UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              WASHINGTON, DC 20549


                                    FORM 10-Q

[X]      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
         SECURITIES EXCHANGE ACT OF 1934

         For Quarterly Period Ended March 31, 2003

[  ]     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 1-14756.

                               AMEREN CORPORATION
             (Exact name of registrant as specified in its charter)

                     Missouri                             43-1723446
         (State or other jurisdiction of               (I.R.S. Employer
         incorporation or organization)               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


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

     Shares  outstanding of each of the registrant's  classes of common stock as
of May 9, 2003: Common Stock, $.01 par value - 161,218,664.






                               AMEREN CORPORATION

                                TABLE OF CONTENTS


                                                                                                                            Page
                                                                                                                            ----
       
PART I.       Financial Information

     ITEM 1.  Financial  Statements  (Unaudited)
              Consolidated Balance Sheet at March 31, 2003 and December 31, 2002.......................................       2
              Consolidated  Statement of Income for the three months ended March 31, 2003  and 2002....................       3
              Consolidated Statement of Cash Flows for the three months ended March 31, 2003 and 2002..................       4
              Consolidated Statement of Common Stockholders' Equity for the three months ended March 31, 2003
              and 2002.................................................................................................       5
              Notes to Consolidated Financial Statements...............................................................       6

     ITEM 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations....................      17

     ITEM 3.  Quantitative and Qualitative Disclosures About Market Risk...............................................      29

     ITEM 4.  Controls and Procedures..................................................................................      31

PART II.      Other Information

     ITEM 1.  Legal Proceedings........................................................................................      33

     ITEM 6.  Exhibits and Reports on Form 8-K.........................................................................      33

SIGNATURE..............................................................................................................      35

CERTIFICATIONS.........................................................................................................      35


This Form 10-Q  contains  "forward-looking  statements"  within  the  meaning of
Section 21E of the Securities Exchange Act of 1934.  Forward-looking  statements
should be read with the cautionary  statements and important factors included in
this Form 10-Q at Part I,  Item 2.  "Management's  Discussion  and  Analysis  of
Financial   Condition   and   Results   of   Operations,"   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.






                          PART I. FINANCIAL INFORMATION

ITEM 1.  Financial Statements.

                               AMEREN CORPORATION
                           CONSOLIDATED BALANCE SHEET
               (Unaudited, in millions, except per share amounts)

                                                                                                      
                                                                                                March 31,    December 31,
                                                                                                  2003           2002
                                                                                              -----------    ------------
ASSETS:
Property and plant, net                                                                       $   10,182     $     8,840
Investments and other assets:
   Investments                                                                                       169              38
   Nuclear decommissioning trust fund                                                                172             172
   Goodwill and other intangibles, net                                                               621               -
   Other assets                                                                                      336             307
                                                                                              -----------     -----------
         Total investments and other assets                                                        1,298             517
                                                                                              -----------     -----------
Current assets:
   Cash and cash equivalents                                                                         294             628
   Accounts receivable - trade (less allowance for doubtful
         accounts of $11 and $7, respectively)                                                       360             266
   Unbilled revenue                                                                                  180             176
   Miscellaneous accounts and notes receivable                                                        54              44
   Materials and supplies, at average cost                                                           354             299
   Other current assets                                                                               49              39
                                                                                              -----------     -----------
         Total current assets                                                                      1,291           1,452
                                                                                              -----------     -----------
Regulatory assets                                                                                    818             690
                                                                                              -----------     -----------
Total Assets                                                                                  $   13,589      $   11,499
                                                                                              ===========     ===========

CAPITAL AND LIABILITIES:
Capitalization:
   Common stock, $.01 par value, 400.0 shares authorized -
     shares outstanding of 161.1 and 154.1, respectively                                      $        2      $         2
   Other paid-in capital, principally premium on common stock                                      2,480            2,203
   Retained earnings                                                                               1,738            1,739
   Accumulated other comprehensive income                                                            (96)             (93)
   Other                                                                                             (14)              (9)
                                                                                              -----------     ------------
      Total common stockholders' equity                                                            4,110            3,842
                                                                                              -----------     ------------
   Preferred stock not subject to mandatory redemption                                               235              193
   Long-term debt, net                                                                             4,499            3,433
                                                                                              -----------     ------------
         Total capitalization                                                                      8,844            7,468
                                                                                              -----------     ------------
Minority interest in consolidated subsidiaries                                                        16               15
Current liabilities:
   Current maturities of long-term debt                                                              342              339
   Short-term debt                                                                                    16              271
   Accounts and wages payable                                                                        295              369
   Asset retirement obligation                                                                         4                -
   Accumulated deferred income taxes                                                                   5                5
   Taxes accrued                                                                                     144               45
   Other current liabilities                                                                         251              172
                                                                                              -----------     ------------
         Total current liabilities                                                                 1,057            1,201
                                                                                              -----------     ------------
Accumulated deferred income taxes                                                                  2,000            1,707
Accumulated deferred investment tax credits                                                          159              149
Regulatory liabilities                                                                               129              136
Asset retirement obligation                                                                          396              174
Accrued pension liabilities                                                                          524              377
Other deferred credits and liabilities                                                               464              272
                                                                                              -----------     ------------
Total Capital and Liabilities                                                                 $   13,589      $    11,499
                                                                                              ===========     ============

See Notes to Consolidated Financial Statements.



                                       2





                               AMEREN CORPORATION
                        CONSOLIDATED STATEMENT OF INCOME
               (Unaudited, in millions, except per share amounts)

                                                                       Three Months Ended
                                                                            March 31,
                                                                  ------------------------------
                                                                       2003             2002
                                                                  -------------    -------------
                                                                            
OPERATING REVENUES:
   Electric                                                          $  856           $  747
   Gas                                                                  250              125
   Other                                                                  2                2
                                                                  -------------    -------------
      Total operating revenues                                        1,108              874
                                                                  -------------    -------------

OPERATING EXPENSES:
   Fuel and purchased power                                             221              203
   Gas                                                                  185               85
   Other operations and maintenance                                     299              262
   Depreciation and amortization                                        124              107
   Income taxes                                                          52               38
   Other taxes                                                           78               68
                                                                  -------------    -------------
      Total operating expenses                                          959              763
                                                                  -------------    -------------

OPERATING INCOME                                                        149              111

OTHER INCOME AND (DEDUCTIONS):
   Allowance for equity funds used during construction                    -                2
   Miscellaneous, net -
     Miscellaneous income                                                 6                3
     Miscellaneous expense                                               (3)              (4)
                                                                  -------------    -------------
      Total other income and (deductions)                                 3                1
                                                                  -------------    -------------


INTEREST CHARGES AND PREFERRED DIVIDENDS:
   Interest                                                              68               52
   Allowance for borrowed funds used during construction                 (2)              (2)
   Preferred dividends of subsidiaries                                    3                3
                                                                  -------------    -------------
      Net interest charges and preferred dividends                       69               53
                                                                  -------------    -------------

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
      ACCOUNTING PRINCIPLE                                               83               59

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
      PRINCIPLE, NET OF INCOME TAXES                                     18                -
                                                                  -------------    -------------

NET INCOME                                                           $  101           $   59
                                                                  =============    =============

EARNINGS PER COMMON SHARE - BASIC AND DILUTED:
    Income before cumulative effect of change
         in accounting principle                                     $ 0.52           $ 0.42
    Cumulative effect of change in accounting
         principle, net of income taxes                                0.11                   -
                                                                  -------------    -------------
    Net income                                                       $ 0.63           $ 0.42
                                                                  =============    =============

AVERAGE COMMON SHARES OUTSTANDING                                     158.9            139.7

See Notes to Consolidated Financial Statements.



                                      3





                               AMEREN CORPORATION
                      CONSOLIDATED STATEMENT OF CASH FLOWS
                            (Unaudited, in millions)

                                                                                          Three Months Ended
                                                                                                 March 31,
                                                                                         ---------------------------
                                                                                            2003            2002
                                                                                         -----------     -----------

                                                                                                   
Cash Flows From Operating:
   Net income                                                                              $  101           $  59
   Adjustments to reconcile net income to net cash
       provided by operating activities:
         Cumulative effect of change in accounting principle                                  (18)              -
         Depreciation and amortization                                                        124             107
         Amortization of nuclear fuel                                                           7               7
         Amortization of debt issuance costs and premium/discounts                              2               2
         Allowance for funds used during construction                                          (2)             (4)
         Deferred income taxes, net                                                             3              (3)
         Deferred investment tax credits, net                                                  (3)             (2)
         Other                                                                                 (7)            (11)
         Changes in assets and liabilities, excluding the effects of the acquisitions:
               Receivables, net                                                                13              26
               Materials and supplies                                                          44              37
               Accounts and wages payable                                                    (186)           (218)
               Taxes accrued                                                                   68              69
               Assets, other                                                                    7             (17)
               Liabilities, other                                                              73              58
                                                                                         -----------     -----------
Net cash provided by operating activities                                                     226             110
                                                                                         -----------     -----------

Cash Flows From Investing:
   Construction expenditures                                                                 (144)           (159)
   Acquisitions, net of cash acquired                                                        (488)              -
   Allowance for funds used during construction                                                 2               4
   Nuclear fuel expenditures                                                                    -              (5)
   Other                                                                                        1               -
                                                                                         -----------     -----------
Net cash used in investing activities                                                        (629)            (160)
                                                                                         -----------     -----------

Cash Flows From Financing:
   Dividends on common stock                                                                 (102)             (91)
   Capital issuance costs                                                                     (10)             (20)
   Redemptions:
      Nuclear fuel lease                                                                       (2)
      Short-term debt                                                                        (255)            (536)
      Long-term debt                                                                          (31)              (4)
   Issuances:
      Common stock                                                                            285              246
      Nuclear fuel lease                                                                        -                3
      Long-term debt                                                                          184              445
                                                                                         -----------     -----------
Net cash provided by financing activities                                                      69               43
                                                                                         -----------     -----------

Net change in cash and cash equivalents                                                      (334)              (7)
Cash and cash equivalents at beginning of year                                                628               67
                                                                                         -----------     -----------
Cash and cash equivalents at end of period                                                 $  294            $  60
                                                                                         ===========     ===========

Cash paid during the periods:
   Interest                                                                                $   45            $  27
   Income taxes, net                                                                           11                4

See Notes to Consolidated Financial Statements.



