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 June 30, 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 August 11, 2003: Common Stock, $.01 par value - 161,799,616.






                               AMEREN CORPORATION

                                TABLE OF CONTENTS

                                                                                                                  Page
                                                                                                                  ----
                                                                                                          
PART I.     Financial Information

   ITEM 1.  Financial Statements (Unaudited)
            Consolidated Balance Sheet at June 30, 2003 and December 31, 2002................................       2
            Consolidated Statement of Income for the three and six months ended June 30, 2003 and 2002.......       3
            Consolidated Statement of Cash Flows for the six months ended June 30, 2003 and 2002.............       4
            Consolidated Statement of Common Stockholders' Equity for the three and six months ended June 30,
            2003 and 2002....................................................................................       5
            Notes to Consolidated Financial Statements.......................................................       6

   ITEM 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations............      19

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

   ITEM 4.  Controls and Procedures..........................................................................      32

            Forward-Looking Statements.......................................................................      32

PART II.    Other Information

   ITEM 1.  Legal Proceedings................................................................................      34

   ITEM 4.  Submission of Matters to a Vote of Security Holders..............................................      35

   ITEM 5.  Other Information................................................................................      35

   ITEM 6.  Exhibits and Reports on Form 8-K.................................................................      36

SIGNATURE....................................................................................................      38

     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  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)

                                                                       June 30,    December 31,
                                                                         2003           2002
                                                                       --------    ------------

                                                                           
ASSETS:
Property and plant, net                                                $ 10,197    $  8,840
Investments and other assets:
   Investments                                                              168          38
   Nuclear decommissioning trust fund                                       191         172
   Goodwill and other intangibles, net                                      620           -
   Other assets                                                             313         307
                                                                       ---------   ---------
         Total investments and other assets                               1,292         517
                                                                       ---------   ---------
Current assets:
   Cash and cash equivalents                                                101         628
   Accounts receivable - trade (less allowance for doubtful
         accounts of $9 and $7, respectively)                               299         266
   Unbilled revenue                                                         257         176
   Miscellaneous accounts and notes receivable                               56          44
   Materials and supplies, at average cost                                  420         299
   Other current assets                                                      44          39
                                                                       ---------   ---------
         Total current assets                                             1,177       1,452
                                                                       ---------   ---------
Regulatory assets                                                           791         690
                                                                       ---------   ---------
Total Assets                                                           $ 13,457    $ 11,499
                                                                       =========   =========

CAPITAL AND LIABILITIES:
Capitalization:
   Common stock, $.01 par value, 400.0 shares authorized -
     shares outstanding of 161.7 and 154.1, respectively               $      2    $      2
   Other paid-in capital, principally premium on common stock             2,500       2,203
   Retained earnings                                                      1,745       1,739
   Accumulated other comprehensive income (loss)                           (100)        (93)
   Other                                                                    (10)         (9)
                                                                       ---------   ---------
      Total common stockholders' equity                                   4,137       3,842
                                                                       ---------   ---------
   Preferred stock not subject to mandatory redemption                      213         193
   Long-term debt, net                                                    4,177       3,433
   Preferred stock subject to mandatory redemption                           22           -
                                                                       ---------   ---------
         Total capitalization                                             8,549       7,468
                                                                       ---------   ---------
Minority interest in consolidated subsidiaries                               19          15
Current liabilities:
   Current maturities of long-term debt                                     407         339
   Short-term debt                                                          180         271
   Accounts and wages payable                                               297         369
   Asset retirement obligations                                               4           -
   Taxes accrued                                                            163          45
   Other current liabilities                                                212         177
                                                                      ---------    ---------
         Total current liabilities                                        1,263       1,201
                                                                      ---------    ---------
Accumulated deferred income taxes                                         1,964       1,707
Accumulated deferred investment tax credits                                 156         149
Regulatory liabilities                                                      123         136
Asset retirement obligations                                                403         174
Accrued pension liabilities                                                 539         377
Other deferred credits and liabilities                                      441         272
                                                                       ---------   ---------
Total Capital and Liabilities                                          $ 13,457    $ 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      Six Months Ended
                                                                 June 30,              June 30,
                                                           ------------------    -------------------
                                                             2003       2002       2003        2002
                                                           ------------------    -------------------
                                                                            
OPERATING REVENUES:
   Electric                                                $   968    $   930    $ 1,824    $ 1,677
   Gas                                                         118         47        368        172
   Other                                                         2          1          4          3
                                                           --------   --------   --------   --------
      Total operating revenues                               1,088        978      2,196      1,852
                                                           --------   --------   --------   --------
OPERATING EXPENSES:
   Fuel and purchased power                                    228        204        449        407
   Gas                                                          87         27        272        112
   Other operations and maintenance                            314        295        613        557
   Depreciation and amortization                               132        106        256        213
   Income taxes                                                 67         83        119        121
   Other taxes                                                  77         69        155        137
                                                           --------   --------   --------   --------
      Total operating expenses                                 905        784      1,864      1,547
                                                           --------   --------   --------   --------

OPERATING INCOME                                               183        194        332        305

OTHER INCOME AND (DEDUCTIONS):
   Allowance for equity funds used during construction           1          -          1          2
   Miscellaneous, net -
     Miscellaneous income                                        5          5         11          8
     Miscellaneous expense                                      (8)       (39)       (11)       (43)
     Income taxes                                                -         10          -         10
                                                           --------   --------   --------   --------
      Total other income and (deductions)                       (2)       (24)         1        (23)
                                                           --------   --------   --------   --------


INTEREST CHARGES AND PREFERRED DIVIDENDS:
   Interest                                                     70         53        138        105
   Allowance for borrowed funds used during construction        (1)        (1)        (3)        (3)
   Preferred dividends of subsidiaries                           2          3          5          6
                                                           --------   --------   --------   --------
      Net interest charges and preferred dividends              71         55        140        108
                                                           --------   --------   --------   --------

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
      ACCOUNTING PRINCIPLE                                     110        115        193        174

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

NET INCOME                                                 $   110    $   115    $   211    $   174
                                                           ========   ========   ========   ========

EARNINGS PER COMMON SHARE - BASIC AND DILUTED:
    Income before cumulative effect of change
         in accounting principle                           $  0.68    $  0.80    $  1.21    $  1.22
    Cumulative effect of change in accounting
         principle, net of income taxes                          -          -       0.11          -
                                                           --------   --------   --------   --------
    Net income                                             $  0.68    $  0.80    $  1.32    $  1.22
                                                           ========   ========   ========   ========

AVERAGE COMMON SHARES OUTSTANDING                            161.2      144.4      160.1      142.1




See Notes to Consolidated Financial Statements.


