UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              Washington, DC 20549
                                    FORM 10-K
                (X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002
                                       OR
              ( ) Transition report pursuant to Section 13 or 15(d)
                     of the Securities Exchange Act of 1934
                       For the transition period from to .

                        COMMISSION FILE NUMBER 333-56594

                        AMEREN ENERGY GENERATING COMPANY
             (Exact name of registrant as specified in its charter)
                                    Illinois
                                   37-1395586
(State or other jurisdiction of
incorporation or organization)           (I.R.S. Employer Identification No.)

                 1901 Chouteau Avenue, St. Louis, Missouri 63103
              (Address of principal executive offices and Zip Code)

       Registrant's telephone number, including area code: (314) 621-3222

        Securities Registered Pursuant to Section 12(b) of the Act: None.

        Securities Registered Pursuant to Section 12(g) of the Act: None.

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

     Indicate by check mark if disclosure of delinquent  filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's  knowledge,  in definitive proxy or information  statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. (X).

     Indicate by check mark whether the registrant is an  accelerated  filer (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ( ). No (X).

     As of June 28,  2002,  all 2,000  outstanding  shares  of the  registrant's
common  stock were held by its  parent,  AmerenEnergy  Development  Company,  an
indirect subsidiary of Ameren Corporation.

     As of March 31,  2003,  there was no  established  trading  market  for the
registrant's  common stock.

     As of March 31, 2003, there were 2,000 outstanding  shares of common stock,
without  par  value,  of  the  registrant,  all  of  which  were  owned  by  the
registrant's parent, AmerenEnergy Development Company, an indirect subsidiary of
Ameren Corporation.

                         OMISSION OF CERTAIN INFORMATION
     The  Registrant  meets  the  conditions  set forth in  General  Instruction
(I)(1)(a) and (b) of Form 10-K as a wholly owned  indirect  subsidiary of Ameren
Corporation and is therefore filing this Form with the reduced disclosure format
allowed under that General Instruction.

                      DOCUMENTS INCORPORATED BY REFERENCE:

None.

<PAGE>
<TABLE>
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                                                             TABLE OF CONTENTS


                                                                                                                             Page
                                                                                                                            -------

PART I
<S>  <C>           <C>                                                                                                     <C>
      Item 1        Business
                         General...........................................................................................    1
                         Capital Program and Financing.....................................................................    3
                         Regulation........................................................................................    3
                         Fuel Supply for Electric Generating Facilities....................................................    4
                         Industry Issues...................................................................................    5
                         Available Information.............................................................................    5
      Item 2        Properties.............................................................................................    6
      Item 3        Legal Proceedings......................................................................................    8
      Item 4        Submission of Matters to a Vote of Security Holders....................................................    9

PART II

      Item 5        Market for Registrant's Common Equity and Related Stockholder Matters..................................    9
      Item 6        Selected Financial Data................................................................................    9
      Item 7        Management's Discussion and Analysis of Financial Condition and Results of Operations..................   10
      Item 7A       Quantitative and Qualitative Disclosures About Market Risk.............................................   26
      Item 8        Financial Statements and Supplementary Data............................................................   27
      Item 9        Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...................   51

PART III

      Item 10       Directors and Executive Officers of the Registrant.....................................................   51
      Item 11       Executive Compensation.................................................................................   51
      Item 12       Security Ownership of Certain Beneficial Owners and Management.........................................   51
      Item 13       Certain Relationships and Related Party Transactions...................................................   51
      Item 14       Controls and Procedures................................................................................   51

PART IV

      Item 15       Exhibits, Financial Statement Schedules and Reports on Form 8-K........................................   52

SIGNATURES.................................................................................................................   55


CERTIFICATIONS.............................................................................................................   55

EXHIBIT INDEX..............................................................................................................   58

</TABLE>

     This Form 10-K contains "forward-looking  statements" within the meaning of
Section 21E of the Securities Exchange Act of 1934, as amended.  Forward-looking
statements  should be read with the cautionary  statements and important factors
included in this Form 10-K at pages 8 and 25 under the  heading  Forward-Looking
Statements.  Forward-looking statements are all statements other than statements
of historical fact, including those statements that are identified by the use of
the words "anticipates," "estimates," "expects," "intends," "plans," "predicts,"
"projects" and similar expressions.

<PAGE>


                                     PART I

ITEM 1.  BUSINESS.

GENERAL

     AmerenEnergy  Generating Company,  headquartered in St. Louis, Missouri, is
an indirect  wholly-owned  subsidiary of Ameren Corporation (Ameren). We own and
operate a wholesale electric generation business in Illinois and Missouri.  Much
of our  business  was  formerly  owned and  operated by our  affiliate,  Central
Illinois  Public  Service  Company,  which  operates  as  AmerenCIPS.   We  were
incorporated in the State of Illinois in March 2000. On May 1, 2000, we acquired
from AmerenCIPS at net book value five coal-fired electric generating  stations,
which we refer to as the coal plants, all related fuel, supply,  transportation,
maintenance and labor agreements,  approximately  45% of AmerenCIPS'  employees,
and other related rights, assets and liabilities.  Since we commenced operations
in May 2000, we have  acquired 25 combustion  turbine  generating  units.  As of
December 31,  2002,  we had  approximately  4,675  megawatts of total  installed
generating  capacity (4,663 of net kilowatt  capability expected for 2003 summer
peak). We currently have no plans to develop additional capacity. For additional
information regarding our generating facilities, see Item 2.

     When we refer to our, we, us or  Generating  Company,  we are  referring to
AmerenEnergy Generating Company and in some cases our agents, AmerenEnergy, Inc.
(AmerenEnergy) and AmerenEnergy Fuels and Services Company (Fuels Company).

Deregulation in Illinois

     In December 1997, the Electric  Service Customer Choice and Rate Relief Law
of  1997  (the  Illinois  Law)  was  enacted   providing  for  electric  utility
restructuring in Illinois.  We were formed as part of Ameren's business strategy
to respond to the advent of  customer  choice in Illinois  and the  increasingly
competitive market for electric generation services in the Midwest brought about
by the Illinois Law and other factors.  As allowed under the Illinois Law and as
part of a plan to divest itself of generating assets, AmerenCIPS transferred the
coal plants to us effective  May 1, 2000.  Major  provisions of the Illinois Law
include the  phasing-in  through  2002 of retail  direct  access,  which  allows
customers to choose their electric generation suppliers.  The phase-in of retail
direct access began on October 1, 1999,  with large  commercial  and  industrial
customers  principally  comprising  the initial group that is entitled to choose
suppliers.  Retail  direct access was offered to the  remaining  commercial  and
industrial  customers  on  December  31,  2000 and was  offered  to  residential
customers May 1, 2002.  Regulated utilities,  like AmerenCIPS,  will continue to
provide "bundled service," that is,  electricity supply as well as delivery,  to
customers who do not choose a competitive supplier.

     For  additional   information   regarding  our  significant   power  supply
agreements,  see Overview in  Management's  Discussion and Analysis of Financial
Condition  and Results of  Operations  under Item 7 and Note 3 to our  Financial
Statements under Item 8.

Ameren Corporation

     Ameren is a public utility holding  company  registered with the Securities
and Exchange  Commission  (SEC) under the Public Utility  Holding Company Act of
1935 (PUHCA),  as amended,  and is also  headquartered  in St. Louis,  Missouri.
Ameren's principal business is the generation,  transmission and distribution of
electricity,  and the  distribution of natural gas to  residential,  commercial,
industrial and wholesale users in the central United States.  In addition to us,
Ameren's principal subsidiaries and our affiliates are as follows:

o    Union  Electric   Company,   which  operates  a   rate-regulated   electric
     generation,  transmission and distribution  business,  and a rate-regulated
     natural gas  distribution  business in Missouri  and  Illinois as AmerenUE.
     AmerenUE was  incorporated in Missouri in 1922 and is successor to a number
     of companies,  the oldest of which was organized in 1881. It is the largest
     electric  utility in the State of Missouri  and  supplies  electric and gas
     service in parts of central and eastern  Missouri and west central Illinois
     having  an  estimated   population  of  2.6  million   within  an  area  of
     approximately  24,500 square  miles,  including the greater St. Louis area.
     AmerenUE  supplies  electric service to approximately 1.2 million customers
     and natural gas service to approximately 130,000 customers.
o    AmerenCIPS,  which  operates a  rate-regulated  electric  and  natural  gas
     transmission  and  distribution   business  in  Illinois.   AmerenCIPS  was
     incorporated  in Illinois in 1902.  It  supplies  electric  and gas utility
     service to portions of central and  southern  Illinois  having an estimated
     population of 820,000 within an area of

                                       1

<PAGE>

     approximately 20,000 square miles.  AmerenCIPS supplies electric service to
     approximately  325,000  customers and natural gas service to  approximately
     170,000 customers.
o    Central Illinois Light Company,  a subsidiary of CILCORP,  Inc.  (CILCORP),
     which operates a rate-regulated  transmission and distribution business, an
     electric generation business, and a rate-regulated natural gas distribution
     business  in Illinois  as  AmerenCILCO.  AmerenCILCO  was  incorporated  in
     Illinois in 1913. It supplies  electric and gas utility service to portions
     of central and east central Illinois in an area of approximately  3,700 and
     4,500 square miles, respectively.  AmerenCILCO supplies electric service to
     about 200,000 customers and natural gas service to about 205,000 customers.
     See CILCORP Acquisition below for further information.
o    AmerenEnergy  Resources Company (Resources Company),  which consists of non
     rate-regulated operations.  Subsidiaries include us, AmerenEnergy Marketing
     Company (Marketing Company), which markets power for periods over one year,
     Fuels Company, which procures fuel and manages the related risks for us and
     our affiliates,  AmerenEnergy  Development Company  (Development  Company),
     which, as our parent, develops and constructs generating facilities for us,
     and AmerenEnergy  Medina Valley Cogen (No. 4), LLC, which indirectly owns a
     40 megawatt,  gas-fired  electric  generation  plant.  On February 4, 2003,
     Ameren  completed its  acquisition  of AES Medina Valley Cogen (No. 4), LLC
     (Medina  Valley) from AES and renamed it  AmerenEnergy  Medina Valley Cogen
     (No. 4), LLC. See CILCORP Acquisition below for further information.
o    AmerenEnergy  which serves as a power marketing and risk  management  agent
     for us and our affiliates for transactions of primarily less than one year.
o    Electric  Energy,  Inc.  (EEI),  which  operates  electric  generation  and
     transmission facilities in Illinois. Ameren has a 60% ownership interest in
     EEI, 40% owned by AmerenUE and 20% owned by Resources.
o    Ameren Services  Company (Ameren  Services),  which provides shared support
     services to us and our affiliates.

     For additional  information  regarding Ameren's  acquisition of CILCORP and
Medina Valley, see Recent  Developments in Management's  Discussion and Analysis
of Financial Condition and Results of Operations under Item 7 and Notes 1 and 12
to our Financial Statements under Item 8.

     For the year 2002,  99% (2001 - 98%; 2000 - 99%) of our operating  revenues
were  derived  from the sale of  electric  energy and 0.1% (2001 - 0.2%;  2000 -
0.1%) came from other sources.

     We  employed   approximately  700  employees  at  December  31,  2002.  For
information on a voluntary  retirement  program  offered in December 2002 and on
labor  agreements and other labor matters,  see Results of Operation and Outlook
in  Management's  Discussion and Analysis of Financial  Condition and Results of
Operations  under Item 7 and Notes 7 and 10 to our  Financial  Statements  under
Item 8.


CILCORP Acquisition

     On January 31,  2003,  after  receipt of the  necessary  regulatory  agency
approvals   and   clearance   from  the   Department   of   Justice   under  the
Hart-Scott-Rodino  Antitrust  Improvements Act, Ameren completed its acquisition
of all of the  outstanding  common  stock of  CILCORP  from AES.  CILCORP is the
parent company of Peoria,  Illinois-based  Central Illinois Light Company, which
operated as CILCO. With the acquisition,  CILCO became an Ameren subsidiary, but
remains a separate  utility  company,  operating as AmerenCILCO.  On February 4,
2003,  Ameren also completed its acquisition of Medina Valley,  which indirectly
owns a 40 megawatt, gas-fired electric cogeneration plant. With the acquisition,
Medina Valley  became a  wholly-owned  subsidiary  of Resources  Company and was
renamed as  AmerenEnergy  Medina  Valley  Cogen (No.  4),  LLC.  The CILCORP and
AmerenEnergy  Medina  Valley Cogen (No.  4), LLC  financial  statements  will be
included  in  Ameren's  consolidated  financial  statements  effective  with the
January and February 2003 acquisition dates.

     Ameren acquired  CILCORP to complement its existing  Illinois  electric and
gas  operations.  The  purchase  included  CILCO's  rate-regulated  electric and
natural gas  businesses in Illinois  serving  approximately  200,000 and 205,000
customers, respectively, of which approximately 150,000 are combination electric
and gas customers.  CILCO's service  territory is contiguous to Ameren's service
territory and accessible by our electric generation facilities. CILCO also has a
non rate-regulated  electric and gas marketing business  principally  focused in
the Chicago, Illinois region. Finally, the purchase includes approximately 1,200
megawatts of largely coal-fired  generating capacity,  most of which is expected
to become non rate-regulated in 2003.

     The total  purchase price was  approximately  $1.4 billion and included the
assumption of CILCORP and Medina  Valley debt and preferred  stock at closing of
approximately  $900  million,   with  the  balance  of  the  purchase  price  of
approximately $500 million paid with cash on hand. The purchase price is subject
to certain  adjustments  for

                                       2

<PAGE>

working capital and other changes pending the finalization of CILCORP's  closing
balance  sheet.  The  cashcomponent  of the  purchase  price came from  Ameren's
issuances in September  2002 of 8.05 million  common shares and in early 2003 of
6.325 million common shares.

     For  additional   information   regarding  our  business  operations,   see
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations under Item 7 and Note 1 to our Financial Statements under Item 8.


CAPITAL PROGRAM AND FINANCING

     For information on our capital program and financial  needs,  see Liquidity
and Capital  Resources  in  Management's  Discussion  and  Analysis of Financial
Condition  and Results of  Operations  under Item 7 and Notes 3, 6 and 10 to our
Financial Statements under Item 8.


REGULATION

General Regulatory Matters

     As a holding  company  registered  with the SEC under the PUHCA,  Ameren is
subject to the regulatory provisions of the PUHCA, including provisions relating
to the issuance of securities,  sales and acquisitions of securities and utility
assets, affiliate transactions,  financial reporting requirements,  the services
performed by Ameren  Services and Fuels  Company,  and the activities of certain
other  subsidiaries.  Issuance  of  short-term  and  long-term  debt  and  other
securities  by Ameren and issuance of debt having a maturity of twelve months or
less by AmerenCIPS,  AmerenUE and AmerenCILCO are subject to approval by the SEC
under the PUHCA.

     We are certified by the Federal Energy  Regulatory  Commission (FERC) as an
"exempt wholesale generator" under the Energy Policy Act of 1992 and as a result
are not a "public  utility  company"  under the  PUHCA.  As an exempt  wholesale
generator, we are exempt from most of the provisions of the PUHCA that otherwise
would apply to us as a subsidiary of a registered  holding company.  Issuance of
securities by us is not subject to approval by the SEC under the PUHCA.  The SEC
has no  jurisdiction  over  the  sale  of  electricity  by us to  affiliates  or
non-affiliates.  The SEC may impose limitations on Ameren in connection with its
financing  for the  purpose of  investing  in exempt  wholesale  generators  and
foreign utility companies if Ameren's  aggregate  investment in those activities
exceeds  50% of its  consolidated  retained  earnings.  At  December  31,  2002,
Ameren's  aggregate  investment in those entities was 23.7% of its  consolidated
retained earnings.

     We are not subject to regulation by the Illinois Commerce  Commission (ICC)
or the Missouri Public Service Commission (MoPSC).

     We are also  subject to  regulation  by the FERC as to rates and charges in
connection  with the  wholesale  sale of energy and  transmission  in interstate
commerce,  mergers, affiliate transactions,  and certain other matters. Issuance
of short-term  and  long-term  debt by us is subject to approval by the FERC. We
currently  have  authority  from the FERC to issue at any time prior to June 22,
2004 up to $225  million  of  long-term  debt and to have up to $300  million of
short-term debt outstanding in the aggregate at any time.

     In  many  states,  including  Illinois,  companies  that  sell  electricity
directly to retail customers  pursuant to state statutes and regulations must be
registered  or  licensed.  Marketing  Company has obtained  "alternative  retail
electricity  supplier" status in Illinois and plans to seek comparable status in
other states where retail competition is developing.  AmerenCILCO is an Illinois
electric  utility,  and as such,  is permitted to provide  power and energy on a
competitive basis to retail customers located outside its service territory.

     For additional  discussion of regulatory matters, see Regulatory Matters in
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations  under Item 7 and Notes 2 and 10 to our  Financial  Statements  under
Item 8.

Environmental Matters.

     Certain  of  our  operations  are  subject  to  federal,  state  and  local
environmental  regulations  relating to the safety and health of personnel,  the
public and the environment,  including the identification,  generation, storage,
handling,  transportation,  disposal, record keeping, labeling, reporting of and
emergency response in connection with

                                       3

<PAGE>

hazardous and toxic materials,  safety and health  standards,  and environmental
protection  requirements,  includingstandards  and  limitations  relating to the
discharge of air and water pollutants.  Failure to comply with those statutes or
regulations  could have material adverse effects on us, including the imposition
of  criminal  or civil  liability  by  regulatory  agencies  or civil  fines and
liability to private parties,  and the required expenditure of funds to bring us
into  compliance.  We  believe  we  are in  material  compliance  with  existing
regulations.

     For  additional  discussion  of  environmental  matters,  see Liquidity and
Capital Resources in Management's Discussion and Analysis of Financial Condition
and Results of Operations  under Item 7 and Note 7 to our  Financial  Statements
under Item 8.

<TABLE>
<CAPTION>

FUEL SUPPLY FOR ELECTRIC GENERATING FACILITIES

Cost of Fuels                                                                                  Year
                                                                  -----------------------------------------------------------------
                                                                     2002         2001         2000         1999          1998
                                                                  -----------  -----------   ----------  ------------  ------------
<S>                                                               <C>          <C>           <C>          <C>          <C>
AmerenEnergy Generating Company/AmerenCIPS(a)
Per Million BTU       - Coal                                        125.456      121.791      123.770      139.700       152.738
                      - Natural Gas (b)                             396.150      439.744         -            -             -
                      - Average - all fuels (c)                     145.220      142.120      129.169      140.615       155.045

</TABLE>

(a)  On May 1, 2000,  all of  AmerenCIPS'  electric  generating  facilities  and
     related fuel supply  agreements were transferred to us (see General section
     above).
(b)  Prior  to 2001,  the use of  natural  gas was  minimal.  The fuel  cost for
     natural gas in 2002 and 2001  represents the actual cost of natural gas and
     variable costs for transportation,  storage,  balancing and fuel losses for
     delivery to the plant. In addition, the fixed costs for firm transportation
     and firm storage capacity are included to calculate a  "fully-loaded"  fuel
     cost for the generating facilities.
(c)  Represents  all  fuels  utilized  in our  electric  generating  facilities,
     including coal, natural gas, oil, and handling.

Coal

     We  have a  policy  of  maintaining  coal  inventory  consistent  with  our
historical  usage. We may adjust levels based on  uncertainties of supply due to
potential work stoppages,  delays in coal deliveries,  equipment  breakdowns and
other factors.  As of December 31, 2002 and 2001,  approximately  46 days and 63
days, respectively, supply of coal was in inventory. For the year ended December
31, 2002, coal represented approximately 88% of our fuel supply.

Natural Gas

     The combustion  turbine  generator  equipment  (CTs),  which we placed into
commercial  operation  in 2002,  2001 and 2000 are fueled by natural gas or have
the  capability  to use  natural  gas or oil.  We use  natural gas to supply our
generating  facilities  principally during peak generating periods.  Our natural
gas procurement  strategy is designed to ensure reliable and immediate  delivery
of natural gas by optimizing transportation,  storage, and balancing options and
minimizing  cost and price risk by  structuring  various  supply  agreements  to
maintain  access to multiple gas pools and supply basins and reducing the impact
of  price  volatility.  For the  year  ended  December  31,  2002,  natural  gas
represented  approximately 8% of our fuel supply. For additional  information on
CTs  and  related  fuel  matters,   see  Liquidity  and  Capital  Resources  and
Quantitative  and  Qualitative  Disclosures  About  Market Risk in  Management's
Discussion and Analysis of Financial  Condition and Results of Operations  under
Item 7 and Note 10 to our Financial Statements under Item 8.

Oil

     The  actual  and  prospective  use of  oil is  minimal,  and  we  have  not
experienced  and do not expect to experience  difficulty  in obtaining  adequate
supplies. For the year ended December 31, 2002, oil represented approximately 4%
of our fuel supply.

     For additional  information on our fuel supply,  see Results of Operations,
Liquidity and Capital  Resources,  and Quantitative and Qualitative  Disclosures
About Market Risk in Management's Discussion and Analysis of Financial Condition
and Results of  Operations  under Item 7 and Notes 1, 4, and 10 to our Financial
Statements under Item 8.

                                      4

<PAGE>

INDUSTRY ISSUES

     We are facing  issues  common to the electric  generating  industry.  These
issues include:

     o    the potential for more intense competition;
     o    the potential for changes in the structure of regulation;
     o    changes in the  structure  of the  industry  as a result of changes in
          federal  and  state  laws,  including  the  formation  of  unregulated
          generating entities and regional transmission organizations;
     o    weak power prices due to overbuilt capacity and a weak economy;
     o    numerous troubled  companies within the energy sector and their impact
          on energy marketing and access to the capital markets;
     o    on-going  consideration  of  additional  changes  of the  industry  by
          federal and state authorities;
     o    continually  developing  environmental  laws,  regulations and issues,
          including proposed new air quality standards;
     o    public concern about the siting of new facilities;
     o    proposals for demand-side management programs; and
     o    global climate issues.

     We are monitoring  these issues and are unable to predict at this time what
impact, if any, these issues will have on our operations, financial condition or
liquidity.  For additional  information,  see Outlook and Regulatory  Matters in
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations  under Item 7 and Notes 2 and 10 to our  Financial  Statements  under
Item 8.


AVAILABLE INFORMATION

     We  make  available  free  of  charge  through  Ameren's  Internet  website
(http://www.ameren.com)  our annual  report on Form 10-K,  quarterly  reports on
Form 10-Q,  current  reports on Form 8-K, and any  amendments  to those  reports
filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange
Act of 1934 as soon as reasonably  practicable after we electronically file such
material with, or furnish it to, the SEC. This information,  for our affiliates,
Ameren, AmerenUE, AmerenCIPS, CILCORP, and AmerenCILCO is also available through
Ameren's Internet website.

     We also make available free of charge through Ameren's Internet website the
code of business conduct for directors, officers and employees of Ameren and its
subsidiaries, including us, referred to as Ameren's Corporate Compliance Policy.
This document is also available in print upon written request to Secretary, P.O.
Box 66149, St. Louis, Missouri 63166-6149.

                                       5

<PAGE>

ITEM 2.  PROPERTIES.

     For information on our principal properties and planned transfers,  see the
generating   facilities  table  below,   Liquidity  and  Capital  Resources  and
Regulatory  Matters  in  Management's   Discussion  and  Analysis  of  Financial
Condition  and  Results  of  Operations  under  Item 7 and Notes 2 and 10 to our
Financial  Statements  under  Item 8.  Our  plans  for  managing  the  size  and
composition of our generating asset portfolio are subject to market  conditions,
regulatory  factors,  our  results  of  operations,  cash  flows  and  financial
condition, availability of financing and other factors.

     Our generating  facilities are located in Illinois and Missouri within MAIN
(Mid-America  Interconnected Network), which is one of the ten regional electric
reliability  councils  organized for  coordinating the planning and operation of
the nation's bulk power supply. MAIN operates primarily in Wisconsin,  Michigan,
Illinois and Missouri.

     Our bulk  power  system is  operated  as an  Ameren-wide  control  area and
transmission  system under the  FERC-approved  amended joint dispatch  agreement
between  us and  our  Missouri-based  affiliate,  AmerenUE.  The  amended  joint
dispatch  agreement  provides a basis upon which we and AmerenUE can participate
in  the  coordinated  operation  of  AmerenUE's  and  AmerenCIPS'   transmission
facilities  with  AmerenUE's and our  generating  facilities in order to achieve
economies  consistent  with the  provision of reliable  electric  service and an
equitable  sharing of the benefits and costs of that coordinated  operation.  In
2002, Ameren had more than 30 interconnections  for transmission service and the
exchange of electric energy,  directly and through the facilities of others. The
output of our generating facilities is sold by our affiliates, Marketing Company
and AmerenEnergy,  which access Ameren's extensive transmission network pursuant
to FERC open access transmission  tariffs.  AmerenCILCO is currently expected to
continue to operate as a separate  control area. As such, its generating  plants
will not be jointly  dispatched with the generating plants owned by AmerenUE and
us.  AmerenCILCO  is a  transmission  owning  member of the Midwest  Independent
System  Operating  (Midwest ISO) and has transferred  functional  control of its
system to the Midwest ISO. Transmission service on the AmerenCILCO  transmission
system  is  provided  pursuant  to the  terms of the  Midwest  ISO  open  access
transmission  tariff on file with the FERC. For  information on AmerenCIPS'  and
AmerenUE's  participation  in the  Midwest  ISO  and  how we may be  potentially
impacted, see Note 2 to our Financial Statements under Item 8.