                                       4





                               AMEREN CORPORATION
              CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY
                            (Unaudited, in millions)


                                                                                  Three Months Ended
                                                                                      March 31,
                                                                           ------------------------------
                                                                                2003             2002
                                                                           ------------     -------------
                                                                                      
Common stock
   Beginning balance                                                         $     2           $     1
   Shares issued                                                                   -                 -
                                                                           ------------     -------------
                                                                                   2                 1
                                                                           ------------     -------------

Other paid-in capital
   Beginning balance                                                           2,203             1,614
   Shares issued (less issuance costs of $8 and $9, respectively)                277               237
   Contracted stock purchase payment obligations                                   -               (46)
   Employee stock awards                                                           -                (1)
                                                                           ------------     -------------
                                                                               2,480             1,804
                                                                           ------------     -------------

Retained earnings
   Beginning balance                                                           1,739             1,733
   Net income                                                                    101                59
   Dividends                                                                    (102)              (91)
                                                                           ------------     -------------
                                                                               1,738             1,701
                                                                           ------------     -------------

Accumulated other comprehensive income
   Beginning balance - derivative financial instruments                            9                 5
   Change in derivative financial instruments in current period                   (3)               (5)
                                                                           ------------     -------------
                                                                                   6                 -
                                                                           ------------     -------------
   Beginning balance - minimum pension liability                                (102)                -
   Change in minimum pension liability in current period                           -                 -
                                                                           ------------     -------------
                                                                                (102)                -
                                                                           ------------     -------------

                                                                                 (96)                -
                                                                           ------------     -------------

Other
   Beginning balance                                                              (9)               (4)
   Restricted stock compensation awards                                           (5)               (7)
   Compensation amortized and mark-to-market adjustments                           -                 1
                                                                           ------------     -------------
                                                                                 (14)              (10)
                                                                           ------------     -------------

Total common stockholders' equity                                            $ 4,110           $ 3,496
                                                                           ============     =============


Comprehensive income, net of taxes
   Net income                                                                $   101           $    59
   Unrealized net gain/(loss) on derivative hedging instruments,
        net of income taxes of $- and $-, respectively                            (1)               (1)
   Reclassification adjustments for gains/(losses) included in net income,
        net of income taxes of $(1) and $(2), respectively                        (2)               (4)
                                                                           ------------     -------------
           Total comprehensive income, net of taxes                          $    98           $    54
                                                                           ============     =============


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

Common stock shares at beginning of period                                     154.1             138.0
   Shares issued                                                                 7.0               6.2
                                                                           ------------     -------------
Common stock shares at end of period                                           161.1             144.2
                                                                          ============      =============


See Notes to Consolidated Financial Statements.



                                       5



AMEREN CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
March 31, 2003

NOTE 1 - Summary of Significant Accounting Policies

General

     Ameren  Corporation is a public utility holding company registered with the
Securities  and  Exchange  Commission  (SEC)  under the Public  Utility  Holding
Company Act of 1935 (PUHCA) and is  headquartered  in St. Louis,  Missouri.  Our
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.  Our  primary
subsidiaries 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    Central  Illinois Public Service  Company,  which operates a rate-regulated
     electric and natural gas transmission and distribution business in Illinois
     as AmerenCIPS.
o    Central  Illinois  Light Company,  a subsidiary of CILCORP Inc.  (CILCORP),
     which operates a  rate-regulated  electric  transmission  and  distribution
     business, an electric generation business, and a rate-regulated natural gas
     distribution  business  in  Illinois  as  AmerenCILCO.   We  completed  our
     acquisition of CILCORP on January 31, 2003.  See Note 2 - Acquisitions  for
     further information.
o    AmerenEnergy  Resources Company (Resources Company),  which consists of non
     rate-regulated  operations.  Subsidiaries include  AmerenEnergy  Generating
     Company (Generating Company) which operates our non rate-regulated electric
     generation  in  Missouri  and  Illinois,   AmerenEnergy  Marketing  Company
     (Marketing  Company),  which  markets  power  for  periods  over one  year,
     AmerenEnergy  Fuels and Services  Company,  which procures fuel and manages
     the related  risks for our  affiliated  companies and  AmerenEnergy  Medina
     Valley Cogen (No. 4), LLC, which  indirectly owns a 40 megawatt,  gas-fired
     electric   generation   plant.  On  February  4,  2003,  we  completed  our
     acquisition  of AES  Medina  Valley  Cogen  (No.  4),  LLC and  renamed  it
     AmerenEnergy  Medina  Valley Cogen (No. 4), LLC. See Note 2 -  Acquisitions
     for further information.
o    AmerenEnergy,  Inc.  (AmerenEnergy),  which serves as a power marketing and
     risk  management  agent for our affiliated  companies for  transactions  of
     primarily less than one year.
o    Electric  Energy,  Inc.  (EEI),  which  operates  electric  generation  and
     transmission  facilities in Illinois.  We have a 60% ownership  interest in
     EEI and consolidate it for financial reporting purposes.
o    Ameren Services  Company,  which provides shared support services to Ameren
     Corporation and its subsidiaries.

     When we  refer  to  Ameren,  our,  we or us,  we are  referring  to  Ameren
Corporation  and  its   subsidiaries   on  a  consolidated   basis.  In  certain
circumstances,   our  subsidiaries  are  specifically  referenced  in  order  to
distinguish among their different business activities.

     The  consolidated  financial  statements  include  the  accounts  of Ameren
Corporation  and  its  majority-owned  subsidiaries.   Results  of  CILCORP  and
AmerenCILCO  include  the period from the  acquisition  date of January 31, 2003
through March 31, 2003 and certain pro-forma financial information. See Note 2 -
Acquisitions for further information.  All significant intercompany transactions
have been  eliminated.  All  tabular  dollar  amounts  are in  millions,  unless
otherwise indicated.

     The accounting  policies of Ameren 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 interim results. These statements should
be read in  conjunction  with the  financial  statements  and the notes  thereto
included in Ameren's and CILCORP and  AmerenCILCO's  2002 Annual Reports on Form
10-K.

                                       6



     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 2003 reporting.

Earnings Per Share

     There was no  difference  between the basic and diluted  earnings per share
amounts  for the  three-month  periods  ended  March  31,  2003  and  2002.  The
reconciling  item in each of the periods was  comprised of assumed  stock option
conversions,  which  increased the number of shares  outstanding  in the diluted
earnings  per share  calculation  by 239,883  shares for the three  months ended
March 31, 2003  compared to 351,794  shares for the three months ended March 31,
2002.

Accounting Changes and Other Matters

Statement of Financial  Accounting  Standards  (SFAS) No. 143 - "Accounting  for
Asset Retirement Obligations"

     We adopted the provisions of SFAS 143 on January 1, 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 on January 1, 2003, we recognized additional
asset retirement obligations of approximately $216 million and a net increase in
net property and plant of  approximately  $110 million related  primarily to the
Callaway  nuclear  decommissioning  costs  and  retirement  costs  for  a  river
structure and a power plant ash pond. The  difference  between the net asset and
the  liability  recorded  upon  adoption of SFAS 143  related to  rate-regulated
assets was recorded as an  additional  regulatory  asset of  approximately  $136
million  because we expect to continue to recover in electric  rates the cost of
Callaway  nuclear  decommissioning  and  other  costs of  removal.  These  asset
retirement  obligations  and  associated  assets are in  addition  to assets and
liabilities  of $174  million  we  previously  recorded  related  to our  future
obligations and funds accumulated to decommission the Callaway nuclear plant. In
addition,  we  recognized  a net  after-tax  gain upon  adoption  of $18 million
resulting from a gain upon elimination of non-legal  obligation costs of removal
for non rate-regulated assets from accumulated  depreciation ($20 million) and a
loss for the  difference  between  the net asset and  liability  for  retirement
obligations to be recorded upon adoption  related to non  rate-regulated  assets
($2 million).

     During  the  first  quarter  of fiscal  year  2003,  our  asset  retirement
obligations also increased as we assumed CILCORP's asset retirement  obligations
of  approximately  $6  million  related  to ash  ponds  in  connection  with our
acquisition of CILCORP on January 31, 2003.  Asset  retirement  obligations also
increased due to accretion of $4 million recorded during the quarter ended March
31, 2003.

     In addition  to those  obligations  that were  identified  and  valued,  we
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.

                                       7



     SFAS 143 required a change in the depreciation  methodology we historically
utilized  for  our  non-regulated  operations.   Historically,  we  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 required
us to  exclude  costs  of  dismantling  and  removal  upon  retirement  from the
depreciation rates applied to non  rate-regulated  plant balances.  Further,  we
were required to remove accumulated provisions for dismantling and removal costs
from  accumulated  depreciation,  where they were  embedded,  and  reflect  such
adjustment  as a gain  upon  adoption  of  this  standard,  to the  extent  such
dismantling  and removal  activities are not considered  legal asset  retirement
obligations  as defined by SFAS 143.  The  elimination  of cost of removal  from
accumulated depreciation resulted in a gain, as noted above, of $20 million, net
of taxes,  for a change in  accounting  principle.  Beginning  in January  2003,
depreciation  rates for non  rate-regulated  assets were  reduced to reflect the
discontinuation  of the accrual of dismantling  and removal costs.  In addition,
non  rate-regulated  asset  removal  costs will  prospectively  be  expensed  as
incurred.  As a result, 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.

     Like  our  non  rate-regulated  operations,  the  depreciation  methodology
historically utilized by our rate-regulated operations has included an estimated
cost of  dismantling  and removing plant from service upon  retirement.  Because
these  estimated costs of removal have been included in the cost of service upon
which our present utility rates are based,  and with the  expectation  that this
practice will  continue in the  jurisdictions  in which we operate,  adoption of
SFAS 143 did not result in any change in the depreciation  accounting  practices
of our  rate  regulated  operations.  We have  estimated  future  removal  costs
embedded in accumulated depreciation related to rate-regulated plant assets were
approximately $660 million at March 31, 2003.

Emerging Issues Task Force (EITF) Issue No. 02-3 and EITF Issue No. 98-10

     In the quarters ended  September 30, 2002 and December 31, 2002, we adopted
the  provisions  of EITF 02-3,  "Issues  Involved in Accounting  for  Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management  Activities,"  that requires  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 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 Other and in Operating  Expenses - Fuel and  Purchased  Power and
Other Operations and Maintenance. 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 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 No. 133  ("Accounting
for  Derivative   Instruments  and  Hedging   Activities")  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
stockholders'  equity.  The  operating  revenues  and costs netted for the three
months ended March 31, 2002 were $241  million,  which reduced  interchange  and
other  revenues  and  purchased  power and  other  costs by equal  amounts.  The
adoption of EITF 02-3, the 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.

SFAS No.  148 -  "Accounting  for  Stock-Based  Compensation  -  Transition  and
Disclosure"

     In December  2002,  the FASB issued SFAS 148. SFAS 148 amends SFAS No. 123,
"Accounting for Stock-Based  Compensation,"  to provide  alternative  methods of
transition for an entity that voluntarily

                                       8



changes to the fair value based method of accounting  for  stock-based  employee
compensation.  It also amends the  disclosure  provisions to require  disclosure
about the  effects  on  reported  net  income of an entity's  accounting  policy
decisions with respect to stock-based employee  compensation.  Prior to 2003, we
accounted for our stock options granted under long-term incentive plan under the
recognition  and measurement  provisions of APB Opinion No. 25,  "Accounting for
Stock  Issued to  Employees."  No  stock-based  employee  compensation  cost was
reflected for options in 2002,  2001, and 2000 as all options  granted under our
plan had an exercise  price equal to the market value of the  underlying  common
stock on the date of grant.  The pretax  effect of  weighted-average  grant-date
fair value of options granted would have been  approximately  $2 million in each
of the years ended 2002, 2001, and 2000 had the fair value method under SFAS 123
been used for  options.  Effective  January 1, 2003,  we adopted  the fair value
recognition  provisions of SFAS 123 by using the prospective  method of adoption
under SFAS 148.  Because no stock  options  have been granted  since  January 1,
2003,  SFAS 148 did not have any effect on our  financial  position,  results of
operations or liquidity in the first quarter of 2003.