                                       3




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

                                                                                      Six Months Ended
                                                                                           June 30,
                                                                                      ----------------
                                                                                       2003     2002
                                                                                      -----    -----
                                                                                  
Cash Flows From Operating:
   Net income                                                                         $ 211    $ 174
   Adjustments to reconcile net income to net cash
     provided by operating activities:
      Cumulative effect of change in accounting principle                               (18)       -
      Depreciation and amortization                                                     256      213
      Amortization of nuclear fuel                                                       16       16
      Amortization of debt issuance costs and premium/discounts                           5        4
      Allowance for funds used during construction                                       (4)      (5)
      Deferred income taxes, net                                                         (9)      (6)
      Deferred investment tax credits, net                                               (6)      (4)
      Other                                                                              (7)       -
      Changes in assets and liabilities, excluding the effects of the acquisitions:
        Receivables, net                                                                  6      (74)
        Materials and supplies                                                          (14)      32
        Accounts and wages payable                                                     (149)    (139)
        Taxes accrued                                                                    99      107
        Assets, other                                                                    17      (12)
        Liabilities, other                                                               27       40
                                                                                      ------   ------
Net cash provided by operating activities                                               430      346
                                                                                      ------   ------

Cash Flows From Investing:
   Construction expenditures                                                           (332)    (401)
   Acquisitions, net of cash acquired                                                  (489)       -
   Allowance for funds used during construction                                           4        5
   Nuclear fuel expenditures                                                             (1)     (16)
   Other                                                                                  2        1
                                                                                      ------   ------
Net cash used in investing activities                                                  (816)    (411)
                                                                                      ------   ------

Cash Flows From Financing:
   Dividends on common stock                                                           (205)    (182)
   Capital issuance costs                                                               (11)     (23)
   Redemptions:
      Nuclear fuel lease                                                                (20)       -
      Short-term debt                                                                   (91)    (637)
      Long-term debt                                                                   (420)      (5)
   Issuances:
      Common stock                                                                      308      269
      Nuclear fuel lease                                                                  -        6
      Long-term debt                                                                    298      720
                                                                                      ------   ------
Net cash provided by (used in) financing activities                                    (141)     148
                                                                                      ------   ------

Net change in cash and cash equivalents                                                (527)      83
Cash and cash equivalents at beginning of year                                          628       67
                                                                                      ------   ------
Cash and cash equivalents at end of period                                            $ 101    $ 150
                                                                                      ======   ======

Cash paid during the periods:
   Interest                                                                           $ 133    $  99
   Income taxes, net                                                                    100       77

See Notes to Consolidated Financial Statements.


                                       4






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


                                                                              Three Months Ended     Six Months Ended
                                                                                       June 30,          June 30,
                                                                             ------------------    -------------------
                                                                               2003       2002       2003       2002
                                                                             --------   -------    --------   --------
                                                                                              
Common stock
   Beginning balance                                                         $     2    $     1    $     2    $     1
   Shares issued                                                                   -          -          -          -
                                                                             --------   --------   --------   --------
                                                                                   2          1          2          1
                                                                             --------   --------   --------   --------

Other paid-in capital
   Beginning balance                                                           2,480      1,804      2,203      1,614
   Shares issued (less issuance costs of $-, $-, $8 and $9, respectively)         23         23        300        260
   Contracted stock purchase payment obligations                                   -          -          -        (46)
   Employee stock awards                                                          (3)        (1)        (3)        (2)
                                                                             --------   --------   --------   --------
                                                                               2,500      1,826      2,500      1,826
                                                                             --------   --------   --------   --------

Retained earnings
   Beginning balance                                                           1,738      1,701      1,739      1,733
   Net income                                                                    110        115        211        174
   Dividends                                                                    (103)       (91)      (205)      (182)
                                                                             --------   --------   --------   --------
                                                                               1,745      1,725      1,745      1,725
                                                                             --------   --------   --------   --------

Accumulated other comprehensive income (loss)
   Beginning balance - derivative financial instruments                            6          -          9          5
   Change in derivative financial instruments in current period                   (4)         3         (7)        (2)
                                                                             --------   --------   --------   --------
                                                                                   2          3          2          3
                                                                             --------   --------   --------   --------
   Beginning balance - minimum pension liability                                (102)         -       (102)         -
   Change in minimum pension liability in current period                           -          -          -          -
                                                                             --------   --------   --------   --------
                                                                                (102)         -       (102)         -
                                                                             --------   --------   --------   --------
                                                                                (100)         3       (100)         3
                                                                             --------   --------   --------   --------

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

Total common stockholders' equity                                            $ 4,137    $ 3,545    $ 4,137    $ 3,545
                                                                             ========   ========   ========   ========


Comprehensive income, net of taxes
   Net income                                                                $   110    $   115    $   211    $   174
   Unrealized net gain/(loss) on derivative hedging instruments,
        net of income taxes of $(2), $1, $(2) and $1, respectively                (4)         2         (5)         1
   Reclassification adjustments for gains/(losses) included in net income,
        net of income taxes of $-, $-, $(1) and $(2), respectively                 -          1         (2)        (3)
                                                                             --------   --------   --------   --------
           Total comprehensive income, net of taxes                          $   106    $   118    $   204    $   172
                                                                             ========   ========   ========   ========

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

Common stock shares at beginning of period                                     161.1      144.2      154.1      138.0
   Shares issued                                                                 0.6        0.6        7.6        6.8
                                                                             --------   --------   --------   --------
Common stock shares at end of period                                           161.7      144.8      161.7      144.8
                                                                             ========   ========   ========   ========

See Notes to Consolidated Financial Statements.


                                        5





AMEREN CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
June 30, 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 principal 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 primarily 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 June 30, 2003. 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,  CILCORP's 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 material difference between the basic and diluted earnings per
share  amounts for the three and six month periods ended June 30, 2003 and 2002.
The  dilutive  component 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 306,389 shares for the three months
ended June 30, 2003 (2002 - 355,420) and 273,136 shares for the six months ended
June 30, 2003 (2002 - 353,607).

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,  effective 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.  Corresponding
increases in asset book values are depreciated over the remaining useful life of
the related asset. Uncertainties as to the probability, timing or amount of cash
flows  associated with an asset  retirement  obligation  affect our estimates of
fair value.

     Upon adoption of this standard,  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
plant  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
that we had recorded at January 1, 2003,  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 power plant ash ponds in connection with
our acquisition of CILCORP on January 31, 2003.

     Asset  retirement  obligations  also  increased  by $4  million  during the
quarter  ended March 31, 2003 and $6 million  during the quarter  ended June 30,
2003 to reflect the obligations at their present value.

     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

                                       7



of operations or liquidity.

     The fair value of our nuclear  decommissioning  trust fund for our Callaway
nuclear  plant  is  reported  in  Nuclear  Decommissioning  Trust  Fund  in  our
Consolidated  Balance Sheet.  This amount is legally  restricted for funding the
costs of  nuclear  decommissioning.  Changes in the fair value of the trust fund
are  recorded as an increase or  decrease to the  regulatory  asset  recorded in
connection with the adoption of SFAS 143.

     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 the methodology  employed by 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 $673 million at June 30, 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 require  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
sum of the  contract  notional  amounts  of the  power  sales  contracts  with a
corresponding  charge to income for the costs of the energy that was  generated,
or for the sum of the contract notional amounts 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.  The  operating  revenues  and costs that were
netted for the three and six months  ended June 30,  2002 were $133  million and
$374  million,  respectively,  which  reduced  Electric  and Other  Revenues and
Purchased  Power and Other  Operations and  Maintenance  by equal  amounts.  The
adoption of EITF 02-3, the rescission of  EITF 98-10 and the related  transition
guidance  resulted  in netting

                                       8



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 Financial  Accounting  Standards  Board (FASB) issued
SFAS  148.  SFAS  148  amended  SFAS  No.  123,   "Accounting   for  Stock-Based
Compensation," to provide  alternative  methods of transition for an entity that
voluntarily 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 our 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 six months
of 2003.

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

     In April  2003,  the FASB issued SFAS 149.  SFAS 149  clarifies  under what
circumstances a contract with initial net investment  meets the  characteristics
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. We do not
expect  SFAS  149 to have any  impact  on our  financial  position,  results  of
operations or liquidity upon adoption in the third quarter of 2003.

