legislation
being considered may regulate carbon dioxide,  NOx, sulfur dioxide,  mercury and
other  emissions from electric  generating  plants.  Management will continue to
support  solutions which are based on sound science,  economics and demonstrated
control technologies. Management is unable to predict the timing or magnitude of
additional  pollution  control  laws  or  regulations.   If  additional  control
technology is required on facilities owned by the electric utility companies and
their costs were not recoverable  from ratepayers or through market based prices
or volumes of  product  sold,  they could  adversely  affect  future  results of
operations and cash flows. The following  discussions  explains existing control
efforts,  litigation and other pending matters related to  environmental  issues
for AEP System companies.

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

         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.

        AEP,  APCo,  CSPCo,  I&M and  OPCo  have  been  involved  in  litigation
regarding generating plant emissions under the Clean Air Act. In 1999 Notices of
Violation were issued and  complaints  were filed by Federal EPA in various U.S.
District Courts alleging APCo,  CSPCo, I&M and OPCo and a number of 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  generating  units previously named only in
the Notices of Violation in the complaint.

        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 certain  AEP System  operating
companies  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  companies  filed motions to dismiss all
or portions of the complaints. Briefing on these motions was completed on August
2, 2000. On February 23, 2001, the government filed a motion for partial summary
judgement  seeking a  determination  that four  projects  undertaken on units at
Sporn,  Cardinal and Clinch River plants do not constitute "routine maintenance,
repair and  replacement" as used in the Clear Air Act.  Management  believes its
maintenance, repair and replacement activities were in conformity with the Clean
Air Act and intends to vigorously pursue its defense.

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

        In December 2000 Cinergy Corp., an unaffiliated utility,  which operates
certain plants  jointly owned by AEP's  subsidiary,  CSPCo,  reached a tentative
agreement  with  Federal EPA and other  parties to settle  litigation  regarding
generating plant emissions under the Clean Air Act.  Negotiations are continuing
between  the parties in an attempt to reach final  settlement  terms.  Cinergy's
settlement  could  impact  the  operation  of  Zimmer  Plant  and W.C.  Beckjord
Generating  Station  Unit 6 which are owned  25.4% and 12.5%,  respectively,  by
CSPCo.  Until a final  settlement is reached,  CSPCo will be unable to determine
the settlement's  impact on its jointly owned facilities and its future earnings
and cash flows.

NOx Reduction - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo

        Federal EPA issued a NOx rule that  required  substantial  reductions in
NOx emissions in a number of eastern states,  including  certain states in which
the AEP System's generating plants are located. A number of utilities, including
several 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, which was denied.

        In December 2000 Federal EPA ruled that eleven states, including certain
states in which the AEP System's generating units are located,  failed to submit
plans to comply with the  mandates of the NOx rule.  This  deter-mination  means
that those  states  could  face  stringent  sanctions  within the next 24 months
including  limits on  construction  of new  sources  of air  emissions,  loss of
federal high-way funding and possible Federal EPA take-over of state air quality
management programs.

        In January 2000 Federal EPA adopted a revised  rule  granting  petitions
filed by certain  northeastern  states  under  Section  126 of the Clean Air Act
seeking  significant  reductions in nitrogen  oxide  emissions  from utility and
industrial  sources.   The  rule  im-poses  emissions   reduction   requirements
com-parable to the NOx rule beginning May 1, 2003, for most of AEP's  coal-fired
generating units. Certain AEP companies and other utili-ties filed petitions for
review in the D.C. Circuit Court.  Briefing has been completed and oral argument
was held in December 2000.
        In a related  matter,  on April 19,  2000,  the Texas  Natural  Resource
Conservation  Commission 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 May 2005 for SWEPCo.

        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.  Construction of selective catalytic  reduction  technology on Amos Plant
Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant is
scheduled to begin in 2001. The Amos and  Mountaineer  projects  (expected to be
completed in 2002) are  estimated to cost a total of $230 million  ($145 million
for APCo and $85 million for OPCo).

        Preliminary  estimates indicate that compliance with the NOx rule upheld
by the D.C.  Circuit Court as well as compliance with the Texas Natural Resource
Conservation  Commission  rule and the Section  126  petitions  could  result in
required  capital  expenditures  of  approximately  $1.6 billion  including  the
amounts discussed in the previous paragraph for the AEP System.