FASB  Interpretation  No.  (FIN) 45 -  "Guarantor's  Accounting  and  Disclosure
Requirements for Guarantees,  Including  Indirect  Guarantees of Indebtedness of
Others"

     FIN 45 was issued in  November  2002 and  requires  that upon  issuance  of
certain guarantees, a guarantor must recognize a liability for the fair value of
the obligation assumed under the guarantee.  These recognition provisions of FIN
45 are to be applied on a  prospective  basis to  guarantees  issued or modified
after December 31, 2002, irrespective of the guarantor's fiscal year-end. FIN 45
also requires  additional  disclosures  by a guarantor in its interim and annual
financial  statements for periods ending after December 15, 2002.  Because we do
not have such obligations, the recognition provisions of FIN 45 did not have any
effect on our  financial  position,  results of  operations  or liquidity in the
first quarter of 2003.

SFAS No. 149 - "Amendment of Statement 133 on Derivative Instruments and Hedging
Activities"

     In  April  2003,  SFAS  149 was  issued.  SFAS  149  clarifies  under  what
circumstances a contract with initial net investment meets the characteristic of
a derivative as discussed in SFAS 133,  "Accounting  for Derivative  Instruments
and  Hedging  Activities."  SFAS  149 is  effective  for  hedging  relationships
designated  and contracts  entered into or modified after June 30, 2003. At this
time, we are assessing the impact of SFAS 149 on our financial position, results
of operations and liquidity upon adoption.

Revenue

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

     Interchange  revenues  included in Operating  Revenues - Electric were $114
million for the three months ended March 31, 2003 (2002 - $81 million).

Purchased Power

     Purchased  power included in Operating  Expenses - Fuel and Purchased Power
was $45 million for the three months ended March 31, 2003 (2002 - $52 million).

Excise Taxes

     Excise taxes on Missouri  electric and gas, and Illinois gas customer bills
are imposed on us and are recorded gross in Operating  Revenues and Other Taxes.
Excise taxes recorded in Operating Revenues and Other Taxes for the three months
ended  March  31,  2003 were $31  million  (2002-  $26  million).  Excise  taxes
applicable to Illinois  electric  customer bills are imposed on the consumer and
are recorded as tax  collections  payable and  included in Taxes  Accrued on the
Consolidated Balance Sheet.

                                       9


Goodwill

     Goodwill is the excess of the  purchase  price of an  acquisition  over the
fair value of the net assets  acquired.  We do not amortize  goodwill  under the
provisions  of SFAS  142,  "Goodwill  and  Other  Intangible  Assets."  SFAS 142
requires the  evaluation of goodwill for  impairment  at least  annually or more
frequently  if  events  and  circumstances  indicate  that  the  asset  might be
impaired.


NOTE 2 - Acquisitions

     On January 31, 2003, we completed our acquisition of all of the outstanding
common stock of CILCORP from The AES Corporation.  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, we also
completed  our  acquisition  of AES Medina  Valley  Cogen (No.  4), LLC  (Medina
Valley)  which  indirectly  owns a 40 megawatt,  gas-fired  electric  generation
plant.  With the  acquisition,  Medina Valley,  which we renamed as AmerenEnergy
Medina Valley Cogen (No. 4), LLC, became a wholly-owned  subsidiary of Resources
Company.  The results of operations for CILCORP and  AmerenEnergy  Medina Valley
Cogen (No.  4),  LLC were  included  in our  consolidated  financial  statements
effective with the January and February 2003 acquisition dates.

     We acquired  CILCORP to complement  our existing  Illinois gas and electric
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 our service  territory.
CILCO  also  has  a non  rate-regulated  electric  and  gas  marketing  business
principally  focused in the  Chicago,  Illinois  region.  Finally,  the purchase
included   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
$895  million  and  consideration  of $488  million  in cash  including  related
acquisition  costs,  net of cash  acquired.  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 its  issuance in early 2003 of an  additional  6.325  million
common shares which together generated aggregate net proceeds of $575 million.

     The following unaudited pro forma financial  information presents a summary
of our combined  results of operations  assuming the acquisitions of CILCORP and
Medina Valley had been  completed at the beginning of fiscal year 2002 including
pro forma adjustments,  which are based upon preliminary  estimates,  to reflect
the allocation of the purchase  price to the acquired net assets.  We are in the
process of completing a third party valuation of acquired property and plant and
intangible assets. Therefore, the allocation of the purchase price is subject to
refinement.  The excess of the purchase price over tangible net assets  acquired
has been allocated preliminarily to goodwill in the amount of $591 million.

================================================================================
                                                        Pro Forma Three Months
--------------------------------------------------------------------------------
                                                            2003          2002
Operating revenues                                      $  1,208      $  1,071

Income before cumulative effect of
  change in accounting principle                              87            62
Cumulative effect of change in accounting
  principle net of taxes                                      22             -
--------------------------------------------------------------------------------
Net income                                              $    109      $     62

Earnings per share    -basic                            $   0.67      $   0.40
                      -diluted                              0.67          0.40
--------------------------------------------------------------------------------

                                       10



     This pro forma information is not necessarily  indicative of the results of
operations  as they would have been had the  transactions  been  effected on the
assumed date, nor is it an indication of trends in future results.


NOTE 3 - Rate and Regulatory Matters

Intercompany Transfer of Electric Generating Facilities

     As a part of the  settlement  of the Missouri  electric  rate case in 2002,
AmerenUE committed to making certain infrastructure  investments from January 1,
2002  through June 30, 2006.  The  requirements  are expected to be satisfied in
part by the proposed transfer at net book value to AmerenUE of approximately 550
megawatts (approximately $260 million) of combustion turbine generating units at
Pinckneyville and Kinmundy,  Illinois from Generating Company,  which is subject
to receipt of necessary  regulatory  approvals.  Approval by the Missouri Public
Service  Commission (MoPSC) is not required in order for this transfer to occur.
However,  the MoPSC has jurisdiction over AmerenUE's ability to recover the cost
of the  transferred  generating  facilities  from its electric  customers in its
rates.  As a part of the settlement of the Missouri  electric rate case in 2002,
AmerenUE is subject to a rate  moratorium  providing  for no changes in electric
rates before June 30, 2006, subject to certain statutory and other exceptions.

     In February  2003, we sought  approval from the Federal  Energy  Regulatory
Commission (FERC) and the Illinois Commerce Commission (ICC) to transfer the 550
megawatts of  generating  assets from  Generating  Company to AmerenUE.  Several
independent  power producers have objected to Ameren's request to the FERC based
on a claim that the transfer may harm competition for the sale of electricity at
wholesale.  In April  2003,  NRG Energy Inc.  (NRG) and some of its  affiliates,
filed  testimony  contending  that NRG's 640  megawatt  generating  facility  at
Vandalia,  Missouri,  known as the Audrain  Facility,  was a better resource for
AmerenUE to acquire as compared to the  Kinmundy  and  Pinckneyville  combustion
turbine generating units.

     In  addition,  in April 2003,  in the ICC  proceeding,  the ICC Staff filed
testimony  which  expressed  concerns about the transfer as to whether it is the
least cost resource for AmerenUE and  recommended  that the ICC deny approval of
the transfer.  AmerenUE will have an opportunity to file testimony responding to
the recommendations of the ICC Staff and NRG.

     On May 5, 2003, the FERC issued an order which set for  hearing  the effect
of the proposed transfer on competition in wholesale  electric markets.  We will
have an opportunity to file testimony addressing this issue at the hearing to be
scheduled.  We can not predict  the ultimate outcome of these proceedings or the
timing of the decisions of the FERC and the ICC.

Affiliate Rules

     On April 22, 2003, the Missouri  Supreme Court issued an opinion  upholding
the adoption of  affiliate  rules by the MoPSC for  Missouri's  gas and electric
utilities.  AmerenUE had objected to the Missouri  asymmetric pricing provisions
contained in the rules.  These provisions require that the utility pay the lower
of cost or market when it is receiving  services from an  affiliate,  and charge
the higher of cost or market when it is providing  services to an affiliate.  In
general,  the rules are intended to prevent regulated utilities from subsidizing
their affiliates' non rate-regulated operations. As a registered holding company
under the PUHCA,  Ameren and its  affiliates  are already  subject to  extensive
regulation  designed  to prevent  cross-subsidization.  The  asymmetric  pricing
provisions  of the MoPSC  affiliate  rules  are  expected  to impose  additional
administrative  burdens  on  AmerenUE.  In May  2003,  AmerenUE  filed  with the
Missouri  Supreme  Court a motion  for  reconsideration  of its April  22,  2003
opinion. We do not expect that the rules would have a material adverse impact on
our future financial position,  cash flows or results of operations in the event
that AmerenUE's motion is denied.

                                       11



Regional Transmission Organization

     Since April 2002,  AmerenCIPS and AmerenUE and  subsidiaries of FirstEnergy
Corporation  and NiSource Inc.  (collectively  the  GridAmerica  Companies) have
participated in a number of filings at the FERC in an effort to form GridAmerica
LLC as an independent transmission company (ITC). On December 19, 2002, the FERC
issued  an  order  conditionally   approving  the  formation  and  operation  of
GridAmerica as an ITC within the Midwest  Independent  System Operator  (Midwest
ISO), subject to further compliance filings.

     In response to the December 19, 2002 order, the GridAmerica  Companies made
three  additional  filings at the FERC.  On  January  31,  2003 the  GridAmerica
Companies filed a request for  authorization to transfer  functional  control of
certain   transmission  assets  to  GridAmerica.   On  February  18,  2003,  the
GridAmerica  Companies  filed  revised  agreements  codifying  the formation and
operation  of  GridAmerica  to  reflect  changes  requested  by the  FERC in the
December  19, 2002 order.  On  February  28,  2003,  the  GridAmerica  Companies
together  with the  Midwest ISO filed  revisions  to the Midwest ISO Open Access
Transmission  Tariff (OATT) to provide  rates for service over the  transmission
facilities to be transferred to GridAmerica by the GridAmerica Companies.

     On April 30 2003,  the FERC  issued  orders in  response to the January 31,
2003 and February  28, 2003  filings.  In its order  regarding  the  GridAmerica
Companies' request to transfer  functional control of their transmission  assets
to GridAmerica,  the FERC  authorized the transfer.  In response to the February
28,  2003  filing,  the FERC  accepted  the  amendments  to the Midwest ISO OATT
effective upon the  commencement  of service over the  GridAmerica  transmission
facilities  under the  Midwest  ISO OATT,  suspended  the  proposed  rates for a
nominal period,  subject to refund, and established hearing and settlement judge
procedures  to determine  the justness and  reasonableness  of the proposed rate
amendments  to the Midwest ISO OATT.  An order in response to the  February  18,
2003 filing is still pending.

     Until the tariffs and other material  terms of  AmerenCIPS'  and AmerenUE'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 regional transmission  organization  developments will have on our
financial position, results of operations or liquidity. AmerenUE's participation
in GridAmerica is subject to MoPSC approval. An order from the MoPSC is expected
during 2003.

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 concern with the potential
impact of the proposed  rules in their current form on the cost and  reliability
of service to retail customers.  We 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. We filed additional
comments on the remaining sections of the NOPR during the first quarter of 2003.