                                       6

<PAGE>


     The following table sets forth  information  with respect to our generating
facilities  and  capability  at  the  time  of our  expected  2003  peak  summer
electrical demand:

<TABLE>
<CAPTION>
                            Our Generating Facilities
                            -------------------------

Primary
 Fuel              Name of                                                  Net Kilowatt     Net Heat
Source              Plant                           Location                Capability(a)     Rate(i)
------             -------                          --------                -------------    --------
<S>              <C>                              <C>                       <C>              <C>
 Coal             Newton(d)                        Newton, IL                 1,134,000       10,403
                  Coffeen(d)                       Coffeen, IL                  900,000       10,368
                  Hutsonville(d)
                   (Units 3 & 4)                   Hutsonville, IL              153,000       10,371
                  Meredosia(d)
                   (Unit 3)                        Meredosia, IL                215,000       11,063
                                                                              ---------
                                                   Total Coal                 2,402,000

 Oil              Meredosia(d)
                   (Unit 4)                        Meredosia, IL                186,000       11,186
                  Hutsonville(d)
                   (Diesel)                        Hutsonville, IL                3,000       11,408
                                                                              ---------
                                                       Total Oil                189,000

 Natural          Gibson City CTs 1 & 2(c)         Gibson City, IL              234,000       11,490
  Gas(b)          Pinckneyville CTs
                    1 through 8                    Pinckneyville, IL            320,000       10,921
                  Kinmundy CTs 1 & 2(c)            Kinmundy, IL                 232,000       11,488
                  Grand Tower CTs 1 & 2(e)         Grand Tower, IL              516,000        7,515
                  Joppa 7B CTs 1, 2 & 3(f)         Joppa, IL                    162,000       11,550
                  Elgin CTs 1 through 4            Elgin, IL                    468,000       11,488
                  Columbia CTs
                    1 through 4                    Columbia, MO                 140,000       12,298
                                                                              ---------
                                                   Total Natural Gas          2,072,000

                                                          TOTAL               4,663,000(g),(h)
</TABLE>

(a)  "Net Kilowatt  Capability"  represents  generating  capacity  available for
     dispatch from the facility into the electric transmission grid.
(b)  The abbreviation "CT" represents combustion turbine generating unit.
(c)  CT has the  capability  of  operating  on either oil or  natural  gas (dual
     fuel).
(d)  Facilities were transferred to us by AmerenCIPS on May 1, 2000 (see Item 1.
     Business - General above).
(e)  The  Grand  Tower  Plant,  which  was a  coal  plant  transferred  to us by
     AmerenCIPS on May 1, 2000, has been repowered with two gas-fired CTs.
(f)  These CTs are owned by us and leased to our  parent,  Development  Company.
     The operating  lease is for a minimum term of 15 years  expiring  September
     30,  2015.  We receive  rental  payments  under the lease in fixed  monthly
     amounts  that vary  over the term of the  lease and range  from $0.8 - $1.0
     million.
(g)  Excludes  approximately 126 megawatts of two coal-fired generating units at
     our Meredosia facility which were mothballed in December 2002.
(h)  Approximately  550 megawatts of generating  capacity  (Pinckneyville  CTs 1
     through  8 and  Kinmundy  CTs 1 and 2) are  expected  to be  sold  by us to
     AmerenUE subject to receipt of necessary regulatory approvals.
(i)  "Net Heat Rate"  represents the amount of energy to produce a given unit of
     output and is expressed as BTU per kilowatthour.

     As identified in the above table,  on May 1, 2000,  AmerenCIPS  transferred
all of its  generating  facilities  and related  assets to us. As a part of this
transfer,  AmerenCIPS' generating property and plant were released from the lien
of the indenture  securing its first  mortgage bonds and such property and plant
are presently  unencumbered.  For

                                       7

<PAGE>

additional information on this asset transfer, see General section under Item 1.
None of our properties are subject to any mortgage or other encumbrance in favor
of our outstanding indebtedness.


ITEM 3.  LEGAL PROCEEDINGS.

     We are  involved in legal and  administrative  proceedings  before  various
courts and agencies  with respect to matters  arising in the ordinary  course of
business,  some of which involve substantial  amounts. We believe that the final
disposition of these proceedings, except as otherwise noted in this report, will
not have a  material  adverse  effect  on our  financial  position,  results  of
operations or liquidity.

     For additional  information on legal and  administrative  proceedings,  see
Regulation under Item 1, Liquidity and Capital Resources and Regulatory  Matters
in  Management's  Discussion and Analysis of Financial  Condition and Results of
Operations under Item 7 and Notes 2, 10 and 12 to our Financial Statements under
Item 8.

FORWARD-LOOKING STATEMENTS

     Statements made in this report which are not based on historical  facts are
"forward-looking"  and, accordingly,  involve risks and uncertainties that could
cause actual results to differ  materially from those  discussed.  Although such
"forward-looking"  statements  have  been  made in good  faith  and are based on
reasonable assumptions,  there is no assurance that the expected results will be
achieved.  These statements include (without limitation) statements as to future
expectations,  beliefs, plans, strategies,  objectives,  events,  conditions and
financial  performance.  In connection with the "safe harbor"  provisions of the
Private  Securities  Litigation  Reform  Act  of  1995,  we are  providing  this
cautionary  statement  to identify  important  factors  that could cause  actual
results to differ materially from those anticipated.  The following factors,  in
addition  to  those  discussed  elsewhere  in  this  report  and  in  subsequent
securities  filings,  could cause results to differ  materially  from management
expectations as suggested by such "forward-looking" statements:

o    the effects of regulatory actions, including changes in regulatory policy;
o    changes in laws and other  governmental  actions,  including  monetary  and
     fiscal policies;
o    the impact on us of current  regulations  related  to the  opportunity  for
     customers to choose alternative energy suppliers in Illinois;
o    the effects of increased competition in the future;
o    the  effects  of  Ameren's   participation  in  a  FERC-approved   Regional
     Transmission Organization, including activities associated with the Midwest
     Independent System Operator;
o    availability  and future  market  prices for fuel and  purchased  power and
     electricity,  including the use of financial and derivative instruments and
     volatility of changes in market prices;
o    the cost of  commodities,  such as natural gas,  used in the  production of
     electricity and our ability to recover such increased costs;
o    wholesale and retail pricing for electricity in the Midwest;
o    business and economic conditions;
o    the impact of the adoption of new accounting  standards on the  application
     of appropriate technical accounting rules and guidance;
o    interest rates and the availability of capital;
o    actions of rating agencies and the effects of such actions;
o    weather conditions;
o    generation plant construction, installation and performance;
o    the  effects  of  strategic   initiatives,   including   acquisitions   and
     divestitures;
o    the impact of current environmental regulations on generating companies and
     the expectation  that more stringent  requirements  will be introduced over
     time, which could potentially have a negative financial effect;
o    future wages and employee  benefit  costs  including  changes in returns of
     benefit plan assets;
o    disruptions of the capital  markets or other events making  Ameren's or our
     access to necessary capital more difficult or costly;
o    competition from other generating facilities, including new facilities that
     may be developed in the future;
o    cost and availability of transmission  capacity for the energy generated by
     our  generating  facilities or required to satisfy energy sales made on our
     behalf; and
o    legal and administrative proceedings.

                                       8

<PAGE>

     Given these  uncertainties,  undue  reliance  should not be placed on these
forward-looking  statements.  Except  to the  extent  required  by  the  federal
securities  laws, we undertake no  obligation  to publicly  update or revise any
forward-looking  statements,  whether  as a result  of new  information,  future
events or otherwise.

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

     This item is omitted in  reliance  on  General  Instruction  (I)(2) of Form
10-K.


                                     PART II

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
         MATTERS.

     There is no established  trading  market for our common stock.  As of March
31, 2003, our parent, Development Company, was the only shareholder of record of
our common stock.


ITEM 6.  SELECTED FINANCIAL DATA.

     The historical operating data presented below reflects our operations since
inception on May 1, 2000.  The  historical  financial  data  presented  below is
derived from our audited financial statements included elsewhere in this report.

================================================================================
For the Years Ended
December 31 (in millions)                  2002(a)        2001(a)        2000(b)
--------------------------------------------------------------------------------
    Operating revenues                     $  743         $  730         $  480
    Operating income                          139            195            103
    Net income                                 32             76             44

    As of December 31,
    Total assets                           $2,010         $1,756         $1,394
    Long-term debt                            698            424            424
    Subordinated intercompany notes           462            508            602
    Total common stockholder's equity         280            274             44
================================================================================

(a)  Revenues  were  netted  with  costs  upon  adoption  of EITF  02-3  and the
     rescission of EITF 98-10.  See Note 1 - Summary of  Significant  Accounting
     Policies to our Financial  Statements under Item 8 for further information.
     The  amount  netted  was  as  follows:  2002 - $253  million  (2001  - $256
     million).
(b)  On May 1, 2000,  AmerenCIPS  transferred its electric generating assets and
     related  liabilities,  at  net  book  value,  to  us,  in  exchange  for  a
     subordinated  promissory  note  from  us in the  principal  amount  of $552
     million and 1,000 shares of our common stock.

                                       9

<PAGE>

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

OVERVIEW

     AmerenEnergy  Generating Company,  headquartered in St. Louis, Missouri, is
an indirect  wholly-owned  subsidiary of Ameren Corporation (Ameren). We own and
operate a wholesale electric generation business in Illinois and Missouri.  Much
of our  business  was  formerly  owned and  operated by our  affiliate,  Central
Illinois  Public  Service  Company,  which  operates  as  AmerenCIPS.   We  were
incorporated in the State of Illinois in March 2000. On May 1, 2000, we acquired
from AmerenCIPS at net book value five coal-fired electric generating  stations,
which we refer to as the coal plants, all related fuel, supply,  transportation,
maintenance and labor agreements,  approximately  45% of AmerenCIPS'  employees,
and other related rights, assets and liabilities.

     Ameren is a public utility holding  company  registered with the Securities
and Exchange  Commission  (SEC) under the Public Utility  Holding Company Act of
1935 (PUHCA),  as amended,  and is also  headquartered  in St. Louis,  Missouri.
Ameren's principal business is the generation,  transmission and distribution of
electricity,  and the  distribution of natural gas to  residential,  commercial,
industrial and wholesale users in the central United States.  Ameren's principal
subsidiaries and our affiliates are as follows:

o    Union  Electric   Company,   which  operates  a   rate-regulated   electric
     generation,  transmission and distribution  business,  and a rate-regulated
     natural gas distribution business in Missouri and Illinois as AmerenUE.
o    AmerenCIPS,  which  operates a  rate-regulated  electric  and  natural  gas
     transmission and distribution business in Illinois.
o    Central  Illinois  Light  Company,  a subsidiary of CILCORP Inc.  (CILCORP)
     which operates a rate-regulated  transmission and distribution business, an
     electric generation business, and a rate-regulated natural gas distribution
     business in Illinois as  AmerenCILCO.  Ameren  completed its acquisition of
     CILCORP on January  31,  2003 from The AES  Corporation  (AES).  See Recent
     Developments for further information.
o    AmerenEnergy  Resources Company (Resources Company),  which consists of non
     rate-regulated operations.  Subsidiaries include us, AmerenEnergy Marketing
     Company (Marketing Company), which markets power for periods over one year,
     AmerenEnergy  Fuels and Services  Company (Fuels  Company),  which procures
     fuel and manages the related risks for us and our affiliates,  AmerenEnergy
     Development Company (Development Company),  which, as our parent,  develops
     and constructs generating facilities for us, and AmerenEnergy Medina Valley
     Cogen (No. 4), LLC, which indirectly owns a 40 megawatt, gas-fired electric
     generation  plant. On February 4, 2003, Ameren completed its acquisition of
     AES Medina  Valley Cogen (No. 4), LLC (Medina  Valley) from AES and renamed
     it AmerenEnergy  Medina Valley Cogen (No. 4), LLC. See Recent  Developments
     for further information.
o    AmerenEnergy,  Inc.  (AmerenEnergy)  which serves as a power  marketing and
     risk  management  agent  for us and  our  affiliates  for  transactions  of
     primarily less than one year.
o    Electric  Energy,  Inc.  (EEI),  which  operates  electric  generation  and
     transmission facilities in Illinois. Ameren has a 60% ownership interest in
     EEI, 40% owned by AmerenUE and 20% owned by Resources.
o    Ameren Services  Company (Ameren  Services),  which provides shared support
     services to us and our affiliates.

     When we refer to our, we, us or  Generating  Company,  we are  referring to
AmerenEnergy  Generating Company and in some cases our agents,  AmerenEnergy and
Fuels  Company.  All tabular dollar  amounts are in millions,  unless  otherwise
indicated.

     We have an  agreement  to  supply  all of our  power to  Marketing  Company
(Generating  Company - Marketing  Company  agreement).  Marketing  Company  then
provides  all the  power  required  for  AmerenCIPS'  native  load  requirements
(Marketing  Company - AmerenCIPS  agreement) and to serve its obligations  under
various long-term  wholesale and retail contracts.  The agreement with Marketing
Company and Marketing Company's agreement with AmerenCIPS expire on December 31,
2004, but Marketing Company and AmerenCIPS plan to seek the necessary regulatory
approvals to extend these agreements to January 1, 2007. If we have any power in
excess of Marketing Company's needs, then AmerenEnergy sells it on our behalf to
the  extent  it is  economical.  See  Illinois  Electric  in  Note 2 - Rate  and
Regulatory  Matters and Note 3 - Related  Party  Transactions  to our  Financial
Statements under Item 8 for additional information.

     We jointly  dispatch  generation with our affiliate,  AmerenUE.  This joint
dispatch agreement requires each company to serve its load requirements from its
own least-cost  generation first, but then allows access to any available excess
generation from the other company at cost. All of our sales to Marketing Company
are considered

                                       10

<PAGE>

load requirements.  The agreement has no expiration, but either party may give a
one year notice of termination beginning January 1, 2004.

     Our results of  operations  and  financial  position  are  impacted by many
factors,  including  both  controllable  and  uncontrollable  factors.  Weather,
economic  conditions,  and the  actions  of key  customers  or  competitors  can
significantly impact the demand for our services.  Our results are also impacted
by seasonal  fluctuations caused by winter heating, and summer cooling,  demand.
We principally  utilize coal in 11 power generating units  (approximately  2,570
megawatts)  and natural gas in our 25 combustion  turbine  units  (approximately
2,105 megawatts) that are primarily used for peaking power. The prices for these
commodities can fluctuate  significantly due to the world economic and political
environment,  weather,  production  levels  and many  other  factors.  We employ
various  risk  management  strategies  in order to try to reduce our exposure to
commodity risks and other risks inherent in our business. The reliability of our
power plants,  and the level of operating and  administrative  costs and capital
investment  are key  factors  that we seek to control in order to  optimize  our
results of operations, cash flows and financial position.

RESULTS OF OPERATIONS

Earnings Summary

     Our financial  statements  are  available  only for the period since May 1,
2000. Prior to that date, all operations of the coal plants now owned by us were
fully  integrated  with, and therefore  results of operations were  consolidated
into the financial  statements of  AmerenCIPS,  whose  business was to generate,
transmit  and  distribute  electricity  and to provide  other  utility  customer
support services.

     Our net income for 2002,  2001 and the period May 1, 2000 through  December
31, 2000,  was $32  million,  $76 million,  and $44 million,  respectively.  Net
income in 2002 included voluntary retirement and other restructuring charges ($6
million,  net of taxes),  which consisted of a voluntary  retirement program ($5
million,  net of  taxes)  and  the  temporary  suspension  of  operation  of two
coal-fired  generating units at our Meredosia,  Illinois coal plant ($1 million,
net of taxes).  In 2001,  net income was reduced by the adoption of Statement of
Financial  Accounting  Standards  (SFAS) No.  133,  "Accounting  for  Derivative
Instruments and Hedging Activities" ($2 million).

     The  following  table  reconciles  our net income to net  income  excluding
voluntary  retirement and other restructuring  charges and SFAS 133 adoption for
the years  ending  December  31,  2002 and 2001,  and for the period May 1, 2000
through December 31, 2000:

<TABLE>
<CAPTION>
================================================================================================================

----------------------------------------------------------------------------------------------------------------
<S>                                                                          <C>            <C>          <C>
                                                                               2002          2001         2000
                                                                               ----          ----         ----
Net income                                                                     $ 32          $ 76         $ 44
Voluntary retirement and other restructuring charges, net of taxes                6             -            -
SFAS 133 adoption, net of taxes                                                   -             2            -
----------------------------------------------------------------------------------------------------------------
Net income excluding restructuring charges and SFAS 133 adoption               $ 38          $ 78         $ 44
================================================================================================================
</TABLE>

     Excluding the charges discussed above, our net income decreased $40 million
in 2002 compared to 2001 due to a decrease in electric margin ($10 million,  net
of taxes)  primarily  from the absence of the one year 450 megawatt power supply
agreement  between Marketing Company and AmerenUE for 2001 for which we supplied
the power (2001  Marketing  Company - AmerenUE  agreement).  The absence of this
agreement  was  partially  offset by a new one year 200  megawatt  power  supply
agreement  between Marketing Company and AmerenUE for 2002 for which we supplied
the power (2002 Marketing  Company - AmerenUE  agreement) and increases in sales
to  new  and  existing  wholesale  customers.  Earnings  also  decreased  due to
increased  depreciation ($10 million, net of taxes) associated with the addition
of new combustion turbine generating units during 2001 and the fourth quarter of
2002, increased costs associated with efficiency  improvements made at our power
plants,  higher employee wages and benefits and other general  operations  costs
($10 million,  net of taxes). We also experienced  increased  interest costs ($7
million,  net of taxes)  associated  with borrowing  additional  funds at higher
interest  rates  for  previous  capacity  additions  and for  general  corporate
purposes.

     Our net income  increased  $34 million in 2001  compared to the period from
May 1, 2000 through  December 31, 2000 primarily due to comparing a twelve month
operating  period for 2001 to the eight month operating period for 2000, as well
as higher  average  period sales volumes in 2001 versus 2000.  In addition,  the
increased  interest  costs  were  due to  borrowing  funds to  support  our 2001
capacity additions.

                                       11

<PAGE>

Recent Developments

CILCORP Acquisition

     On January 31,  2003,  after  receipt of the  necessary  regulatory  agency
approvals   and   clearance   from  the   Department   of   Justice   under  the
Hart-Scott-Rodino  Antitrust  Improvements Act, Ameren completed its acquisition
of all of the  outstanding  common  stock of  CILCORP  from AES.  CILCORP is the
parent company of Peoria,  Illinois-based  Central Illinois Light Company, which
operated as CILCO. With the acquisition,  CILCO became an Ameren subsidiary, but
remains a separate  utility  company,  operating as AmerenCILCO.  On February 4,
2003,  Ameren also completed its  acquisition of Medina Valley which  indirectly
owns a 40 megawatt, gas-fired electric cogeneration plant. With the acquisition,
Medina Valley  became a  wholly-owned  subsidiary  of Resources  Company and was
renamed as  AmerenEnergy  Medina  Valley  Cogen (No.  4),  LLC.  The CILCORP and
AmerenEnergy  Medina  Valley Cogen (No.  4), LLC  financial  statements  will be
included  in  Ameren's  consolidated  financial  statements  effective  with the
January and February 2003 acquisition dates.

     Ameren acquired  CILCORP to complement its existing  Illinois  electric and
gas  operations.  The  purchase  included  CILCO's  rate-regulated  electric and
natural gas  businesses in Illinois  serving  approximately  200,000 and 205,000
customers, respectively, of which approximately 150,000 are combination electric
and gas customers.  CILCO's service  territory is contiguous to Ameren's service
territory and accessible by our electric generation facilities. CILCO also has a
non rate-regulated  electric and gas marketing business  principally  focused in
the Chicago, Illinois region. Finally, the purchase includes approximately 1,200
megawatts of largely coal-fired  generating capacity,  most of which is expected
to become non rate-regulated in 2003.

     The total  purchase price was  approximately  $1.4 billion and included the
assumption of CILCORP and Medina  Valley debt and preferred  stock at closing of
approximately  $900  million,   with  the  balance  of  the  purchase  price  of
approximately $500 million paid with cash on hand. The purchase price is subject
to certain  adjustments  for  working  capital  and other  changes  pending  the
finalization  of CILCORP's  closing  balance  sheet.  The cash  component of the
purchase  price came from Ameren's  issuances in September  2002 of 8.05 million
common shares and in early 2003 of 6.325 million common shares.

Credit Ratings

     In April 2002, as a result of  AmerenUE's  then pending  Missouri  electric
earnings  complaint case and the CILCORP  transaction and related  assumption of
debt,  credit rating agencies placed Ameren's and its  subsidiaries'  debt under
review.  Following the completion of the acquisition of CILCORP in January 2003,
Standard & Poor's  lowered the ratings of Ameren,  AmerenUE and  AmerenCIPS  and
increased our ratings.  At the same time,  Standard & Poor's changed the outlook
assigned to all of Ameren's ratings to stable. Moody's also lowered Ameren's and
AmerenUE's  ratings  subsequent  to the  acquisition  and changed the outlook on
these  ratings to stable.  These  actions were  consistent  with the actions the
rating agencies  disclosed they were  considering  following the announcement of
the CILCORP acquisition.

                                       12

<PAGE>

     As of February  2003,  the ratings by Moody's and Standard & Poor's were as
follows:
================================================================================
                                               Moody's         Standard & Poor's
--------------------------------------------------------------------------------
Ameren Corporation:
     Issuer/Corporate credit rating              A3                  A-
     Unsecured debt                              A3                  BBB+
     Commercial paper                            P-2                 A-2

AmerenUE:
     Secured debt                                A1                  A-
     Unsecured debt                              A2                  BBB+
     Commercial paper                            P-1                 A-2

AmerenCIPS:
      Secured debt                               A1                  A-
     Unsecured debt                              A2                  BBB+

AmerenEnergy Generating Company:
     Senior Notes - due 2005                     A3                  A-
     Senior Notes - due 2010 and 2032            Baa2                A-
================================================================================

     Standard & Poor's  increased the ratings of CILCORP and CILCO subsequent to
the acquisition of these entities by Ameren.  As of February 2003, the unsecured
debt ratings of CILCORP  were BBB+ and Baa2 from  Standard & Poor's and Moody's,
respectively.  The  secured  debt  ratings  of  AmerenCILCO  were A- and A2 from
Standard & Poor's and Moody's,  respectively.  Standard & Poor's assigned stable
outlooks to the ratings.  Moody's also assigned a stable  outlook to the ratings
for CILCORP and AmerenCILCO.

     Any  adverse  change in our or  Ameren's  ratings  may reduce our access to
capital and/or  increase the costs of borrowings  resulting in a negative impact
on  earnings.  A credit  rating  is not a  recommendation  to buy,  sell or hold
securities and should be evaluated  independently  of any other rating.  Ratings
are  subject to  revision  or  withdrawal  at any time by the  assigning  rating
organization.

Electric Operations

     The  following  table  represents  the  favorable  (unfavorable)  impact on
electric  margin versus the prior periods for the years ended  December 31, 2002
and 2001:

================================================================================
                                                   2002             2001(a)
--------------------------------------------------------------------------------
Electric Revenues:
   Wholesale revenues                              $  5             $  283
   Interchange revenues                               8                (45)
   Other                                              3                  2
--------------------------------------------------------------------------------
    Total variation in electric operating revenues   16                240
--------------------------------------------------------------------------------
Fuel and Purchased Power:
   Fuel:
     Generation                                     (52)               (47)
     Price                                           (4)               (14)
     Generation efficiencies and other                5                 (3)
   Purchased power                                   18                 (6)
--------------------------------------------------------------------------------
      Total variation in fuel and purchased power   (33)               (70)
--------------------------------------------------------------------------------
Change in electric margin                         $ (17)            $  170
================================================================================
(a) This column represents the comparison between the year ended December 31,
    2001 and the period May 1, 2000 through December 31, 2000.

     Electric margins decreased $17 million for the year ended December 31, 2002
compared to 2001.  Decreases in electric  margin in 2002 were  primarily  due to
lower  power  prices  and the  reduction  of  indirect  sales to our  affiliate,
AmerenUE, under the 2001 and 2002 Marketing Co - AmerenUE agreements,  partially
offset by increases in other wholesale and interchange revenues and increases in
use of lower cost generation due to better  availability.  Revenues increased in
2002 due to an  increase  in the  volume  of  interchange  sales  for the  year,
although these sales provided lower margins due to lower electricity  prices. In
addition,  a net increase in new wholesale  customers

                                       13

<PAGE>

added by  Marketing  Company  and an  increase  in sales to  existing  wholesale
customers due to warmer weather increased  revenues.  Fuel increased in 2002 due
primarily to increased use of lower cost generation stations due to fewer forced
and maintenance  outages at our coal plants.  Reduced purchased power costs were
due to lower energy  prices.  We expect  power  prices in the energy  markets to
remain  generally  soft,  which will  impact  the  margins  we can  generate  by
marketing our power into the interchange markets.

     During 2002, we adopted the provisions of Emerging Issues Task Force (EITF)
Issue 02-3,  "Issues  Involved in Accounting for  Derivative  Contracts Held for
Trading  Purposes and Contracts  Involved in Energy Trading and Risk  Management
Activities,"  that required  revenues and costs  associated  with certain energy
contracts to be shown on a net basis in the income statement.  Prior to adopting
EITF 02-3 and the rescission of EITF Issue No. 98-10,  "Accounting for Contracts
Involved  in Energy  Trading and Risk  Management  Activities,"  our  accounting
practice was to present all settled energy purchase or sale contracts within our
power risk management  program on a gross basis in Operating Revenues - Electric
and in Operating  Expenses - Fuel and Purchased Power.  This meant that revenues
were  recorded  for the  notional  amount of the  power  sale  contracts  with a
corresponding  charge to income for the costs of the energy that was  generated,
or for the notional amount of a purchased power  contract.  Upon adoption,  EITF
02-3  requires  that prior periods also be netted to conform to the current year
presentation. Adoption of this EITF 02-3 did not have any impact on operating or
net income for any period or stockholder's  equity.  The operating  revenues and
costs netted for the year ended December 31, 2002 were $253 million (2001 - $256
million),  which reduced interchange revenues and purchased power costs by equal
amounts.  SFAS 133 was adopted on January 1, 2001 and therefore,  no netting was
required for the year ended December 31, 2000.

     Electric  margins  increased  $170 million for the year ended  December 31,
2001 compared to the period May 1, 2000 through  December 31, 2000 primarily due
to the longer operating  period, as well as higher average sales volumes in 2001
versus 2000 associated with sales through Marketing Company,  the 2001 Marketing
Company - AmerenUE agreement,  and through AmerenEnergy.  Electric revenues from
AmerenEnergy's  marketing  efforts  increased  $211 million or 201% for the year
2001 compared to the eight month period in the prior year as kilowatthours  sold
increased 228%.