        The following  table shows the estimated  compliance cost for certain of
AEP's registrant subsidiaries.

Company            Amount
-------            ------
               (in millions)
APCo                $365
CPL                   57
I&M                  202
OPCo                 606
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.

Superfund - Affecting AEP, APCo, CPL, CSPCo, I&M, OPCo and SWEPCo

        By-products from the generation of electricity include materials such as
ash,  slag,  sludge,  low-level  radioactive  waste  and  SNF.  Coal  combustion
by-products,  which constitute the  overwhelming  percentage of these materials,
are  typically  disposed  of or treated in captive  disposal  facilities  or are
beneficially  utilized.  In  addition,  the AEP System's  generating  plants and
transmission  and  distribution  facilities  have used asbestos,  PCBs and other
hazardous and  non-hazardous  materials.  The AEP System companies are currently
incurring costs to safely dispose of these substances. Additional costs could be
incurred to comply with new laws and regulations if enacted.

        Superfund  addresses clean-up of hazardous  substances at disposal sites
and authorized Federal EPA to administer the clean-up  programs.  As of year-end
2000,  subsidiaries  of AEP have been named by the Federal EPA as a PRP for five
sites.  APCo,  CSPCo, and OPCo each have one PRP site and I&M has two PRP sites.
There are five additional sites for which AEP, APCo, CSPCo, I&M, OPCo and SWEPCo
have received  information  requests which could lead to PRP  designation.  CPL,
OPCo and  SWEPCo  have also been  named a PRP at three  sites  under  state law.
Liability has been resolved for a number of sites with no significant  effect on
the AEP subsidiaries' results of operations. In those instances where AEP or its
subsidiaries  have been named a PRP or  defendant,  their  disposal or recycling
activities were in accordance  with the  then-applicable  laws and  regulations.
Unfortunately, Superfund does not recognize compliance as a defense, but imposes
strict liability on parties who fall within its broad statutory categories.

        While the potential  liability for each Superfund site must be evaluated
separately,  several  general  statements  can be made  regarding  AEP's and its
subsidiaries' potential future liability.  Disposal of materials at a particular
site is often  unsubstantiated and the quantity of materials deposited at a site
was small and  often  nonhazardous.  Although  liability  is joint and  several,
typically  many  parties  are  named as PRPs for each  site and  several  of the
parties are  financially  sound  enterprises.  Therefore,  management's  present
estimates do not  anticipate  material  cleanup costs for  identified  sites for
which AEP System companies have been declared PRPs. If significant cleanup costs
are attributed to AEP or its subsidiaries in the future under Superfund, results
of operations,  cash flows and possibly  financial  condition would be adversely
affected unless the costs can be recovered from customers.

Global Climate Change

        At the Third  Conference of the Parties to the United Nations  Framework
Convention on Climate Change held in Kyoto, Japan in December 1997 more than 160
countries,  including the U.S.,  negotiated a treaty  requiring  legally-binding
reductions in emissions of greenhouse gases, chiefly carbon dioxide,  which many
scientists believe are contributing to global climate change. The treaty,  which
requires  the advice  and  consent of the U.S.  Senate for  ratification,  would
require the U.S. to reduce  greenhouse  gas  emissions  seven percent below 1990
levels in the years  2008-2012.  Although  the U.S. has agreed to the treaty and
signed it on November 12, 1998,  the treaty has not been submitted to the Senate
for   consideration  as  it  does  not  contain   requirements  for  "meaningful
participation   by  key  developing   countries"  and  the  rules,   procedures,
methodologies  and  guidelines  of the  treaty's  emissions  trading  and  joint
implementation  programs and  compliance  enforcement  provisions  have not been
negotiated.  At the Fourth  Conference  of the  Parties in  November  1998,  the
parties agreed to a work plan to complete  negotiations  on  outstanding  issues
with a view toward  approving them at the Sixth  Conference of the Parties to be
held in November 2000.  During the Sixth Conference of the Parties agreement was
not reached on any of the outstanding  issues  requiring  resolution in order to
faciliate  ratification  of the Kyoto  Protocol.  There are several  contentious
issues and literally hundreds of pages of detailed, complex rules that remain to
be  negotiated.  Discussions  are  expected  to  resume  in July  2001.  While a
candidate  for the  presidency,  George Bush had stated his  opposition  to U.S.
ratification  of the Kyoto  Protocol.  The Seventh  Conference of the Parties is
scheduled for October 2001 in Morocco.  AEP does not support the Kyoto Treaty as
presently drafted.  Management will continue to work with the Administration and
Congress to develop responsible public policy on this issue.