     On April  28,  2003 the FERC  issued a "white  paper"  reflecting  comments
received in response to the NOPR. More  specifically,  the white paper indicated
that the FERC will not assert  jurisdiction over the transmission rate component
of bundled retail service and will insure that existing bundled retail customers
retain  their  existing  transmission  rights and retain  rights for future load
growth in its final rule. Moreover,  the white paper acknowledged that the final
rule will  provide  the states  with input on  resource  adequacy  requirements,
allocation of firm transmission rights, and transmission planning. The FERC also
requested   input  on  the   flexibility   and   timing  of  the  final   rule's
implementation.

                                       12



     Even though issuance of the final rule and its implementation  schedule are
still  unknown,  the  Midwest ISO is already in the  process of  implementing  a
market design similar to the proposed market design in the NOPR. The Midwest ISO
has  targeted  March  2004 as the start date for  implementation.  We are in the
process of reviewing the FERC's white paper. 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.

Illinois Gas

     In November 2002,  AmerenCIPS,  AmerenUE, and CILCO filed requests with the
ICC to  increase  annual  rates for natural  gas  service by  approximately  $16
million,  $4 million and $14 million,  respectively.   The ICC has until October
2003 to render a decision  in the  AmerenCIPS,  AmerenUE  and CILCORP gas cases;
however,  the ICC Staff has recommended the annual increase to be $8 million, $2
million and $9 million, respectively.

Missouri Gas

     In May 2003,  AmerenUE expects to file a request with the MoPSC to increase
annual rates for natural gas service.


NOTE 4 - Derivative Financial Instruments

     As of March 31, 2003,  we recorded the fair value of  derivative  financial
instrument  assets  of $11  million  in  Other  Assets  and the  fair  value  of
derivative  financial  instrument  liabilities  of $11 million in Other Deferred
Credits and Liabilities.

Cash Flow Hedges

     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
Accumulated  Other  Comprehensive  Income  (OCI)  due to  transactions  going to
delivery or settlement, was approximately a $1 million loss for the three months
ended March 31, 2003 (2002 - $1 million gain).

     As of March 31,  2003,  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 net gain of approximately $2 million ($1 million, net of taxes).

     As of March 31, 2003, 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 debt that was issued in June 2002.
The swaps cover the first ten years of debt that has a 30-year  maturity and the
gain in OCI is amortized over a ten-year period that began in June 2002.

     We also hold two call options for coal with two suppliers. These options to
purchase  coal  expire  October  2003 and July  2005.  As of March 31,  2003,  a
mark-to-market  gain of  approximately  $6 million  ($4  million,  net of taxes)
associated  with these  options  was  included  in OCI.  The final  value of the
options  will be  recognized  as a reduction in fuel costs as the hedged coal is
burned.

     As of March  31,  2003,  EEI,  CILCORP  and  Medina  Valley  had  losses of
approximately $1 million each included in OCI (less than $1 million each, net of
taxes).

Other Derivatives

     We enter into option transactions to manage our positions in sulfur dioxide
allowances,  coal,  heating oil and electricity.  Most of these transactions are
treated as non-hedge  transactions  under SFAS 133. The

                                       13




net  change in the  market  value of  sulfur  dioxide  options  is  recorded  as
Operating Revenues - Electric, while the net change in the market value of coal,
heating oil and electricity options is recorded as Operating Expenses - Fuel and
Purchased  Power in the income  statement.  The net change in the market  values
ofsulfur  dioxide,  coal,  heating oil and electricity  options was a gain of $1
million  (less than $1 million,  net of taxes) for the three  months ended March
31, 2003 (2002 - gain of $2 million).


NOTE 5 - Property and Plant, Net

     Property and plant, net at March 31, 2003 and December 31, 2002 consisted of the following:
======================================================================================================

------------------------------------------------------------------------------------------------------
                                                                     March 31,         December 31,
                                                                        2003                2002
======================================================================================================
                                                                                
Property and plant, at original cost:
  Electric                                                           $ 15,665            $ 14,495
  Gas                                                                     719                 557
  Other                                                                   189                 145
------------------------------------------------------------------------------------------------------
                                                                       16,573              15,197
     Less accumulated depreciation and amortization                     6,974               6,831
------------------------------------------------------------------------------------------------------
                                                                        9,599               8,366
Construction work in progress:
  Nuclear fuel in process                                                  82                  81
  Other                                                                   501                 393
------------------------------------------------------------------------------------------------------
Property and plant, net                                              $ 10,182            $  8,840
======================================================================================================




NOTE 6 - Debt and Equity Financings

Ameren Corporation

     In August 2002, a shelf registration  statement filed by Ameren Corporation
with the SEC on Form S-3 was declared effective.  This statement  authorized the
offering  from  time  to  time of up to  $1.473  billion  of  various  forms  of
securities  including  long-term debt, and trust preferred and equity securities
to finance ongoing construction and maintenance programs, to redeem, repurchase,
repay, or retire outstanding debt, to finance strategic  investments,  including
our then pending acquisition of CILCORP, and for general corporate purposes.

     In the  first  quarter  of  2003,  Ameren  issued,  pursuant  to the  shelf
registration  statement,  6.325 million shares of its common stock at $40.50 per
share.  We received net proceeds after fees of $248 million,  which were used to
fund the remaining  cash portion of the purchase  price for our  acquisition  of
CILCORP. See Note 2 - Acquisitions for further information.  We may sell all, or
a portion of, the remaining  securities  registered under the shelf registration
statement if warranted by market  conditions and our capital  requirements.  Any
offer  and  sale  will be  made  only  by  means  of a  prospectus  meeting  the
requirements  of the  Securities  Act of 1933  and  the  rules  and  regulations
thereunder.  In 2002 and in the first  quarter of 2003,  $594 million was issued
under the shelf registration  statement. At April 30, 2003, the amount remaining
on the shelf registration statement was approximately $879 million.

     The  purchase of CILCORP on January 31, 2003 and Medina  Valley on February
4, 2003 included the  assumption of CILCORP and Medina Valley debt and preferred
stock at closing of $895 million.  The assumed debt primarily  consisted of $250
million 9.375% first  mortgage bonds due 2029,  $225 million 8.7% first mortgage
bonds due 2009,  $100 million  floating  rate term loan due 2004,  other secured
indebtedness   totaling  $279  million  and  preferred  stock  of  $41  million.
Subsequent to the acquisition  date, the other secured  indebtedness was reduced
by $101 million through  maturities and redemptions funded with a combination of
available cash and short-term intercompany borrowings.

                                       14



     At March 31, 2003, neither Ameren Corporation, nor any of its subsidiaries,
had any off-balance  sheet financing  arrangements,  other than operating leases
entered into in the ordinary course of business.  At this time, we do not expect
to  engage  in  any  significant   off-balance  sheet  financing   arrangements.

     Amortization  of debt  issuance  costs and any premium or discounts for the
three  months  ended  March 31,  2003 of $2  million  (2002 - $2  million)  were
included in interest expense in the income  statement.  Amortization  related to
recording  the fair value of debt  assumed upon the  acquisition  of CILCORP was
less than $1 million for the two months ended March 31, 2003.  The  amortization
was included in interest expense in the income statement.

     At March 31, 2003,  Ameren and its  subsidiaries  were in  compliance  with
their indenture and credit agreement provisions and covenants.

AmerenUE

     In August 2002, a shelf  registration  statement filed by AmerenUE with the
SEC on Form S-3 was declared effective.  This statement  authorized the offering
from time to time of up to $750 million of various  forms of long-term  debt and
trust preferred  securities to refinance  existing debt and preferred stock, and
for general  corporate  purposes,  including the  repayment of  short-term  debt
incurred to finance construction expenditures and other working capital needs.

     In March 2003, AmerenUE issued,  pursuant to the shelf  registration,  $184
million of 5.50% Senior Secured Notes due March 15, 2034.  AmerenUE received net
proceeds after fees of $180 million, which, along with other funds, were used to
redeem $104 million  principal amount of outstanding  8.25% first mortgage bonds
due October 15,  2022,  at a  redemption  price of 103.61% of par,  plus accrued
interest,  in April  2003,  prior to  maturity,  and to  repay  short-term  debt
incurred to pay at maturity $75 million principal amount of 8.33% first mortgage
bonds that were due in December 2002.

     In April 2003, AmerenUE issued,  pursuant to the shelf  registration,  $114
million of 4.75% Senior Secured Notes due April 1, 2015.  AmerenUE  received net
proceeds after fees of $113 million,  which, along with other funds were used to
redeem $85 million  principal  amount of outstanding  8.00% first mortgage bonds
due  December 15, 2022,  at a redemption  price of 103.38% of par,  plus accrued
interest, prior to maturity, and to reduce short-term money pool debt.

     AmerenUE may sell all, or a portion of, the remaining securities registered
under  the  AmerenUE  shelf  registration   statement  if  warranted  by  market
conditions and our capital requirements. Any offer and sale will be made only by
means of a prospectus meeting the requirements of the Securities Act of 1933 and
the rules and regulations thereunder. At April 30, 2003, the amount remaining on
the shelf registration statement was approximately $279 million.

     On April 1, 2003,  AmerenUE  entered into an additional  364-day  committed
credit facility totaling $75 million to be used for general corporate  purposes,
including  support of commercial paper programs.  This facility makes borrowings
available  at various  interest  rates  based on LIBOR,  agreed  rates and other
options.  Ameren and  AmerenCIPS  can access this  facility  through the utility
money pool.

AmerenCIPS

     On April 7, 2003, AmerenCIPS redeemed,  with cash, prior to maturity and at
par our $50 million first mortgage bonds 7.5% Series X due July 1, 2007.

                                       15




NOTE 7 - Miscellaneous, Net

     Miscellaneous, net for the three months ended March 31, 2003 and 2002 consisted of the following:
=======================================================================================================
                                                                          Three Months
-------------------------------------------------------------------------------------------------------
                                                                   2003                  2002
                                                                                 
Miscellaneous income:
   Interest and dividend income                                   $   1                 $   -
   Other                                                              5                     3
-------------------------------------------------------------------------------------------------------
Total miscellaneous income                                        $   6                 $   3
=======================================================================================================

Miscellaneous expense:
   Minority interest in EEI                                       $  (1)                $  (1)
   Donations                                                          -                    (1)
   Other                                                             (2)                   (2)
-------------------------------------------------------------------------------------------------------
Total miscellaneous expense                                       $  (3)                $  (4)
=======================================================================================================




NOTE 8 - Segment Information

     Ameren's  principal  business segment is comprised of the utility operating
companies  that  provide  electric  and gas service in portions of Missouri  and
Illinois. The other reportable segment includes our nonutility subsidiaries,  as
well as our 60% interest in EEI.

     The accounting  policies of the segments are the same as those described in
Note 1 - Summary of  Significant  Accounting  Policies.  Segment  data  includes
intersegment  revenues,  as well as a charge  allocating costs of administrative
support services to each of the operating companies. These costs are accumulated
in a separate subsidiary,  Ameren Services Company,  which provides a variety of
support services to Ameren and its subsidiaries.  We evaluate the performance of
our segments and allocate resources to them, based on revenues, operating income
and net income.