Other Operating Expenses

Other Operations and Maintenance

     Other  operations and  maintenance  expenses  increased $17 million in 2002
compared to 2001,  primarily  due to higher  employee  benefit  costs related to
increasing  healthcare costs and the investment  performance of employee benefit
plans' assets ($4 million),  higher wages,  higher injuries and damages expenses
based on claims experience ($4 million),  incremental  increases associated with
the combustion  turbine generating units added during 2001, costs for efficiency
improvements  made at the coal plants and timing of plant outages between years.
See also "Equity  Price Risk" below for a  discussion  of our  expectations  and
plans  regarding  trends  in  employee  benefit  costs.   Other  operations  and
maintenance expenses increased $57 million in 2001 compared to the period May 1,
2000 through December 31, 2000 primarily due to the longer operating period ($43
million) as well as due to higher  employee  benefit costs in 2001 ($3 million),
resulting from increasing  healthcare  costs, and the investment  performance of
employee benefit plans' assets and increased operating costs associated with the
combustion turbine generating units added in 2001.

     Ameren Services and AmerenEnergy  provided services to us, including wages,
employee  benefits  and  professional  services  that  were  included  in  other
operations and maintenance expenses.  See Note 3 - Related Party Transactions to
our Financial Statements under Item 8 for further information.

Restructuring Charges

     Voluntary retirement and other restructuring charges of $10 million in 2002
consisted primarily of a charge related to Ameren's voluntary retirement program
of $8  million  based  on  voluntary  retirements  of  approximately  35 of  our
employees and additional  employees  providing  support  functions to us through
Ameren Services. These costs consisted primarily of special termination benefits
associated  with our  pension and  post-retirement  benefit  plans.  Most of the
employees who voluntarily  retired will leave Ameren by March 2003. In addition,
in December 2002, we announced  plans to temporarily  suspend  operations of two
coal-fired  generating  units (126 megawatts) at our Meredosia,  Illinois plant,
which  resulted in a total  charge of  approximately  $2  million.  See Note 7 -
Voluntary Retirement and Other Restructuring Charges to our Financial Statements
under Item 8 for further information.

                                       14

<PAGE>

Depreciation and Amortization

     Depreciation  and  amortization  expense  increased  $16  million  in  2002
compared  to 2001 and $25  million  in 2001  compared  to the period May 1, 2000
through  December  31,  2000.  These net  increases  were  primarily  due to our
investment in combustion turbine generating units and coal-fired power plants in
2001 and 2002 in addition  to the longer  operating  period in 2001  compared to
2000.

Other Taxes

     Other  taxes  expense  in 2002  decreased  $7  million  compared  to  2001,
primarily due to reduced property tax assessments  partially offset by increased
property taxes in 2002 associated with the combustion  turbine  generating units
added in the prior  year.  Other  taxes  expense  in 2001  increased  $6 million
compared to the period May 1, 2000 through  December 31, 2000,  primarily due to
the longer operating period.

Interest

     Interest expense increased $11 million in 2002 compared to 2001,  primarily
due to our  issuance  of $275  million  of 7.95%  Senior  Notes in June 2002 and
additional borrowings,  prior to the issuance of the Senior Notes, from Ameren's
non-utility  money pool at higher  interest  rates,  compared to the prior year.
These  increases were partially  offset by a reduction in the principal  amounts
outstanding on our subordinated  intercompany promissory notes to AmerenCIPS and
Ameren,  therefore  reducing  associated  interest  costs  in the  current  year
compared to the prior year. Proceeds from the Senior Notes offering were used to
repay  lower cost  short-term  borrowings  and for general  corporate  purposes.
Interest  expense  increased $40 million in 2001,  compared to the period May 1,
2000 through December 31, 2000, primarily due to the longer operating period, as
well as our issuance of $425 million of Senior Notes in November  2000. See Note
6 - Long-Term Debt and  Intercompany  Notes Payable to our Financial  Statements
under Item 8 for further discussion of our Senior Notes.

Income Taxes

     Income  tax  expense  decreased  $27  million  in 2002,  compared  to 2001,
primarily due to lower pretax income.  Income tax expense  increased $20 million
in 2001, compared to the period May 1, 2000 through December 31, 2000, primarily
due to higher pretax income associated with the longer operating period.

LIQUIDITY AND CAPITAL RESOURCES

Operating

     Our net cash flows  provided by operating  activities  totaled $111 million
for 2002, compared to $130 million for 2001, and $98 million for the period from
May 1, 2000 through  December 31, 2000. Cash provided from operations  decreased
$19 million in 2002, primarily due to increased funds used in accounts and wages
payable  compared  to the same year ago period due to timing of payment of funds
to and from our affiliates. These decreases were partially offset by an increase
in cash  flows  from  accounts  receivable,  intercompany  due to the  timing of
receipt  of  payments  to and from our  affiliates.  Cash flow  from  operations
increased in 2001 due to the longer  operating  period,  higher  average  period
sales volumes in 2001 versus 2000 due to increased available generating capacity
and a change in working capital requirements.

Pension Funding

     Ameren made cash  contributions  totaling  $31 million to Ameren's  defined
benefit  retirement  plan during 2002.  Our share of the cash  contribution  was
approximately  $4  million.  At December  31,  2002,  Ameren  recorded a minimum
pension liability of $102 million,  net of taxes,  which resulted in a charge to
Accumulated  Other  Comprehensive  Income (OCI) and a reduction to stockholder's
equity. Our share of the minimum pension liability was $6 million, net of taxes.

     Based on the performance of plan assets through  December 31, 2002,  Ameren
expects to be required under the Employee Retirement Income Security Act of 1974
(ERISA) to fund approximately  $150 million to $175 million annually,  including
CILCORP,  in 2005, 2006 and 2007 in order to maintain minimum funding levels for
Ameren's  pension plan. In addition,  Ameren  estimates the pension  funding for
CILCORP to be less than $1 million in 2003 and approximately $5 million in 2004.
We expect our share of the annual funding in 2005,  2006, and 2007 to be between
approximately  $18 million to $21 million  which  includes our share  related to
employees of Ameren

                                       15

<PAGE>

Services.  These  amounts are  estimates  and may change  based on actual  stock
market  performance,  changes in interest  rates,  and any pertinent  changes in
government  regulations.  At December 31, 2002,  Ameren's Net Benefit Obligation
was $1,587  million  and its Fair Value of Plan Assets was $1,059  million.  See
Benefit Plan Accounting under Accounting Matters - Critical  Accounting Policies
below.

Investing

     Our cash  flows  used in  investing  activities  was $442  million  in 2002
compared  to $247  million in 2001 and $570  million  for the period May 1, 2000
through December 31, 2000.  Construction  expenditures were $442 million in 2002
(2001 - $347 million;  2000 - $470 million) primarily related to construction of
combustion  turbine generating units and various upgrades at our coal plants. In
2002, we placed into service  approximately 470 megawatts of combustion  turbine
generating  capacity  (approximately $215 million) at Elgin,  Illinois.  Also in
2002, we paid approximately $140 million to Development Company for a combustion
turbine  generating unit purchased and in accounts  payable at December 2001. In
addition, Selective Catalytic Reduction technology was added on units 1 and 2 of
our  Coffeen  coal  plant  at a cost of  approximately  $42  million.  We  added
approximately   850   megawatts   (approximately   $530  million)  in  2001  and
approximately 595 megawatts  (approximately  $275 million) in 2000 of combustion
turbine generating capacity.

     For the five-year period 2003 through 2007,  construction  expenditures are
estimated to approximate $200 - $230 million, of which approximately $50 million
is expected in 2003. This estimate includes capital expenditures for upgrades to
existing coal and gas fired facilities and other generation-related  activities,
as well as for compliance with new NOx (nitrogen oxide) control regulations,  as
discussed  below. We do not have any plans at this time to purchase or construct
additional power generating units.

     We  intend  to  sell  at  net  book  value   approximately   550  megawatts
(approximately  $260 million) of our combustion turbine generating units located
at Pinckneyville and Kinmundy,  Illinois to our regulated  affiliate,  AmerenUE,
which wants them to comply with AmerenUE's  recent  Missouri  electric rate case
settlement  and to meet its future  regulated  generating  capacity  needs.  The
transfer is subject to receipt of necessary regulatory approvals and is expected
to be  completed in 2003.  Cash  proceeds  from the sale will be applied  toward
reducing our short-term  money pool  borrowings and for other general  operating
activities. The indenture for our Senior Notes imposes limitations on the use of
proceeds of the sale of our  generating  units if the net book value of the sold
assets  (together with prior assets sales since November 1, 2000) exceeds 25% of
consolidated  tangible  assets (as defined in the indenture) as of the first day
of the most recently ended fiscal quarter prior to the date the assets are sold.
We do not expect that the sale of the  Pinckneyville  and  Kinmundy  units would
exceed the 25% amount.  If the sale  proceeds  did exceed the  limitation,  they
would have to be (1)  reinvested in our business  within 12 months,  (2) used to
repay  indebtedness  or (3) retained by us. This  transfer is expected to reduce
operating and depreciation costs for 2003. Taking into account this sale and the
temporary  suspension of Meredosia units as previously  mentioned,  we expect to
maintain  our  generation  capacity at  approximately  4,125  megawatts  for the
foreseeable future.

     We  continually  review our  generation  portfolio and expected  electrical
needs and, as a result, we could modify our plan for generation asset purchases,
which  could  include  the timing of when  certain  assets  will be added to, or
removed from our portfolio, the type of generation asset technology that will be
employed, or whether capacity may be purchased,  among other things. Any changes
that we may plan to make for future generating needs could result in significant
capital expenditures or losses being incurred, which could be material.

Environmental

     We are subject to various environmental  regulations by federal, state, and
local authorities.  From the beginning phases of siting and development,  to the
ongoing  operation  of  existing  or new  electric  generating  facilities,  our
activities  involve  compliance with diverse laws and  regulations  that address
emissions  and  impacts  to air and  water,  special,  protected,  and  cultural
resources (such as wetlands,  endangered species,  and  archeological/historical
resources),  chemical and waste  handling,  and noise  impacts.  Our  activities
require complex and often lengthy  processes to obtain  approvals,  permits,  or
licenses for new, existing,  or modified facilities.  Additionally,  the use and
handling of various chemicals or hazardous materials (including wastes) requires
preparation of release  prevention plans and emergency response  procedures.  As
new laws or  regulations  are  promulgated,  we assess their  applicability  and
implement the necessary modifications to our facilities or their operations,  as
required.

     The U.S.  Environmental  Protection  Agency  (EPA) issued a rule in October
1998  requiring  22  Eastern  states  and the  District  of  Columbia  to reduce
emissions of NOx in order to reduce ozone in the Eastern  United  States.  Among
other things,  the EPA's rule  establishes an ozone season,  which runs from May
through September,  and a NOx

                                       16

<PAGE>

emission budget for each state,  including Illinois where most of our facilities
are located.  The EPA rule requires states to implement  controls  sufficient to
meet their NOx budget by May 31, 2004. In addition, the Illinois EPA already has
a rule which will  require  additional  NOx  controls by the summer of 2003.  We
expect to have the NOx  controls in operation by the summer of 2003 to meet both
regulatory requirements.

     As a result of these state requirements, we estimate spending an additional
$40 million for pollution control capital  expenditures and NOx credits by 2006.
A total of $90 million was spent in 2002 and 2001.  This  estimate  includes the
assumption  that the  regulations  will  require the  installation  of Selective
Catalytic  Reduction  technology  on some of our  units,  as well as  additional
controls.

     See Note 10 - Commitments  and  Contingencies  to our Financial  Statements
under Item 8 for further discussion of environmental matters.

Financing

     Our cash flows  provided by  financing  activities  totaled $332 million in
2002,  $118  million in 2001 and $467  million  for the period  from May 1, 2000
through  December 31, 2000. Our principal  financing  activities for the periods
included the issuance of long-term debt,  additional  short-term borrowings from
Ameren's  non-utility money pool, and receipt of a cash contribution from Ameren
of $150 million,  partially offset by redemptions of intercompany  notes payable
and payment of dividends.

Notes Payable -Intercompany and Liquidity

     Our gross margins from power supply  contracts  with  affiliated  companies
continue to be the principal source of cash from operating  activities.  We plan
to utilize  short-term  debt to support normal  operations  and other  temporary
capital  requirements.  We have the  ability to borrow up to $600  million  from
Ameren through a non-utility  money pool  agreement.  However,  the total amount
available to us at any time is reduced by the amount of  borrowings  from Ameren
by our  affiliates  and is increased  to the extent  other Ameren  non-regulated
companies  advance  surplus  funds to the  non-utility  money  pool or  external
sources are used by Ameren to increase the  available  amounts.  At December 31,
2002,  $445  million  was  available  through  the  non-utility  money  pool not
including  additional  funds available  through invested cash balances at Ameren
and  uncommitted  bank lines.  The  non-utility  money pool was  established  to
coordinate and provide for short-term cash and working  capital  requirements of
Ameren's  non-regulated  activities  and is  administered  by  Ameren  Services.
Interest is calculated at varying rates of interest depending on the composition
of internal  and  external  funds in the  non-utility  money  pool.  The average
interest rate for borrowings from the  non-utility  money pool was 7.60% in 2002
(2001 - 4.08%) and 6.52% for the period from May 1, 2000  through  December  31,
2000.  These  rates are based on the cost of  Ameren's  funds used to fund money
pool  advances.  We incurred  $6 million in net  intercompany  interest  expense
associated with outstanding  borrowings from the non-utility  money pool in 2002
(2001 - $2  million)  and $1  million  for the period  from May 1, 2000  through
December 31, 2000. At December 31, 2002, we had  borrowings of $191 million from
the non-utility money pool.

     We and Ameren rely on access to the capital markets as a significant source
of funding for capital  requirements  not satisfied by operating cash flows. The
inability by us to raise capital on favorable terms,  particularly  during times
of uncertainty in the capital markets,  could  negatively  impact our ability to
maintain  and grow our  businesses.  Based on our and  Ameren's  current  credit
ratings, we believe that we will continue to have access to the capital markets.
However, events beyond our control may create uncertainty in the capital markets
such that our cost of  capital  would  increase  or our  ability  to access  the
capital markets would be adversely affected.

                                       17
<PAGE>
<TABLE>
<CAPTION>

     The following  table  summarizes  available  borrowing  capacity  under our
committed lines of credit and credit agreements as of December 31, 2002:

                                                               Amount of commitment expiration per period:
====================================================================================================================
<S>                                              <C>            <C>              <C>        <C>         <C>
                                                    Total        Less than 1       1 - 3     4 - 5       After 5
                                                  committed         year           years     years        years
--------------------------------------------------------------------------------------------------------------------
Lines of credit and credit agreements:
--------------------------------------------------------------------------------------------------------------------
   Guarantees (a)                                  $   463          $  -          $  463      $   -       $   -
   Other commercial commitments (b)                    600            470            130          -           -
--------------------------------------------------------------------------------------------------------------------
     Total                                         $ 1,063          $ 470         $  593      $   -       $   -
--------------------------------------------------------------------------------------------------------------------
     (a)  Ameren's "aggregate  investment" in Exempt Wholesale Generators (EWGs)
          (such as us) and foreign  utility  companies is limited under PUHCA to
          an amount  not  greater  than 50% of  Ameren's  consolidated  retained
          earnings  unless  regulatory  approval is obtained to make  additional
          investments.  Aggregate  investment includes all amounts invested,  or
          committed  to be invested,  for which there is  recourse,  directly or
          indirectly,  to the registered holding company and includes guarantees
          by Ameren  of our  obligations.  At  December  31,  2002,  Ameren  had
          capacity to increase its aggregate investment in EWGs by $463 million.
     (b)  Available through the non-utility money pool.

     The following table summarizes our contractual obligations as of December
31, 2002:
<CAPTION>
====================================================================================================================
<S>                                              <C>            <C>              <C>        <C>         <C>
                                                                Less than 1       1 - 3     4 - 5       After 5
                                                 Total             year           years     years        years
--------------------------------------------------------------------------------------------------------------------
Long-term debt                                  $  700           $   -            $ 225     $   -        $ 475
Subordinated notes payable - intercompany          462               50             412         -            -
Notes payable - intercompany                       191              191              -          -            -
Operating leases (a)                                 8                1              1          1            5
Other long-term obligations (b)                    813              185             284       175          169
--------------------------------------------------------------------------------------------------------------------
Total cash contractual obligations              $2,173           $  427           $ 921     $ 176        $ 649
--------------------------------------------------------------------------------------------------------------------
</TABLE>
(a)  Amounts  related to certain  real  estate  leases have  indefinite  payment
     periods.  The amounts for these items are included in the less than 1 year,
     1-3 years and 4-5 years.  Amounts for after 5 years are not included in the
     total amount due to the indefinite periods.
(b)  Represents purchase contracts for coal and gas.

Indenture and Credit Agreement Provisions and Covenants

     Ameren's and our financial  agreements  include  customary default or cross
default  provisions  that could impact the continued  availability  of credit or
result in the  acceleration  of  repayment.  Many of Ameren's  committed  credit
facilities  require the borrower to represent in  connection  with any borrowing
under the facility that no material  adverse  change has occurred  since certain
dates.  Ameren's  financing  arrangements do not contain credit rating triggers,
with  the  exception  of  certain  ratings  triggers  within  CILCO's  financing
arrangements.

     Covenants in Ameren's  committed credit facilities  require the maintenance
of the  percentage  of total debt to total  capital  of 60% or less for  Ameren,
AmerenUE and AmerenCIPS.  As of December 31, 2002, this ratio was  approximately
50%, 43% and 50% for Ameren,  AmerenUE, and AmerenCIPS,  respectively.  Ameren's
committed credit facilities also include  indebtedness  cross default provisions
that could trigger a default under these  facilities in the event any subsidiary
of Ameren  (subject to definition in the underlying  credit  agreements),  other
than certain project finance subsidiaries, defaults on indebtedness in excess of
$50 million.

     Most of Ameren's  committed credit facilities include provisions related to
the funded status of Ameren's  pension plan.  These  provisions  either  require
Ameren  to meet  minimum  ERISA  funding  requirements  or  limit  the  unfunded
liability  status of the plan.  Under the most  restrictive of these  provisions
impacting  Ameren  facilities  totaling $400  million,  an event of default will
result if the unfunded  liability  status (as defined in the  underlying  credit
agreements)  of Ameren's  pension plan  exceeds  $300 million in the  aggregate.
Based on the most recent  valuation  report  available to Ameren at December 31,
2002,  which was based on  January  2002  asset and  liability  valuations,  the
unfunded liability status (as defined) was $31 million.  However, based on stock
market and interest  rate  performance  during 2002,  Ameren  believes an excess
unfunded  liability  may occur.  As a result,  Ameren may need to  terminate  or
replace the affected facilities, renegotiate the facility provisions or fund any
unfunded liability shortfall. Should Ameren elect to terminate these facilities,
Ameren  believes it would  otherwise  have  sufficient  liquidity  to manage its
short-term funding requirements.

     Our Senior Note indenture includes provisions that require us to maintain a
senior  debt  service  coverage  ratio of at least 1.75 to 1 (for both the prior
four fiscal quarters and for the next  succeeding  four,  six-month  periods) in
order to pay  dividends,  or to make  payments of  principal  or interest  under
certain   subordinate   indebtedness,   excluding

                                       18

<PAGE>

amounts payable under our  intercompany  note payable with  AmerenCIPS.  For the
four quarters  ended  December 31, 2002,  this ratio was 4.10 to 1. In addition,
the indenture also restricts us from incurring any additional indebtedness, with
the exception of certain  permitted  indebtedness  as defined in the  indenture,
unless our senior debt service  coverage  ratio equals at least 2.5 to 1 for the
most  recently  ended four fiscal  quarters and our senior debt to total capital
ratio  would  not  exceed  60%,  both  after  giving  effect  to the  additional
indebtedness  on  a  pro-forma  basis.  This  debt  incurrence   requirement  is
disregarded  in the event  certain  rating  agencies  reaffirm our ratings after
considering  the  additional  indebtedness.  As of December 31, 2002, our senior
debt to total capital ratio was 55%.

     At December 31, 2002,  Ameren and its subsidiaries  were in compliance with
their credit agreement provisions and covenants.

Off-Balance Sheet Arrangements

     At  December  31,  2002,  neither  Ameren,  nor  any of  its  subsidiaries,
including  us, had any  off-balance  sheet  financing  arrangements,  other than
operating  leases  entered  into in the ordinary  course of business.  We do not
expect to engage in any significant  off-balance sheet financing arrangements in
the near future.

Long-Term Debt

     The following  table  summarizes  our  issuances of long-term  debt for the
years ended 2002, 2001 and for the period May 1, 2000 through December 31, 2000.
For additional  information related to the terms and uses of these issuances and
the sources of funds and terms for redemptions,  see Note 6 - Long-Term Debt and
Intercompany Notes Payable to our Financial Statements under Item 8.

================================================================================
                                          Month
Issuances -                               Issued        2002      2001      2000
--------------------------------------------------------------------------------
Long-term Debt
7.95% Series F, senior notes, due 2032     June        $ 275     $  -      $  -
7.75% Series C, senior notes, due 2005    November        -         -        225
8.35% Series D, senior notes, due 2010    November        -         -        200
--------------------------------------------------------------------------------
Total long-term debt issuances                         $ 275     $  -      $ 425
--------------------------------------------------------------------------------

     We expect to fund maturities of long-term debt and contractual  obligations
through a combination of cash flow from operations and external financing.

OUTLOOK

     We believe  there will be  challenges to earnings in 2003 and beyond due to
industry-wide trends and company-specific  issues. The following are expected to
put pressure on earnings in 2003 and beyond:

     o    Weak economic conditions, which impacts native load demand,
     o    Generally  soft power  prices in the Midwest are expected to limit the
          amount of revenues we can generate by marketing  our excess power into
          the interchange markets,
     o    The  adverse  effects  of rising  employee  benefit  costs and  higher
          insurance costs, and
     o    An assumed return to more normal weather patterns.

     In late 2002, we and Ameren announced the following actions to mitigate the
effect of these challenges:

     o    A voluntary  retirement program that was accepted by approximately 550
          Ameren  employees,  including  approximately  35 of our  employees and
          additional  employees providing support functions to us through Ameren
          Services,
     o    Modifications   to  retiree   employee   benefit   plans  to  increase
          co-payments and limit our overall cost,
     o    A wage  freeze in 2003 for all  management  employees,  including  our
          employees,
     o    Suspension  of  operations  at  two  1940's-era   generating   plants,
          including two units at our Meredosia coal plant,  to reduce  operating
          costs, and
     o    Reductions of 2003 expected capital expenditures.

     We are considering  additional actions,  including  modifications to active
employee benefits, further staffing reductions and other initiatives.

                                       19

<PAGE>

     In the ordinary course of business,  we and Ameren  evaluate  strategies to
enhance our financial  position,  results of  operations  and  liquidity.  These
strategies may include potential acquisitions,  divestitures,  and opportunities
to reduce costs or increase revenues,  and other strategic  initiatives in order
to increase Ameren's  shareholder value. We are unable to predict which, if any,
of these  initiatives will be executed,  as well as the impact these initiatives
may have on our future financial position, results of operations or liquidity.

Labor Agreements

     Certain of our employees are represented by the  International  Brotherhood
of Electrical Workers (IBEW) and the International  Union of Operating Engineers
(IUOE).  These  employees  comprise  approximately  70% of our workforce.  Labor
agreements  covering  the  majority of  employees  represented  by IBEW and IUOE
expire  by June  2003.  We  cannot  predict  what  issues  may be  raised by the
collective bargaining units and, if raised, whether negotiations concerning such
issues will be successfully concluded.

REGULATORY MATTERS

Illinois Electric

     See Note 2 - Rate and Regulatory Matters to our Financial  Statements under
Item 8.

Federal - Electric Transmission

     See Note 2 - Rate and Regulatory Matters to our Financial  Statements under
Item 8.

ACCOUNTING MATTERS

Critical Accounting Policies

     Preparation  of  the  financial   statements  and  related  disclosures  in
compliance  with  generally   accepted   accounting   principles   requires  the
application of appropriate  technical accounting rules and guidance,  as well as
the use of estimates.  Our  application  of these  policies  involves  judgments
regarding many factors, which, in and of themselves, could materially impact the
financial  statements  and  disclosures.  A future change in the  assumptions or
judgments applied in determining the following matters, among others, could have
a material  impact on future  financial  results.  In the table  below,  we have
outlined  those  accounting   policies  that  we  believe  are  most  difficult,
subjective or complex:

<TABLE>
<S>                                                <C>
Accounting Policy                                  Uncertainties Affecting Application
-----------------                                  -----------------------------------

Environmental Costs

We accrue for all known environmental              o  Extent of contamination
contamination where remediation can be             o  Responsible party determination
reasonably estimated.  However, we are             o  Approved methods for cleanup
contractually indemnified by AmerenCIPS for        o  Present and future legislation and governmental
remediation costs that we incur at the sites of       regulations and standards
our coal plants relating to environmental          o  Results of ongoing research and development
contamination that occurred prior to the              regarding environmental impacts
AmerenCIPS' transfer of the coal plants to us on
May 1, 2000.

</TABLE>

Basis for Judgment
We determine the proper amounts to accrue for environmental  contamination based
on  internal  and third  party  estimates  of  clean-up  costs in the context of
current remediation standards and available technology.


<TABLE>
Benefit Plan Accounting
<S>                                               <C>
Based on actuarial calculations, we accrue         o  Future rate of return on pension and other plan assets
costs of providing future employee benefits in     o  Interest rates used in valuing benefit obligations
accordance with SFAS 87, 106 and 112. See          o  Healthcare cost trend rates
Note 9 - Retirement Benefits to our Financial
</TABLE>
                                       20

<PAGE>
<TABLE>
<S>                                               <C>
Statements under Item 8.                           o  Timing of employee retirements

</TABLE>

Basis for Judgment
We utilize a third party consultant to assist us in evaluating and recording the
proper  amount for future  employee  benefits.  Our  ultimate  selection  of the
discount  rate,  healthcare  trend rate and  expected  rate of return on pension
assets is based on our review of available  current,  historical  and  projected
rates, as applicable.