SFAS  No.  150  -   "Accounting   for   Certain   Financial   Instruments   with
Characteristics of Both Liabilities and Equity"

     In May 2003, the FASB issued SFAS 150 that established standards for how an
issuer   classifies   and   measures   certain   financial    instruments   with
characteristics  of both  liabilities  and equity.  SFAS 150 requires  financial
instruments  that  were  issued  in the  form of  shares  with an  unconditional
obligation,  where the issuer must redeem the  instrument  by  transferring  its
assets on a specified date, be classified as liabilities.  Accordingly, SFAS 150
requires issuers to classify  mandatorily  redeemable  financial  instruments as
liabilities. SFAS 150 also requires such financial instruments to be measured at
fair value and a cumulative  effect adjustment to be recognized in the statement
of income for any difference  between the carrying  amount and fair value.  SFAS
150 will be effective in the third quarter of 2003.  AmerenCILCO has $22 million
of preferred stock subject to mandatory redemption. Effective July 1, 2003, this
preferred  stock is redeemable at par at any time,  and  therefore,  there is no
difference between book value and fair value.

FASB Interpretation No. (FIN) 46 - "Consolidation of Variable Interest Entities,
an  Interpretation of Accounting  Research  Bulletin (ARB) No. 51,  Consolidated
Financial Statements"

     The FASB issued FIN 46 in January  2003.  FIN 46  provides  guidance on the
identification  of, and financial  reporting for, entities over which control is
achieved  through  means other than voting  rights;  such  entities are known as
variable-interest entities (VIEs). FIN 46 will determine the following:

o    Whether   consolidation  is  required  under  the  "controlling   financial
     interest" model of ARB 51, or other existing authoritative guidance;
o    Or, alternatively,  whether the variable-interest model under FIN 46 should
     be used to account for existing and new entities.


                                       9



     The  initial  application  of FIN 46  depends  on the date that the VIE was
created. For public entities, FIN 46 is effective no later than the beginning of
the first  interim  period that starts after June 15, 2003. At this time, we are
assessing the impact of FIN 46 on our financial position, results of operations,
or liquidity upon adoption in the third quarter of 2003.

Interchange Revenues

     Interchange  revenues  included in Operating  Revenues - Electric  were $71
million for the three  months  ended June 30, 2003 (2002 - $67 million) and $185
million for the six months ended June 30, 2003 (2002 - $148 million).

Purchased Power

     Purchased  power included in Operating  Expenses - Fuel and Purchased Power
was $64 million for the three  months  ended June 30, 2003 (2002 - $52  million)
and $109 million for the six months ended June 30, 2003 (2002 - $104 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 June 30, 2003 were $31 million  (2002 - $30  million)  and $62 million for
the six months ended June 30, 2003 (2002 - $56 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.

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.

Pension

     At December  31,  2002,  we recorded a minimum  pension  liability  of $102
million,   after  taxes,  which  resulted  in  a  charge  to  Accumulated  Other
Comprehensive Income (Loss)(OCI) and a reduction in stockholders'  equity. Based
on changes in interest  rates,  we may need to change our actuarial  assumptions
for our pension plan at December 31, 2003,  which could result in a  requirement
to record an additional minimum pension liability.


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 indirect 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.


                                       10




     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 acquisition cost 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 $489 million in cash,  net of cash acquired.
The cash  component  of the  purchase  price  came  from  Ameren's  issuance  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 $604 million.




-----------------------------------------------------------------------------------------------------------------
For the periods ended June 30,                          Pro Forma Three Months             Pro Forma Six Months
-----------------------------------------------------------------------------------------------------------------
                                                         2003              2002             2003            2002
-----------------------------------------------------------------------------------------------------------------
                                                                                      
Operating revenues                                    $ 1,088           $ 1,146          $ 2,296         $ 2,217

Income before cumulative effect of
   change in accounting principle                         110               117              197             181
Cumulative effect of change in accounting
   principle, net of taxes                                  -                 -               22               -
-----------------------------------------------------------------------------------------------------------------
Net income                                              $ 110             $ 117            $ 219           $ 181

Earnings per share     -basic                          $ 0.68            $ 0.74           $ 1.36          $ 1.16
                       -diluted                        $ 0.68            $ 0.74           $ 1.36          $ 1.16
-----------------------------------------------------------------------------------------------------------------



     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 and Illinois  Service
Territory

     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 from Generating  Company to AmerenUE,  at net book
value, of approximately 550 megawatts of combustion  turbine generating units at
Pinckneyville  and  Kinmundy,  Illinois.  The  transfer 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


                                       11



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 in the ICC proceeding  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,  the ICC Staff filed testimony
that expressed  concerns about whether the transfer is the least cost generating
resource  for  AmerenUE,  and  recommended  that  the ICC deny  approval  of the
transfer.

     On May 5, 2003,  the FERC  issued an order which set for hearing the effect
ofthe proposed transfer on competition in wholesale electric markets.  On June4,
2003, we filed a Motion for  Reconsideration  of this order  contending that the
FERC erred in setting this matter for hearing. On June 10, 2003, we filed direct
testimony with the FERC in support of the proposed transfer.  On August 8, 2003,
two intervenors, NRG and The Electric Power Supply Association,  filed testimony
opposing the proposed transfer.

     On May 30, 2003, AmerenUE filed a Notice of Withdrawal with the ICC stating
that AmerenUE elected not to pursue approval of the transfer and was withdrawing
its request.  In the Notice,  AmerenUE stated that the concerns expressed by the
ICC Staff  regarding  AmerenUE's  means of satisfying  its  generating  capacity
needs,  as well  as the  MoPSC's  views  of the  appropriate  means  of  meeting
generating capacity obligations, have demonstrated to AmerenUE the difficulty of
a single company operating as an electric utility in both a regulated generation
jurisdiction such as Missouri and an unregulated generation jurisdiction such as
Illinois.  To remedy this difficulty,  AmerenUE announced in the Notice its plan
to  limit  its  public  utility  operations  to the  State  of  Missouri  and to
discontinue  operating as a public utility subject to ICC  regulation.  AmerenUE
intends to accomplish this plan by transferring its Illinois-based  electric and
natural gas businesses,  including its  Illinois-based  distribution  assets and
certain  of  its  transmission   assets,  to  AmerenCIPS.   AmerenUE's  electric
generating  facilities  and certain of its electric  transmission  facilities in
Illinois  would  not be  part  of  the  transfer.  The  transfer  of  AmerenUE's
Illinois-based  utility  businesses  will  require the  approval of the ICC, the
FERC, the MoPSC and the SEC under the provisions of the PUHCA. On June 13, 2003,
the ICC Staff filed a response to  AmerenUE's  Notice of  Withdrawal  indicating
that the ICC Staff did not object to it and on July 23, 2003,  the ICC issued an
order accepting the withdrawal.  In the third quarter of 2003, we expect to file
with  the  MoPSC,  the  ICC,  the FERC  and the SEC for  authority  to  transfer
AmerenUE's Illinois-based utility businesses, at net book value, to AmerenCIPS.

     Upon receipt of regulatory  approvals and completion of the transfer of its
Illinois-based utility businesses, the ICC's approval will no longer be required
for the Pinckneyville  and Kinmundy  combustion  turbine  generating units to be
transferred from Generating Company to AmerenUE.  We intend to continue with the
transfer  of these  electric  generating  facilities  and will  continue to seek
approvals  from  regulators  having  jurisdiction  over  the  transaction.  FERC
approval of the  transaction  is needed,  and because the  transaction  does not
require  state  regulatory  approvals,  SEC  approval  under  the  PUHCA is also
required.