     Segment  information for the three months ended March 31, 2003 and 2002 was as follows:
=======================================================================================================
                                                                                    
                                                        Utility                 Intercompany
                                                       Operations     Other       Revenues       Total
-------------------------------------------------------------------------------------------------------

     Three months ended March 31, 2003:
Revenues                                                $ 1,247       $ 47        $ (186)      $ 1,108
Net income                                                  102         (1)            -           101
-------------------------------------------------------------------------------------------------------

     Three months ended March 31, 2002:
Revenues                                                  $ 995       $ 69        $ (190)       $  874
Net income                                                   58          1             -            59
-------------------------------------------------------------------------------------------------------



     Ameren Services  Company,  which provides shared support services to us and
our  subsidiaries,  allocates  administrative  support  services to each segment
based on various  factors,  such as headcount,  number of  customers,  and total
assets.

                                       16



ITEM 2.  Management's Discussion and Analysis of Financial Condition and Results
         of Operations

OVERVIEW

     Ameren  Corporation is a public utility holding company registered with the
Securities  and  Exchange  Commission  (SEC)  under the Public  Utility  Holding
Company Act of 1935 (PUHCA) and is  headquartered  in St. Louis,  Missouri.  Our
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.  Our  primary
subsidiaries 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    Central  Illinois Public Service  Company,  which operates a rate-regulated
     electric and natural gas transmission and distribution business in Illinois
     as AmerenCIPS.
o    Central  Illinois  Light Company,  a subsidiary of CILCORP Inc.  (CILCORP),
     which operates a  rate-regulated  electric  transmission  and  distribution
     business, an electric generation business, and a rate-regulated natural gas
     distribution  business  in  Illinois  as  AmerenCILCO.   We  completed  our
     acquisition  of CILCORP on January 31, 2003.  See Recent  Developments  for
     further information.
o    AmerenEnergy  Resources Company (Resources Company),  which consists of non
     rate-regulated  operations.  Subsidiaries include  AmerenEnergy  Generating
     Company  (Generating  Company) which operates non  rate-regulated  electric
     generation  in  Missouri  and  Illinois,   AmerenEnergy  Marketing  Company
     (Marketing  Company),  which  markets  power  for  periods  over one  year,
     AmerenEnergy  Fuels and Services  Company,  which procures fuel and manages
     the related  risks for our  affiliated  companies and  AmerenEnergy  Medina
     Valley Cogen (No. 4), LLC which  indirectly  owns a 40 megawatt,  gas-fired
     electric   generation   plant.  On  February  4,  2003,  we  completed  our
     acquisition  of AES  Medina  Valley  Cogen  (No.  4),  LLC 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 our affiliated  companies for  transactions  of
     primarily less than one year.
o    Electric  Energy,  Inc.  (EEI),  which  operates  electric  generation  and
     transmission  facilities in Illinois.  We have a 60% ownership  interest in
     EEI and consolidate it for financial reporting purposes.
o    Ameren Services  Company,  which provides shared support services to Ameren
     Corporation and its subsidiaries.

     You should read the following discussion and analysis in conjunction with:
o    The  financial  statements  and related  notes  included in this  Quarterly
     Report on Form 10-Q.
o    Management's  Discussion and Analysis of Financial Condition and Results of
     Operations that is incorporated by reference from our 2002 Annual Report to
     Shareholders  into our  Annual  Report  on Form 10-K for the  period  ended
     December 31, 2002.
o    The audited financial statements and related notes that are incorporated by
     reference  from our 2002  Annual  Report to  Shareholders  into our  Annual
     Report on Form 10-K for the period ended December 31, 2002.
o    Management's  Discussion and Analysis of Financial Condition and Results of
     Operations in CILCORP and AmerenCILCO's  Annual Report on Form 10-K for the
     period ended December 31, 2002.
o    The  audited  financial   statements  and  related  notes  in  CILCORP  and
     AmerenCILCO's  Annual Report on Form 10-K for the period ended December 31,
     2002.

     When we  refer  to  Ameren,  our,  we or us,  we are  referring  to  Ameren
Corporation  and  its   subsidiaries   on  a  consolidated   basis.  In  certain
circumstances,   our  subsidiaries  are  specifically  referenced  in  order  to
distinguish  among their  different  business  activities.  All  tabular  dollar
amounts are in  millions,  unless  otherwise  indicated.  Results of CILCORP and
AmerenCILCO  include  the period from the  acquisition  date of January 31, 2003
through March 31, 2003.

                                       17



     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.
With approximately 85% of our revenues directly subject to regulation by various
state and federal  agencies,  decisions by regulators can have a material impact
on the price we charge for our services.  We principally  utilize coal,  nuclear
fuel,  natural gas and oil in our operations.  The prices for these  commodities
can fluctuate significantly due to the world economic and political environment,
weather,  production  levels  and many other  factors.  We do not have fuel cost
recovery mechanisms in Missouri or Illinois for our electric utility businesses,
but we do have gas cost  recovery  mechanisms  in each state for our gas utility
businesses. In addition, our electric rates in Missouri and Illinois are largely
set through 2006. 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 transmission and distribution
systems,  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 net income increased to $101 million or 63 cents per share in the first
quarter of 2003 from $59  million or 42 cents per share in the first  quarter of
2002. Net income in the first quarter of 2003 included a net  cumulative  effect
gain of $18  million,  or 11 cents per share,  associated  with the  adoption of
Statement of Financial  Accounting  Standards  (SFAS) No. 143,  "Accounting  for
Asset  Retirement  Obligations."  The net  gain  resulted  principally  from the
elimination  of  non-legal  obligation  costs of removal for non  rate-regulated
assets from accumulated depreciation.

     Excluding the cumulative  effect of change in accounting  principle related
to SFAS 143, net income increased $24 million or 10 cents per share in the first
quarter of 2003  compared to the prior year period.  The increase was  primarily
due to favorable  weather  conditions  in our  pre-CILCORP  acquisition  service
territory (10 cents per share), increased electric margins due to greater use of
low-cost  generating  units to serve  native  customers  (4 cents per share) and
increased   earnings  from  interchange  sales  (16  cents  per  share)  due  to
approximately  90%  higher  power  prices in the energy  markets  than the prior
period. In Ameren's pre-CILCORP acquisition service territory, weather-sensitive
residential  electric  kilowatthour sales increased by 14%,  commercial electric
kilowatthour  sales  increased  by 5% and gas  sales  increased  6% in the first
quarter of 2003 compared to the first quarter of 2002.  Partially offsetting the
benefit  on  net  income  of  weather,   interchange   margins  and   generation
availability  in the first quarter of 2003 was increased  dilution and financing
costs outside of those  incurred in connection  with the CILCORP  acquisition (5
cents per share),  higher employee  benefit costs (5 cents per share) related to
plan  performance  and  increasing  healthcare  costs  and no sales of  emission
credits in 2003 (5 cents per share). In addition,  the impact of the acquisition
of CILCORP and related financings, resulted in a reduction to earnings per share
in the first quarter of 2003 of  approximately  2 cents.  We continue to believe
CILCORP will be  accretive  to earnings in year one as we realize the  synergies
associated with this acquisition and a full year of operations.

     As a holding company, our net income and cash flows are primarily generated
by our principal operating subsidiaries,  AmerenUE, AmerenCILCO,  AmerenCIPS and
Generating  Company.  These  subsidiaries also file quarterly and annual reports
with the SEC. The  contribution by our principal  operating  subsidiaries to net
income for the three months ended March 31, 2003 and 2002 was as follows:

                                       18





=======================================================================================================
                                                                           Three Months
                                                                    2003                  2002
                                                                                  
Primarily rate-regulated operations
      AmerenUE (a)                                                  $ 67                  $ 49
      CILCORP (b)                                                      3                     -
      AmerenCIPS                                                       1                     1
-------------------------------------------------------------------------------------------------------
                                                                    $ 71                  $ 50
-------------------------------------------------------------------------------------------------------

Primarily non rate-regulated operations
      Generating Company (a)(c)                                       39                    13

Other                                                                 (9)                   (4)
-------------------------------------------------------------------------------------------------------
Ameren net income                                                  $ 101                  $ 59
=======================================================================================================


(a)  Includes  earnings from  interchange  sales by  AmerenEnergy  that provided
     approximately  $22 million (2002 - $5 million) of AmerenUE's net income and
     $12 million (2002 - $3 million) of  Generating  Company's net income in the
     first quarter of 2003.
(b)  Most of CILCORP's  electric  generation  business is expected to become non
     rate-regulated  in 2003  with  the  transfer  of  substantially  all of its
     generating assets to a non rate-regulated subsidiary.
(c)  Includes  earnings  from  contracts to supply  power to our  rate-regulated
     AmerenCIPS customers.

Recent Developments

Acquisitions

     On January 31, 2003, we completed our acquisition of all of the outstanding
common stock of CILCORP from The AES Corporation.  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, we also
completed  our  acquisition  of AES Medina  Valley  Cogen (No.  4), LLC  (Medina
Valley)  which  indirectly  owns a 40 megawatt,  gas-fired  electric  generation
plant.  With the  acquisition,  Medina Valley,  which we renamed as AmerenEnergy
Medina Valley Cogen (No. 4), LLC, became a wholly-owned  subsidiary of Resources
Company.  The results of operations for CILCORP and  AmerenEnergy  Medina Valley
Cogen (No.  4),  LLC were  included  in our  consolidated  financial  statements
effective with the January and February 2003 acquisition dates.

     We acquired  CILCORP to complement  our existing  Illinois gas and electric
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 our service  territory.
CILCO  also  has  a non  rate-regulated  electric  and  gas  marketing  business
principally  focused in the  Chicago,  Illinois  region.  Finally,  the purchase
included   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
$895  million  and  consideration  of $488  million  in cash  including  related
acquisition  costs,  net of cash  acquired.  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 its  issuance in early 2003 of an  additional  6.325  million
common shares which together generated aggregate net proceeds of $575 million.

                                       19



Common Stock Offering

     In the first quarter of 2003,  Ameren sold 6.325  million  shares of common
stock at $40.50 per share.  We received net proceeds after fees of $248 million,
which were used to fund a portion of the purchase  price for our  acquisition of
CILCORP and for general corporate purposes.

Debt Issuances

     In March 2003,  AmerenUE  issued $184 million of 5.50% Senior Secured Notes
due March 15, 2034.  AmerenUE  received net proceeds after fees of $180 million,
which, along with other funds, were used to redeem $104 million principal amount
of outstanding  8.25% first mortgage bonds due October 15, 2022, at a redemption
price  of  103.61%  of par,  plus  accrued  interest,  in April  2003,  prior to
maturity,  and to repay  short-term debt incurred to pay at maturity $75 million
principal amount of 8.33% first mortgage bonds due in December 2002.

     In April 2003,  AmerenUE  issued $114 million of 4.75% Senior Secured Notes
due April 1, 2015.  AmerenUE  received net proceeds  after fees of $113 million,
which,  along with other funds were used to redeem $85 million  principal amount
of outstanding 8.00% first mortgage bonds due December 15, 2022, at a redemption
price of 103.38% of par, plus accrued interest, prior to maturity, and to reduce
short-term money pool debt.