Derivative Financial Instruments
<TABLE>
<S>                                               <C>
We record all derivatives at their fair market     o  Market conditions in the energy industry, especially
value in accordance with SFAS 133.  The               the effects of price volatility on contractual
identification and classification of a derivative  o  commodity commitments
and the fair value of such derivative must be      o  Regulatory and political environments and
determined.  We designate certain derivatives         requirements
as hedges of future cash flows.  See Note 4 -      o  Fair value estimations on longer term contracts
Derivative Financial Instruments to our            o  Complexity of financial instruments and accounting
Financial Statements under Item 8.                    rules
                                                   o  Effectiveness of our derivatives that have been
                                                      designated as hedges
</TABLE>

Basis for Judgment
We determine  whether a transaction is a derivative  versus a normal purchase or
sale  based on  historical  practice  and our  intention  at the time we enter a
transaction.  We utilize  actively  quoted prices,  prices  provided by external
sources,  and prices based on internal  models,  and other valuation  methods to
determine the fair market value of derivative financial instruments.

Impact of Future Accounting Pronouncements

     See Note 1 - Summary of  Significant  Accounting  Policies to our Financial
Statements under Item 8.

EFFECTS OF INFLATION AND CHANGING PRICES

     Under the  Marketing  Company -  AmerenCIPS  agreement  which we supply the
power for, our rates are fixed through January 1, 2004. In 2002, legislation was
passed in Illinois to extend the rate freeze period through January 1, 2007 from
the  original  expiration  of January 1,  2005.  As a result of this  extension,
Marketing  Company  expects to seek to renew or extend the  Marketing  Company -
AmerenCIPS  agreement  through the same period.  In addition,  Marketing Company
also has several wholesale  customers under fixed energy and capacity  contracts
ranging  from less than one year to eleven  years which we also supply the power
to serve. As a result, inflation affects our operations, earnings, stockholder's
equity and financial performance.

     We have no provisions for adjusting  prices for changes in the cost of fuel
for electric generation. In the short-term, we are impacted by changes in market
prices for natural gas we must purchase to run our combustion  turbine  electric
generators.  We have structured  various supply agreements to maintain access to
multiple  gas pools and supply  basins to minimize  the impact to the  financial
statements.  In the  long-term,  we are impacted by the price of coal,  which we
purchase under short-term and long-term fixed price contracts  through 2010. See
discussion below under Commodity Price Risk for further information.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Market risk  represents the risk of changes in value of a physical asset or
a financial instrument, derivative or non-derivative,  caused by fluctuations in
market variables (e.g.,  interest rates, etc.). The following  discussion of our
risk management  activities includes  "forward-looking"  statements that involve
risks and  uncertainties.  Actual  results  could differ  materially  from those
projected  in the  "forward-looking"  statements.  We  handle  market  risks  in
accordance with  established  policies,  which may include entering into various
derivative  transactions.  In the normal course of business,  we also face risks
that are  either  non-financial  or  non-quantifiable.  Such  risks  principally
include  business,  legal and  operational  risks and are not represented in the
following discussion.

     Our risk management objective is to optimize our physical generating assets
within prudent risk parameters.  Our risk management  policies are set by a Risk
Management  Steering  Committee,  which  is  comprised  of  senior-level  Ameren
officers.

                                       21

<PAGE>

Interest Rate Risk

     We are exposed to market risk through changes in interest rates  associated
with the  issuance  of both  long-term  and  short-term  variable-rate  debt and
fixed-rate  debt. We manage our interest rate exposure by controlling the amount
of these  instruments we hold within our total  capitalization  portfolio and by
monitoring  the effects of market  changes in interest  rates.  At December  31,
2002, we had $191 million of variable  rate  non-utility  money pool  borrowings
outstanding.

     Utilizing  our variable  rate debt  outstanding  at December  31, 2002,  if
interest rates  increased by 1%, our annual  interest  expense would increase by
approximately  $2 million  and net income  would  decrease by  approximately  $1
million.  The model  does not  consider  the  effects  of the  reduced  level of
potential overall economic activity that would exist in such an environment.  In
the event of a significant  change in interest  rates,  management  would likely
take actions to further mitigate our exposure to this market risk. However,  due
to the  uncertainty  of the  specific  actions  that  would be taken  and  their
possible  effects,  the sensitivity  analysis assumes no change in our financial
structure.

Credit Risk

     Credit risk represents the loss that would be recognized if  counterparties
fail to perform as  contracted.  New York  Mercantile  Exchange  (NYMEX)  traded
futures  contracts  are  supported by the  financial  and credit  quality of the
clearing  members  of the  NYMEX  and have  nominal  credit  risk.  On all other
transactions,  we are exposed to credit risk in the event of  nonperformance  by
the counterparties in the transaction.

     Our  physical  and  financial   instruments  are  subject  to  credit  risk
consisting  of accounts  receivable  and  executory  contracts  with market risk
exposures.  Our revenues are primarily  derived from the sales of electricity to
Marketing  Company as described in Note 3 - Related  Party  Transactions  to our
Financial  Statements  under Item 8. At December  31,  2002,  approximately  $52
million of our accounts  receivable are related party receivables from Marketing
Company.  No  other  customer  represents  greater  than  10%  of  our  accounts
receivable. We analyze each counterparty's financial condition prior to entering
into sales,  forwards,  swaps,  futures or option  contracts.  We also establish
credit limits for these  counterparties and monitor the appropriateness of these
limits on an  ongoing  basis  through a credit  risk  management  program  which
involves  daily  exposure  reporting to senior  management,  master  trading and
netting agreements,  and credit support management such as letters of credit and
parental guarantees.

Commodity Price Risk

     We are  exposed to changes in market  prices for fuel and  electricity.  We
utilize  several  techniques to mitigate risk,  including  utilizing  derivative
financial  instruments.  A derivative is a contract whose value is dependent on,
or derived from, the value of some underlying  asset.  The derivative  financial
instruments that we use (primarily forward contracts,  futures contracts, option
contracts  and  financial  swap  contracts)  are  dictated  by  risk  management
policies.

     Fuels Company is responsible for providing fuel procurement services on our
behalf and for managing fuel price risks. Fixed price forward contracts, as well
as futures, options, and financial swaps are all instruments,  which may be used
to manage these risks.  The majority of our coal supply  contracts  are physical
forward contracts. We have entered into several long-term contracts with various
suppliers to purchase  coal in order to manage our exposure to fuel prices.  See
Note 10 - Commitments and Contingencies to our Financial Statements under Item 8
for further  information.  We have  satisfied 67% of our 2002 power supply needs
through coal.  All of the required 2003 and over 90% of the required 2004 supply
of coal for our  coal-fired  power plants has been acquired at fixed prices.  As
such,  we have minimal coal price risk for 2003 and 2004.  At December 31, 2002,
approximately 52% of our coal requirements for 2005 through 2007 were covered by
contracts.  We are  exposed to changes in market  prices for natural gas we must
purchase to run our combustion turbine  generators.  Our natural gas procurement
strategy is designed to ensure reliable and immediate delivery of natural gas to
our  intermediate  and peaking  units by optimizing  transportation  and storage
options  and  minimizing  cost and  price  risk by  structuring  various  supply
agreements  to  maintain  access to  multiple  gas pools and  supply  basins and
reducing the impact of price volatility.  For 2002, 2001 and for the period from
May 1, 2000 through December 31, 2000,  natural gas costs were approximately $44
million,  $30 million  and $5  million,  respectively.  At  December  31,  2002,
approximately  36% of our 2003  natural gas  requirements  for  generation  were
covered by contracts.

     Although  we  cannot   completely   eliminate  the  effects  of  gas  price
volatility, our strategy is designed to minimize the effect of market conditions
on our results of operations.  Our gas procurement  strategy includes  procuring

                                       22

<PAGE>

natural gas under a portfolio of  agreements  with price  structures,  including
fixed price,  indexed price and embedded  price hedges such as caps and collars.
Our  strategy  also  utilizes  physical  assets  through  storage,  operator and
balancing  agreements  to minimize  price  volatility.  Our  electric  marketing
strategy  is to extract  additional  value  from our  generation  facilities  by
selling energy in excess of needs into the long-term and short-term  markets for
term sales and purchasing  energy when the market price is less than the cost of
generation.  Our primary use of derivatives has involved  transactions  that are
expected to reduce price risk exposure for us.

     With regard to our exposure to commodity price risk for purchased power and
excess  electricity  sales,  we have an affiliate,  AmerenEnergy,  whose primary
responsibility  includes  managing market risks  associated with changing market
prices for electricity purchased and sold on our behalf.

Electricity Price Risk

     We  measure  our  electricity   position  as  total  generating   resources
available,  given  historical  forced outage rates,  planned outages and forward
market prices,  less projected  fixed price load  requirements.  We consider the
contracts  in place  through  the end of 2004 to  supply  full  requirements  to
AmerenCIPS'  native  load and fixed price  market-based  retail  customers  plus
Marketing Company's wholesale contract commitments to be load requirements.  Our
electricity  and capacity price risks are primarily  mitigated by the Generating
Company -  Marketing  Company  agreement,  the  Marketing  Company -  AmerenCIPS
agreement,  and Marketing  Company's  fixed price  wholesale and retail contract
commitments  and are therefore the largest  single  protection  against  falling
electricity and capacity prices. For the year ended December 31, 2002,  revenues
generated  from the  Generating  Company - Marketing  Company  agreement was 85%
(2001 - 87%).

     The  portion of our  capacity  which is not covered by the  agreements  and
contracts discussed above will be managed either by Marketing Company (generally
for  wholesale  transactions  over one year and  retail  sales) or  AmerenEnergy
(generally  for  wholesale  transactions  under one year).  Our  strategy  is to
continue  to  utilize  Marketing  Company  to  offer  most of our  output  under
long-term  wholesale  contracts  as  more  of our  capacity  and  energy  become
available  for resale as  existing  contracts  expire.  AmerenEnergy  expects to
extract  additional  value from the  generating  facilities by selling energy in
excess of the needs of Marketing Company. Also, AmerenEnergy will purchase power
on our behalf when power is  available  for purchase at lower cost than the cost
of our  generation.  Such  power  would be  purchased  to satisfy  our  delivery
requirements  under our  agreements  with  Marketing  Company,  which  Marketing
Company will use to meet its obligations under the load  requirements  discussed
above.

     The amended joint dispatch  agreement  includes a sharing  mechanism  which
provides a benefit to us when we are able to use relatively  low-cost generation
available from AmerenUE to meet our long-term  fixed price sales  obligations as
an  alternative or supplement to our own generating  resources.  Conversely,  we
forgo some of the potential gain that would arise from high peak power prices in
short-term or spot markets  because  AmerenUE has the right to use our available
energy  (e.g.,  energy not sold by us to  Marketing  Company) to the extent such
energy  is less  expensive  than  energy  produced  from  AmerenUE's  next  most
economically  dispatchable  generating  unit.  The price  payable to us in these
circumstances  would likely be lower than peak market prices.  Under the amended
joint  dispatch  agreement,  we also share revenues with AmerenUE when sales are
made  from  our or  AmerenUE's  generating  facilities  to  third  parties  on a
short-term  or spot  basis.  See  Note 3 -  Related  Party  Transactions  to our
Financial Statements under Item 8 for further information.

                                       23

<PAGE>

Equity Price Risk

     We, along with other  subsidiaries of Ameren, are a participant in Ameren's
defined benefit plans and  postretirement  benefit plans and are responsible for
our   proportional   share  of  the   costs.   Ameren's   costs   of   providing
non-contributory defined benefit retirement and postretirement benefit plans are
dependent upon a number of factors,  such as the rates of return on plan assets,
discount rate, the rate of increase in health care costs and contributions  made
to the plans.  The market  value of Ameren's  plan  assets has been  affected by
declines in the equity  market  since 2000 for the  pension  and  postretirement
plans.  As a result,  at December 31, 2002, we recognized an additional  minimum
pension  liability as  prescribed  by SFAS No. 87,  "Employers'  Accounting  for
Pensions."  The  liability  resulted in a  reduction  to equity as a result of a
charge to OCI of $6 million,  net of taxes.  The amount of the liability was the
result of asset returns  experienced  through 2002,  interest rates and Ameren's
contributions to the plan during 2002. In future years, the liability  recorded,
the costs reflected in net income,  or OCI, or cash  contributions  to the plans
could increase  materially without a recovery in equity markets in excess of our
assumed return on plan assets. If the fair value of the plan assets were to grow
and exceed the accumulated  benefit obligations in the future, then the recorded
liability  would be  reduced  and a  corresponding  amount  of  equity  would be
restored in the Balance Sheet.  See Liquidity and Capital  Resources - Operating
above.

Fair Value of Contracts

     We, through  AmerenEnergy and Fuels Company acting as agents on our behalf,
utilize  derivatives  principally to manage the risk of changes in market prices
for fuel,  electricity  and emission  credits.  Price  fluctuations  in fuel and
electricity cause:

o    an unrealized  appreciation  or  depreciation  of our firm  commitments  to
     purchase or sell when  purchase or sales prices  under the firm  commitment
     are compared with current commodity prices;
o    market  values of fuel  inventories  or purchased  power to differ from the
     cost of those commodities in inventory and under firm commitment; and
o    actual cash  outlays for the purchase of these  commodities  to differ from
     anticipated cash outlays.

     The  derivatives  that we use to hedge  these  risks are  dictated  by risk
management  policies and include forward contracts,  futures contracts,  options
and swaps. We continually  assess our supply and delivery  commitment  positions
against forward market prices and internally  forecast forward prices and modify
our exposure to market,  credit and  operational  risk by entering  into various
offsetting  transactions.  In general,  we believe these  transactions  serve to
reduce our price risk.  See Note 4 -  Derivative  Financial  Instruments  to our
Financial Statements under Item 8 for further information.

     The following table summarizes the favorable  (unfavorable)  changes in the
fair value of all contracts marked to market during 2002 and 2001:

<TABLE>
=============================================================================================================
                                                                                       2002         2001
-------------------------------------------------------------------------------------------------------------
<S>                                                                                   <C>          <C>
Fair value of contracts at beginning of period, net                                    $  2         $ (9)
     Contracts which were realized or otherwise settled during the period                (2)           9
     Changes in fair values attributable to changes in valuation techniques and                        -
         assumptions                                                                     (a)
     Fair value of new contracts entered into during the period                          (a)          (a)
    Other changes in fair value                                                          (a)           2
-------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at end of period, net                              $ (a)        $  2
=============================================================================================================
(a) Less than $1 million.
</TABLE>


                                       24

<PAGE>
<TABLE>
<CAPTION>
     Maturities of contracts as of December 31, 2002 were as follows:

=============================================================================================================
<S>                                   <C>           <C>            <C>         <C>            <C>
                                        Maturity                                Maturity in
                                       less than      Maturity      Maturity    excess of 5    Total fair
Sources of fair value                    1 year      1-3 years     4-5 years       years       value (a)
-------------------------------------------------------------------------------------------------------------
Prices actively quoted                    $ -           $ -           $ -           $ -           $ -
Prices provided by other external
    sources (b)                             1             -             -             -             1
Prices based on models and other
    valuation methods (c)                  (d)           (1)            -             -            (1)
-------------------------------------------------------------------------------------------------------------
Total                                     $ 1          $ (1)          $ -           $ -          $ (d)
=============================================================================================================
</TABLE>
(a)  Contracts  of  approximately  47% of the  absolute  fair  value  were  with
     non-investment-grade rated counterparties.
(b)  Principally power forward values based on NYMEX prices for over-the-counter
     contracts.
(c)  Principally  power  forwards  and SO2 options  valued on  information  from
     external sources and our estimates. (d) Less than $1 million.
(d)  Less than $1 million.

FORWARD-LOOKING STATEMENTS

     Statements made in this report which are not based on historical  facts are
"forward-looking"  and, accordingly,  involve risks and uncertainties that could
cause actual results to differ  materially from those  discussed.  Although such
"forward-looking"  statements  have  been  made in good  faith  and are based on
reasonable assumptions,  there is no assurance that the expected results will be
achieved.  These statements include (without limitation) statements as to future
expectations,  beliefs, plans, strategies,  objectives,  events,  conditions and
financial  performance.  In connection with the "safe harbor"  provisions of the
Private  Securities  Litigation  Reform  Act  of  1995,  we are  providing  this
cautionary  statement  to identify  important  factors  that could cause  actual
results to differ materially from those anticipated.  The following factors,  in
addition  to  those  discussed  elsewhere  in  this  report  and  in  subsequent
securities  filings,  could cause results to differ  materially  from management
expectations as suggested by such "forward-looking" statements:

o    the effects of regulatory actions, including changes in regulatory policy;
o    changes in laws and other  governmental  actions,  including  monetary  and
     fiscal policies;
o    the impact on us of current  regulations  related  to the  opportunity  for
     customers to choose alternative energy suppliers in Illinois;
o    the effects of increased competition in the future;
o    the  effects  of  Ameren's   participation  in  a  FERC-approved   Regional
     Transmission Organization, including activities associated with the Midwest
     Independent System Operator;
o    availability  and future  market  prices for fuel and  purchased  power and
     electricity,  including the use of financial and derivative instruments and
     volatility of changes in market prices;
o    the cost of  commodities,  such as natural gas,  used in the  production of
     electricity and our ability to recover such increased costs;
o    wholesale and retail pricing for electricity in the Midwest;
o    business and economic conditions;
o    the impact of the adoption of new accounting  standards on the  application
     of appropriate technical accounting rules and guidance;
o    interest rates and the availability of capital;
o    actions of rating agencies and the effects of such actions;
o    weather conditions;
o    generation plant construction, installation and performance;
o    the  effects  of  strategic   initiatives,   including   acquisitions   and
     divestitures;
o    the impact of current environmental regulations on generating companies and
     the expectation  that more stringent  requirements  will be introduced over
     time, which could potentially have a negative financial effect;
o    future wages and employee  benefit  costs  including  changes in returns of
     benefit plan assets;
o    disruptions of the capital  markets or other events making  Ameren's or our
     access to necessary capital more difficult or costly;
o    competition from other generating facilities, including new facilities that
     may be developed in the future;
o    cost and availability of transmission  capacity for the energy generated by
     our  generating  facilities or required to satisfy energy sales made on our
     behalf; and
o    legal and administrative proceedings.

                                       25

<PAGE>

     Given these  uncertainties,  undue  reliance  should not be placed on these
forward-looking  statements.  Except  to the  extent  required  by  the  federal
securities  laws, we undertake no  obligation  to publicly  update or revise any
forward-looking  statements,  whether  as a result  of new  information,  future
events or otherwise.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

     Information  required  to be  reported  by  this  item  is  included  under
Quantitative  and  Qualitative  Disclosures  About  Market Risk in  Management's
Discussion and Analysis of Financial  Condition and Results of Operations  under
Item 7 and Note 4 - Derivative Financial Instruments and Note 11 - Fair Value of
Financial Instruments to our Financial Statements under Item 8.




                                       26

<PAGE>

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

                        REPORT OF INDEPENDENT ACCOUNTANTS

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

In our opinion,  the financial  statements  listed in the index  appearing under
Item 15(A)(1) on Page 52 present fairly, in all material respects, the financial
position of AmerenEnergy  Generating  Company at December 31, 2002 and 2001, and
the  results  of their  operations  and their  cash  flows  for the years  ended
December  31, 2002 and 2001 and for the period May 1, 2000 to December 31, 2000,
in conformity with accounting principles generally accepted in the United States
of America.  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.  We conducted  our audit of these  statements in
accordance with auditing  standards  generally  accepted in the United States of
America,  which 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,   assessing  the
accounting  principles  used and significant  estimates made by management,  and
evaluating the overall  financial  statement  presentation.  We believe that our
audits provide a reasonable basis for our opinion.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
St. Louis, Missouri
February 13, 2003



                                       27


<PAGE>
<TABLE>
<CAPTION>
                        AMEREN ENERGY GENERATING COMPANY
                                  BALANCE SHEET
                          (In millions, except shares)

                                                                                  December 31,         December 31,
                                                                                      2002                 2001
                                                                                ---------------      --------------
<S>                                                                            <C>                  <C>
ASSETS:
Property and plant, net (Note 5)                                                 $    1,767           $    1,512
Current assets:
   Cash and cash equivalents                                                              3                    2
   Accounts receivable                                                                   10                    8
   Accounts receivable - intercompany                                                    68                  121
   Other receivables                                                                      2                    -
   Materials and supplies, at average cost -
      Fossil fuel                                                                        50                   40
      Other                                                                              27                   20
   Taxes receivable                                                                      71                    -
   Other                                                                                  -                    2
                                                                                ---------------      --------------
         Total current assets                                                           231                  193
                                                                                ---------------      --------------
Deferred income taxes, net (Note 8)                                                       -                   38
Other                                                                                    12                   13
                                                                                ---------------      --------------
Total Assets                                                                     $    2,010              $ 1,756
                                                                                ===============      ==============

CAPITAL AND LIABILITIES:
Capitalization:
   Common stock, no par value, 10,000 shares authorized -
     2,000 shares outstanding                                                    $        -              $     -
   Other paid-in capital                                                                150                  150
   Retained earnings                                                                    131                  120
   Accumulated other comprehensive income                                                (1)                   4
                                                                                ---------------      --------------
         Total common stockholder's equity                                              280                  274
                                                                                ---------------      --------------
  Subordinated notes payable - intercompany (Note 6)                                    412                  461
  Long-term debt (Note 6)                                                               698                  424
                                                                                ---------------      --------------
         Total capitalization                                                         1,390                1,159
                                                                                ---------------      --------------
Current liabilities:
   Current portion of subordinated notes payable - intercompany (Note 6)                 50                   47
   Accounts and wages payable                                                            55                   63
   Accounts and wages payable - intercompany                                             32                  181
   Notes payable - intercompany                                                         191                   62
   Current portion of income taxes payable - intercompany                                13                   18
   Income taxes payable                                                                   -                   12
   Interest payable                                                                       8                    6
   Interest payable - intercompany                                                        7                    6
   Other                                                                                  2                    3
                                                                                ---------------      --------------
         Total current liabilities                                                      358                  398
                                                                                ---------------      --------------
Commitments and contingencies (Note 1, 2, and 10)
Deferred income taxes, net (Note 8)                                                      66                    -
Accumulated deferred investment tax credits                                              15                   17
Income tax payable - intercompany                                                       162                  177
Other deferred credits and liabilities                                                   19                    5
                                                                                ---------------      --------------
Total Capital and Liabilities                                                    $    2,010              $ 1,756
                                                                                ===============      ==============
</TABLE>

See Notes to Financial Statements.


                                       28

<PAGE>


                        AMEREN ENERGY GENERATING COMPANY
                               STATEMENT OF INCOME
                                  (In millions)


<TABLE>
<CAPTION>

                                                                                                    For the period
                                                                                                     May 1, 2000
                                                                               Year Ended              through
                                                                               December 31,          December 31,
                                                                       ----------------------------  -------------
                                                                           2002           2001           2000
                                                                       -------------  -------------  -------------
<S>                                                                   <C>               <C>          <C>
OPERATING REVENUES:
   Electric - intercompany                                                $ 671          $ 657          $ 372
   Electric                                                                  62             60            105
   Other - intercompany                                                      10             13              3
                                                                       -------------  -------------  -------------
      Total operating revenues                                              743            730            480
                                                                       -------------  -------------  -------------

OPERATING EXPENSES:
   Fuel and purchased power                                                 339            306            236
   Other operations and maintenance                                         174            157            100
   Voluntary retirement and other restructuring charges (Note 6)             10              -              -
   Depreciation and amortization                                             69             53             28
   Other taxes                                                               12             19             13
                                                                       -------------  -------------  -------------
      Total operating expenses                                              604            535            377
                                                                       -------------  -------------  -------------

OPERATING INCOME                                                            139            195            103

OTHER INCOME AND (DEDUCTIONS):
   Miscellaneous, net -
     Miscellaneous income                                                    (1)             5              3
     Miscellaneous expense                                                    -              -              -
                                                                       -------------  -------------  -------------
      Total other income and (deductions)                                    (1)             5              3
                                                                       -------------  -------------  -------------

INTEREST CHARGES:
   Interest expense - intercompany                                           40             41             30
   Interest expense                                                          46             34              5
                                                                       -------------  -------------  -------------
      Total interest charges                                                 86             75             35
                                                                       -------------  -------------  -------------

INCOME TAXES                                                                 20             47             27

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
      IN ACCOUNTING PRINCIPLE                                                32             78             44

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
      PRINCIPLE, NET OF INCOME TAXES                                          -             (2)             -
                                                                       -------------  -------------  -------------

NET INCOME                                                                $  32          $  76          $  44
                                                                       =============  =============  =============
</TABLE>

See Notes to Financial Statements.

                                       29

<PAGE>

                        AMEREN ENERGY GENERATING COMPANY
                             STATEMENT OF CASH FLOWS
                                  (In millions)

<TABLE>
<CAPTION>
                                                                                                     For the period
                                                                                                       May 1, 2000
                                                                                    Year Ended            through
                                                                                    December 31,       December 31,
                                                                              ---------------------  --------------
                                                                                   2002       2001          2000
                                                                              ----------  ---------  --------------
<S>                                                                           <C>         <C>       <C>
Cash Flows From Operating:
   Net income                                                                      $ 32       $ 76          $ 44
   Adjustments to reconcile net income to net cash
       provided by operating activities:
         Cumulative effect of change in accounting principle                          -          2             -
         Depreciation and amortization                                               69         53            28
         Deferred income taxes, net                                                  63         29             6
         Deferred investment tax credits, net                                        (2)        (1)           (1)
         Voluntary retirement and other restructuring charges                        10          -             -
         Other                                                                        -          1             -
         Changes in assets and liabilities:
               Accounts receivable                                                   (2)        49           (11)
               Accounts receivable - intercompany                                    51        (84)          (58)
               Materials and supplies                                               (17)       (16)           10
               Taxes receivable, net                                                (39)       (14)           26
               Accounts and wages payable                                           (24)       (39)           24
               Accounts and wages payable - intercompany                            (11)        89            23
               Current portion of income taxes payable-intercompany                 (20)       (16)           (8)
               Interest payable                                                       2          -             6
               Interest payable - intercompany                                        1          3             4
               Assets, other                                                         (5)        (8)            2
               Liabilities, other                                                     3          6             3
                                                                              ----------  ---------  ------------
Net cash provided by operating activities                                           111        130            98
                                                                              ----------  ---------  ------------

Cash Flows Used In Investing:
   Construction expenditures                                                       (442)      (347)         (470)
   Notes receivable - intercompany                                                    -        100          (100)
                                                                              ----------  ---------  ------------
Net cash used in investing activities                                              (442)      (247)         (570)
                                                                              ----------  ---------  ------------

Cash Flows From Financing:
   Paid in capital                                                                    -        150             -
   Dividends paid to Ameren                                                         (21)         -             -
   Debt issuance costs                                                               (4)         -            (7)
   Redemptions:
      Subordinated notes payable - intercompany                                     (46)       (94)            -
      Current portion of subordinated notes payable - intercompany                    -          -             -
   Issuances:
      Notes payable - intercompany                                                  129         62             -
      Subordinated notes payable - intercompany                                       -          -            50
      Long-term debt                                                                274          -           424
                                                                              ----------  ---------  ------------
Net cash provided by financing activities                                           332        118           467
                                                                              ----------  ---------  ------------

Net change in cash and cash equivalents                                               1          1            (5)
Cash and cash equivalents at beginning of year                                        2          1             6
                                                                              ----------  ---------  ------------
Cash and cash equivalents at end of period                                          $ 3        $ 2           $ 1
                                                                              ==========  =========  ============

Cash paid during the periods:
   Interest                                                                        $ 45       $ 34           $ -
   Interest - intercompany                                                           38         39            26
   Income taxes                                                                       1         36            14

</TABLE>
See Notes to Financial Statements for further information including
non-cash transactions.