     We  are  unable  to  predict   the ultimate  outcome  of  these  regulatory
proceedings or the timing of the final  decisions of the various  agencies.  The
timing of regulatory approvals of these proposed transactions is not anticipated
to have any material effect on our financial position,  results of operations or
liquidity.

Regional Transmission Organization (RTO)

     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


                                       12


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
procedures  to determine  the justness and  reasonableness  of the proposed rate
amendments  to the Midwest  ISO OATT.  At this time,  the  parties are  pursuing
settlement of the disputed rate issues.  Absent  settlement,  the rates filed in
the February 28, 2003 filing will go into effect on October 1, 2003,  subject to
refund.  On May 15, 2003,  the FERC issued an order  accepting  the February 18,
2003 compliance filing.

     Once  GridAmerica  becomes  operational and Ameren has secured  approval to
participate  in GridAmerica  from the MoPSC,  the FERC has ordered the return of
the $18 million exit fee, with interest,  paid by Ameren when it previously left
the Midwest ISO. 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. We expect GridAmerica
to become operational in late 2003, subject to regulatory approvals.

     In July 2003, the FERC issued an Order (July Order) that could  potentially
reduce  Ameren's,  as well as other  utilities', "through and out"  transmission
revenues  effective  November 1, 2003,  reversing an Administrative  Law Judge's
previous  decision on this matter.  The revenues  subject to  elimination by the
July Order are those revenues from transmission reservations that travel through
or out of our  transmission  system and are also used to provide  electricity to
load within the Midwest ISO or PJM Interconnection  LLC systems.  The  magnitude
of the potential net revenue  reduction  resulting  from the July Order is still
being  evaluated,  but could be up to $20 to $25 million  annually.  While it is
anticipated that our  transmission  revenues could be reduced by the July Order,
transmission  expenses for our affiliates could also be reduced.  Moreover,  the
FERC's  Order  explicitly  permits  companies  participating  in an RTO to  seek
collection  of  the  lost   "through  and  out"  revenues   through  other  rate
mechanisms.   At this time,  we intend to seek  rehearing of the July Order.  We
also intend to seek  recovery of any  potential  lost "through and out" revenues
through rate mechanisms acknowledged by the FERC in the July Order.

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.


                                       13



     Although  issuance of the final rule is  uncertain  and the  implementation
schedule is unknown, the Midwest ISO is already in the process of implementing a
separate  market  design  similar to the proposed  market design in the NOPR. In
July 2003,  the Midwest  ISO filed with the FERC a revised  OATT  codifying  the
terms and conditions  under which it will  implement the new market design.  The
Midwest ISO has targeted March 2004 as the start date for implementation. We are
reviewing the Midwest ISO's market design and the potential impact of the market
design on the cost and reliability of service to retail customers. At this time,
we are unable to predict the ultimate  impact the new market design will have on
our future financial position, results of operations or liquidity.

Illinois Gas

     In November 2002,  AmerenCIPS,  AmerenUE and CILCO (now AmerenCILCO)  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
Staff has recommended  annual increases of approximately $8 million,  $2 million
and $9 million,  respectively.  In addition,  other parties have proposed  lower
increases in each case. Hearings were completed in June and July 2003. In August
2003, the Administrative Law Judge in the CILCO gas rate proceeding  recommended
to the ICC the adoption of a Proposed Order to increase annual rates for natural
gas service by $10 million at CILCO.  The ICC has until October 2003 to render a
decision  in each of these gas cases and any rate  changes  are  expected  to be
effective in November 2003.

Missouri Gas

     In May 2003,  AmerenUE  filed a request  with the MoPSC to increase  annual
rates for natural gas service by approximately $27 million. AmerenUE proposed to
phase in the rate increases over two years, with one half of the increase taking
effect  December 1, 2003 and the other half taking  effect  November 1, 2004. We
also proposed not to seek additional  increases in gas rates through November 1,
2006,  subject  to  certain  exceptions.  Our  proposal  also  called  for us to
contribute  $1.75  million to an energy  assistance  program to help  low-income
customers.  The direct  testimony  of the MoPSC Staff and other  parties to this
proceeding  is due to be filed with the MoPSC in  October  2003.  A  pre-hearing
settlement  conference  is scheduled to be held in October 2003 and a hearing is
scheduled to be held in January 2004. The MoPSC has until April 2004 to render a
decision in this gas case.


NOTE 4 - Derivative Financial Instruments

     As of June 30,  2003,  we recorded the fair value of  derivative  financial
instrument  assets  of $10  million  in  Other  Assets  and the  fair  value  of
derivative  financial  instrument  liabilities  of $9 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
OCI due to  transactions  going to  delivery or  settlement,  was less than a $1
million gain for the three months (2002 - less than a $1 million  loss) and a $1
million  loss for the six  months  ended  June 30,  2003  (2002 - less than a $1
million gain).

     As of June 30, 2003, we hedged a portion of the electricity  price exposure
for periods generally less than one year.  Certain contracts that are designated
as hedges  of  electricity  price  exposure  have  terms up to five  years.  The
mark-to-market  value  accumulated in OCI for the effective portion of hedges of
electricity price exposure was a net loss of approximately $1 million (less than
$1 million, net of taxes).

     As of June 30, 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.

                                       14



     As of June 30, 2003, a loss of approximately $4 million ($2 million, net of
taxes),  associated with natural gas swaps and future contracts, was included in
OCI.  The swaps are a partial  hedge of our  natural  gas  requirements  through
October 2006.

     We also hold two call options for coal with two suppliers. These options to
purchase  coal  expire  October  2003 and July  2005.  As of June  30,  2003,  a
mark-to-market  gain of  approximately  $5 million  ($3  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.

Other Derivatives

     We enter into option transactions to manage our positions in sulfur dioxide
allowances, coal, heating oil and electricity. Certain of these transactions are
treated as non-hedge  transactions  under SFAS 133. The 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 of sulfur dioxide,  coal,
heating oil and  electricity  options  was a gain of less than $1 million  (less
than $1 million,  net of taxes) for the three  months  ended June 30, 2003 and a
gain of $1 million (less than $1 million, net of taxes) for the six months ended
June 30,  2003.  For the three and six  months  ended June 30,  2002,  the above
related  amounts  were a $2  million  gain ($1  million,  net of taxes) and a $3
million gain ($2 million, net of taxes).


NOTE 5 - Property and Plant, Net



     Property and plant, net at June 30, 2003 and December 31, 2002 consisted of
the following:
---------------------------------------------------------------------------------------------
---------------------------------------------------------------------------------------------
                                                               June 30,         December 31,
                                                                 2003              2002
---------------------------------------------------------------------------------------------
                                                                       
Property and plant, at original cost:
  Electric                                                     $15,895           $14,495
  Gas                                                              725               557
  Other                                                            196               145
---------------------------------------------------------------------------------------------
                                                                16,816            15,197
     Less accumulated depreciation and amortization              7,075             6,831
---------------------------------------------------------------------------------------------
                                                                 9,741             8,366
Construction work in progress:
  Nuclear fuel in process                                           71                81
  Other                                                            385               393
--------------------------------------------------------------------------------------------
Property and plant, net                                        $10,197            $8,840
--------------------------------------------------------------------------------------------



NOTE 6 - Debt and Equity Financings

Ameren Corporation

     In August 2002, the SEC declared effective a shelf  registration  statement
filed by Ameren  Corporation  covering 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,
and to finance strategic investments,  including our then pending acquisition of
CILCORP, and for general corporate purposes.