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  Corporation'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  Corporation,
AmerenUE and AmerenCIPS and increased the ratings of Generating Company, CILCORP
and  AmerenCILCO.  At the same  time,  Standard  & Poor's  changed  the  outlook
assigned to all of  Ameren's  ratings to stable.  Moody's  also  lowered  Ameren
Corporation'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.



     As of April 30, 2003, selected 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

CILCORP:
     Unsecured debt                                    Baa2                           BBB+

AmerenCILCO:
     Secured debt                                        A2                             A-

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

Generating Company:
     Unsecured debt                                 A3/Baa2                             A-
=======================================================================================================

                                       20



     Any adverse  change in our credit  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)  variation on
electric  margin for the three months  ended March 31, 2003 from the  comparable
period in 2002:
================================================================================
                                                                Three Months
--------------------------------------------------------------------------------
Electric  Revenues:
  CILCORP                                                          $ 80
  Interchange revenues                                               36
  Effect of weather (estimate)                                       28
  Rate reductions                                                   (11)
  Growth and other (estimate)                                       (12)
  EEI                                                               (12)
--------------------------------------------------------------------------------
  Total variation in electric operating revenues                    109
Fuel and Purchased Power:
  Fuel:
    Generation                                                     $(13)
    Price                                                            (1)
    Generation efficiencies and other                                 1
  Purchased power                                                    23
  CILCORP                                                           (35)
  EEI                                                                 7
--------------------------------------------------------------------------------
  Total variation in fuel and purchased power                       (18)
================================================================================
Change in electric margin                                          $ 91
================================================================================


     Electric margin  increased $91 million for the three months ended March 31,
2003  compared to the same period in 2002.  Increases in electric  margin in the
first quarter of 2003 were primarily attributable to the acquisition of CILCORP,
increased  interchange  margins and higher native load customer demand resulting
from colder winter weather.  CILCORP's  electric margin for the two month period
ended March 31, 2003 was  approximately  $45 million.  Residential  kilowatthour
sales increased 22% and commercial kilowatthour sales increased 14% in the first
quarter of 2003.  Industrial sales were also up approximately 24% in the quarter
compared to the same period in 2002 due  primarily  to the  addition of CILCORP.
Excluding CILCORP, industrial sales decreased in the first quarter of 2003 by 4%
due to the continued soft economy. Interchange margins increased due to improved
power prices in the energy markets and solid low-cost  generation  availability.
Average power prices  increased from  approximately  $22 per megawatthour in the
first quarter of 2002 to approximately $42 per megawatthour in the first quarter
of 2003. EEI sales decreased compared to the prior period due to decreased sales
to its  principal  customer,  which  also  resulted  in a  decrease  in fuel and
purchased  power.  No sales of emission  credits at AmerenUE in 2003 (2002 - $13
million) and rate reductions in Missouri relating to a 2002 rate settlement ($11
million)  negatively  impacted  electric  revenues in the first quarter of 2003.
Revenues  will  continue  to be  negatively  affected by the  settlement  of the
Missouri  electric  rate case,  which  requires  the  phase-in of $30 million of
electric rate reductions effective April 1, 2003 and $30 million effective April
1,  2004.  Fuel and  purchased  power  increased  in the first  quarter  of 2003
compared  to the  prior  period  due to  increased  kilowatthour  sales  related
primarily to the addition of CILCORP to our results.  Excluding  the addition of
CILCORP,  fuel and purchased power costs decreased  approximately $17 million in
the first quarter of 2003 due to greater availability of low-cost generation.

     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.  The  operating
revenues  and costs
                                       21



netted  for the three  months  ended  March 31,  2002 were $241  million,  which
reduced  interchange  and other revenues and purchased  power and other costs by
equal amounts.  See Note 1 - Summary of Significant  Accounting  Policies to our
Consolidated  Financial  Statements  under  Item 1 of Part I of this  report for
further information.

Gas Operations

     Our gas margin increased $25 million in the first quarter of 2003, compared
to the first quarter of 2002, with revenues increasing by $125 million and costs
increasing  by $100  million.  The increase in margin was  primarily  due to the
acquisition  of CILCORP ($20 million) and increased  customer  demand  resulting
from colder winter weather.

Other Operating Expenses

Other Operations and Maintenance

     Other  operations  and  maintenance  expenses  increased $37 million in the
first quarter of 2003,  compared to the first quarter of 2002,  primarily due to
the  addition  of  CILCORP's   other   operations   and   maintenance   expenses
(approximately  $29 million) and higher  employee  benefit  costs ($12  million)
related  to  increasing  healthcare  costs  and the  investment  performance  of
employee benefit plans' assets.

Depreciation and Amortization

     Depreciation and amortization  expenses  increased $17 million in the first
quarter of 2003 compared to the prior period.  The increase was primarily due to
the addition of CILCORP's  depreciation  and  amortization  ($14  million),  the
completion of four combustion  turbine  generating units in the third and fourth
quarter 2002 at Generating Company and the completion of four combustion turbine
generating  units at AmerenUE in May 2002. These increases were partially offset
by a  reduction  of  depreciation  rates  based on an updated  analysis of asset
values,  service lives and accumulated  depreciation levels that was included in
our 2002 Missouri electric rate case settlement ($5 million).

Income Taxes

     Income tax  expense  increased  $14  million in the first  quarter of 2003,
compared to the 2002 period, primarily due to higher pretax income.

Other Taxes

     Other taxes  expense  increased  $10 million in the first  quarter of 2003,
compared to the 2002  period,  primarily  due to an  increase in gross  receipts
taxes related to increased native sales ($5 million), as well as the acquisition
of CILCORP.

Other Income and Deductions

     Other income and deductions  (excluding  income taxes) for the three months
ended  March  31,  2003  were  comparable  to  the  2002  period.  See  Note 7 -
Miscellaneous, Net to our Consolidated Financial Statements under Item 1 of Part
I of this report for further information.

Interest

     Interest  expense  increased  $16  million  in the first  quarter  of 2003,
compared to the 2002 period, primarily due to the assumption of CILCORP debt ($9
million),  the interest  expense  component  associated with the $345 million of
adjustable  conversion  rate equity  security units we issued in March 2002, and
Generating  Company's  issuance  of $275  million  of 7.95%  notes in June 2002,
partially offset by lower interest rates.

                                       22



LIQUIDITY AND CAPITAL RESOURCES

Operating

     Our cash flows  provided by operating  activities  totaled $215 million for
the first quarter of 2003, compared to $110 million for the same period in 2002.
Cash provided from operations increased in 2003, primarily as a result of higher
cash earnings  resulting from higher  electric and gas margins and the timing of
payments on accounts payable.

     The  tariff-based  gross margins of our  rate-regulated  utility  operating
companies continue to be our principal source of cash from operating activities.
Our  diversified  retail customer mix of primarily  rate-regulated  residential,
commercial  and  industrial  classes  and a  commodity  mix of gas and  electric
service provide a reasonably  predictable source of cash flows. In addition,  we
plan to utilize short-term debt to support normal operations and other temporary
capital requirements.

Investing

     Our net cash used in  investing  activities  was $618  million in the first
quarter  of 2003  compared  to $160  million  for the same  period in 2002.  The
increase  over the prior year period was  primarily  related to the cash paid of
$488  million  for the  acquisition  of CILCORP on January  31,  2003 and Medina
Valley on February 4, 2003.

     In addition, in the first quarter of 2003, construction expenditures in our
rate-regulated  operations  were $133 million (2002 - $122  million),  primarily
related to various  upgrades at our power plants.  Construction  expenditures in
our non  rate-regulated  operations  of $11 million in the first quarter of 2003
(2002 - $37  million)  decreased  from the first  quarter of 2002 due to reduced
construction  of  combustion  turbine  generating  units.  Capital  expenditures
relating to our rate-regulated and non rate-regulated operations are expected to
approximate $640 million and $35 million, respectively, in 2003.

     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  Ameren  may plan to make for  future  generating  needs  could  result  in
significant  capital  expenditures  or losses  being  incurred,  which  could be
material.

Financing

     Our cash flows provided by financing  activities totaled $69 million in the
first  quarter of 2003 and $43 million for the  comparable  period in 2002.  Our
principal  financing  activities  for the first  quarter  of 2003  included  the
issuances of long-term debt and common stock, partially offset by redemptions of
short-term and long-term debt, as well as payments of dividends.  In addition to
the  activities  above,  the first  quarter of 2002 also  included  issuances of
adjustable conversion-rate equity security units.

     Ameren  Corporation  and AmerenUE are authorized by the SEC under the PUHCA
to have up to an  aggregate  of $1.5  billion and $1 billion,  respectively,  of
short-term  unsecured  debt  instruments  outstanding  at any time. In addition,
AmerenCIPS,  AmerenCILCO  and CILCORP have the PUHCA  authority to have up to an
aggregate  of  $250  million  each  of  short-term  unsecured  debt  instruments
outstanding at any time.  Generating Company is authorized by the Federal Energy
Regulatory  Commission  (FERC) to have up to $300  million  of  short-term  debt
outstanding at any time.

Short-Term Debt and Liquidity

     Short-term  debt  consists of commercial  paper and bank loans  (maturities
generally  within 1 to 45 days). At March 31, 2003,  Ameren had committed credit
facilities,  expiring at various  dates  between  2003 and 2005,  totaling  $694
million,  excluding  AmerenCILCO of $60 million,  EEI of $45 million and nuclear

                                       23



fuel lease  facilities of $120 million.  All of these amounts were available for
use by two of our rate-regulated  subsidiaries,  (AmerenUE and AmerenCIPS),  and
Ameren Services  Company,  and $600 million of this amount was available for use
by Ameren Corporation and most of our non rate-regulated subsidiaries including,
but not limited to, Resources Company,  Generating  Company,  Marketing Company,
AmerenEnergy  Fuels and Services Company and AmerenEnergy.  AmerenCILCO may also
access $600 million of these  facilities  through direct  borrowings from Ameren
Corporation.   These  committed  credit  facilities  are  used  to  support  our
commercial  paper programs under which no amounts were  outstanding at March 31,
2003.  At March 31,  2003,  $694  million was unused and  available  under these
committed credit facilities.

     Subject to the  receipt of  regulatory  approval,  which is being  pursued,
AmerenCILCO will participate in Ameren's utility money pool  arrangement.  Under
this  arrangement,  AmerenCILCO  will  have  access  to up to  $694  million  of
additional committed  liquidity,  subject to reduction based on the use by other
utility  money  pool  participants,  but  increased  to the  extent  other  pool
participants  have surplus cash balances,  which may be used to fund pool needs.
CILCORP  participates  in Ameren's  non-utility  money pool  arrangement,  which
provides  it access to up to $600  million of  committed  liquidity,  subject to
reduction  based  on  use  by  other  pool  participants,   which  may  also  be
supplemented by available cash balances among pool participants.

     On April 1, 2003,  AmerenUE  entered into an additional  364-day  committed
credit facility totaling $75 million to be used for general corporate  purposes,
including  support of commercial paper programs.  This facility makes borrowings
available  at various  interest  rates  based on LIBOR,  agreed  rates and other
options.  Ameren and  AmerenCIPS  can access this  facility  through the utility
money pool.

     We also have two bank credit agreements totaling $45 million that expire in
2003 at EEI. At March 31, 2003, $32 million was unused and available under these
committed credit facilities.