        If the Kyoto  treaty is approved by Congress as presently  drafted,  the
costs  for the AEP  System  to  comply  with the  required  emission  reductions
required by the treaty are expected to be substantial  and would have a material
adverse  impact on results of  operations,  cash  flows and  possibly  financial
condition if not recovered from customers.  It is  management's  belief that the
Kyoto  Protocol is unlikely to be ratified  and  implemented  in the U.S. in its
current form.

Costs for Spent Nuclear Fuel and Decommissioning - Affecting AEP, CPL and I&M

        I&M, as the owner of the Cook Plant, and CPL, as a partial owner of STP,
have a significant  future  financial  commitment  to safely  dispose of SNF and
decommission and decontaminate the plants.  The Nuclear Waste Policy Act of 1982
established  federal  responsibility  for the permanent off-site disposal of SNF
and high-level  radioactive  waste.  By law CPL and I&M participate in the DOE's
SNF disposal  program which is described in Note 8 of the Notes to  Consolidated
Financial  Statements.  Since 1983 I&M has collected $275 million from customers
for the  disposal of nuclear  fuel  consumed at the Cook Plant.  $116 million of
these  funds have been  deposited  in  external  trust  funds to provide for the
future  disposal of SNF and $159  million has been  remitted to the DOE. CPL has
collected  and remitted to the DOE,  $44 million for the future  disposal of SNF
since STP began operation in the late 1980s. Under the provisions of the Nuclear
Waste Policy Act,  collections  from customers are to provide the DOE with money
to build a  permanent  repository  for spent  fuel.  However,  in 1996,  the DOE
notified the  companies  that it would be unable to begin  accepting  SNF by the
January 1998 deadline required by law. To date DOE has failed to comply with the
requirements of the Nuclear Waste Policy Act.

        As a result  of  DOE's  failure  to make  sufficient  progress  toward a
permanent  repository or otherwise assume  responsibility for SNF, AEP on behalf
of I&M and STPNOC on behalf of CPL and the other STP owners, along with a number
of  unaffiliated  utilities  and states,  filed suit in the D.C.  Circuit  Court
requesting,  among other things,  that the D.C.  Circuit Court order DOE to meet
its  obligations  under the law. The D.C.  Circuit  Court ordered the parties to
proceed with  contractual  remedies but declined to order DOE to begin accepting
SNF for disposal.  DOE estimates its planned site for the nuclear waste will not
be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S.
Court of Federal  Claims  seeking  damages in excess of $150  million due to the
DOE's partial material breach of its unconditional contractual deadline to begin
disposing of SNF  generated by the Cook Plant.  Similar  lawsuits  were filed by
other  utilities.  In August 2000, in an appeal of related cases involving other
unaffiliated  utilities,  the U.S. Court of Appeals for the Federal Circuit held
that the delays clause of the standard  contract  between  utilities and the DOE
did not apply to DOE's complete failure to perform its contract obligations, and
that the utilities' suits against DOE may continue in court.  AEP's and I&M suit
has been stayed pending further action by the U.S. Court of Federal  Claims.  As
long  as  the  delay  in  the  availability  of a  government  approved  storage
repository for SNF continues,  the cost of both temporary and permanent  storage
and the cost of decommissioning will continue to increase.

        In January 2001, I&M and STPNOC, on behalf of STP's joint owners, joined
a lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related
to  DOE's  nuclear  waste  fund  cost  recovery   settlement  with  PECO  Energy
Corporation.  The  settlement  allows  PECO to skip two  payments to the DOE for
disposal of SNF due to the lack of progress  towards  development of a permanent
repository  for SNF. The  companies  believe the  settlement  is unlawful as the
settlement  would force other  utilities  to make up any  shortfall in DOE's SNF
disposal funds.