     In the first quarter of 2003, Ameren  Corporation  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

                                       15



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 six months of 2003, $594 million was issued
under  this  shelf  registration  statement.  At June 30,  2003,  the  amount of
securities  remaining to be issued  pursuant to the  registration  statement was
$879 million.

     The  purchases 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% senior notes due 2029, $225 million 8.7% senior notes due 2009, a
$100  million  secured   floating  rate  term  loan  due  2004,   other  secured
indebtedness   totaling  $279  million  and  preferred  stock  of  $41  million.
Subsequent to the acquisition dates, the other secured  indebtedness was reduced
by $136 million through maturities and early redemptions.

     In July 2003, Ameren Corporation entered into two new credit agreements for
$470 million in revolving  credit  facilities  to be used for general  corporate
purposes,  including support of our commercial paper programs.  The $470 million
in new facilities  includes a $235 million 364-day revolving credit facility and
a $235 million three-year revolving credit facility. These new credit facilities
replaced Ameren  Corporation's  existing $270 million 364-day  revolving  credit
facility,  which matured in July 2003 and a $200 million  facility,  which would
have matured in December  2003.  The new credit  facilities  contain  provisions
which require us to meet minimum Employee Retirement Income Security Act (ERISA)
funding  requirements for our pension plan. The prior credit facilities included
more  restrictive  provisions  related to the funded status of our pension plan,
which are not present in the new facilities.  In addition,  in July 2003, Ameren
Corporation  entered into an amendment  of an existing  $130 million  multi-year
credit  facility that similarly  modified the  ERISA-related  provisions in this
facility. As a result, all of Ameren Corporation's facilities require us to meet
minimum ERISA funding  requirements,  but do not otherwise limit the underfunded
status of our pension plan.  At July 31, 2003,  all of such  borrowing  capacity
under these facilities was available.

     At June 30, 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.

     Amortization  of debt  issuance  costs and any premium or discounts for the
three and six months  ended June 30, 2003 of $3 million  (2002 - $2 million) and
$5 million (2002 - $4 million),  respectively, 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  approximately  $2 million for
the three  months and $3 million for the five months  ended June 30,  2003.  The
amortization was included in interest expense in the income statement.

     At  June  30,  2003,  Ameren  Corporation  and  its  subsidiaries  were  in
compliance with their financial agreement provisions and covenants.

AmerenUE

     In August 2002, the SEC declared effective a shelf  registration  statement
filed by AmerenUE  covering 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
statement,  $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 matured in December 2002.



                                       16


     In  April  2003,  AmerenUE  issued,  pursuant  to  the  shelf  registration
statement,  $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 debt.

     In July 2003,  AmerenUE  issued $200 million of 5.10% Senior  Secured Notes
due August 1, 2018.  AmerenUE  received net proceeds after fees of $198 million,
which,  along with other funds were used to repay  short-term  debt  incurred to
fund the maturity of $100 million  principal  amount 7.65% first  mortgage bonds
due July 15,  2003,  and to repay $21  million  of other  short-term  debt.  The
remaining proceeds will be used to redeem and refinance,  prior to maturity, $75
million principal amount of outstanding 7.15% first mortgage bonds due August 1,
2023 at a redemption  price of 103.01% of par,  plus accrued  interest in August
2003.

     In August 2003, AmerenUE plans to file another shelf registration statement
with the SEC. We expect this registration statement,  when declared effective by
the SEC,  will  authorize  the offering from time to time of up to $1 billion of
various  forms of long-term  debt and trust  preferred  securities  to refinance
existing  debt and for general  corporate  purposes,  including the repayment of
short-term debt incurred to finance construction  expenditures and other working
capital  needs.  The $79 million of securities  which remains to be issued under
the August 2002 shelf  registration is expected to be included in the $1 billion
of securities proposed to be issued under this registration statement.

     Once declared effective by the SEC, AmerenUE may sell all, or a portion of,
the 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.

     In April 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. AmerenCIPS can access this facility through the utility money pool.

AmerenCIPS

     On April 1, 2003, AmerenCIPS repaid $40 million first mortgage bonds 6.375%
Series Z which matured on that date.  AmerenCIPS  also redeemed,  in April 2003,
prior to maturity and at par, its $50 million first mortgage bonds 7.5% Series X
due July 1, 2007.

AmerenCILCO

     In April 2003,  three series of  AmerenCILCO's  first  mortgage  bonds were
redeemed prior to maturity.  These included  AmerenCILCO's $65 million principal
amount 8.20% series notes due January 15, 2022, at a redemption price of 103.29%
and two 7.8% series notes totaling $10 million  principal amount due February 9,
2023, at a redemption price of 103.90%.

Other

     On June 30, 2003,  AmerenEnergy  Medina Valley Cogen, LLC repaid,  prior to
maturity,  a $36 million  secured term loan with an effective  interest  rate of
7.65% and terminated two related interest rate swaps. This redemption eliminated
the outstanding bank debt at AmerenEnergy Medina Valley Cogen, LLC.




                                       17



NOTE 7 - Miscellaneous, Net

     Miscellaneous,  net for the three and six months  ended  June 30,  2003 and
2002 consisted of the following:

--------------------------------------------------------------------------------
                                                    Three Months     Six Months
--------------------------------------------------------------------------------
                                                   2003     2002    2003    2002
                                                   ----     ----    ----    ----
Miscellaneous income:
   Interest and dividend income                     $  1    $  2    $  2   $  2
   Gain on disposition of property                     -       3       -      3
   Other                                               4       -       9      3
--------------------------------------------------------------------------------
Total miscellaneous income                          $  5    $  5    $ 11   $  8
--------------------------------------------------------------------------------


Miscellaneous expense:
   Minority interest in subsidiary                  $ (4)   $(10)   $ (5)  $(11)
   Donations, including 2002 rate settlement          (1)    (26)     (1)   (26)
   Other                                              (3)     (3)     (5)    (6)
--------------------------------------------------------------------------------
Total miscellaneous expense                         $ (8)   $(39)   $(11)  $(43)
--------------------------------------------------------------------------------


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  for   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.

     Segment  information  for the three and six months  ended June 30, 2003 and
2002 was as follows:


------------------------------------------------------------------------------------------------------------------
                                               Utility                       Intercompany
                                              Operations        Other          Revenues                 Total
------------------------------------------------------------------------------------------------------------------
                                                                                       

     Three months ended June 30, 2003:
Revenues                                       $1,189            $ 75            $(176)                $1,088
Net income                                        108               2               -                     110
------------------------------------------------------------------------------------------------------------------

     Three months ended June 30, 2002:
Revenues                                       $1,046            $106            $(174)                $ 978
Net income                                        101              14               -                    115
---------------------------------------------------------------------------------------------------------------

     Six months ended June 30, 2003:
Revenues                                       $2,436            $ 122           $(362)               $2,196
Net income                                        210                1              -                    211
-------------------------------------------------------------------------------------------------------------

     Six months ended June 30, 2002:
Revenues                                       $2,041            $ 175           $(364)               $1,852
Net income                                        159               15              -                    174
------------------------------------------------------------------------------------------------------------




                                       18



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


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  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 non rate-regulated  electric
     generation  in  Missouri  and  Illinois,   AmerenEnergy  Marketing  Company
     (Marketing  Company),  which markets power for periods  primarily  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 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.