     AmerenUE  also has a lease  agreement  that  provides for the  financing of
nuclear fuel. At March 31, 2003, the maximum amount that could be financed under
the  agreement was $120  million.  At March 31, 2003,  $111 million was financed
under the lease.

     In addition to committed credit  facilities,  a further source of liquidity
for Ameren is available  cash and cash  equivalents.  At March 31, 2003,  we had
$294  million of cash.  In the first  quarter  of 2003,  we paid a total of $488
million  of cash on  hand,  including  related  acquisition  costs,  net of cash
acquired to acquire CILCORP and Medina Valley.

     We  rely on  access  to  short-term  and  long-term  capital  markets  as a
significant  source of funding for capital  requirements  not  satisfied  by our
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
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.

Indenture and Credit Agreement Provisions and Covenants

     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.  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, except for three funded bank
term loans at AmerenCILCO totaling $105 million at March 31, 2003.

     Ameren's  committed credit  facilities  include  provisions  related to the
funded status of Ameren's pension plan.  These provisions  either require Ameren
to meet the minimum  Employee  Retirement  Income  Security  Act of 1974 (ERISA)
funding  requirements or limit the unfunded  liability status of the plan.

                                       24



Under the most restrictive of these  provisions  impacting  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 pensionplan 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.  While an updated  valuation  report  will not be  available  until the
second  half of 2003,  we  believe  that the  unfunded  liability  status of our
pension  plans (as defined)  could exceed $300 million  based on the  investment
performance  of the pension plan assets and interest  rate changes since January
1,  2002.  As a result,  we may need to  renegotiate  the  facility  provisions,
terminate or replace the  affected  facilities,  or fund any unfunded  liability
shortfall.  Should we elect to terminate these  facilities,  we believe we would
otherwise  have   sufficient   liquidity  to  manage  our   short-term   funding
requirements.

     At March 31, 2003,  Ameren and its  subsidiaries  were in  compliance  with
their indenture and credit agreement provisions and covenants.

Debt and Equity Financings

     See Note 6 - Debt  and  Equity  Financings  to our  Consolidated  Financial
Statements under Item 1 of Part I of this report for further  information  about
financings during the first quarter of 2003.

Dividends

     Our Board of Directors does not set specific  targets or payout  parameters
when declaring  common stock  dividends.  However,  the Board considers  various
issues,  including our historic earnings and cash flow; projected earnings; cash
flow and  potential  cash  flow  requirements;  dividend  payout  rates at other
utilities; return on investments with similar risk characteristics;  and overall
business  considerations.  On April 22, 2003, our Board of Directors  declared a
quarterly  common  stock  dividend  of 63.5 cents per share that will be paid on
June 30, 2003 to shareholders of record on June 11, 2003.

Off-Balance Sheet Arrangements

     At March 31, 2003, neither Ameren Corporation, nor any of its subsidiaries,
had any off-balance  sheet financing  arrangements,  other than operating leases
entered into in the ordinary course of business.  At this time, we do not expect
to engage in any significant off-balance sheet financing arrangements.


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    Power  prices in the  Midwest  will  impact the amount of  revenues  we can
     generate  by  marketing  any  excess  power into the  interchange  markets.
     Long-term  power  prices  continue  to be  generally  soft in the  Midwest,
     despite  the  fact  that   short-term   power   prices  have   strengthened
     significantly  from  the  prior  year in the  first  quarter  of  2003  due
     primarily to higher prices for natural gas;
o    A  rate  settlement  approved  in  2002  by  the  Missouri  Public  Service
     Commission (MoPSC) that required electric rate reductions of $50 million on
     April 1,  2002 and $30  million  on April 1, 2003  with an  additional  $30
     million reduction required for April 1, 2004;
o    The adverse  effects of rising  employee  benefit costs,  higher  insurance
     costs and increased  security costs associated with additional  measures we
     have taken,  or may have to take, at our Callaway  nuclear plant related to
     world events;
o    The incremental dilution from equity issued in both 2002 and 2003; and
o    An assumed return to more normal weather patterns relative to 2002.

                                       25



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

o    A voluntary  retirement  program  that was  accepted by  approximately  550
     employees;
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;
o    Suspension  of  operations at two  1940's-era  generating  plants to reduce
     operating costs; and
o    Reductions of 2003 expected capital expenditures.

     We are pursuing annual gas rate increases of  approximately  $34 million in
Illinois and we expect to file an annual gas rate  increase in Missouri.  We are
also considering additional actions,  including modifications to active employee
benefits,  further  staffing  reductions,   accelerating  synergy  opportunities
related to the CILCORP acquisition and other initiatives.

     In early May 2003, our service territory  experienced several severe storms
that damaged parts of our transmission and distribution  system. As a result, we
expect to incur  increased costs in the quarter ending June 30, 2003 for repairs
required to our system.  We are  currently  unable to estimate the impact on our
future financial position, results of operations or cash flows.

     In the ordinary course of business,  we 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
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.


REGULATORY MATTERS

     See Note 3 - Rate and  Regulatory  Matters  to our  Consolidated  Financial
Statements under Item 1 of Part I of this report for information.


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:


                                               
Accounting Policy                                  Uncertainties Affecting Application
-----------------                                  -----------------------------------

Regulatory Mechanisms and Cost Recovery
  We defer costs as regulatory assets in           o    Regulatory environment, external regulatory
  accordance with SFAS 71 and make investments          decisions and requirements
  that we assume we will be able to collect in     o    Anticipated future regulatory decisions and
  future rates.                                         their impact
                                                   o    Impact of deregulation and competition on
                                                        ratemaking process and ability to recover costs



  Basis for Judgment
  We determine that costs are  recoverable  based on  previous  rulings by state
  regulatory authorities in jurisdictions where we operate or other factors that
  lead us to believe that cost recovery is probable.

                                       26



                                               
Accounting Policy (Continued)                      Uncertainties Affecting Application (Continued)
-----------------------------                      -----------------------------------------------

Nuclear Plant Decommissioning Costs
  In our rates and earnings we assume the
  Department of Energy will develop a permanent    o    Estimates of future decommissioning costs
  storage site for spent nuclear fuel, the         o    Availability of facilities for waste disposal
  Callaway nuclear plant will have a useful life   o    Approved methods for waste disposal and
  of 40 years and estimated costs of                    decommissioning
  approximately $515 million to dismantle the      o    Useful lives of nuclear plants
  plant are accurate.  See Note 15 - Callaway
  Nuclear Plant to our Consolidated Financial
  Statements in our 2002 Annual Report to
  Shareholders which is incorporated by
  reference into our 2002 Annual Report on Form
  10-K.



  Basis for Judgment
  We determine that decommissioning costs are reasonable, or require adjustment,
  based on third party decommissioning  studies  that are completed  every three
  years, the evaluation of our facilities by our engineers and the monitoring of
  industry trends.


                                               
Environmental Costs
  We accrue for all known environmental            o    Extent of contamination
  contamination where remediation can be           o    Responsible party determination
  reasonably estimated, but some of our            o    Approved methods for cleanup
  operations have existed for over 100 years and   o    Present and future legislation and governmental
  previous contamination may be unknown to us.          regulations and standards
                                                   o    Results of ongoing research and development
                                                        regarding environmental impacts


  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.


                                               
Unbilled Revenue
  At the end of each period, we estimate, based    o    Projecting customer energy usage
  on expected usage, the amount of revenue to      o    Estimating impacts of weather and other
  record for services that have been provided to        usage-affecting factors for the unbilled period
  customers, but not billed.  This period can be
  up to one month.



  Basis for Judgment
  We determine the proper amount of unbilled revenue to accrue each period based
  on the volume of energy delivered as valued by a model of  billing  cycles and
  historical usage rates and growth by customer class for our service  area,  as
  adjusted for the modeled impact of seasonal  and weather  variations  based on
  historical results.


                                       27



                                               
Accounting Policy (Continued)                      Uncertainties Affecting Application (Continued)
-----------------------------                      -----------------------------------------------

Benefit Plan Accounting
  Based on actuarial calculations, we accrue       o    Future rate of return on pension and other plan
  costs of providing future employee benefits in        assets
  accordance with SFAS 87, 106 and 112.  See       o    Interest rates used in valuing benefit
  Note 12 - Retirement Benefits to our                  obligations
  Consolidated Financial Statements in our 2002    o    Healthcare cost trend rates
  Annual Report to Shareholders which is           o    Timing of employee retirements
  incorporated by reference into our 2002 Annual   o    Future plan designs
  Report on Form 10-K.



  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
  We record all derivatives at their fair market   o    Market conditions in the energy industry,
  value in accordance with SFAS 133.  The               especially the effects of price volatility on
  identification and classification of a                contractual commodity commitments
  derivative and the fair value of such            o    Regulatory and political environments and
  derivative must be determined. We designate           requirements
  certain derivatives as hedges of future cash     o    Fair value estimations on longer term contracts
  flows.  See Note 4 - Derivative Financial        o    Complexity of financial instruments and
  Instruments to our Consolidated Financial             accounting rules
  Statements under Item 1 of Part I of this        o    Effectiveness of our derivatives that have been
  report.                                               designated as hedges



  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.



                                              
Leveraged Leases
  We account for our investment in leveraged
  leases in accordance with SFAS 13, "Accounting   o    Market conditions of the industry of the leased
  for Leases."  As required by SFAS 13, we review       asset that might affect the residual value at the
  the estimated residual value as well as all           end of the lease terms.  This would include:  the
  other important assumptions affecting estimated       real estate markets where each of the assets are
  total net income from the leases.  SFAS 13            located; the rail industry; the aerospace industry;
  requires the rate of return and total income of       and energy market where the asset is located.
  a lease to be recalculated if there is a
  permanent decline in the estimated residual
  value below the value currently used to
  calculate income.



  Basis for Judgment
  We determine whether the residual value has been  "permanently impaired" based
  on an internal review  as well as  periodic third party review of the residual
  value.

                                       28



Impact of Future Accounting Pronouncements

     See  Note  1  -  "Summary  of  Significant   Accounting  Policies"  to  our
Consolidated  Financial  Statements  under  Item 1 of Part I of this  report for
information.


ITEM 3. 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.

Interest Rate Risk

     We are exposed to market risk through changes in interest rates  associated
with both  long-term and  short-term  variable-rate  debt and  fixed-rate  debt,
commercial paper,  auction-rate long-term debt and auction-rate preferred stock.
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.

     Utilizing  our debt  outstanding  at March  31,  2003,  if  interest  rates
increased by 1%, our annual interest  expense would increase by approximately $9
million and net income would  decrease by  approximately  $6 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 trade  accounts  receivables  and executory  contracts with market
risk exposures.  The risk associated with trade  receivables is mitigated by the
large  number of customers in a broad range of industry  groups  comprising  our
customer  base.  No  customer  represents  greater  than  10%  of  our  accounts
receivable.  Our revenues are primarily  derived from sales of  electricity  and
natural  gas  to   customers  in  Missouri   and   Illinois.   We  analyze  each
counterparty's  financial  condition  prior to entering  into  sales,  forwards,
swaps, futures or option contracts and monitor counterparty  exposure associated
with our  leveraged  leases.  As of March 31, 2003,  we had  approximately  $169
million invested in 7 leveraged leases,  primarily at CILCORP. 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.