        The  cost to  decommission  nuclear  plants  is  affected  by  both  NRC
regulations  and the delayed SNF  disposal  program.  Studies  completed in 2000
estimate  the cost to  decommission  the Cook Plant  ranges from $783 million to
$1,481 million in 2000  non-discounted  dollars.  External trust funds have been
established with amounts  collected from customers to decommission the plant. At
December 31, 2000, the total  decommissioning  trust fund balance for Cook Plant
was $558  million  which  includes  earnings on the trust  investments.  Studies
completed in 1999 for STP  estimate  CPL's share of  decommissioning  cost to be
$289 million in 1999 non-discounted dollars. Amounts collected from customers to
decommission  STP have been placed in an external  trust.  At December 31, 2000,
the total  decommissioning  trust  fund for CPL's  share of STP was $94  million
which  includes   earnings  on  the  trust   investments.   Estimates  from  the
decommissioning studies could continue to escalate due to the uncertainty in the
SNF  disposal  program  and the length of time that SNF may need to be stored at
the plant  site.  We will work with  regulators  and  customers  to recover  the
remaining  estimated  costs  of  decommissioning  Cook  Plant  and  STP  through
regulated  rates and,  where  generation  has been  deregulated,  through  wires
charges.  However,  AEP's,  CPL's and I&M's future results of  operations,  cash
flows and possibly their financial conditions would be adversely affected if the
cost of SNF  disposal  and  decommissioning  continues to increase and cannot be
recovered.

Foreign Energy Delivery, Worldwide Energy Investments and Other Business
Operations

        Worldwide electric and gas operations on AEP's  Consolidated  Statements
of Income include the foreign energy delivery, worldwide energy investments, and
other  segments  of AEP's  business.  See Note 14 of the  Notes to  Consolidated
Financial Statements for a discussion of segments.

        AEP's investment in certain types of activities is limited by PUHCA. SEC
authorization  under PUHCA  limits AEP to issuing and selling  securities  in an
amount  up to 100%  of its  average  quarterly  consolidated  retained  earnings
balance for investment in EWGs and FUCOs. At December 31, 2000, AEP's investment
in EWGs and FUCOs was $1.8  billion  compared to AEP's limit of $3.4  billion by
law.

        SEC rules  under  PUHCA  permit AEP to invest up to 15% of  consolidated
capitalization   (such  amount  was  $3.5  billion  at  December  31,  2000)  in
energy-related companies that engage in marketing and/or trading of electricity,
gas and other energy  commodities.  AEP's gas trading business and its interests
in domestic  cogeneration  projects are reported as investments  under this rule
and at December 31, 2000, AEP's investment was less than one million dollars.

        Management  continues  to evaluate  the U.S.  and  international  energy
markets for investment opportunities that complement AEP's wholesale operations.
Management expects to continue to pursue new and existing energy supply projects
and to provide  energy related  services  worldwide.  AEP's future  consolidated
earnings  will be  impacted  by the  performance  of  existing  and  any  future
investments.

        The  major  business  activities  and  subsidiaries  of AEP's  worldwide
electric and gas operations are SEEBOARD, CitiPower,  Yorkshire, European energy
trading  operations,  U.S.  power  trading  more than two  transmission  systems
removed from the AEP transmission system and gas trading operations in the U.S.,
domestic  and  foreign  generating  facilities  in China,  Mexico  and the U.S.,
electric distribution in South America and power plant construction.  SEEBOARD's
principal  business is the  distribution  and supply of electricity in southeast
England. CitiPower provides electricity and electric distribution service in the
city of  Melbourne,  Australia.  AEP owns 100% of SEEBOARD  and  CitiPower.  The
revenues and  operating  expenses for  SEEBOARD  and  CitiPower  are included in
worldwide  revenues and  expenses on AEP's  Consolidated  Statements  of Income.
Interest,  taxes and other  nonoperating  items for SEEBOARD and  CitiPower  are
included in the appropriate income statement lines.

        In 1998 SEEBOARD's 80% owned subsidiary,  SEEBOARD  Powerlink,  signed a
30-year  contract for $1.6 billion to operate,  maintain,  finance and renew the
high-voltage power distribution network of the London Underground transportation
system.  SEEBOARD  Powerlink will be responsible for  distributing  high voltage
electricity to supply 270 London Underground  stations and 250 miles of the rail
system's track. SEEBOARD's partners in Powerlink are an international electrical
engineering group and an international cable and construction group.