     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    The financial statements and related notes included in our Quarterly Report
     on Form 10-Q for the period ended March 31, 2003.
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, as amended by Form 10-K/A.
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,  as amended by
     Form 10-K/A.
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.

                                       19



     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 June 30, 2003.

     Our results of  operations  and  financial  position  are  affected by many
factors.  Weather,  economic  conditions  and the  actions of key  customers  or
competitors can  significantly  impact the demand for our services.  Our results
are also affected 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. Fluctuations in interest rates impact our
cost of borrowings,  and pension and post-retirement benefits. 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.

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 indirect 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
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 acquisition cost 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 $489 million in cash,  net of cash acquired.
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.

                                       20



RESULTS OF OPERATIONS

Earnings Summary

     Our net income decreased $5 million to $110 million, or 68 cents per share,
in the second quarter of 2003 from $115 million,  or 80 cents per share,  in the
second  quarter of 2002.  Net income  decreased in the second quarter of 2003 as
compared  to 2002  principally  as a result of milder  weather,  lower  sales of
emission  credits,  increased  dilution  and  financing  costs  outside of those
incurred in  connection  with the CILCORP  acquisition  and higher  depreciation
expense.  Partially offsetting these items were lower operations and maintenance
expenses,  excluding CILCORP, and favorable  interchange margins due to improved
power prices in the energy markets and solid low-cost  generation  available for
sale.  In  addition,  we  expensed  costs of  economic  development  and  energy
assistance  programs  that  were  required  by a  Missouri  electric  rate  case
settlement in the second quarter of 2002.

     Our net income  increased $37 million to $211  million,  or $1.32 per share
($1.32 per share  diluted),  for the six months ended June 30, 2003  compared to
the  year-ago  earnings of $174  million,  or $1.22 per share.  In the first six
months of 2003,  our net income  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.  In addition to the items discussed above, net income
for the first six months of 2003  benefited from higher  interchange  margins as
well as colder winter weather than 2002, which resulted in increased native load
electric demand and higher gas margins in the first quarter of 2003.

     The impact from the acquisition of CILCORP and related financings  resulted
in a  reduction  to earnings  per share in the second  quarter and the first six
months of 2003 of approximately 3 cents and 5 cents per share, respectively.  We
continue to believe the  operations  of CILCORP will be accretive to earnings in
the first full year following the  acquisition  date as we realize the synergies
associated  with this  acquisition  following  the  integration  of systems  and
operating practices later in 2003.


     Because  we are 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 and six months ended June 30,
2003 and 2002 was as follows:


 -------------------------------------------------------------------------------------------
                                              Three Months             Six Months
-------------------------------------------------------------------------------------------
                                             2003        2002       2003       2002
                                             ----        ----       ----       -----
                                                               

Primarily rate-regulated operations
      AmerenUE (a)                           $ 105       $ 105      $ 172      $ 154
      CILCORP (b)                                -           -          3          -
      AmerenCIPS                                 3           7          4          8
-------------------------------------------------------------------------------------------
                                             $ 108       $ 112      $ 179      $ 162
-------------------------------------------------------------------------------------------

Primarily non rate-regulated operations
      Generating Company (a)(c)                 10           3         49         16

Other (d)                                       (8)          -        (17)        (4)
------------------------------------------------------------------------------------------
Ameren net income                            $ 110       $ 115      $ 211      $ 174
------------------------------------------------------------------------------------------

(a)  Includes  earnings from  interchange  sales by  AmerenEnergy  that provided
     approximately  $11 million and $33 million of AmerenUE's  net income in the
     three  and six  months  ended  June 30,  2003  (2002 - second  quarter - $4
     million;  year-to-date - $9 million).  Includes  earnings from  interchange
     sales by  AmerenEnergy  that  provided  approximately  $5  million  and $17
     million  of  Generating  Company's  net  income in the three and six months
     ended June 30, 2003 (2002 - second quarter - $2 million;  year-to-date - $5
     million).
(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.


                                       21



(c)  Includes  earnings  from  contracts to supply  power to our  rate-regulated
     AmerenCIPS customers.
(d)  Includes  corporate general and administrative  expenses,  transition costs
     associated  with the  CILCORP  acquisition,  stock  compensation  and other
     unregulated operations.



Electric Operations

     The following table  represents the favorable  (unfavorable)  variations on
electric  margin  for the  three and six  months  ended  June 30,  2003 from the
comparable period in 2002:

--------------------------------------------------------------------------------
                                                Three Months         Six Months
--------------------------------------------------------------------------------
Electric Revenues:
   CILCORP                                         $ 124             $   204
   Interchange revenues                                5                  41
   Effect of weather (estimate)                      (60)                (32)
   Rate reductions                                    (5)                (16)
   Growth and other (estimate)                        10                  (2)
   EEI                                               (36)                (48)
--------------------------------------------------------------------------------
    Total variation in electric operating revenues    38                 147
--------------------------------------------------------------------------------
Fuel and Purchased Power:
   Fuel:
     Generation                                    $  (2)                (15)
     Price                                            11                  10
     Generation efficiencies and other                (2)                 (1)
   Purchased power                                    25                  48
   CILCORP                                           (57)                (92)
   EEI                                                 1                   8
--------------------------------------------------------------------------------
    Total variation in fuel and purchased power      (24)                (42)
--------------------------------------------------------------------------------
Change in electric margin                          $  14             $   105
--------------------------------------------------------------------------------

     Electric margin increased $14 million for the three months and $105 million
for the six months  ended June 30,  2003,  compared to the same periods in 2002.
Increases in electric  margin in the second quarter and first six months of 2003
were  primarily  attributable  to the  acquisition  of  CILCORP,  and  increased
interchange  margins,   partially  offset  by  unfavorable  weather  conditions.
CILCORP's  electric  margin for the three and six months ended June 30, 2003 was
$67  million  and $112  million,  respectively.  Interchange  margins  increased
approximately $18 million in the second quarter and approximately $60 million in
the first six months of 2003 due to improved  power prices in the energy markets
and solid low-cost  generation  availability.  Average power prices increased to
approximately  $36 per  megawatthour  in the  first  six  months  of  2003  from
approximately $24 per megawatthour in the first six months of 2002.

     The unfavorable  weather conditions were primarily due to mild early summer
weather in the second  quarter of 2003 versus  warmer than normal  conditions in
the  same  period  in  2002.  In  Ameren's  pre-acquisition  service  territory,
weather-sensitive   residential  and  commercial  electric   kilowatthour  sales
declined 17% and 8%, respectively, in the second quarter of 2003 (year-to-date -
1% and 2%, respectively)  compared to the second quarter of 2002. Cooling degree
days were  approximately 30% and 40% less in the second quarter of 2003 compared
to normal and the prior year period, respectively.

     Rate reductions of $50 million and $30 million  effective April 1, 2002 and
2003, respectively,  relating to the 2002 rate case settlement in Missouri, also
negatively  impacted electric revenues in the first six months of 2003. Revenues
will be further  negatively  affected by the settlement of the Missouri electric
rate case,  due to an additional  $30 million of annual  electric rate reduction
effective April 1, 2004.