                                       30

<PAGE>
<TABLE>
<CAPTION>
                        AMEREN ENERGY GENERATING COMPANY
                    STATEMENT OF COMMON STOCKHOLDER'S EQUITY
                                  (In millions)

                                                                                                 For the period
                                                                                                  May 1, 2000
                                                                             Year Ended             through
                                                                             December 31,         December 31,
                                                                       ------------------------  ---------------
                                                                           2002        2001            2000
                                                                       -----------  -----------  ---------------
<S>                                                                   <C>           <C>          <C>

Common stock                                                             $     -     $     -          $   -

Other paid-in capital
   Beginning balance                                                         150           -              -
   Change in current period                                                    -         150              -
                                                                       -----------  -----------  ------------
                                                                             150         150              -
                                                                       -----------  -----------  ------------

Retained earnings
   Beginning balance                                                         120          44             -
   Net income                                                                 32          76            44
   Dividends paid to Ameren                                                  (21)          -             -
                                                                       -----------  -----------  ------------
                                                                             131         120            44
                                                                       -----------  -----------  ------------

Accumulated other comprehensive income
   Beginning balance                                                           4           -             -
   Change in derivative financial instruments in current period                1           4             -
                                                                       -----------  -----------  ------------
                                                                               5           4             -
                                                                       -----------  -----------  ------------

   Beginning balance - minimum pension liability                               -           -             -
   Change in minimum pension liability in current period                      (6)          -             -
                                                                       -----------  -----------  ------------

                                                                              (1)          4             -
                                                                       -----------  -----------  ------------

Total common stockholder's equity                                        $   280      $  274          $ 44
                                                                       ===========  ===========  ============


Comprehensive income, net of taxes
   Net income                                                            $    32      $   76          $ 44
   Unrealized net gain/(loss) on derivative hedging instruments,
        net of income taxes of $-, $3, and $-, respectively                    -           4             -
   Reclassification adjustments for gains/(losses) included in net income
        net of income taxes of $1, $2, and $-, respectively                    1           3             -
   Cumulative effect of accounting change net of income taxes of
        $-, $(2), and $-, respectively                                         -          (3)            -
   Minimum pension liability adjustment, net of income taxes of
        $3, $-, and $-, respectively                                          (6)          -             -
                                                                       -----------  -----------  ------------
           Total comprehensive income, net of taxes                      $    27      $   80          $ 44
                                                                       ===========  ===========  ============
</TABLE>

See Notes to Financial Statements.


                                       31

<PAGE>

AMEREN ENERGY GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
December 31, 2002

NOTE 1 - Summary of Significant Accounting Policies

 General

     AmerenEnergy  Generating Company,  headquartered in St. Louis, Missouri, is
an indirect  wholly-owned  subsidiary of Ameren Corporation (Ameren). We own and
operate a wholesale electric generation business in Illinois and Missouri.  Much
of our  business  was  formerly  owned and  operated by our  affiliate,  Central
Illinois  Public  Service  Company,  which  operates  as  AmerenCIPS.   We  were
incorporated in the State of Illinois in March 2000. On May 1, 2000, we acquired
from AmerenCIPS at net book value five coal-fired electric generating  stations,
which we refer to as the coal plants, all related fuel, supply,  transportation,
maintenance and labor agreements,  approximately  45% of AmerenCIPS'  employees,
and other related rights, assets and liabilities.

     Ameren is a public utility holding  company  registered with the Securities
and Exchange  Commission  (SEC) under the Public Utility  Holding Company Act of
1935 (PUHCA),  as amended,  and is also  headquartered  in St. Louis,  Missouri.
Ameren's principal business is the generation,  transmission and distribution of
electricity,  and the  distribution of natural gas to  residential,  commercial,
industrial and wholesale users in the central United States.  Ameren's principal
subsidiaries and our affiliates are as follows:

o    Union  Electric   Company,   which  operates  a   rate-regulated   electric
     generation,  transmission and distribution  business,  and a rate-regulated
     natural gas distribution business in Missouri and Illinois as AmerenUE.
o    AmerenCIPS,  which  operates a  rate-regulated  electric  and  natural  gas
     transmission and distribution business in Illinois.
o    Central  Illinois  Light Company,  a subsidiary of CILCORP Inc.  (CILCORP),
     which operates a rate-regulated  transmission and distribution business, an
     electric generation business, and a rate-regulated natural gas distribution
     business in Illinois as  AmerenCILCO.  Ameren  completed its acquisition of
     CILCORP on January  31,  2003 from The AES  Corporation  (AES).  See Recent
     Developments for further information.
o    AmerenEnergy  Resources Company (Resources Company),  which consists of non
     rate-regulated operations.  Subsidiaries include us, AmerenEnergy Marketing
     Company (Marketing Company), which markets power for periods over one year,
     AmerenEnergy  Fuels and Services  Company (Fuels  Company),  which procures
     fuel and manages the related risks for us and our affiliates,  AmerenEnergy
     Development Company (Development Company),  which, as our parent,  develops
     and constructs generating facilities for us, and AmerenEnergy Medina Valley
     Cogen (No. 4), LLC, which indirectly owns a 40 megawatt, gas-fired electric
     generation  plant. On February 4, 2003, Ameren completed its acquisition of
     AES Medina  Valley Cogen (No. 4), LLC (Medina  Valley) from AES and renamed
     it AmerenEnergy Medina Valley Cogen (No. 4), LLC.
o    AmerenEnergy,  Inc.  (AmerenEnergy),  which serves as a power marketing and
     risk  management  agent  for us and  our  affiliates  for  transactions  of
     primarily less than one year.
o    Electric  Energy,  Inc.  (EEI),  which  operates  electric  generation  and
     transmission facilities in Illinois. Ameren has a 60% ownership interest in
     EEI, 40% owned by AmerenUE and 20% owned by Resources.
o    Ameren Services  Company (Ameren  Services),  which provides shared support
     services to us and our affiliates.

     When we refer to our, we, us or  Generating  Company,  we are  referring to
AmerenEnergy  Generating Company and in some cases our agents,  AmerenEnergy and
Fuels  Company.  All tabular dollar  amounts are in millions,  unless  otherwise
indicated.

     Our accounting policies conform to generally accepted accounting principles
in the United States (GAAP).  Our financial  statements  reflect all adjustments
(which include normal,  recurring adjustments)  necessary, in our opinion, for a
fair  presentation of our results.  The  preparation of financial  statements in
conformity  with  GAAP  requires   management  to  make  certain  estimates  and
assumptions.  Such estimates and assumptions  affect reported  amounts of assets
and liabilities and disclosure of contingent  assets and liabilities at the date
of the financial  statements  and the reported  amounts of revenues and expenses
during the reported  period.  Actual results could differ from those  estimates.
Certain reclassifications have been made to prior years' financial statements to
conform to 2002 reporting.

     Our financial  statements  are  available  only for the period since May 1,
2000. Prior to that date, all operations of the coal plants now owned by us were
fully  integrated  with, and therefore  results of operations were  consolidated

                                       32

<PAGE>

into the financial  statements of  AmerenCIPS,  whose  business was to generate,
transmit  and  distribute  electricity  and to provide  other  utility  customer
support services.

Property and Plant

     The cost of additions to, and  betterments  of, units of property and plant
is capitalized.  Cost includes labor, material,  applicable taxes and overheads.
Interest during construction is added for our assets.  Maintenance  expenditures
and the  renewal of items not  considered  units of  property  are  expensed  as
incurred.  When units of depreciable property are retired, the original cost and
removal cost, less salvage value, are charged to accumulated  depreciation.  See
Accounting  Changes  and  Other  Matters  relating  to  Statement  of  Financial
Accounting   Standards   (SFAS)  No.  143,   "Accounting  for  Asset  Retirement
Obligations."

Depreciation

     Depreciation is provided over the estimated lives of the various classes of
depreciable  property by applying composite rates on a straight-line  basis. The
provision for  depreciation in 2002 and 2001 and for the period from May 1, 2000
through December 31, 2000 was approximately 3% of the average depreciable costs.

Interest Capitalized

     Interest is capitalized in accordance with SFAS No. 34,  "Capitalization of
Interest Cost." For 2002,  interest expense capitalized was $1.2 million (2001 -
$1.3 million, 2000 - $0.8 million).

Impairment of Long-Lived Assets

     We  evaluate  long-lived  assets for  impairment  when events or changes in
circumstances  indicate  that  the  carrying  value  of such  assets  may not be
recoverable. The determination of whether impairment has occurred is based on an
estimate of undiscounted cash flows attributable to the assets, as compared with
the carrying value of the assets. If impairment has occurred,  the amount of the
impairment  recognized is determined by estimating  the fair value of the assets
and  recording a provision  for loss if the  carrying  value is greater than the
fair value.  See Accounting  Changes and Other Matters relating to SFAS No. 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets."

Cash and Cash Equivalents

     Cash and cash  equivalents  include cash on hand and temporary  investments
purchased with an original maturity of three months or less.

Unamortized Debt Discount, Premium and Expense

     Discount and expense  associated with long-term debt are amortized over the
lives of the related issues.

Revenue

     We accrue an estimate  of  electric  revenues  for  service  rendered,  but
unbilled, at the end of each accounting period.

     Interchange revenues included in Operating Revenues - Electric and Electric
Intercompany  were $100 million for the year ended December 31, 2002 (2001 - $92
million, 2000 - $137 million).  See Emerging Issues Task Force (EITF) Issue 02-3
"Issues  Involved  in  Accounting  for  Derivative  Contracts  Held for  Trading
Purposes  and  Contracts   Involved  in  Energy  Trading  and  Risk   Management
Activities"  discussion  under  Accounting  Changes and Other  Matters below for
further information.

Purchased Power

     Purchased  power included in Operating  Expenses - Fuel and Purchased Power
was $107 million for the year ended December 31, 2002 (2001 - $125 million, 2000
- $119 million).  See EITF 02-3 discussion  under  Accounting  Changes and Other
Matters for further information.

                                       33

<PAGE>

Income Taxes

     We are  included in the  consolidated  federal  income tax return  filed by
Ameren. As a subsidiary of Ameren, we could be considered  jointly and severally
liable for assessments of additional tax on the consolidated group. Income taxes
are allocated to the  individual  companies  based on their  respective  taxable
income or loss.  Our  provision  for income  taxes has been  presented  based on
federal and state taxes we would have presented on a stand-alone  company basis.
Deferred tax assets and liabilities  are recognized for the tax  consequences of
transactions that have been treated  differently for financial reporting and tax
return purposes, measured using statutory tax rates.

     Investment tax credits  utilized in prior years were deferred and are being
amortized over the useful lives of the related properties.

 Accounting Changes and Other Matters

     In January  2001,  we adopted  SFAS No.  133,  "Accounting  for  Derivative
Instruments and Hedging  Activities." The impact of that adoption  resulted in a
cumulative  effect charge of $2 million,  net of taxes, to the income statement,
and a cumulative effect  adjustment of $3 million,  net of taxes, to Accumulated
Other Comprehensive Income (OCI), which reduced common stockholder's equity. See
Note 4 - Derivative Financial Instruments for further information.

     In January 2002, we adopted SFAS No. 141, "Business Combinations," and SFAS
No. 142,  "Goodwill and Other  Intangible  Assets."  SFAS 141 requires  business
combinations to be accounted for under the purchase method of accounting,  which
requires  one  party  in the  transaction  to be  identified  as  the  acquiring
enterprise  and for that party to allocate the purchase  price to the assets and
liabilities  of the acquired  enterprise  based on fair market  value.  SFAS 142
requires  goodwill  and  indefinite-lived  intangible  assets  recorded  in  the
financial statements to be tested for impairment at least annually,  rather than
amortized over a fixed period,  with  impairment  losses  recorded in the income
statement.  SFAS  141 and SFAS 142 did not  have  any  effect  on our  financial
position,  results of operations or liquidity upon  adoption.  SFAS 141 and SFAS
142 were  utilized  for  Ameren's  acquisition  of CILCORP,  Inc. and AES Medina
Valley  Cogen  (No.  4),  LLC.  See  Note  12 -  Subsequent  Event  for  further
information.

     We are adopting  SFAS 143 in the first  quarter of 2003.  SFAS 143 provides
the accounting  requirements  for asset retirement  obligations  associated with
tangible,  long-lived assets.  SFAS 143 requires us to record the estimated fair
value of legal obligations associated with the retirement of tangible long-lived
assets in the period in which the  liabilities  are incurred and to capitalize a
corresponding  amount as part of the book value of the related long-lived asset.
In subsequent  periods,  we are required to adjust asset retirement  obligations
based on changes in estimated  fair value,  and the  corresponding  increases in
asset book values are  depreciated  over the useful  life of the related  asset.
Uncertainties  as to the  probability,  timing or cash flows  associated with an
asset retirement obligation affect our estimate of fair value.

     Upon adoption of this  standard,  we expect to recognize  asset  retirement
obligations of  approximately  $5 million related  primarily to retirement costs
for an ash pond.  The  difference  between the net asset and the liability to be
recorded  upon  adoption  related to our assets  will be  recorded  as a loss of
approximately $2 million, net of taxes, for a change in accounting principle.

     In addition to these  obligations,  we have  determined  that certain other
asset retirement  obligations exist. However, we are unable to estimate the fair
value of  those  obligations  because  the  probability,  timing  or cash  flows
associated with the obligations are indeterminable. We do not believe that these
obligations, when incurred, will have a material adverse impact on our financial
position, results of operations or liquidity.

     SFAS 143 also may require a change in the depreciation  methodology we have
historically utilized for our non-regulated  operations.  Historically,  we have
included an estimated cost of  dismantling  and removing plant from service upon
retirement in the basis upon which our depreciation rates were determined.  SFAS
143 requires us to exclude costs of dismantling and removal upon retirement from
the depreciation rates applied to non rate-regulated plant balances. Further, we
are required to remove accumulated  provisions for dismantling and removal costs
from accumulated  depreciation,  where they are currently embedded,  and reflect
such  adjustment  as a gain upon adoption of this  standard,  to the extent such
dismantling and removal activities are not considered  obligations as defined by
SFAS 143. At this time we have not finalized our determination of the gain to be
recorded  upon  adoption  of SFAS  143 for  our non  rate-regulated  operations;
however,  it will likely  substantially  exceed the loss resulting from adopting
this standard.  Additionally,  beginning in January 2003, depreciation rates for
non rate-regulated  assets will be reduced to reflect the discontinuation of the
accrual of dismantling and removal costs. As a result, non rate-

                                       34

<PAGE>

regulated  asset removal costs will be expensed as incurred.  The impact of this
change in accounting  will result in a decrease in  depreciation  expense and an
increase  in  operations  and  maintenance  expense,  the net impact of which is
indeterminable, but not expected to be material.

     On January 1, 2002,  we adopted SFAS 144.  SFAS 144 addresses the financial
accounting and reporting for the impairment or disposal of long-lived assets and
supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived  Assets to Be Disposed Of." SFAS 144 retains the guidance related
to  calculating  and  recording  impairment  losses,  but adds  guidance  on the
accounting  for  discontinued   operations,   previously   accounted  for  under
Accounting Principles Board Opinion No. 30, "Reporting the Results of Operations
- Reporting the Effects of a Segment of a Business,  and Extraordinary,  Unusual
and Infrequently  Occurring Events and Transactions."  SFAS 144 did not have any
effect on our financial position, results of operations or liquidity in 2002.

     In June  2002,  the  FASB  issued  SFAS  No.  146,  "Accounting  for  Costs
Associated  with Exit or Disposal  Activities."  SFAS 146  requires an entity to
recognize,  and measure at fair value, a liability for a cost associated with an
exit or disposal  activity in the period in which the  liability is incurred and
nullifies  EITF Issue No.  94-3,  "Liability  Recognition  for Certain  Employee
Termination  Benefits  and Other  Costs to Exit an Activity  (Including  Certain
Costs Incurred in a Restructuring)."  SFAS 146 is effective for exit or disposal
activities that are initiated after December 31, 2002.

     During 2002, we adopted the provisions of EITF 02-3 that required  revenues
and costs associated with certain energy contracts to be shown on a net basis in
the income  statement.  Prior to adopting  EITF 02-3 and the  rescission of EITF
Issue No. 98-10,  "Accounting for Contracts  Involved in Energy Trading and Risk
Management  Activities,"  our  accounting  practice  was to present  all settled
energy purchase or sale contracts within our power risk management  program on a
gross basis in Operating  Revenues - Electric  and in Operating  Expenses - Fuel
and  Purchased  Power.  This meant that  revenues were recorded for the notional
amount of the power sales  contracts with a  corresponding  charge to income for
the costs of the energy  that was  generated,  or for the  notional  amount of a
purchased power contract.

     In October  2002,  the EITF reached a consensus to rescind EITF No.  98-10.
The effective date for the full  rescission of EITF 98-10 was for fiscal periods
beginning after December 15, 2002, with early adoption  permitted.  In addition,
the EITF  reached  a  consensus  in  October  2002  that  all  SFAS 133  trading
derivatives  (subsequent to the rescission of EITF 98-10) should be shown net in
the income statement,  whether or not physically settled. This consensus applies
to  all  energy  and  non-energy  related  trading  derivatives  that  meet  the
definition  of a  derivative  pursuant to SFAS 133. We have  adopted and applied
this  guidance  to 2002 and 2001,  which had no  impact on  previously  reported
earnings or stockholder's  equity. The adoption of EITF 02-3, rescission of EITF
98-10  and the  related  transition  guidance  resulted  in  netting  of  energy
contracts  and  lowered  our  reported  revenues  and  costs  with no  impact on
earnings.  The following table  summarizes the impact of energy contract netting
for the year ended  December  31,  2001 and for the  period May 1, 2000  through
December 31, 2000:

================================================================================
                                                     2001                   2000
--------------------------------------------------------------------------------
Previously reported gross operating  revenues       $ 986                  $ 480
Revenues and costs netted (a)                         256                     -
--------------------------------------------------------------------------------
Net operating revenues reported                     $ 730                  $ 480
================================================================================
(a) Revenues and costs netted for the year ended December 31, 2002 were $253
million. SFAS 133 was adopted on January 1, 2001 and therefore, no netting was
required for the year ended December 31, 2000.


NOTE 2 - Rate and Regulatory Matters

Missouri Electric

Marketing Company - AmerenUE Power Supply Agreements

     In order to satisfy its  regulatory  load  requirements  for 2001 and 2002,
AmerenUE  purchased,  under a one-year  contract  450  megawatts of capacity and
energy (the 2001  Marketing  Company - AmerenUE  agreement) and 200 megawatts of
capacity  and energy  (the 2002  Marketing  Company - AmerenUE  agreement)  from
Marketing  Company.  These  agreements  were entered into through a  competitive
bidding  process and  reflected  market-based  rates.  We supplied the power for
these agreements under our power supply  agreement with Marketing  Company.

                                       35

<PAGE>

     The Federal Energy Regulatory Commission (FERC) accepted the 2001 Marketing
Company - AmerenUE  agreement as filed.  The 2002  Marketing  Company - AmerenUE
agreement was set for hearing to determine that the contract terms were just and
reasonable.  On March 12, 2003, a settlement  between  Marketing Company and the
FERC Staff was approved by the FERC effectively  resolving all issues concerning
the 2002 Marketing Company - AmerenUE agreement set for hearing.  While the FERC
order contains a standard  refund report  requirement,  no refunds are due under
the settlement as approved.

     In May 2001 and May 2002, the Missouri  Public Service  Commission  (MoPSC)
filed  complaints  with SEC relating to these  agreements.  While the complaints
were pending,  the MoPSC and AmerenUE  reached an agreement for resolving  these
disputes. The agreement requires AmerenUE to not enter into any new contracts to
purchase  wholesale  electric energy from any Ameren affiliate that is an exempt
wholesale   generator   without  first   obtaining,   on  a  timely  basis,  the
determinations  required of the MoPSC that are specified in Section 32(k) of the
PUHCA.  However,  this  commitment did not prevent  AmerenUE from completing the
purchases  contemplated  by the 2001  and  2002  Marketing  Company  -  AmerenUE
agreements and does not prevent AmerenUE from making short term energy purchases
(less than 90 days) from an Ameren affiliate, without prior MoPSC determination,
to prevent or alleviate system emergencies. As part of this agreement, the MoPSC
has agreed to terminate its SEC complaints.


Illinois Electric

     In 2002, all of Ameren's  Illinois  residential,  commercial and industrial
customers had choice in electric suppliers.

     As a  provision  of the  legislation  related to the  restructuring  of the
Illinois  electric  industry  (the  Illinois  Law),  a rate  freeze is in effect
through January 1, 2007. As a result of this extension  through January 1, 2007,
Marketing  Company  expects to seek to renew or extend a power supply  agreement
between  AmerenCIPS and Marketing  Company through the same period. A renewal or
extension  of  the  power  supply  agreement  will  depend  on  compliance  with
regulatory  requirements  in effect at the time, and we cannot  predict  whether
Marketing  Company will be successful in securing a renewal or extension of this
agreement.

Federal - Electric Transmission

Regional Transmission Organization

     In December  1999,  the FERC issued  Order 2000  requiring  all  utilities,
subject to FERC  jurisdiction,  to state their intentions for joining a regional
transmission  organization  (RTO). RTOs are independent  organizations that will
functionally  control the  transmission  assets of utilities and are designed to
improve the wholesale  power market.  Beginning in January 2001, our affiliates,
AmerenUE and  AmerenCIPS,  along with several other  utilities,  sought approval
from the FERC to  participate  in an RTO known as the  Alliance  RTO. The Ameren
companies had previously been members of the Midwest Independent System Operator
(Midwest  ISO) and  recorded a pretax  charge to earnings in 2000 of $25 million
($15 million,  net of taxes) for an exit fee and other costs when they left that
organization.  Ameren  believed that the for-profit  Alliance RTO business model
was  superior to the  not-for-profit  Midwest ISO  business  model and  provided
Ameren with a more equitable return on its transmission assets.

     In late 2001,  the FERC issued an order that  rejected the formation of the
Alliance  RTO and  ordered the  Alliance  RTO  companies  and the Midwest ISO to
discuss how the  Alliance RTO business  model could be  accommodated  within the
Midwest  ISO. In April 2002,  after the  Alliance  RTO and Midwest ISO failed to
reach an  agreement,  and after a series of filings by the two parties  with the
FERC,  the FERC  issued a  declaratory  order  setting  forth  the  division  of
responsibilities  between the Midwest ISO and National Grid (the managing member
of the transmission  company formed by the Alliance  companies) and approved the
rate design and the revenue  distribution  methodology  proposed by the Alliance
companies.  However,  the FERC denied a request by the  Alliance  companies  and
National Grid to purchase  certain  services from the Midwest ISO at incremental
cost rather than  Midwest  ISO's full tariff  rates.  The FERC also  ordered the
Midwest  ISO to return  the exit fee paid by the Ameren  companies  to leave the
Midwest ISO,  provided the Ameren  companies return to the Midwest ISO and agree
to pay their proportional share of the startup and ongoing operational  expenses
of the Midwest ISO. Moreover, the FERC required the Alliance companies to select
the RTO in which they will participate within thirty days of the order.

     Following the April 2002 FERC order, the Ameren companies made filings with
the FERC  indicating  that they would  return to the  Midwest  ISO through a new
independent transmission company,  GridAmerica LLC, that was agreed to be formed
by AmerenCIPS and AmerenUE,  and  subsidiaries  of FirstEnergy  Corporation  and
NiSource

                                       36

<PAGE>

Inc.  Upon  receipt  of  final  FERC  approval  of  the  definitive   agreements
establishing  GridAmerica,  a  subsidiary  of  National  Grid will  serve as the
managing  member of GridAmerica and will manage the  transmission  assets of the
three  companies and  participate  in the Midwest ISO on behalf of  GridAmerica.
Other  Alliance  RTO  companies  announced  their  intentions  to  join  the PJM
Interconnection  LLC (PJM) RTO. On July 25, 2002, the Ameren  companies  filed a
motion with the FERC requesting that it condition the approval of the choices of
other  Illinois  utilities  to join the PJM RTO on Midwest ISO and PJM  entering
into an agreement addressing  important  reliability and rate-barrier issues. On
July 31, 2002,  the FERC issued an order  accepting the formation of GridAmerica
as an independent  transmission company under the Midwest ISO subject to further
compliance  filings ordered by the FERC. The FERC also issued an order accepting
the elections  made by the other  Illinois  utilities to join the PJM RTO on the
condition  PJM and  Midwest  ISO  immediately  begin a process  to  address  the
reliability  and  rate-barrier  issues raised by the Ameren  companies and other
market participants in previous filings.

     The  compliance  filing  to  facilitate  the  formation  and  operation  of
GridAmerica  as an independent  transmission  company within the Midwest ISO, as
contemplated in the July 31, 2002 order of the FERC, was conditionally  accepted
by the FERC in an  order  issued  December  19,  2002.  In the  order,  the FERC
approved the return of the $18 million exit fee paid by the Ameren  companies to
leave the Midwest ISO with interest once GridAmerica  becomes  operational.  The
FERC also approved, subject to further filings,  reimbursement of $36 million to
the  GridAmerica  companies  for  expenses  incurred to form the  Alliance  RTO.
GridAmerica  is  scheduled  to  become  operational  in  spring  2003.  Ameren's
participation  in GridAmerica  remains subject to MoPSC approval.  An order from
the MoPSC is expected during the third quarter of 2003.