                                       29



Equity Price Risk

     Our costs of providing  non-contributory  defined  benefit  retirement  and
post-retirement  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 our
plan assets has been  affected by declines in the equity  market  since 2000 for
the pension and  post-retirement  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 Accumulated Other  Comprehensive  Income (OCI)
of $102  million,  net of taxes.  The amount of the  liability was the result of
asset returns  experienced through 2002, interest rates and our contributions to
the plans during 2002. The minimum pension liability did not change at March 31,
2003.  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
Consolidated Balance Sheet.

     We also  maintain  trust  funds,  as  required  by the  Nuclear  Regulatory
Commission  and  Missouri  and Illinois  state laws,  to fund  certain  costs of
nuclear  decommissioning.  By  maintaining a portfolio  that includes  long-term
equity  investments,  we seek to  maximize  the  returns to be  utilized to fund
nuclear  decommissioning  costs.  However, the equity securities included in our
portfolio  are  exposed  to  price   fluctuations  in  equity  markets  and  the
fixed-rate, fixed-income securities are exposed to changes in interest rates. We
actively   monitor  our  portfolio  by  benchmarking   the  performance  of  our
investments  against  certain  indices  and  by  maintaining,  and  periodically
reviewing, established target allocation percentages of the assets of our trusts
to various investment  options.  Our exposure to equity price market risk is, in
large part, mitigated,  due to the fact that we are currently allowed to recover
decommissioning costs in our rates.

Fair Value of Contracts

     We utilize derivatives  principally to manage the risk of changes in market
prices  for  natural  gas,  fuel,   electricity  and  emission  credits.   Price
fluctuations in natural gas, 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 and natural gas  inventories  or purchased  power to
     differ  from  the  cost  of  those  commodities  in  inventory  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
Consolidated  Financial  Statements  under  Item 1 of Part I of this  report for
further information.

     The following table summarizes the favorable  (unfavorable)  changes in the
fair value of all contracts marked-to-market during the first quarter of 2003:


----------------------------------------------------------------------------------------------------------
                                                                                             
Fair value of contracts at beginning of period, net                                              $   3
   Contracts which were realized or otherwise settled during the period                             (9)
   Changes in fair values attributable to changes in valuation techniques and assumptions           --
   Fair value of new contracts entered during the period                                            --
   Other changes in fair value                                                                       6
----------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at end of period, net                                        $  --
----------------------------------------------------------------------------------------------------------


                                       30



     Maturities of contracts as of March 31, 2003 were as follows:


                                                                               
==========================================================================================================
                                        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                   $ (3)         $ (2)        $ (1)         $ (1)         $  (7)
Prices provided by other external
   sources (b)                              2            --           --            --              2
Prices based on models and other
   valuation methods (c)                    4             1           --            --              5
----------------------------------------------------------------------------------------------------------
Total                                    $  3          $ (1)        $ (1)         $ (1)         $  --
----------------------------------------------------------------------------------------------------------

(a)  Contracts  of less than $1  million  were with  non-investment-grade  rated
     counterparties.
(b)  Principally   power  forward  hedges  valued  based  on  NYMEX  prices  for
     over-the-counter contracts.
(c)  Principally  coal and sulfur dioxide option values based on a Black-Scholes
     model that includes information from external sources and our estimates.


ITEM 4.  Controls and Procedures

     (a)  Evaluation of Disclosure Controls and Procedures

     Within the 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 Ameren
which is required to be included in our periodic SEC filings.

     (b)  Change in Internal Controls

     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.


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 and others,  could cause results to differ  materially  from
management expectations as suggested by such "forward-looking" statements:

o    the effects of the  stipulation  and  agreement  relating  to the  AmerenUE
     Missouri  electric  excess  earnings  complaint  case and other  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 due to,  among other
     things,  deregulation  of certain aspects of our business at both the state
     and federal levels;

                                       31



o    the  effects of  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 for the  production  of
     electricity, such as coal and natural gas, purchased power, electricity and
     natural gas for distribution, including the use of financial and derivative
     instruments,  the volatility of changes in market prices and the ability to
     recover increased costs;
o    average rates 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    operation of nuclear power facilities and decommissioning costs;
o    the  effects  of  strategic   initiatives,   including   acquisitions   and
     divestitures;
o    the impact of current environmental regulations on utilities and 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 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    difficulties in integrating CILCO with Ameren's other businesses;
o    changes in the coal markets,  environmental  laws or  regulations  or other
     factors  adversely  impacting  synergy  assumptions in connection  with the
     CILCORP acquisition;
o    cost and availability of transmission  capacity for the energy generated by
     our  generating  facilities  or  required to satisfy  energy  sales made by
     Ameren; and
o    legal and administrative proceedings.

     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.

                                       32



                           PART II. OTHER INFORMATION

ITEM 1.  Legal Proceedings

     Reference  is  made  to  Note 14 to the  Notes  to  Consolidated  Financial
Statements in our 2002 Annual Report to  Shareholders  which is  incorporated by
reference into Item 8. "Financial  Statements and Supplementary Data" in Part II
of our 2002  Annual  Report on Form 10-K and to Note 7 under  Item 8  "Financial
Statements and Supplementary  Data" in Part II of the 2002 Annual Report on Form
10-K of our  subsidiaries,  CILCORP Inc.  and Central  Illinois  Light  Company,
operating as AmerenCILCO, for a discussion of a number of lawsuits that name our
subsidiaries,  Central Illinois Public Service Company, operating as AmerenCIPS,
Union  Electric  Company,  operating as AmerenUE,  AmerenCILCO  and us (which we
refer to as the  Ameren  companies),  along  with  numerous  other  parties,  as
defendants that have been filed by plaintiffs claiming varying degrees of injury
from  asbestos  exposure.  Since the filing of the 2002  Annual  Reports on Form
10-K, 25 additional  lawsuits have been filed against  AmerenCIPS  and AmerenUE,
but no additional lawsuits have been filed against AmerenCILCO.  These lawsuits,
like the  previous  cases,  were mostly  filed in the  Circuit  Court of Madison
County,  Illinois,   involve  a  large  number  of  total  defendants  and  seek
unspecified damages in excess of $50,000,  which, if proved,  typically would be
shared  among the named  defendants.  Also since the  filing of the 2002  Annual
Reports on Form 10-K, the Ameren companies have been voluntarily dismissed in 58
cases and have settled six cases.

     To date, a total of 152  asbestos-related  lawsuits have been filed against
the Ameren companies,  of which 72 are pending, 16 have been settled and 64 have
been dismissed.  We believe that the final disposition of these proceedings will
not have a  material  adverse  effect  on our  financial  position,  results  of
operations or liquidity.

     Note  3 -  Rate  and  Regulatory  Matters  to  our  Consolidated  Financial
Statements under Item 1 of Part I of this report contains additional information
on legal and administrative proceedings which is incorporated by reference under
this item.


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

         (a)(i) Exhibits filed herewith.

                  10.1 - * 2003 Ameren Executive Incentive Plan.

                  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.

         (a)(ii) Exhibits incorporated by reference.

                  4.1  -  AmerenUE Company Order dated April 9, 2003
                          establishing the 4.75% Senior Secured Notes due 2015
                          (AmerenUE Form 8-K dated April 9, 2003, Exhibit 4.2).

                  4.2  -  Supplemental Indenture dated April 1, 2003 to
                          Indenture of Mortgage and Deed of Trust dated June 15,
                          1937, as amended, from AmerenUE to The Bank of New
                          York, as successor Trustee, relating to First Mortgage
                          Bonds, Senior Notes Series CC, 4.75% due 2015
                          (AmerenUE Form 8-K dated April 9, 2003 Exhibit 4.4).


                 ---------------------------
                 * Management compensatory plan or arrangement.

                                       33



         (b)  Reports  on Form 8-K.  Ameren  Corporation  filed  the  following
              reports on Form 8-K during the  quarterly  period ended March 31,
              2003:


        =============================================================================================
                                                               Items Reported        Financial
                   Date of Report                                                 Statements Filed
        ---------------------------------------------------------------------------------------------
                                                                                  
              December 10, 2002 (filed January 15, 2003)              5                   None
              January 22, 2003                                      5,7                   None
              January 30, 2003                                      5,7                   None
              January 31, 2003, as amended March 7, 2003          2,5,7                   None
              February 11, 2003                                     7,9                   None
              March 5, 2003                                         5,7                   (a)



         (a)  Consolidated  financial  statements  as of December  31, 2002 and
              2001,  and for  each  of the  three  years  in the  period  ended
              December    31,    2002,    and    the    report    thereon    of
              PricewaterhouseCoopers LLP, independent accountants.

         Note:  Reports of Central Illinois Public Service Company on Forms 8-K,
                10-Q and 10-K are on file with the SEC under File Number 1-3672.

                Reports of Union Electric Company on Forms 8-K, 10-Q and 10-K
                are on file with the SEC under File Number 1-2967.

                Reports of AmerenEnergy Generating Company on Forms 8-K, 10-Q
                and 10-K are on file with the SEC under File Number 333-56594.

                Reports of CILCORP Inc. on Forms 8-K, 10-Q and 10-K are on file
                with the SEC under File Number 2-95569.

                Reports of Central Illinois Light Company on Forms 8-K, 10-Q and
                10-K are on file with the SEC under File Number 1-2732.




                                       34



                                    SIGNATURE

     Pursuant to the  requirements  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 CORPORATION
                                                    (Registrant)

                                                By  /s/ Martin J. Lyons
                                                  ------------------------------
                                                        Martin J. Lyons
                                                  Vice President and Controller
                                                  (Principal Accounting Officer)
Date:  May 14, 2003



                                 CERTIFICATIONS

     I, Charles W. Mueller, certify that:

     1.   I  have  reviewed  this  quarterly  report  on  Form  10-Q  of  Ameren
Corporation;

     2.   Based on my  knowledge,  this  quarterly  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
quarterly report;

     3.   Based on my knowledge,  the financial statements,  and other financial
information  included in this quarterly  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 quarterly 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 we 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
               quarterly 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 quarterly report (the "Evaluation Date"); and

          c)   presented  in this  quarterly  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 function):

          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

                                       35



                           CERTIFICATIONS (CONTINUED)

          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
quarterly  report  whether or not 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.


                                            /s/ Charles W. Mueller
                                            ----------------------------------
                                            Charles W. Mueller
                                            Chairman and Chief Executive Officer
                                            (Principal Executive Officer)

Date:  May 14, 2003



     I, Warner L. Baxter, certify that:

     1.   I  have  reviewed  this  quarterly  report  on  Form  10-Q  of  Ameren
Corporation;

     2.   Based on my  knowledge,  this  quarterly  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
quarterly report;

     3.   Based on my knowledge,  the financial statements,  and other financial
information  included in this quarterly  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 quarterly 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 we 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
               quarterly 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 quarterly report (the "Evaluation Date"); and

          c)   presented  in this  quarterly  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 function):

          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

                                       36



                           CERTIFICATIONS (CONTINUED)

          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
quarterly  report  whether or not 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.



                                              /s/ Warner L. Baxter
                                              ----------------------------------
                                              Warner L. Baxter
                                              Senior Vice President, Finance
                                              (Principal Financial Officer)


Date:  May 14, 2003

                                       37