        AEP has a 50% investment in Yorkshire, another U.K. regional electricity
distribution  and supply  company.  The  investment  is accounted  for using the
equity method of accounting with equity earnings  included in other income (net)
on the AEP Consolidated  Statements of Income. In December 2000 AEP entered into
negotiations  to sell its  investment  in  Yorkshire.  On February 26, 2001,  an
agreement  to sell AEP's 50%  interest  in  Yorkshire  was  signed.  The sale is
expected to close by March 31,  2001.  See Note 10 of the Notes to  Consolidated
Financial Statements.

        In the U.K. all residential  and commercial  customers have been allowed
to choose their electricity  supplier since May 1999. Margins on retail electric
sales have been  generally  declining  due to  competition.  In April 2000 final
proposals  from  the  regulatory   commission  reduced  distribution  rates  and
electricity  supply price caps.  The  distribution  rate  reductions and reduced
price caps are expected to reduce AEP's earnings from SEEBOARD and its Yorkshire
investment.  In response to these final  proposals and  increasing  competition,
SEEBOARD and Yorkshire  adopted an aggressive  program of reducing  controllable
costs.   Significant   features  of  this  program  include  staff   reductions,
outsourcing of certain  functions and  consolidation  of facilities.  Management
intends to  aggressively  pursue this cost  reduction  program and  continues to
evaluate  additional cost reduction  measures to further mitigate the effects of
the final proposals and increasing  competition in the U.K.  electricity  supply
business.  Management expects that, despite the cost control measures,  the rate
reductions will negatively impact AEP's earnings.

        The  Utilities  Act which became law in the U.K. in July 2000 includes a
requirement for separate  licensing of electricity  supply and  distribution and
the  introduction  of a  prohibition  of  electricity  supply  and  distribution
licenses being held by the same legal entity. This requirement effectively means
that  the  electricity  supply  and  distribution  businesses  of  SEEBOARD  and
Yorkshire must be held by separate companies.  However, AEP will not be required
to divest its interest in either the supply entity or the  distribution  entity.
The  separation of the supply and  distribution  business into two entities each
for SEEBOARD and  Yorkshire is not expected to have a material  impact on future
results of operations or cash flows.

        Beginning   January  1,  2001  price   reductions   on  the  supply  and
distribution of electricity are being  implemented in Victoria,  Australia.  The
effect of these price  reductions is expected to reduce  CitiPower's  results of
operations  to the  extent  that they  cannot be  offset  by  reduced  expenses,
improved efficiencies or increased sales.

        A new, higher tariff rate for the electricity from two 250 MW coal-fired
generating  units located in Henan  Province,  China was approved by the Central
Chinese  government  in  January  2000.  AEP owns 70% of these  units,  with the
remaining 30% owned by two Chinese  partners.  As a result of the new tariff the
units  contributed  positively  to AEP's  results of  operations  for 2000 after
incurring a loss in 1999.

        Other foreign  generating  facilities include a 37.5% interest in 675 MW
of capacity in the U.K. and a 50% interest in 118 MW of capacity in Mexico.  AEP
also has a 50% ownership interest in two generating plants under construction; a
600 MW  facility  in  Mexico  and a 400 MW  facility  in the  U.K.  All of these
facilities  sell their capacity  under  long-term  contracts.  The investment in
these facilities is accounted for using the equity method.

        AEP,  through its CSW Energy  subsidiary,  has an ownership  interest in
seven operational domestic generation facilities in Colorado,  Florida and Texas
with one 440 MW facility under construction. These plants are EWGs or qualifying
facilities  (QF) as defined by law and not subject to cost-based rate regulation
or the  application  of SFAS 71 regulatory  accounting.  The combined  installed
capacity of the  operational  facilities  is 1,508 MW at December 31, 2000.  The
power from these QF facilities is sold under long-term power purchase agreements
with the local host facility. Any merchant power is sold in the wholesale market
generally under short-term contract. As a result,  increases in the market price
of natural gas used to generate  electricity  at these  facilities may adversely
impact results of operations.

        In 1999 a 50% equity interest in one of the above facilities was sold to
an unaffiliated  company. The after-tax gain from the sale was approximately $33
million. An additional unit is under construction at this facility.  Pursuant to
the terms of the sale agreement,  the unaffiliated  company will make additional
payments to CSW Energy upon completion of the additional unit.