     We do not own transmission assets.  However, we pay AmerenUE and AmerenCIPS
for the use of their transmission lines to transmit power. Until the reliability
and rate-barrier issues are resolved as ordered by the FERC, and the tariffs and
other material terms of Ameren's participation in GridAmerica, and GridAmerica's
participation in the Midwest ISO, are finalized and approved by the FERC, we are
unable to predict the impact that  on-going  RTO  developments  will have on our
financial position, results of operations or liquidity.

Standard Market Design Notice of Proposed Rulemaking (NOPR)

     On July 31, 2002,  the FERC issued a Standard  Market Design NOPR. The NOPR
proposes  a number of  changes  to the way the  current  wholesale  transmission
service and energy  markets are operated.  Specifically,  the NOPR calls for all
jurisdictional  transmission  facilities  to be placed  under the  control of an
independent   transmission   provider  (similar  to  an  RTO),  proposes  a  new
transmission  service tariff that provides a single form of transmission service
for all users of the  transmission  system  including  bundled  retail load, and
proposes  a new  energy  market  and  congestion  management  system  that  uses
locational marginal pricing as its basis. On November 15, 2002, Ameren filed its
initial  comments  on the NOPR with the FERC  expressing  its  concern  with the
potential  impact of the  proposed  rules in their  current form on the cost and
reliability  of service to retail  customers.  Ameren also proposed that certain
modifications  be made to the  proposed  rules in order to protect  transmission
owners  from the  possibility  of trapped  transmission  costs that might not be
recoverable  from  ratepayers as a result of inconsistent  regulatory  policies.
Ameren filed  additional  comments on the remaining  sections of the NOPR during
the first quarter of 2003.  Until the FERC issues a final rule, we are unable to
predict  the  ultimate  impact on our  future  financial  position,  results  of
operations or liquidity.


NOTE 3 - Related Party Transactions

     We have  transactions  in the normal  course of business  with Ameren,  our
ultimate parent company,  and Ameren's other  subsidiaries.  These  transactions
primarily  consist of power purchases and sales,  services received or rendered,
borrowings and lendings.  The transactions with these affiliates are reported as
intercompany transactions.

                                       37

<PAGE>

Transfer of Assets

     On May 1, 2000,  AmerenCIPS  transferred its electric generating assets and
related  liabilities,  at net book value,  to us, in exchange for a subordinated
promissory note from us in the principal amount of $552 million and 1,000 shares
of our common stock (Transfer).  The transferred assets  represented  generating
capacity  of  approximately  2,860  megawatts  at  the  time  of  the  transfer.
Approximately 45% of AmerenCIPS' employees were transferred to us as part of the
transaction.  The  significant  components  of  net  assets  transferred  are as
follows:

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

   -------------------------------------------------------------------
   Cash                                                          $  6
   Other receivable - intercompany                                 26
   Material and supplies                                           54
   Other current assets                                             6
   Property and plant, net                                        635
   -------------------------------------------------------------------
   Total assets transferred                                      $727
   -------------------------------------------------------------------

   Accounts payable                                              $  6
   Other current liabilities                                        3
   Other deferred credits                                           2
   Deferred investment tax credits                                 20
   Deferred tax liabilities, net                                  144
   -------------------------------------------------------------------
   Total liabilities transferred                                 $175
   -------------------------------------------------------------------

   -------------------------------------------------------------------
   Net assets transferred                                        $552
   ===================================================================

Capital Additions

     During  2000,  we acquired  nine  combustion  turbine  generating  units at
Pinckneyville,  Gibson City, and Joppa, Illinois from Development Company and an
affiliate at their  historical net book value. The total installed cost of these
combustion turbine generating units was approximately $275 million.  These units
represent approximately 595 megawatts of capacity.

     During 2001, we acquired  twelve  combustion  turbine  generating  units at
Kinmundy,  Pinckneyville,  and Grand Tower, Illinois and Columbia, Missouri from
Development  Company at Development  Company's  historical  net book value.  The
total   installed  cost  of  the  combustion   turbine   generating   units  was
approximately $530 million. These units represent approximately 850 megawatts of
capacity.

     During 2002, we acquired four combustion turbine generating units at Elgin,
Illinois from Development Company at Development  Company's  historical net book
value. The total installed cost of the combustion  turbine  generating units was
approximately $215 million. These units represent approximately 470 megawatts of
capacity.

     See  Note  10 -  Commitments  and  Contingencies  for  further  information
regarding  our  intention  to sell  our  Pinckneyville  and  Kinmundy,  Illinois
combustion turbine generating units to our affiliate, AmerenUE.

Operating Lease

     We entered into an operating lease agreement with  Development  Company for
the units at the Joppa,  Illinois  site  wherein  the three  combustion  turbine
generating units (totaling  approximately 185 megawatts of capacity) were leased
to Development  Company for a minimum term of fifteen years  expiring  September
30, 2015. We receive rental  payments  under the lease in fixed monthly  amounts
that vary over the term of the lease  and  range  from $0.8 - $1.0  million  per
month.  Development  Company is entitled to all of the output  produced from the
three units and is responsible for all operating  expenses.  Development Company
entered into an agreement with Midwest Electric Power, Inc., an affiliate, under
which Midwest Electric Power, Inc. provides operations and maintenance  services
at the Joppa  site.  On  November 1, 2000,  Development  Company  and  Marketing
Company  entered  into an electric  power supply  agreement,  referred to as the
Development  Company - Marketing  Company  agreement.  This  agreement  entitles
Marketing  Company to all of the output from the Joppa site. This agreement also
contains  a  monthly  capacity  charge  that  approximates  the  lease  payments
Development Company makes to us and an energy charge equal to the variable costs
of operating the combustion turbine generating units.

                                       38

<PAGE>

Electric Power Supply Agreements

     We have a power supply agreement with Marketing Company,  which we refer to
as the Generating Company - Marketing Company agreement.  Marketing Company,  in
turn,  has a power supply  agreement with  AmerenCIPS,  which we refer to as the
Marketing Company - AmerenCIPS  agreement.  Under these power supply agreements,
we agree to supply to Marketing Company,  and Marketing Company, in turn, agrees
to supply to AmerenCIPS,  all of the energy and capacity needed by AmerenCIPS to
fulfill its obligations to offer service to its retail  customers.  For capacity
and energy needed to meet its obligations to retail tariff customers, AmerenCIPS
pays  Marketing  Company fixed prices.  For its  fixed-price  retail  contracts,
AmerenCIPS pays Marketing  Company the price it receives under these  contracts.
Under the Generating  Company - Marketing Company  agreement,  Marketing Company
"passes  through"  to us the  amounts  received  under the  Marketing  Company -
AmerenCIPS  agreement.   The  Marketing  Company  -  AmerenCIPS  agreement  will
terminate  December  31,  2004.  The  Generating  Company  -  Marketing  Company
agreement will remain in effect unless  terminated by either party upon at least
one year's  notice,  but may not be terminated  prior to December 31, 2004.  See
Illinois  Electric in Note 2 for  information  regarding  a possible  renewal or
extension of the Marketing  Company - AmerenCIPS  agreement  through  January 1,
2007. Electric revenues derived under the Generating Company - Marketing Company
agreement  were $626 million for 2002 (2001 - $623 million) and $341 million for
the  period  from May 1, 2000  through  December  31,  2000.  No other  customer
represents greater than 10% of our revenues.

Joint Dispatch Agreement

     We  jointly  dispatch  generation  with  AmerenUE  under an  amended  joint
dispatch  agreement.  Under the amended  agreement,  both of us are  entitled to
serve our load requirements  from our own least-cost  generation first, and then
allow the other company access to any available  excess  generation.  All of our
sales to Marketing Company are considered load requirements. Sales made by us to
other  customers  through  AmerenEnergy,  as our agent,  are not considered load
requirements.  The agreement has no expiration,  but either party may give a one
year  notice of  termination  beginning  January  1, 2004.  Termination  of this
agreement could have a material adverse impact on our business.

     Electric  revenues  derived through sales of available  generation  through
AmerenEnergy  were $56 million for 2002 (2001- $55 million) and $105 million for
the period  from May 1, 2000  through  December  31,  2000.  These  amounts  are
inclusive of the adjustments made in accordance with EITF Issue 02-3. See Note 1
- "Summary  of  Significant  Accounting  Policies."  Electric  revenues  derived
through  sales of available  generation  to AmerenUE  through the amended  joint
dispatch agreement were $40 million for 2002 (2001- $33 million) and $31 million
for the period from May 1, 2000 through December 31, 2000.

     Purchased power derived from  AmerenEnergy was $30 million for 2002 (2001 -
$41 million)  and $67 million for the period from May 1, 2000  through  December
31, 2000. Intercompany power purchases from the amended joint dispatch agreement
between  AmerenUE and us and other  agreements  for 2002 were $77 million (2001-
$84 million)  and $52 million for the period from May 1, 2000  through  December
31, 2000.

Other Electric Revenues - Intercompany

     Electric  revenues  derived  through  sales of available  generation to our
affiliate  EEI were $4 million for 2002 (2001 - less than $1  million)  and less
than $1 million for the period from May 1, 2000 through December 31, 2000.

Ameren Services and AmerenEnergy Charges

     Support   services   provided  by  our  affiliates,   Ameren  Services  and
AmerenEnergy,  including wages,  employee  benefits,  professional  services and
other  expenses are based on actual costs  incurred.  Other  operating  expenses
provided by Ameren Services and AmerenEnergy,  for 2002 were $35 million (2001 -
$28  million)  and $18 million for the period May 1, 2000  through  December 31,
2000.

Non-Utility Money Pool

     Our gross margins from power supply  contracts  with  affiliated  companies
continue to be the principal source of cash from operating  activities.  We plan
to utilize  short-term  debt to support normal  operations  and other  temporary
capital  requirements.  We have the  ability to borrow up to $600  million  from
Ameren through a non-utility  money pool  agreement.  However,  the total amount
available to us at any time is reduced by the amount of  borrowings  from Ameren
by our  affiliates  and is increased  to the extent  other Ameren  non-regulated
companies advance surplus

                                       39

<PAGE>

funds to the  non-utility  money pool or external  sources are used by Ameren to
increase the available amounts. At December 31, 2002, $445 million was available
through the  non-utility  money pool not including  additional  funds  available
through  invested  cash  balances  at Ameren and  uncommitted  bank  lines.  The
non-utility  money pool was established to coordinate and provide for short-term
cash and working capital requirements of Ameren's  non-regulated  activities and
is administered by Ameren  Services.  Interest is calculated at varying rates of
interest  depending on the  composition  of internal  and external  funds in the
non-utility  money  pool.  The average  interest  rate for  borrowings  from the
non-utility money pool was 7.60% in 2002 (2001 - 4.08%) and 6.52% for the period
from May 1, 2000 through December 31, 2000. These rates are based on the cost of
Ameren's funds used to fund money pool  advances.  We incurred $6 million in net
intercompany  interest expense  associated with outstanding  borrowings from the
non-utility money pool in 2002 (2001 - $2 million) and $1 million for the period
from May 1, 2000  through  December  31,  2000.  At December  31,  2002,  we had
borrowings of $191 million from the non-utility money pool.

     Ameren's and our financial  agreements  include  customary default or cross
default  provisions  that could impact the continued  availability  of credit or
result in the  acceleration  of  repayment.  Many of Ameren's  committed  credit
facilities  require the borrower to represent,  in connection with any borrowing
under the facility that no material  adverse  change has occurred  since certain
dates.  Ameren's  financing  arrangements do not contain credit rating triggers,
with  the  exception  of  certain  ratings  triggers  within  CILCO's  financing
arrangements.

     Covenants in Ameren's  committed credit facilities  require the maintenance
of the  percentage  of total debt to total  capital  of 60% or less for  Ameren,
AmerenUE and AmerenCIPS.  As of December 31, 2002, this ratio was  approximately
50%, 43% and 50% for Ameren,  AmerenUE, and AmerenCIPS,  respectively.  Ameren's
committed credit facilities also include  indebtedness  cross default provisions
that could trigger a default under these  facilities in the event any subsidiary
of Ameren  (subject to definition in the underlying  credit  agreements),  other
than certain project finance subsidiaries, defaults on indebtedness in excess of
$50 million.

     Most of Ameren's  committed credit facilities include provisions related to
the funded status of Ameren's  pension plan.  These  provisions  either  require
Ameren  to meet  minimum  ERISA  funding  requirements  or  limit  the  unfunded
liability  status of the plan.  Under the most  restrictive of these  provisions
impacting  Ameren  facilities  totaling $400  million,  an event of default will
result if the unfunded  liability  status (as defined in the  underlying  credit
agreements)  of Ameren's  pension plan  exceeds  $300 million in the  aggregate.
Based on the most recent  valuation  report  available to Ameren at December 31,
2002,  which was based on  January  2002  asset and  liability  valuations,  the
unfunded liability status (as defined) was $31 million.  However, based on stock
market and interest  rate  performance  during 2002,  Ameren  believes an excess
unfunded  liability  may occur.  As a result,  Ameren may need to  terminate  or
replace the affected facilities, renegotiate the facility provisions or fund any
unfunded liability shortfall. Should Ameren elect to terminate these facilities,
Ameren  believes it would  otherwise  have  sufficient  liquidity  to manage its
short-term funding requirements.

Other

     See Note 6 -  Long-Term  Debt and  Intercompany  Notes  Payable for further
information regarding our intercompany notes payable to AmerenCIPS and Ameren.


NOTE 4 - Derivative Financial Instruments

     We, through  AmerenEnergy and Fuels Company acting as agents on our behalf,
utilize  derivatives  principally to manage the risk of changes in market prices
for fuel,  electricity  and emission  credits.  Price  fluctuations  in fuel and
electricity cause:

o    an unrealized  appreciation  or  depreciation  of our firm  commitments  to
     purchase or sell when  purchase or sales prices  under the firm  commitment
     are compared with current commodity prices;
o    market  values of fuel  inventories  or purchased  power to differ from the
     cost of those commodities in inventory and under firm commitment; and
o    actual cash  outlays for the purchase of these  commodities  to differ from
     anticipated cash outlays.

     The  derivatives  that we use to hedge  these  risks are  dictated  by risk
management  policies and include forward contracts,  futures contracts,  options
and swaps. We continually  assess our supply and delivery  commitment  positions
against  forward  market  prices and internal  forecasts of forward  prices.  We
actively  manage  our  exposure  to power  price  risk  through  our power  risk
management  program carried out under our risk  management  guidelines to modify

                                       40

<PAGE>

our exposure to market,  credit and  operational  risk by entering  into various
offsetting  transactions.  In general,  we believe these  transactions  serve to
reduce price risk for us.

     In addition, we may purchase additional power, again within risk management
guidelines,  in  anticipation  of power  requirements  and future price changes.
Certain  derivative  contracts  we enter into on a regular  basis as part of our
power risk management  program do not qualify for hedge accounting or the normal
purchase and sale exceptions  under SFAS 133.  Accordingly,  these contracts are
recorded at fair value with changes in the fair value charged or credited to the
income statement in the period in which the change occurred.  Contracts we enter
into as part of our power  risk  management  program  may be  settled  by either
physical  delivery  or net  settled  with the  counterparty.  See also  Note 1 -
Summary of Significant Accounting Policies for further information.

     As of December 31, 2002, we recorded the fair value of derivative financial
instrument assets of $1 million in Other Assets and the fair value of derivative
financial  instrument  liabilities of $1 million in Other  Deferred  Credits and
Liabilities.

Cash Flow Hedges

     We  routinely   enter  into  forward   purchase  and  sales  contracts  for
electricity  based on  forecasted  levels of economic  generation  and  customer
requirements.  The relative balance between  customer  requirements and economic
generation varies throughout the year. The contracts typically cover a period of
twelve  months or less.  The  purpose  of these  contracts  is to hedge  against
possible price  fluctuations in the spot market for the period covered under the
contracts.  We formally document all relationships  between hedging  instruments
and hedged  items,  as well as our risk  management  objective  and strategy for
undertaking  various hedge transactions.  The mark-to-market  value of cash flow
hedges will  continue to fluctuate  with changes in market prices up to contract
expiration.

     The pretax net gain or loss on power forward derivative instruments,  which
represented the impact of discontinued cash flow hedges, the ineffective portion
of cash flow hedges, as well as the reversal of amounts  previously  recorded in
OCI due to transactions going to delivery or settlement,  was approximately a $1
million loss for 2002 (2001 - $4 million gain).

     As of December 31, 2002, we had hedged a portion of the  electricity  price
exposure  for  the  upcoming   twelve-month  period.  The  mark-to-market  value
accumulated  in OCI for the  effective  portion of hedges of  electricity  price
exposure was a gain of less than $1 million.

     As of December 31, 2002,  a gain of  approximately  $6 million ($4 million,
net of taxes) associated with interest rate swaps was included in OCI. The swaps
were a partial hedge of the interest  rate on long-term  debt that was issued in
June  2002.  The  swaps  covered  the first ten years of debt that has a 30-year
maturity and the gain in OCI is being amortized over a ten-year period beginning
in June 2002.


NOTE 5 - Property and Plant, Net

     At December  31, 2002 and 2001,  property and plant,  net  consisted of the
following:

================================================================================
                                                         2002               2001
--------------------------------------------------------------------------------
Property and plant, at original cost:
  Electric                                            $ 2,462           $ 2,141
     Less accumulated depreciation and amortization       745               689
--------------------------------------------------------------------------------
                                                        1,717             1,452
Construction work in progress:                             50                60
--------------------------------------------------------------------------------
Property and plant, net                               $ 1,767           $ 1,512
================================================================================

                                       41

<PAGE>

NOTE 6 - Long-Term Debt and Intercompany Notes Payable

     The following tables  summarize our long-term debt and  intercompany  notes
payable at December 31, 2002 and 2001:

================================================================================
                                                              2002         2001
--------------------------------------------------------------------------------
Subordinated intercompany notes payable
--------------------------------------------------------------------------------
     2000 AmerenCIPS note 7% due 2005 (a)                   $   419       $ 462
     2000 Ameren note 7% due 2005 (b)                            43          46
================================================================================
                                                                462         508
--------------------------------------------------------------------------------
Unsecured notes
--------------------------------------------------------------------------------
      2000 Senior Notes Series C 7.75% due 2005 (c) (f) (g)     225         225
      2000 Senior Notes Series D 8.35% due 2010 (d) (f) (g)     200         200
      2002 Senior Notes Series F 7.95% due 2032 (e) (f) (g)     275           -
--------------------------------------------------------------------------------
                                                                700         425
--------------------------------------------------------------------------------
Unamortized discount and premium on debt                         (2)         (1)
--------------------------------------------------------------------------------
Maturities due within one year                                  (50)        (47)
--------------------------------------------------------------------------------
Total long-term debt and intercompany notes payable         $ 1,110       $ 885
================================================================================
(a)  Interest is payable on February 1, May 1, August 1, and  November 1 of each
     year  commencing  August 1, 2000.  Partial  principal  payments are payable
     annually on May 1 with the remaining principal due May 1, 2005.
(b)  Interest is payable on February 1, May 1, August 1, and  November 1 of each
     year  commencing  August 1, 2000.  Partial  principal  payments are payable
     annually on May 1 with the remaining principal due May 1, 2005.
(c)  Interest is payable semiannually in arrears on May 1 and November 1 of each
     year,  commencing  May 1, 2001.  Principal  will be payable on  November 1,
     2005.
(d)  Interest is payable semiannually in arrears on May 1 and November 1 of each
     year,  commencing  May 1, 2001.  Principal  will be payable on  November 1,
     2010.
(e)  Interest  is payable  semiannually  in arrears on June 1 and  December 1 of
     each year,  commencing December 1, 2002.  Principal will be payable on June
     1, 2032.
(f)  Our senior note indenture  contains  covenants  which,  among other things,
     restrict dividend payments,  subordinated debt interest payments and future
     bond issuance if certain financial conditions are not met. These conditions
     include  minimum  interest  coverage  ratios and a maximum  debt to capital
     ratio.  At  December  31,  2002,  we  were  in  compliance  with  all  such
     provisions.
(g)  We may redeem these notes, in whole or in part, at any time at a redemption
     price  equal to 100% of the  principal  amount of the notes to be  redeemed
     plus accrued interest, if any, plus a make-whole premium,  calculated using
     a discount  rate equal to the interest  rate on  comparable  U.S.  treasury
     securities plus 25 basis points.
(h)  We may redeem these notes, in whole or in part, at any time at a redemption
     price  equal to 100% of the  principal  amount of the notes to be  redeemed
     plus accrued interest, if any, plus a make-whole premium,  calculated using
     a discount  rate equal to the interest  rate on  comparable  U.S.  treasury
     securities plus 37.5 basis points.

     The  following   table   summarizes   maturities  of  long-term   debt  and
intercompany notes payable at December 31, 2002:

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

          ----------------------------------------
                  2003                 $ 50
                  2004                   53
                  2005                  584
                  2006                    -
                  2007                    -
          ----------------------------------------
               Thereafter               475
          ----------------------------------------
                  Total              $ 1,162
          ----------------------------------------

     On June 6, 2002, we issued $275 million of 7.95% Senior Notes, Series E due
June 1, 2032 (Series E Notes) in a Rule 144A  transaction  sold to institutional
investors.  Interest is payable  semi-annually  on June 1 and December 1 of each
year,  beginning  December 1, 2002.  We received net  proceeds of $271  million,
after debt  discount and fees,  that were used to reduce  short-term  borrowings
incurred  to finance  previous  generating  capacity  additions  and for general
corporate  purposes.  In the  fourth  quarter of 2002,  we filed a  registration
statement on Form S-4 to register the Senior Notes under the  Securities  Act of
1933, as amended,  to permit an exchange  offer of the Senior Notes.  In January
2003, all holders  completed their exchange of the Senior Notes for new Series F
Notes which were identical in all material respects to the Series E Notes except
that the new  series  of  notes do not  contain  transfer  restrictions  and are
registered.

     On November 1, 2000, we issued $225 million of Senior  Notes,  Series A due
November 1, 2005 (Series A Notes) and $200 million of Senior Notes, Series B due
November 1, 2010  (Series B Notes)  (collectively,  the Senior  Notes) in a Rule
144A transaction sold to institutional investors. The proceeds received from the
Senior Notes were $423.6

                                       42

<PAGE>

million  before  transaction  costs.  In the first  quarter of 2001,  we filed a
registration  statement  on Form S-4 to  register  the  Senior  Notes  under the
Securities  Act of 1933, as amended,  to permit an exchange  offer of the Senior
Notes.  In June 2001, all holders  completed  their exchange of the Senior Notes
for new Series C Notes and Series D Notes which are  identical  in all  material
respects to the Series A Notes and Series B Notes, respectively, except that the
new series of notes do not contain transfer restrictions and are registered.

     On May 1, 2000,  AmerenCIPS  transferred its electric generating assets and
related  liabilities,  at net book value,  to us in exchange for a  subordinated
promissory note from us in the principal amount of $552 million and 1,000 shares
of our  common  stock.  On June  30,  2000,  we  issued  a  second  subordinated
intercompany  note  in the  amount  of $50  million  to  Ameren.  This  note  is
subordinated  to all  senior  debt as well as to the  subordinated  note held by
AmerenCIPS.  The two  subordinated  intercompany  notes each have a term of five
years and bear interest at 7% based on a 10-year amortization schedule.

     Our Senior Note indenture includes provisions that require us to maintain a
senior  debt  service  coverage  ratio of at least 1.75 to 1 (for both the prior
four fiscal quarters and for the next  succeeding  four,  six-month  periods) in
order to pay  dividends,  or to make  payments of  principal  or interest  under
certain   subordinate   indebtedness,   excluding   amounts  payable  under  our
intercompany note payable with AmerenCIPS.  For the four quarters ended December
31, 2002, this ratio was 4.10 to 1. In addition, the indenture also restricts us
from  incurring  any  additional  indebtedness,  with the  exception  of certain
permitted  indebtedness  as defined  in the  indenture,  unless our senior  debt
service coverage ratio equals at least 2.5 to 1 for the most recently ended four
fiscal quarters and our senior debt to total capital ratio would not exceed 60%,
both after giving effect to the additional  indebtedness  on a pro-forma  basis.
This debt  incurrence  requirement  is  disregarded  in the event certain rating
agencies reaffirm our ratings after considering the additional indebtedness.  As
of  December  31,  2002,  our senior  debt to total  capital  ratio was 55%.  At
December 31, 2002,  we were in  compliance  with our Senior Note  indenture  and
covenants.

     Amortization  of debt  issuance  costs and  premium/discount  for the years
ended  December 31, 2002 of $1 million  (2001 - $1 million;  2000 - less than $1
million) were included in interest expense in the income statement.


NOTE 7 - Voluntary Retirement and Other Restructuring Charges

     Voluntary  retirement and other  restructuring  charges were $10 million in
2002 or $6 million, net of tax.

     In December 2002, approximately 550 employees, which includes approximately
35 of our employees and additional  employees  providing support functions to us
through  Ameren  Services,  accepted a  voluntary  retirement  program  that was
offered to approximately  1,000 of Ameren's 7,400 employees.  Eligible employees
had to be age 50 or  over,  regular,  full-time  employees  and have at least 10
years of service with Ameren.  While we expect to realize significant  long-term
savings as a result of this  program,  we incurred a pretax charge of $8 million
($5 million,  net of taxes) in December 2002 related to the voluntary retirement
program.  These  costs  consisted  primarily  of  special  termination  benefits
associated with Ameren's pension and post-retirement benefit plans.

     In  December  2002,  we  announced  that  we  were  temporarily  suspending
operation of two coal-fired  generating units at our Meredosia,  Illinois plant,
representing 126 megawatts of power generation capacity. The capacity reductions
and related  severance  charges  resulted in a charge of $2 million ($1 million,
net of taxes) in December 2002.

                                       43

<PAGE>

NOTE 8 - Income Taxes

     Total income tax expense for 2002  resulted in an effective tax rate of 39%
on earnings  before income taxes (38% in 2001 and 38% for the period from May 1,
2000 through December 31, 2000).