     The growth and other line item  includes  the sale of  emission  credits at
AmerenUE.  The sale of  emission  credits at  AmerenUE  increased  in the second
quarter of 2003 by $4 million,  but decreased in the first six months of 2003 by
$9  million,  compared  to the same  periods in 2002.  In  addition,  industrial
electric kilowatthour sales increased  approximately 6% in the second quarter of
2003 in our pre-acquisition

                                       22



service territory.

     EEI sales  decreased  compared to the prior  periods due to lower  emission
credits and decreased sales to its principal customer,  which also resulted in a
decrease in fuel and purchased  power.  EEI's sales of emission credits were $10
million  in the  second  quarter  and  first six  months of 2003  (2002 - second
quarter and year-to-date - $38 million).

     Fuel and  purchased  power  increased  in the second  quarter and first six
months 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 $33
million in the second  quarter  and $50  million in the first six months 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 that were netted for the three and six months ended June 30,
2002 were $133 million and $374 million, respectively, 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 $11 million in the second quarter of 2003 and $36
million in the first six  months of 2003,  compared  to the same  periods in the
prior year.  The increases in margin were  primarily due to the  acquisition  of
CILCORP (second quarter - $16 million; year-to-date - $36 million).

Other Operating Expenses

Other Operations and Maintenance

     Other  operations  and  maintenance  expenses  increased $19 million in the
second  quarter and $56 million in the first six months of 2003  compared to the
prior year periods,  primarily due to the addition of CILCORP's other operations
and  maintenance  expenses  (second  quarter - $44 million;  year-to-date  - $73
million), CILCORP's transition costs and higher employee benefit costs primarily
related to higher  healthcare and pension  costs.  The increases in expense were
partially  offset  by  lower  labor  costs  related  to our  voluntary  employee
retirement  program instituted at the end of 2002 and lower maintenance costs at
our power plants primarily due to the number and timing of outages.

Depreciation and Amortization

     Depreciation and amortization  expenses increased $26 million in the second
quarter  and $43  million  in the first  six  months  of 2003,  compared  to the
year-ago  periods.  The increase was  primarily due to the addition of CILCORP's
depreciation and amortization (second quarter - $21 million;  year-to-date - $35
million),  and the completion of four combustion turbine generating units in the
third  and  fourth  quarters  of  2002  at  Generating  Company.  The  increased
depreciation  and  amortization  expense  was  partially  offset by a $5 million
reduction in depreciation  expense in the first quarter of 2003 resulting from a
$20 million annual depreciation  reduction of depreciation rates. This reduction
was based on the updated analysis of asset values, service lives and accumulated
depreciation  levels that were required by our 2002 Missouri  electric rate case
settlement.



                                       23



Income Taxes

     Income tax expense  decreased $6 million in the second  quarter of 2003, as
compared to the second  quarter of 2002,  primarily due to lower pre-tax  income
and a lower effective tax rate.  Income tax expense  increased $8 million in the
first six months of 2003, as compared to the same period in 2002,  primarily due
to higher pre-tax income.

Other Taxes

     Other  taxes  expense  increased  $8 million in the second  quarter and $18
million  in the first six  months of 2003,  compared  to the  year-ago  periods,
primarily  due to the  acquisition  of  CILCORP  (second  quarter - $9  million;
year-to-date - $17 million).

Other Income and Deductions

     Other income and deductions  (excluding income taxes) increased $32 million
in the second  quarter of 2003 and $34  million in the first six months of 2003,
compared to the same  periods in the prior year,  primarily  due to expensing of
economic  development and energy  assistance  programs  required in the Missouri
electric  rate case  settlement  in 2002 ($26  million)  and an  increase in the
minority interest expense related to EEI's higher contribution in June 2002. 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  $17  million  in the second  quarter  and $33
million  in the first six  months of 2003,  compared  to the  year-ago  periods,
primarily due to the  assumption of CILCORP debt (second  quarter - $12 million;
year-to-date - $22 million).  In addition,  interest  expense was higher in 2003
due to 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.


LIQUIDITY AND CAPITAL RESOURCES

Operating

     Our cash flows  provided by operating  activities  totaled $430 million for
the first six months of 2003,  compared  to $346  million for the same period in
2002. Cash provided by operating  activities  increased in 2003,  primarily as a
result of higher electric and gas margins and the timing of receipts on accounts
receivable.

     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 $816 million in the first six
months of 2003,  compared  to $411  million  for the same  period  in 2002.  The
increase  over the prior year period was  primarily  related to the cash paid of
$489  million  for the  acquisition  of CILCORP on January  31,  2003 and Medina
Valley on February 4, 2003.

     In addition, in the first six months of 2003, construction  expenditures in
our rate-regulated operations were $300 million (2002 - $289 million), primarily
related to various  upgrades at our power plants.

                                       24




Construction expenditures in our non rate-regulated operations of $32 million in
the first six months of 2003  decreased  from the first six months of 2002 ($112
million) due to reduced  construction of combustion  turbine generating units in
2002. Capital expenditures  primarily relating to our rate-regulated  operations
are expected to approximate $675 million in 2003.

     We  continually  review our  generation  portfolio and expected  electrical
needs, and as a result, we could modify our plan for generation capacity,  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 used in  financing  activities  totaled  $141 million in the
first six months of 2003 as  compared to our cash flows  provided  by  financing
activities  of $148  million  in the first six  months  of 2002.  Our  principal
financing  activities for the first six months of 2003 included the  redemptions
of short-term  and long-term  debt, as well as payments of dividends,  partially
offset by  issuances  of  long-term  debt and common  stock.  In addition to the
activities  above,  the first six  months 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  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 June 30, 2003,  Ameren had committed  credit
facilities,  expiring at various  dates  through  2005,  totaling  $772 million,
excluding  AmerenCILCO  facilities of $59 million, EEI facilities of $41 million
and nuclear fuel lease  facilities  of $120  million.  Ameren's  $772 million of
committed credit facilities were available for use by two of our  rate-regulated
subsidiaries,  AmerenUE and AmerenCIPS,  and Ameren Services Company through our
utility money pool  arrangement,  and $600 million of this amount may be used 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   through  our
non-regulated  subsidiary money pool arrangement.  AmerenCILCO could also access
up to $600 million of these  facilities  through direct  borrowings  from Ameren
Corporation,  subject to reduction based on use by our affiliates and subject to
a $250 million  intercompany  borrowing  restriction  pursuant to  AmerenCILCO's
financing  authority  under the  PUCHCA.  Subject to the  receipt of  regulatory
approval,  which is being pursued,  AmerenCILCO  will participate in the utility
money pool  arrangement.  These committed credit  facilities are used to support
our commercial  paper programs under which $177 million was  outstanding at June
30, 2003. At June 30, 2003,  $595 million was unused and  available  under these
committed credit facilities.

     In July 2003, Ameren Corporation entered into two new credit agreements for
$470 million in revolving  credit  facilities  to be used for general  corporate
purposes,  including  the support of our  commercial  paper  programs.  The $470
million in new  facilities  includes a $235  million  364-day  revolving  credit
facility and a $235 million  three-year  revolving  credit  facility.  These new
credit facilities  replaced Ameren  Corporation's  existing $270 million 364-day
revolving  credit  facility,  which  matured  in July  2003  and a $200  million
facility,  which would have matured in December 2003. The new credit  facilities
contain  provisions which require us to meet minimum Employee  Retirement Income
Security Act (ERISA) funding requirements for our pension plan. The prior credit
facilities included more restrictive  provisions related to the funded status of
our pension plan, which are not present in the new facilities. In addition, in

                                       25



July 2003,  Ameren  Corporation  entered into an  amendment of an existing  $130
million  multi-year  credit facility that similarly  modified the  ERISA-related
provisions in this facility. As a result, all of Ameren Corporation's facilities
require us to meet minimum  ERISA  funding  requirements,  but do not  otherwise
limit the underfunded  status of our pension plan. At July 31, 2003, all of such
borrowing capacity under these facilities was available.