        Under terms of the FERC and Texas  settlement  agreements  that approved
the  merger,  the  divestiture  of certain  generating  units is  required.  The
Frontera power plant, one of CSW Energy's facilities, is specifically identified
as one of the  plants  where the  entire  ownership  interest  must be sold.  On
February  8,  2001,  AEP  announced  that  it  had  reached  agreement  with  an
unaffiliated company to sell the 500 MW Frontera power plant for $265 million in
cash.

        In 2000 an  electricity  and gas trading  operation in Europe was added.
This business  requires minimal capital  investment and offers an opportunity to
employ our expertise in energy marketing and trading to a new market.

        The domestic gas trading  operation  grew  substantially  in 2000 and is
expected  to benefit  from the  planned  acquisition  of the  Houston  Pipe Line
Company  which was announced in January 2001.  The  acquisition  of Houston Pipe
Line  Company,  which has more than  4,400  miles of  natural  gas  transmission
pipeline  and  operates one of the largest  storage  facilities,  is expected to
complement our intra-state gas transmission and storage  facilities in Louisiana
and extends AEP's  strategy of linking  physical  energy asset  operations  with
trading and marketing operations.

        AEP's Louisiana gas operation is LIG, a midstream natural gas operation,
that was purchased in December  1998 for  approximately  $340 million  including
working capital funds.  LIG includes a fully  integrated  natural gas gathering,
processing,  storage and transportation operation in Louisiana and a gas trading
and marketing operation.  Assets include an intrastate pipeline system,  natural
gas liquids processing plants and natural gas storage facilities.

        AEP's  subsidiaries  are engaged in the engineering and construction for
third  parties of three  power  plants in the U.S.  with a capacity of 1,910 MW.
These  plants will be natural  gas-fired  facilities  that are  scheduled  to be
completed  from 2001 to 2003.  AEP intends to use its  engineering,  trading and
marketing  expertise on these projects some of which also include power purchase
and power sale agreements to enhance its results of operations.

Other Matters - Affecting AEP, AEGCo,  APCo, CPL, CSPCo,  I&M, KPCo,  OPCo, PSO,
SWEPCo and WTU

New Accounting Standards - SFAS 133, "Accounting for Derivative  Instruments and
Hedging  Activities",  as amended by SFAS 137 and SFAS 138, is 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.  Changes  in  the  derivatives  that  are
effective cash flow hedges are recorded in other comprehensive income.

        Pending the resolution of certain  industry issues  presently before the
FASB's  Derivatives  Implementation  Group (DIG), the effect of adoption of SFAS
133 will result in transition  adjustment  amounts which will have an immaterial
effect on both net income and other comprehensive income.


        The FASB's DIG, has issued  tentative  guidance,  which has not yet been
approved by the FASB, that option  contracts  cannot qualify as normal purchases
and sales. In addition there are two industry  issues pending  resolution by the
DIG  related  to  whether  electric  capacity   contracts  that  may  have  some
characteristics  of purchased  and written  options can qualify as normal sales,
and whether  contracts which do not result in physical delivery of power because
of transmission constraints are derivatives.

        While  the  Company  believes  the  majority  of  the  its  fuel  supply
agreements should qualify as normal purchases and that the majority of its power
sales agreements  qualify as normal sales, the ultimate  resolution of the above
issues  may  result in  accounting  for  certain  power  sales  and fuel  supply
agreements  as  derivatives  which may have a material  effect on  reported  net
income  under SFAS 133.  Whether the impact will be  favorable  or adverse  will
depend on the market prices  compared to the  contractual  prices at the time of
valuation.


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INVESTOR INQUIRIES
Investors  should  direct  inquiries to Investor  Relations  using the toll free
number,  1-800-237-2667  or by writing to: Bette Jo Rozsa  Managing  Director of
Investor  Relations  American  Electric Power Service  Corporation  28th Floor 1
Riverside Plaza Columbus, OH 43215-2373

FORM 10-K ANNUAL REPORT
The Annual Report (Form 10-K) to the Securities  and Exchange  Commission
will be available in April 2001 at no cost to  shareholders.
Please address requests for copies to:
Geoffrey C. Dean
Director of Financial Reporting
American Electric Power Service Corporation
26th Floor
1 Riverside Plaza
Columbus, OH  43215-2373

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