     Principal reasons such rates differ from the statutory federal rate for the
years ended December 31, 2002,  2001 and for the period from May 1, 2000 through
December 31, 2000 were as follows:

================================================================================
                                                2002             2001       2000
--------------------------------------------------------------------------------
Statutory federal income tax rate:               35%              35%        35%
Increases (decreases) from:
  Depreciation differences                       (1)               1           -
  Amortization of investment tax credit          (3)              (1)        (2)
  State income tax                                5                3          5
  Other                                           3                -          -
--------------------------------------------------------------------------------
Effective income tax rate                        39%              38%        38%
--------------------------------------------------------------------------------

     Components  of income tax expense for the years ended  December  31,  2002,
2001 and for the period May 1, 2000 through December 31, 2000 were as follows:

================================================================================
                                                2002             2001       2000
--------------------------------------------------------------------------------
Taxes currently payable (principally federal):
Included in operating expenses                $ (41)             $ 18      $ 23
Included in other income--
     Miscellaneous, net                           -                 1         -
--------------------------------------------------------------------------------
                                              $ (41)             $ 19      $ 23

Deferred taxes (principally federal):
Included in operating expenses--
     Depreciation differences                 $  60              $ 22      $  2
     Other                                        3                 7         3
--------------------------------------------------------------------------------
                                              $  63              $ 29      $  5

Deferred investment tax credits, amortization:
Included in operating expenses                $  (2)             $ (1)     $ (1)
--------------------------------------------------------------------------------
Total income tax expense                      $  20              $ 47      $ 27
================================================================================

     In accordance with SFAS 109,  "Accounting for Income Taxes," the step-up in
basis for tax purposes of the  transferred  assets from  AmerenCIPS to us in May
2000, resulted in an additional tax basis for us and a deferred intercompany tax
gain for AmerenCIPS of approximately  $552 million,  resulting in a deferred tax
asset for us of approximately  $219 million and an equivalent income tax payable
- intercompany balance. This transaction was recorded as a non-cash transaction.
The  deferred tax asset and  intercompany  tax payable are being  amortized  and
paid,  respectively,  over twenty years,  the approximate  remaining life of the
transferred assets.

     Temporary  differences  gave rise to the following  deferred tax assets and
deferred tax liabilities at December 31, 2002 and 2001:

================================================================================
                                                              2002          2001
--------------------------------------------------------------------------------
Accumulated deferred income taxes:
  Accelerated depreciation                                   $ 200        $ 132
  Tax basis step-up                                           (175)        (196)
  Investment tax credits                                        (6)          (7)
  Capitalized taxes and expenses                                49           34
  Deferred benefits                                             (4)          (1)
  Other                                                          2            -
--------------------------------------------------------------------------------
Total net accumulated deferred income tax liability (asset)  $  66        $ (38)
================================================================================

                                       44

<PAGE>

NOTE 9 - Retirement Benefits

Pension

     Ameren has defined benefit  retirement plans covering  substantially all of
our  employees.  Benefits  are  based on the  employees'  years of  service  and
compensation.   Ameren's  plans  are  funded  in  compliance   with  income  tax
regulations and federal funding requirements.  We, along with other subsidiaries
of Ameren,  are a  participant  in Ameren's  plans and are  responsible  for our
proportional  share of the costs.  Our share of the pension costs for 2002, were
$2 million (2001 and 2000 were less than $1 million) of which  approximately  3%
(2001 - 4%; 2000 - 1%) was charged to construction accounts.

     Ameren made cash  contributions  totaling  $31 million to Ameren's  defined
benefit  retirement  plan during 2002.  Our share of the cash  contribution  was
approximately  $4  million.  At December  31,  2002,  Ameren  recorded a minimum
pension liability of $102 million,  net of taxes,  which resulted in a charge to
OCI and a reduction in  stockholder's  equity.  Our share of the minimum pension
liability was $6 million,  net of taxes. Based on the performance of plan assets
through  December 31,  2002,  Ameren  expects to be required  under the Employee
Retirement  Income  Security Act of 1974 to fund  annually  $150 million to $175
million in 2005, 2006 and 2007 in order to maintain  minimum funding levels.  In
addition,  Ameren  estimates the pension  funding for CILCORP to be less than $1
million in 2003 and approximately $5 million in 2004. We expect our share of the
annual  funding in 2005,  2006,  and 2007 to be between $18 million to $21 which
includes our share  related to employees of Ameren  Services.  These amounts are
estimates  and may change based on actual stock market  performance,  changes in
interest rates and any changes in government regulations.  At December 31, 2002,
Ameren's Net Benefit  Obligation  was $1,587  million and its Fair Value of Plan
Assets was $1,059 million.

     Ameren's  assumptions  for  actuarial  present  value of projected  benefit
obligations during 2002, 2001 and 2000 were as follows:

================================================================================
                                           2002            2001             2000
--------------------------------------------------------------------------------
Discount rate at measurement date         6.75%           7.25%            7.50%
Expected return on plan assets            8.50%           8.50%            8.50%
Increase in future compensation           3.75%           4.25%            4.50%
--------------------------------------------------------------------------------

Post-Retirement

     Ameren's  funding policy for  post-retirement  benefits is to annually fund
the Voluntary Employee Beneficiary  Association trusts (VEBA) with the lesser of
the net periodic cost or the amount  deductible for federal income tax purposes.
We, along with other  subsidiaries  of Ameren,  are a  participant  in the VEBA,
which covers  substantially  all of our employees,  and are  responsible for our
proportional share of the costs. Our share of the  postretirement  benefit costs
for  2002  were $4  million  (2001 - $3  million;  2000 - $2  million)  of which
approximately 16% (2001 - 5%) were charged to construction accounts.

     Ameren's  assumptions  for  the  post-retirement  benefit  plan  obligation
measurements  for the  years  ended  December  31,  2002,  2001 and 2000 were as
follows:

================================================================================
                                           2002            2001             2000
--------------------------------------------------------------------------------
    Discount rate at measurement date     6.75%           7.25%            7.50%
    Expected return on plan assets        8.50%           8.50%            8.50%
    Medical cost trend rate (initial)    10.00%           5.25%            5.00%
    Medical cost trend rate (ultimate)    5.25%           5.25%            5.00%
================================================================================


NOTE 10 - Commitments and Contingencies

     As a result of issues  generated  in the course of daily  business,  we are
involved  in  legal,  tax and  regulatory  proceedings  before  various  courts,
regulatory  commissions  and  governmental  agencies,   some  of  which  involve
substantial  amounts of money.  We believe that the final  disposition  of these
proceedings,  except as  otherwise  disclosed in this Report and in the Notes to
our  Financial  Statements,  will not have an  adverse  material  effect  on our
financial position, results of operations or liquidity.

                                       45

<PAGE>

Capital Expenditures

     We  estimate  our  capital  expenditures  over the next five  years will be
approximately $200 million - $230 million,  including capitalized interest. This
estimate  includes  capital  expenditures  for upgrades to existing coal and gas
fired  facilities  and  other  generation  related  activities,  as  well as for
compliance with new NOx (nitrogen oxide) control regulations, as discussed later
in this Note.

     Our capital program is subject to periodic review and revision,  and actual
capital  costs may vary from the above  estimate  because of  numerous  factors.
These factors include changes in business conditions,  acquisition of additional
generating  assets,  revised  load growth  estimates,  changes in  environmental
regulations,  increasing  costs of labor,  equipment and materials,  and cost of
capital.

     We  intend  to  sell  at  net  book  value   approximately   550  megawatts
(approximately  $260 million) of our combustion turbine generating units located
at Pinckneyville and Kinmundy,  Illinois to our regulated  affiliate,  AmerenUE,
which wants them to comply with AmerenUE's  recent  Missouri  electric rate case
settlement  and to meet its future  regulated  generating  capacity  needs.  The
transfer is subject to receipt of necessary regulatory approvals and is expected
to be  completed in 2003.  Cash  proceeds  from the sale will be applied  toward
reducing our short-term  money pool  borrowings and for other general  operating
activities. The indenture for our Senior Notes imposes limitations on the use of
proceeds of the sale of our  generating  units if the net book value of the sold
assets  (together with prior assets sales since November 1, 2000) exceeds 25% of
consolidated  tangible  assets (as defined in the indenture) as of the first day
of the most recently ended fiscal quarter prior to the date the assets are sold.
We do not expect that the sale of the  Pinckneyville  and  Kinmundy  units would
exceed the 25% amount.  If the sale  proceeds  did exceed the  limitation,  they
would have to be (1)  reinvested in our business  within 12 months,  (2) used to
repay  indebtedness  or (3) retained by us. This  transfer is expected to reduce
operating and depreciation costs for 2003.

Fuel Purchase Commitments

     To supply a portion of the fuel  requirements of our generating  plants, we
have entered into various long-term  commitments for the procurement of coal and
natural gas. In addition, we have entered into various long-term commitments for
the purchase of  electricity.  Total  estimated  fuel  purchase  commitments  at
December 31, 2002 were as follows:

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

                                                    Coal                Gas
--------------------------------------------------------------------------------
       2003                                         $174                $11
       2004                                          157                  4
       2005                                          120                  3
       2006                                           96                  2
       2007                                           77                  -
--------------------------------------------------------------------------------
       Thereafter                                    165                  4
--------------------------------------------------------------------------------
       Total                                        $789                $24
================================================================================


Leases

     The following table summarizes our lease  obligations at December 31, 2002:
================================================================================

                                      Less than    1 - 3    4 - 5     After 5
                            Total       1 year     years    years      years
--------------------------------------------------------------------------------
    Operating leases (a)     $ 8         $ 1        $ 1      $ 1        $ 5
--------------------------------------------------------------------------------

     (a)  Amounts related to certain real estate leases have indefinite  payment
          periods.  The amounts for these items are  included in the less than 1
          year,  1-3  years  and 4-5  years.  Amounts  for after 5 years are not
          included  in the  total  amount  due to the  indefinite  periods.  The
          estimated  obligation  for  after 5  years  is  less  than $1  million
          annually for the real estate leases.

     We lease various facilities, office equipment, plant equipment and railcars
under operating  leases.  As of December 31, 2002,  rental expense,  included in
Other  Operations and Maintenance  expenses,  totaled  approximately  $2 million
(2001 - $4 million; 2000 - $4 million).

                                       46

<PAGE>

 Environmental Matters

     We are subject to various environmental  regulations by federal, state, and
local authorities.  From the beginning phases of siting and development,  to the
ongoing  operation  of  existing  or new  electric  generating  facilities,  our
activities  involve  compliance with diverse laws and  regulations  that address
emissions  and  impacts  to air and  water,  special,  protected,  and  cultural
resources (such as wetlands,  endangered species,  and  archeological/historical
resources),  chemical and waste  handling,  and noise  impacts.  Our  activities
require complex and often lengthy  processes to obtain  approvals,  permits,  or
licenses for new, existing,  or modified facilities.  Additionally,  the use and
handling of various chemicals or hazardous materials (including wastes) requires
preparation of release  prevention plans and emergency response  procedures.  As
new laws or  regulations  are  promulgated,  we assess their  applicability  and
implement the necessary modifications to our facilities or their operations,  as
required. The more significant matters are discussed below.

Clean Air Act

     The Clean Air Act  affects  both  existing  generating  facilities  and new
projects.  The Clean Air Act and many state laws require significant  reductions
in SO2 (sulfur dioxide) and NOx emissions that result from burning fossil fuels.
The Clean Air Act also contains other  provisions that could  materially  affect
some of our  projects.  Various  provisions  require  permits,  inspections,  or
installation  of  additional  pollution  control  technology  or may require the
purchase of emission  allowances.  Certain of these  provisions are described in
more detail below.

     The Clean Air Act creates a marketable commodity called an SO2 "allowance."
All generating facilities over 25 megawatts that emit SO2 must obtain allowances
in order to operate after 1999. Each allowance gives the owner the right to emit
one  ton  of  SO2.  All  existing  generating  facilities  have  been  allocated
allowances  based on a facility's  past  production  and the statutory  emission
reduction  goals.  If  additional  allowances  are  needed  for  new  generating
facilities,  they can be purchased from facilities  having excess  allowances or
from  SO2  allowance  banks.  Our  generating  facilities  comply  with  the SO2
allowance  caps through the purchase of  allowances  or use of low sulfur fuels.
The  additional  costs of  obtaining  allowances  needed for  future  generation
projects should not materially affect our ability to build, acquire, and operate
them.

     The U.S.  Environmental  Protection  Agency  (EPA) issued a rule in October
1998  requiring  22  Eastern  states  and the  District  of  Columbia  to reduce
emissions of NOx in order to reduce ozone in the Eastern  United  States.  Among
other things,  the EPA's rule  establishes an ozone season,  which runs from May
through September,  and a NOx emission budget for each state, including Illinois
where  most of our  facilities  are  located.  The EPA rule  requires  states to
implement  controls  sufficient  to meet  their NOx budget by May 31,  2004.  In
addition,  the Illinois EPA already has a rule which will require additional NOx
controls by the summer of 2003.  We expect to have the NOx controls in operation
by the summer of 2003 to meet both regulatory requirements.

     As a result of these state requirements, we estimate spending an additional
$40 million for pollution control capital  expenditures and NOx credits by 2006.
This estimate  includes the  assumption  that the  regulations  will require the
installation of Selective Catalytic  Reduction  technology on some of our units,
as well as additional controls.

     Under both Illinois and Missouri regulatory  programs,  we have applied for
Early Reduction NOx credits which would allow us to manage compliance strategies
by either purchasing NOx control equipment or utilizing credits. We are eligible
for such credits due to the current low NOx emission  rates  achieved on some of
our boilers due to past NOx control efforts.

     On December 31, 2002, the EPA published in the Federal  Register  revisions
to the New  Source  Review  (NSR)  programs  under the Clean Air Act,  including
changes to the routine maintenance,  repair and replacement exclusions.  Various
Northeastern  states have filed a petition with the United States District Court
for the District of Columbia  challenging  the legality of the  revisions to the
NSR programs. It is likely that various industries and environmental groups will
seek to intervene in that challenge.  At this time, we are unable to predict the
impact  of  this  challenge  on  our  future  financial  position,   results  of
operations, or liquidity.


National Ambient Air Quality Standards

     In July 1997, the EPA issued regulations  revising the National Ambient Air
Quality  Standards  for  ozone  and  particulate   matter.  The  standards  were
challenged by industry and some states,  and arguments were eventually

                                       47

<PAGE>

heard by the U.S.  Supreme Court. In February 2001, the Supreme Court upheld the
standards  in large part,  but remanded a number of  significant  implementation
issues back to the EPA for  resolution.  The EPA is  currently  working on a new
rulemaking  to address  the issues  raised by the  Supreme  Court.  New  ambient
standards may require significant additional reductions in SO2 and NOx emissions
from our power  plants by 2008.  At this  time,  we are  unable to  predict  the
ultimate impact of these revised air quality  standards on our future  financial
position, results of operations or liquidity.

Mercury and Regional Haze Regulations

     In December 1999, the EPA issued a decision to regulate  mercury  emissions
from  coal-fired  power  plants  by  2008.  The  EPA  is  scheduled  to  propose
regulations by 2004.  These  regulations  have the potential to add  significant
capital and/or operating costs to our generating  systems after 2005. The EPA is
scheduled to issue Best  Available  Retrofit  Technology  (BART)  guidelines  to
address  visibility  impairment  (so called  "Regional  Haze") across the United
States from sources of air pollution,  including  coal-fired  power plants.  The
guidelines are to be used by states to mandate  pollution  control  measures for
SO2 and NOx emissions.  These rules could also add significant pollution control
costs to our generating systems between 2008 and 2012.

Multi-Pollutant Legislation

     The United States  Congress has been working on  legislation to consolidate
the  numerous  air  pollution  regulations  facing the  utility  industry.  This
"multi-pollutant" legislation is expected to be deliberated in Congress in 2003.
While  the  cost  to  comply  with  such  legislation,   if  enacted,  could  be
significant,  it is  anticipated  that the costs would be less than the combined
impact of the new National Ambient Air Quality  Standards,  mercury and Regional
Haze   regulations,   discussed  above.   Pollution  control  costs  under  such
legislation  are  expected to be incurred in phases from 2007 through  2015.  At
this time,  we are unable to predict the ultimate  impact of the above  expected
regulations and this  legislation on our future financial  position,  results of
operations, or liquidity; however, the impact could be material.

     Future  initiatives  regarding  greenhouse gas emissions and global warming
continue to be the subject of much debate. The related Kyoto Protocol was signed
by the United States but has since been rejected by the  President,  who instead
has asked for an 18% decrease in carbon intensity on a voluntary  basis.  Future
initiatives on this issue and the ultimate effects of the Kyoto Protocol and the
President's  initiatives  on us are  unknown.  As a result of our  diverse  fuel
portfolio, our contribution to greenhouse gases varies. Coal-fired power plants,
however,  are  significant  sources of carbon  dioxide  emissions,  a  principal
greenhouse  gas.  Therefore,  our  compliance  costs with any  mandated  federal
greenhouse gas reductions in the future could be material.


Clean Water Act

     In April  2002,  the EPA  proposed  rules  under the  Clean  Water Act that
require  that  cooling  water  intake  structures  reflect  the best  technology
available for minimizing adverse environmental  impacts.  These rules pertain to
existing  generating  facilities  that  currently  employ a cooling water intake
structure  whose flow exceeds 50 million  gallons per day. A final action on the
proposed  rules is expected by August 2003.  The proposed rule may require us to
install  additional  intake  screens or other  protective  measures,  as well as
extensive  site specific study and  monitoring  requirements.  There is also the
possibility  that the  proposed  rules may lead to the  installation  of cooling
towers on some of our facilities. Our compliance costs associated with the final
rules are unknown, but could be material.

Remediation

     On July 30, 2002, the Illinois Attorney General's Office advised us that it
would be commencing an enforcement  action concerning an inactive waste disposal
site near  Coffeen,  Illinois,  which is the  location  of a  disposal  facility
permitted by the Illinois Environmental  Protection Agency (IEPA) to receive fly
ash from the Coffeen power plant.  The Illinois  Attorney  General also notified
the disposal facility's current and former owners as to the proposed enforcement
action. The Attorney General advised that it may initiate an action under CERCLA
to  recover  past  costs  incurred  at  the  site  ($322,000)  and to  obtain  a
declaratory  judgment as to liability for future costs.  Neither us, the current
owner of the Coffeen power plant, nor AmerenCIPS, the prior owner of the Coffeen
power  plant,  owned or operated  the  disposal  facility.  We believe that this
matter  will not have a  material  adverse  effect  on our  financial  position,
results of operations or liquidity.

                                       48

<PAGE>

     Our affiliate,  AmerenCIPS,  is involved in a number of remediation actions
to clean up hazardous waste sites as required by federal and state law.  Several
of these sites involve  facilities  currently owned by us. Such statutes require
that responsible parties fund remediation actions regardless of fault,  legality
of original  disposal,  or ownership of a disposal site. We accrue for all known
environmental  contamination where remediation can be reasonably  estimated.  As
part of the Transfer,  AmerenCIPS has  contractually  agreed to indemnify us for
remediation  costs associated with pre-existing  environmental  contamination at
the sites of our coal plants.

Labor Agreements

     Certain of our employees are represented by the  International  Brotherhood
of Electrical Workers (IBEW) and the International  Union of Operating Engineers
(IUOE).  These  employees  comprise  approximately  70% of our workforce.  Labor
agreements  covering  the  majority of  employees  represented  by IBEW and IUOE
expire  by June  2003.  We  cannot  predict  what  issues  may be  raised by the
collective bargaining units and, if raised, whether negotiations concerning such
issues will be successfully concluded.

Regulation

     Regulatory  changes  enacted and being  considered at the federal and state
levels  continue to change the  structure  of the utility  industry  and utility
regulation,  as well as encourage  increased  competition.  At this time, we are
unable to predict the impact of these changes on our future financial  position,
results of operations or liquidity. See Note 2 - Rate and Regulatory Matters for
further information.


NOTE 11 - Fair Value of Financial Instruments

     The following  methods and assumptions were used to estimate the fair value
of each class of financial  instruments  for which it is practicable to estimate
that value:

Cash and Temporary Investments/Short-Term Borrowings

     The  carrying  amounts  approximate  fair value  because of the  short-term
maturity of these instruments.

Long-Term Debt

     The fair value is estimated  based on the quoted  market prices for same or
similar  issues or on the  current  rates  offered to us for debt of  comparable
maturities.

Derivative Financial Instruments

     Market  prices  used to  determine  fair  value are  based on  management's
estimates,  which take into consideration  factors like closing exchange prices,
over-the-counter  prices,  and time value of money and volatility  factors.  All
derivative  financial  instruments are carried at fair value on the consolidated
balance sheet.

     Carrying amounts and estimated fair values of our financial  instruments at
December 31, 2002 and 2001 were as follows:

<TABLE>
<CAPTION>
                                                                    2002                           2001
===================================================================================================================
<S>                                                      <C>              <C>           <C>             <C>
                                                          Carrying          Fair         Carrying        Fair
                                                           Amount          Value          Amount         Value
-------------------------------------------------------------------------------------------------------------------
Long-term debt (including current portion)                  $700            $783           $424          $451
-------------------------------------------------------------------------------------------------------------------
</TABLE>

NOTE 12 - Subsequent Event

     On January 31,  2003,  after  receipt of the  necessary  regulatory  agency
approvals   and   clearance   from  the   Department   of   Justice   under  the
Hart-Scott-Rodino  Antitrust  Improvements Act, Ameren completed its acquisition
of all of the  outstanding  common  stock of  CILCORP  from AES.  CILCORP is the
parent company of Peoria,  Illinois-based  Central Illinois Light Company, which
operated as CILCO. With the acquisition,  CILCO became an Ameren subsidiary, but
remains a separate  utility  company,  operating as AmerenCILCO.  On February 4,
2003,  Ameren also completed its acquisition of Medina Valley,  which indirectly
owns a 40 megawatt, gas-fired electric

                                       49

<PAGE>

cogeneration  plant.  With the acquisition,  Medina Valley became a wholly-owned
subsidiary of Resources  Company and was renamed as  AmerenEnergy  Medina Valley
Cogen (No. 4), LLC. The CILCORP and  AmerenEnergy  Medina  Valley Cogen (No. 4),
LLC financial  statements  will be included in Ameren's  consolidated  financial
statements effective with the January and February 2003 acquisition dates.

     Ameren acquired  CILCORP to complement its existing  Illinois  electric and
gas  operations.  The  purchase  included  CILCO's  rate-regulated  electric and
natural gas  businesses in Illinois  serving  approximately  200,000 and 205,000
customers, respectively, of which approximately 150,000 are combination electric
and gas customers.  CILCO's service  territory is contiguous to Ameren's service
territory and accessible by our electric generation facilities. CILCO also has a
non rate-regulated  electric and gas marketing business  principally  focused in
the Chicago, Illinois region. Finally, the purchase includes approximately 1,200
megawatts of largely coal-fired  generating capacity,  most of which is expected
to become non rate-regulated in 2003.

     The total  purchase price was  approximately  $1.4 billion and included the
assumption of CILCORP and Medina  Valley debt and preferred  stock at closing of
approximately  $900  million,   with  the  balance  of  the  purchase  price  of
approximately $500 million paid with cash on hand. The purchase price is subject
to certain  adjustments  for  working  capital  and other  changes  pending  the
finalization  of CILCORP's  closing  balance  sheet.  The cash  component of the
purchase  price came from Ameren's  issuances in September  2002 of 8.05 million
common shares and in early 2003 of 6.325 million common shares.


                                       50

<PAGE>

SELECTED QUARTERLY INFORMATION (Unaudited)
-------------------------------
(In Millions)

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

                                Operating       Operating                Net
Quarter Ended:                  Revenues(a)       Income                Income
--------------------------------------------------------------------------------
March 31, 2002                    $ 176           $ 38                   $ 13
March 31, 2001                      164             43                     13
June 30, 2002                       175             26                      2
June 30, 2001                       162             37                     12
September 30, 2002                  207             49                     15
September 30, 2001                  236             88                     43
December 31, 2002 (b)               185             26                      2
December 31, 2001                   168             27                      8
--------------------------------------------------------------------------------

(a)  Revenues  were  netted  with  costs  upon  adoption  of EITF  02-3  and the
     rescission of EITF 98-10.  See Note 1 - Summary of  Significant  Accounting
     Policies for further information.  The amount netted for each quarter is as
     follows:  2002 - $87 in first quarter,  $44 in second quarter, $60 in third
     quarter,  and $62 in fourth  quarter (2001 - $43 in first  quarter,  $49 in
     second quarter, $90 in third quarter, and $74 in fourth quarter).
(b)  Amounts include Voluntary Retirement and Other Restructuring Charges of $10
     million ($6 million,  net of taxes). See Note 7 - Voluntary  Retirement and
     Other Restructuring Charges for further information.

     Other  impacts to  quarterly  earnings  are due to the effect of weather on
sales and other  factors that are  characteristic  of public  utility  wholesale
electric generation operations.

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

     None.

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

     This item is omitted in  reliance  on  General  Instruction  (I)(2) of Form
10-K.


ITEM 11.  EXECUTIVE COMPENSATION.

     This item is omitted in  reliance  on  General  Instruction  (I)(2) of Form
10-K.


ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

     This item is omitted in  reliance  on  General  Instruction  (I)(2) of Form
10-K.


ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS.

     This item is omitted in  reliance  on  General  Instruction  (I)(2) of Form
10-K.


ITEM 14.  CONTROLS AND PROCEDURES.

     Within  90 days  prior  to the  date  of this  report,  we  carried  out an
evaluation,  under the  supervision  and with  participation  of our management,
including  our Chief  Executive  Officer  and Chief  Financial  Officer,  of the
effectiveness  of the  design  and  operation  of our  disclosure  controls  and
procedures pursuant to Rule 13a-14 under the Securities Exchange Act of 1934, as
amended.  Based upon that  evaluation,  the Chief  Executive  Officer  and Chief
Financial  Officer  concluded  that our  disclosure  controls and procedures are
effective  in  timely  alerting  them  to  material   information   relating  to
AmerenEnergy Generating Company which is required to be included in our periodic
SEC filings.

                                       51

<PAGE>

     There have been no significant changes in our internal controls or in other
factors which could  significantly  affect internal  controls  subsequent to the
date we carried out our evaluation.

                                     PART IV

ITEM 15.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
          ON FORM 8-K.

<TABLE>
<CAPTION>

(A) Financial Statements:
                                                                                                                        Pages Herein
<S>                                                                                                                    <C>
(1)  Financial Statements of Ameren Energy Generating Company which
     are included at Item 8 of this report.

     (a)  Report of Independent Accountants...........................................................................       27
     (b)  Balance Sheet - December 31, 2002 and 2001..................................................................       28
     (c)  Statement of Income - Years Ended December 31, 2002 and 2001 and for the Period May
            1, 2000 through December 31, 2000.........................................................................       29
     (d)  Statement of Cash Flows - Years Ended December 31, 2002 and 2001 and for the Period
            May 1, 2000 through December 31, 2000.....................................................................       30
     (e)  Statement of Common Stockholder's Equity - Years Ended December 31, 2002 and 2001
            and for the Period May 1, 2000 through December 31, 2000..................................................       31
     (f)  Notes to Financial Statements...............................................................................       32
 </TABLE>

(2)  Financial Statement Schedule

     None.

(3)  Exhibits filed with this report are listed on the "Exhibit Index".

(B)  Reports on Form 8-K

     None.

(C)  Exhibits.

  Exhibit
  Number                                  Description
  -------                                 -----------
    3.1        Articles of  Incorporation  of  AmerenEnergy  Generating  Company
               (Generating  Company),  filed  March  2,  2000  (incorporated  by
               reference  to Exhibit 3.1 to  Generating  Company's  Registration
               Statement on Form S-4 (Commission File No. 333-56594)).

    3.2        Amendment to Articles of  Incorporation  of  Generating  Company,
               filed April 19, 2000 (incorporated by reference to Exhibit 3.2 to
               Generating   Company's   Registration   Statement   on  Form  S-4
               (Commission File No. 333-56594)).

    3.3**      By-laws of Generating  Company (as amended  effective January 21,
               2003).

    4.1        Indenture  dated  as of  November  1,  2000,  between  Generating
               Company and The Bank of New York, as Trustee,  relating to senior
               notes  (Indenture)  (incorporated  by reference to Exhibit 4.1 to
               Generating   Company's   Registration   Statement   on  Form  S-4
               (Commission File No. 333-56594)).

    4.2       First  Supplemental  Indenture  to  the  Indenture,  dated  as of
               November  1,  2000  (including  as  exhibit  the  form of  Notes)
               (incorporated by reference to Exhibit 4.2 to Generating Company's
               Registration   Statement  on  Form  S-4   (Commission   File  No.
               333-56594)).

    4.3        Form of Second Supplemental Indenture to the Indenture,  dated as
               of June 12, 2001 (including as exhibit the form of Exchange Note)
               (incorporated by reference to Exhibit 4.3 to Generating Company's
               Registration   Statement  on  Form  S-4   (Commission   File  No.
               333-56594)).

                                       52

<PAGE>

  Exhibit
  Number                                  Description
  -------                                 -----------

    4.4        Third Supplemental  Indenture to the Indenture,  dated as of June
               1, 2002 (including as exhibit the form of Note)  (incorporated by
               reference to Exhibit 4.1 to Generating Company's quarterly report
               on Form 10-Q for the quarter ended June 30, 2002).

    4.5**      Fourth  Supplemental  Indenture  to the  Indenture,  dated  as of
               January  15,  2003  (including  as exhibit  the form of  Exchange
               Note).

   10.1        Asset Transfer  Agreement between  Generating Company and Central
               Illinois  Public Service  Company d/b/a  AmerenCIPS  (AmerenCIPS)
               (incorporated by reference to Exhibit 10 to AmerenCIPS' quarterly
               report on Form 10-Q for the quarter ended June 30, 2000).

   10.2        Amended  Electric  Power  Supply  Agreement  between   Generating
               Company and AmerenEnergy  Marketing Company  (Marketing  Company)
               (incorporated   by  reference  to  Exhibit  10.2  to   Generating
               Company's Registration Statement on Form S-4 (Commission File No.
               333-56594)).

   10.3        Second Amended Electric Power Supply Agreement between Generating
               Company and  Marketing  Company  (incorporated  by  reference  to
               Exhibit 10.1 to Ameren Corporation's  (Ameren's) quarterly report
               on Form 10-Q for the quarter ended March 31, 2001).

   10.4        Electric Power Supply  Agreement  between  Marketing  Company and
               AmerenCIPS   (incorporated   by  reference  to  Exhibit  10.3  to
               Generating   Company's   Registration   Statement   on  Form  S-4
               (Commission File No. 333-56594)).

   10.5        Amended Electric Power Supply Agreement between Marketing Company
               and  AmerenCIPS  (incorporated  by  reference  to Exhibit 10.2 to
               Ameren's  quarterly  report  on Form 10-Q for the  quarter  ended
               March 31, 2001).

   10.6        Power  Sales  Agreement   between  Marketing  Company  and  Union
               Electric  Company  d/b/a  AmerenUE  (AmerenUE)  (incorporated  by
               reference to Exhibit 10.1 to AmerenUE's  quarterly report on Form
               10-Q for the quarter ended September 30, 2001).

   10.7        Amended  Joint  Dispatch  Agreement  among  Generating   Company,
               AmerenCIPS  and  AmerenUE  (incorporated  by reference to Exhibit
               10.4 to Generating Company's  Registration  Statement on Form S-4
               (Commission File No. 333-56594)).

   10.8        Agency Agreement among Generating  Company,  AmerenUE,  Marketing
               Company and  AmerenEnergy,  Inc.  (incorporated  by  reference to
               Exhibit 10.5 to Generating  Company's  Registration  Statement on
               Form S-4 (Commission File No. 333-56594)).

   10.9        General  Services   Agreement  between  Ameren  Services  Company
               (Ameren Services) and AmerenEnergy  Resources Company (Resources)
               (incorporated   by  reference  to  Exhibit  10.6  to   Generating
               Company's Registration Statement on Form S-4 (Commission File No.
               333-56594)).

   10.10       Fuel Services  Agreement between  AmerenEnergy Fuels and Services
               Company and Resources  (incorporated by reference to Exhibit 10.7
               to  Generating  Company's  Registration  Statement  on  Form  S-4
               (Commission File No. 333-56594)).

   10.11       Form of Parallel  Operating  Agreement between Generating Company
               and Ameren Services (incorporated by reference to Exhibit 10.8 to
               Generating   Company's   Registration   Statement   on  Form  S-4
               (Commission File No. 333-56594)).

   10.12       Committed Unit Contribution  Agreement between Generating Company
               and Resources (on behalf of itself and  AmerenEnergy  Development
               Company  (Development  Company)  (incorporated  by  reference  to
               Exhibit 10.9 to Generating  Company's  Registration  Statement on
               Form S-4 (Commission File No. 333-56594)).

   10.13       Lease  Agreement  between   Generating  Company  and  Development
               Company (incorporated by reference to Exhibit 10.10 to Generating
               Company's Registration Statement on Form S-4 (Commission File No.
               333-56594)).

                                       53

<PAGE>

  Exhibit
  Number                                  Description
  -------                                 -----------

   10.14       Amended and Restated  Appendix I ITC Agreement dated February 14,
               2003  between  the  Midwest   Independent   Transmission   System
               Operator,  Inc.  (Midwest ISO) and GridAmerica LLC  (GridAmerica)
               (incorporated  by reference to Exhibit  10.17 of Ameren's  annual
               report on Form 10-K for the year ended December 31, 2002).

   10.15       Amended and  Restated  Limited  Liability  Company  Agreement  of
               GridAmerica dated February 14, 2003 (incorporated by reference to
               Exhibit 10.18 of Ameren's annual report on Form 10-K for the year
               ended December 31, 2002).

   10.16       Amended and Restated Master  Agreement by and among  GridAmerica,
               GridAmerica  Holdings  Inc.,  GridAmerica  Companies and National
               Grid USA dated  February 14, 2003  (incorporated  by reference to
               Exhibit 10.19 of Ameren's annual report on Form 10-K for the year
               ended December 31, 2002).

   10.17       Amended and Restated  Operation  Agreement by and among AmerenUE,
               AmerenCIPS, American Transmission Systems, Inc., Northern Indiana
               Public Service  Company and  GridAmerica  dated February 14, 2003
               (incorporated  by reference to Exhibit  10.20 of Ameren's  annual
               report on Form 10-K for the year ended December 31, 2002).

   10.18       Power Sales  Agreement  between  Marketing  Company and  AmerenUE
               (incorporated   by  reference  to  Exhibit  10.1  to   Generating
               Company's  quarterly  report on Form 10-Q for the  quarter  ended
               March 31, 2002).

   10.19*      Long-Term  Incentive Plan of 1998  (incorporated  by reference to
               Exhibit 10.1 to Ameren's  annual report on Form 10-K for the year
               ended December 31, 1998).

   10.20*      Change of Control  Severance Plan  (incorporated  by reference to
               Exhibit 10.2 to Ameren's  annual report on Form 10-K for the year
               ended December 31, 1998).

   10.21*      Ameren's  Deferred  Compensation  Plan for  Members of the Ameren
               Leadership Team as amended and restated effective January 1, 2001
               (incorporated  by reference  to Exhibit  10.1 to Ameren's  annual
               report on Form 10-K for the year ended December 31, 2000).

   10.22*      Ameren's  Deferred  Compensation Plan for Members of the Board of
               Directors  (incorporated by reference to Exhibit 10.4 to Ameren's
               annual report on Form 10-K for the year ended December 31, 1998).

   10.23*      Ameren's  Executive  Incentive   Compensation   Program  Elective
               Deferral  Provisions for Members of the Ameren Leadership Team as
               amended and restated  effective January 1, 2001  (incorporated by
               reference to Exhibit 10.2 to Ameren's  annual report on Form 10-K
               for the year ended December 31, 2000).

   12.1**      Statement of Computation of Ratio of Earnings to Fixed Charges.

   99.1**      Certificate of Chief Executive Officer required by Section 906 of
               the Sarbanes-Oxley Act of 2002.

   99.2**      Certificate of Chief Financial Officer required by Section 906 of
               the Sarbanes-Oxley Act of 2002.
---------------------------
        * Management compensatory plan or arrangement.
       ** Filed herewith.

Note:  Reports of Ameren Corporation on Forms 10-K, 10-Q and 8-K are on file
       with the Securities and Exchange Commission (the "SEC") under File No.
       1-14756.

       Reports of Union Electric Company on Forms 10-K, 10-Q and 8-K are on file
       with the SEC under File No. 1-2967.

       Reports of Central Illinois Public Service Company on Forms 10-K, 10-Q
       and 8-K are on file with the SEC under File No. 1-3672.

       Reports of CILCORP Inc. on Forms 10-K, 10-Q, and 8-K are on file with the
       SEC under File No. 1-8946.

       Reports of Central Illinois Light Company on Forms 10-K, 10-Q and 8-K are
       on file with the SEC under File No. 1-2732.

                                       54

<PAGE>


                                   SIGNATURES

     Pursuant  to the  requirements  of  Section  13 or 15(d) of the  Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its  behalf  by  the  undersigned,  thereunto  duly  authorized.

                                              AMEREN  ENERGY GENERATING  COMPANY
                                                         (Registrant)

Date:  March  31,  2003                       By     /s/  DANIEL F. COLE
                                                --------------------------------
                                                          Daniel F. Cole
                                                             President

     Pursuant to the  requirements of the Securities  Exchange Act of 1934, this
report  has  been  signed  below  by the  following  persons  on  behalf  of the
registrant and in the capacities and on the date indicated.

     Signature                     Title                                Date
     ---------                     -----                                ----

/s/ DANIEL F. COLE          President and Director                March 31, 2003
------------------------    (Principal Executive Officer
    Daniel F. Cole

/s/ PAUL A. AGATHEN         Senior Vice President and             March 31, 2003
------------------------    Director
    Paul A. Agathen

/s/ WARNER L. BAXTER        Senior Vice President and             March 31, 2003
------------------------    Director
    Warner L. Baxter        (Principal Financial Officer)

/s/ MARTIN J. LYONS         Vice President and Controller         March 31, 2003
------------------------    (Principal Accounting Officer)
    Martin J. Lyons


                                 CERTIFICATIONS



     I, Daniel F. Cole, certify that:



     1.   I have  reviewed  this  annual  report on Form  10-K of Ameren  Energy
Generating Company;

     2.   Based on my knowledge,  this annual report does not contain any untrue
statement of a material fact or omit to state a material fact  necessary to make
the statements made, in light of the  circumstances  under which such statements
were made,  not  misleading  with  respect to the period  covered by this annual
report;

     3.   Based on my knowledge,  the financial statements,  and other financial
information  included  in this annual  report,  fairly  present in all  material
respects the financial  condition,  results of operations  and cash flows of the
registrant as of, and for, the periods presented in this annual report;

     4.   The registrant's  other  certifying  officer and I are responsible for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

          a)   designed such  disclosure  controls and procedures to ensure that
               material  information  relating to the registrant,  including its
               consolidated  subsidiaries,  is made known to us by others within
               those  entities,  particularly  during  the  period in which this
               annual report is being prepared;

          b)   evaluated  the  effectiveness  of  the  registrant's   disclosure
               controls and  procedures as of a date within 90 days prior to the
               filing date of this annual report (the "Evaluation Date"); and

                                       55

<PAGE>

                           CERTIFICATIONS (CONTINUED)

          c)   presented  in  this  annual  report  our  conclusions  about  the
               effectiveness of the disclosure  controls and procedures based on
               our evaluation as of the Evaluation Date;

     5.   The registrant's other certifying officer and I have disclosed,  based
on our most  recent  evaluation,  to the  registrant's  auditors  and the  audit
committee  of  registrant's  board  of  directors  (or  persons  performing  the
equivalent functions):

              a)  all significant deficiencies in the design or operation of
                  internal controls which could adversely affect the
                  registrant's ability to record, process, summarize and report
                  financial data and have identified for the registrant's
                  auditors any material weaknesses in internal controls; and

              b)  any fraud, whether or not material, that involves management
                  or other employees who have a significant role in the
                  registrant's internal controls; and

         6. The registrant's other certifying officer and I have indicated in
this annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.



Date:  March  31, 2003                        /s/ Daniel F. Cole
                                              ----------------------------------
                                              Daniel F. Cole
                                              Chief Executive Officer



     I, Warner L. Baxter, certify that:



     1.   I have  reviewed  this  annual  report on Form  10-K of Ameren  Energy
Generating Company;

     2.   Based on my knowledge,  this annual report does not contain any untrue
statement of a material fact or omit to state a material fact  necessary to make
the statements made, in light of the  circumstances  under which such statements
were made,  not  misleading  with  respect to the period  covered by this annual
report;

     3.   Based on my knowledge,  the financial statements,  and other financial
information  included  in this annual  report,  fairly  present in all  material
respects the financial  condition,  results of operations  and cash flows of the
registrant as of, and for, the periods presented in this annual report;

     4.   The registrant's  other  certifying  officer and I are responsible for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

          a)   designed such  disclosure  controls and procedures to ensure that
               material  information  relating to the registrant,  including its
               consolidated  subsidiaries,  is made known to us by others within
               those  entities,  particularly  during  the  period in which this
               annual report is being prepared;

          b)   evaluated  the  effectiveness  of  the  registrant's   disclosure
               controls and  procedures as of a date within 90 days prior to the
               filing date of this annual report (the "Evaluation Date"); and

          c)   presented  in  this  annual  report  our  conclusions  about  the
               effectiveness of the disclosure  controls and procedures based on
               our evaluation as of the Evaluation Date;

     5.   The registrant's other certifying officers and I have disclosed, based
on our most  recent  evaluation,  to the  registrant's  auditors  and the  audit
committee  of  registrant's  board  of  directors  (or  persons  performing  the
equivalent functions):

                                       56

<PAGE>


                           CERTIFICATIONS (CONTINUED)

          a)   all  significant  deficiencies  in the  design  or  operation  of
               internal  controls which could adversely  affect the registrant's
               ability to record,  process,  summarize and report financial data
               and have  identified for the  registrant's  auditors any material
               weaknesses in internal controls; and

          b)   any fraud,  whether or not material,  that involves management or
               other employees who have a significant  role in the  registrant's
               internal controls; and

     6.   The registrant's other certifying officer and I have indicated in this
annual report whether there were significant  changes in internal controls or in
other factors that could  significantly  affect internal controls  subsequent to
the date of our most recent  evaluation,  including any corrective  actions with
regard to significant deficiencies and material weaknesses.



Date:  March  31, 2003                        /s/ Warner L. Baxter
                                              ----------------------------------
                                              Warner L. Baxter
                                              Chief Financial Officer








                                       57

<PAGE>

                                 EXHIBIT INDEX
  Exhibit
  Number                                  Description
  -------                                 -----------

    3.1        Articles of  Incorporation  of  AmerenEnergy  Generating  Company
               (Generating  Company),  filed  March  2,  2000  (incorporated  by
               reference  to Exhibit 3.1 to  Generating  Company's  Registration
               Statement on Form S-4 (Commission File No. 333-56594)).

    3.2        Amendment to Articles of  Incorporation  of  Generating  Company,
               filed April 19, 2000 (incorporated by reference to Exhibit 3.2 to
               Generating   Company's   Registration   Statement   on  Form  S-4
               (Commission File No. 333-56594)).

    3.3**      By-laws of Generating  Company (as amended  effective January 21,
               2003).

    4.1        Indenture  dated  as of  November  1,  2000,  between  Generating
               Company and The Bank of New York, as Trustee,  relating to senior
               notes  (Indenture)  (incorporated  by reference to Exhibit 4.1 to
               Generating   Company's   Registration   Statement   on  Form  S-4
               (Commission File No. 333-56594)).

    4.2        First  Supplemental  Indenture  to  the  Indenture,  dated  as of
               November  1,  2000  (including  as  exhibit  the  form of  Notes)
               (incorporated by reference to Exhibit 4.2 to Generating Company's
               Registration   Statement  on  Form  S-4   (Commission   File  No.
               333-56594)).

    4.3        Form of Second Supplemental Indenture to the Indenture,  dated as
               of June 12, 2001 (including as exhibit the form of Exchange Note)
               (incorporated by reference to Exhibit 4.3 to Generating Company's
               Registration   Statement  on  Form  S-4   (Commission   File  No.
               333-56594)).

    4.4        Third Supplemental  Indenture to the Indenture,  dated as of June
               1, 2002 (including as exhibit the form of Note)  (incorporated by
               reference to Exhibit 4.1 to Generating Company's quarterly report
               on Form 10-Q for the quarter ended June 30, 2002).

    4.5**      Fourth  Supplemental  Indenture  to the  Indenture,  dated  as of
               January  15,  2003  (including  as exhibit  the form of  Exchange
               Note).

   10.1        Asset Transfer  Agreement between  Generating Company and Central
               Illinois  Public Service  Company d/b/a  AmerenCIPS  (AmerenCIPS)
               (incorporated by reference to Exhibit 10 to AmerenCIPS' quarterly
               report on Form 10-Q for the quarter ended June 30, 2000).

   10.2        Amended  Electric  Power  Supply  Agreement  between   Generating
               Company and AmerenEnergy  Marketing Company  (Marketing  Company)
               (incorporated   by  reference  to  Exhibit  10.2  to   Generating
               Company's Registration Statement on Form S-4 (Commission File No.
               333-56594)).

   10.3        Second Amended Electric Power Supply Agreement between Generating
               Company and  Marketing  Company  (incorporated  by  reference  to
               Exhibit 10.1 to Ameren Corporation's  (Ameren's) quarterly report
               on Form 10-Q for the  quarter  ended  March 31,  2001).

   10.4        Electric Power Supply  Agreement  between  Marketing  Company and
               AmerenCIPS   (incorporated   by  reference  to  Exhibit  10.3  to
               Generating   Company's   Registration   Statement   on  Form  S-4
               (Commission File No. 333-56594)).

   10.5        Amended Electric Power Supply Agreement between Marketing Company
               and  AmerenCIPS  (incorporated  by  reference  to Exhibit 10.2 to
               Ameren's  quarterly  report  on Form 10-Q for the  quarter  ended
               March 31, 2001).

   10.6        Power  Sales  Agreement   between  Marketing  Company  and  Union
               Electric  Company  d/b/a  AmerenUE  (AmerenUE)  (incorporated  by
               reference to Exhibit 10.1 to AmerenUE's  quarterly report on Form
               10-Q for the quarter ended September 30, 2001).

   10.7        Amended  Joint  Dispatch  Agreement  among  Generating   Company,
               AmerenCIPS  and  AmerenUE  (incorporated  by reference to Exhibit
               10.4 to Generating Company's  Registration  Statement on Form S-4
               (Commission File No. 333-56594)).

   10.8        Agency Agreement among Generating  Company,  AmerenUE,  Marketing
               Company and  AmerenEnergy,  Inc.  (incorporated  by  reference to
               Exhibit 10.5 to Generating  Company's  Registration  Statement on
               Form S-4 (Commission File No. 333-56594)).

                                       58

<PAGE>

  Exhibit
  Number                                  Description
  -------                                 -----------

   10.9        General  Services   Agreement  between  Ameren  Services  Company
               (Ameren Services) and AmerenEnergy  Resources Company (Resources)
               (incorporated   by  reference  to  Exhibit  10.6  to   Generating
               Company's Registration Statement on Form S-4 (Commission File No.
               333-56594)).

   10.10       Fuel Services  Agreement between  AmerenEnergy Fuels and Services
               Company and Resources  (incorporated by reference to Exhibit 10.7
               to  Generating  Company's  Registration  Statement  on  Form  S-4
               (Commission File No. 333-56594)).

   10.11       Form of Parallel  Operating  Agreement between Generating Company
               and Ameren Services (incorporated by reference to Exhibit 10.8 to
               Generating   Company's   Registration   Statement   on  Form  S-4
               (Commission File No. 333-56594)).

   10.12       Committed Unit Contribution  Agreement between Generating Company
               and Resources (on behalf of itself and  AmerenEnergy  Development
               Company  (Development  Company)  (incorporated  by  reference  to
               Exhibit 10.9 to Generating  Company's  Registration  Statement on
               Form S-4 (Commission File No. 333-56594)).

   10.13       Lease  Agreement  between   Generating  Company  and  Development
               Company (incorporated by reference to Exhibit 10.10 to Generating
               Company's Registration Statement on Form S-4 (Commission File No.
               333-56594)).

   10.14       Amended and Restated  Appendix I ITC Agreement dated February 14,
               2003  between  the  Midwest   Independent   Transmission   System
               Operator,  Inc.  (Midwest ISO) and GridAmerica LLC  (GridAmerica)
               (incorporated  by reference to Exhibit  10.17 of Ameren's  annual
               report on Form 10-K for the year ended December 31, 2002).

   10.15       Amended and  Restated  Limited  Liability  Company  Agreement  of
               GridAmerica dated February 14, 2003 (incorporated by reference to
               Exhibit 10.18 of Ameren's annual report on Form 10-K for the year
               ended December 31, 2002).

   10.16       Amended and Restated Master  Agreement by and among  GridAmerica,
               GridAmerica  Holdings  Inc.,  GridAmerica  Companies and National
               Grid USA dated  February 14, 2003  (incorporated  by reference to
               Exhibit 10.19 of Ameren's annual report on Form 10-K for the year
               ended December 31, 2002).

   10.17       Amended and Restated  Operation  Agreement by and among AmerenUE,
               AmerenCIPS, American Transmission Systems, Inc., Northern Indiana
               Public Service  Company and  GridAmerica  dated February 14, 2003
               (incorporated  by reference to Exhibit  10.20 of Ameren's  annual
               report on Form 10-K for the year ended December 31, 2002).

   10.18       Power Sales  Agreement  between  Marketing  Company and  AmerenUE
               (incorporated   by  reference  to  Exhibit  10.1  to   Generating
               Company's  quarterly  report on Form 10-Q for the  quarter  ended
               March 31, 2002).

   10.19*      Long-Term  Incentive Plan of 1998  (incorporated  by reference to
               Exhibit 10.1 to Ameren's  annual report on Form 10-K for the year
               ended December 31, 1998).

   10.20*      Change of Control  Severance Plan  (incorporated  by reference to
               Exhibit 10.2 to Ameren's  annual report on Form 10-K for the year
               ended December 31, 1998).

   10.21*      Ameren's  Deferred  Compensation  Plan for  Members of the Ameren
               Leadership Team as amended and restated effective January 1, 2001
               (incorporated  by reference  to Exhibit  10.1 to Ameren's  annual
               report on Form 10-K for the year ended December 31, 2000).

   10.22*      Ameren's  Deferred  Compensation Plan for Members of the Board of
               Directors  (incorporated by reference to Exhibit 10.4 to Ameren's
               annual report on Form 10-K for the year ended December 31, 1998).

               Ameren's  Executive  Incentive   Compensation   Program  Elective
   10.23*      Deferral  Provisions for Members of the Ameren Leadership Team as
               amended and restated  effective January 1, 2001  (incorporated by
               reference to Exhibit 10.2 to Ameren's  annual report on Form 10-K
               for the year ended December 31, 2000).

   12.1**      Statement of Computation of Ratio of Earnings to Fixed Charges.

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<PAGE>

  Exhibit
  Number                                  Description
  -------                                 -----------

   99.1**      Certificate of Chief Executive Officer required by Section 906 of
               the Sarbanes-Oxley Act of 2002.

   99.2**      Certificate of Chief Financial Officer required by Section 906 of
               the Sarbanes-Oxley Act of 2002.
-----------------------
 * Management compensatory plan or arrangement.
** Filed herewith.

Note:  Reports of Ameren Corporation on Forms 10-K, 10-Q and 8-K are on file
       with the Securities and Exchange Commission (the "SEC") under File No.
       1-14756.

       Reports of Union Electric Company on Forms 10-K, 10-Q and 8-K are on file
       with the SEC under File No. 1-2967.

       Reports of Central Illinois Public Service Company on Forms 10-K, 10-Q
       and 8-K are on file with the SEC under File No. 1-3672.

       Reports of CILCORP Inc. on Forms 10-K, 10-Q, and 8-K are on file with the
       SEC under File No. 1-8946.

       Reports of Central Illinois Light Company on Forms 10-K, 10-Q and 8-K are
       on file with the SEC under File No. 1-2732.


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