     We also have two bank credit agreements totaling $41 million that expire in
2004 at EEI. At June 30, 2003, $41 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 June 30, 2003,  the maximum amount that could be financed under
the agreement was $120 million. At June 30, 2003, $93 million was financed under
the lease.

     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.  Our  inability  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.

Financial 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.  The  majority  of Ameren's  committed  credit
facilities  require the borrower to represent in  connection  with any borrowing
under the facility that no material  adverse  change has occurred  since certain
dates.  Ameren's  financing  arrangements do not contain credit rating triggers,
except for three funded bank term loans at AmerenCILCO  totaling $105 million at
June 30, 2003.

     At  June  30,  2003,  Ameren  Corporation  and  its  subsidiaries  were  in
compliance with their financial agreement provisions and covenants.

Debt Issuances and Redemptions

     On February 10, 2003,  AmerenCILCO  repaid $25 million first mortgage bonds
6.82% Series which matured on that date.

     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 that matured 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 debt.

     On April 1, 2003, AmerenCIPS repaid $40 million first mortgage bonds 6.375%
Series Z which matured on that date.  AmerenCIPS  also redeemed,  in April 2003,
prior to maturity and at par, its $50 million first mortgage bonds 7.5% Series X
due July 1, 2007.


                                       26



     In April 2003,  three series of  AmerenCILCO's  first  mortgage  bonds were
redeemed prior to maturity.  These included  AmerenCILCO's $65 million principal
amount 8.20% series due January 15, 2022,  at a redemption  price of 103.29% and
two 7.8% series totaling $10 million principal amount due February 9, 2023, at a
redemption price of 103.90%.

     On June 30,  2003,  AmerenEnergy  Medina  Valley  Cogen,  LLC,  an indirect
subsidiary of AmerenEnergy  Medina Valley Cogen (No. 4), LLC,  repaid,  prior to
maturity,  a $36 million,  secured term loan with an effective  interest rate of
7.65% and terminated two related interest rate swaps. This redemption eliminated
the outstanding bank debt at AmerenEnergy Medina Valley Cogen, LLC.

     In July 2003,  AmerenUE  issued $200 million of 5.10% Senior  Secured Notes
due August 1, 2018.  AmerenUE  received net proceeds  after fees of $198 million
which,  along with other funds were used to repay  short-term  debt  incurred to
fund the maturity of $100 million  principal  amount 7.65% first  mortgage bonds
due July 15,  2003  and to repay  $21  million  of other  short-term  debt.  The
remaining proceeds will be used to redeem and refinance,  prior to maturity, $75
million principal amount of outstanding 7.15% first mortgage bonds due August 1,
2023 at a redemption price of 103.01% of par, plus accrued  interest,  in August
2003.

     See also 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 six months 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 was paid on June
30, 2003 to shareholders of record on June 11, 2003.

Off-Balance Sheet Arrangements

     At June 30, 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.

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  six  months 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    Fixed electric rates in our Illinois service territory;
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.

                                       27




     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 a  1940's-era  generating  plant  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 $27 million in Missouri.  See Note 3 - Rate and Regulatory  Matters
to our Consolidated  Financial  Statements under Item 1 of Part I of this report
for  additional  information.   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.

     International   Brotherhood   of   Electrical   Workers   (IBEW)   and  the
International  Union of Operating  Engineers  (IUOE) labor agreements for eleven
bargaining  units covering 52% of our entire  workforce  expired between April 1
and July 1, 2003. The principal  issues being  negotiated are wages,  work rules
and our  proposal to change the  employee  medical  benefits  program to require
employees to pay for a greater portion of their benefit coverage.

     During  July  2003,  after  engaging  in  extensive  negotiations  with the
collective bargaining units, we finalized new tentative agreements with seven of
the bargaining units with terms expiring in 2006. The membership of three of the
bargaining  units have  ratified the  agreements  with respect to wages and work
rules and the membership of four  bargaining  units is expected to vote on their
new  agreement in the third  quarter of 2003.  Changes to the  employee  medical
benefits  program  have  been  agreed  to  with  a  joint  bargaining  committee
representing  all unions;  however,  the changes cannot be  implemented  without
ratification by a majority of the collective membership of all bargaining units.
We are unable to predict whether the agreements will be ratified or what action,
if any, the  collective  bargaining  units will take in the event the agreements
are not  ratified or the  response of other  union-represented  employees to any
action by its  employees.  We are still  negotiating  as to wages and work rules
with three bargaining units, which represent approximately 29% of our workforce.
We are unable to determine  what, if any,  impact these labor matters could have
on our future financial condition, results of operations or liquidity.

     At December  31,  2002,  we recorded a minimum  pension  liability  of $102
million,   after  taxes,  which  resulted  in  a  charge  to  Accumulated  Other
Comprehensive Income (Loss)(OCI) and a reduction in stockholders'  equity. Based
on changes in interest  rates,  we may need to change our actuarial  assumptions
for our pension plan at December 31, 2003,  which could result in a  requirement
to record an additional minimum pension liability.

     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.



                                       28



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.  Refer to  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 1, 2002,  as amended by Form 10-K/A,
for a discussion  of the critical  accounting  policies that we believe are most
difficult,  subjective or complex.  In the discussion below, we have outlined an
additional  accounting  policy  that has  developed  due to our  acquisition  of
CILCORP.  A future change in the assumptions or judgments applied in determining
the  following  matter,  among  others,  could have a material  impact on future
financial results.



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

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.

                                       29




     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 June  30,  2003,  if  interest  rates
increased by 1%, our annual interest expense would increase by approximately $11
million and net income would  decrease by  approximately  $7 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 June 30,  2003,  we had  approximately  $168
million invested in 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.

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 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 June 30,  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.

                                       30



     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 three and six months
ended June 30, 2003:

---------------------------------------------------------------------------------------------------------
                                                                                      Three      Six
                                                                                      months    months
---------------------------------------------------------------------------------------------------------
                                                                                     

Fair value of contracts at beginning of period, net                                  $   -     $   3
   Contracts which were realized or otherwise settled during the period                  5        (4)
   Changes in fair values attributable to changes in valuation techniques and            -         -
   assumptions
   Fair value of new contracts entered into during the period                            -         -
   Other changes in fair value                                                          (4)        2
----------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at end of period, net                            $   1     $   1
----------------------------------------------------------------------------------------------------------


                                       31






     Maturities of contracts as of June 30, 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                    $ -          $ -          $ -          $  -          $ -
Prices provided by other external
   sources (b)                              -           (1)          (1)            -           (2)
Prices based on models and other
   valuation methods (c)                    3            1           (1)            -            3
---------------------------------------------------------------------------------------------------------
Total                                     $ 3          $ -         $ (2)         $  -          $ 1
---------------------------------------------------------------------------------------------------------
(a)  Contracts  of less than $1  million  were with  non-investment-grade  rated
     counterparties.
(b)  Principally power forward values based on NYMEX prices for over-the-counter
     contracts and natural gas swap values based primarily on Inside FERC.
(c)  Principally  coal and sulfur dioxide option values based on a Black-Scholes
     model that includes  information  from external  sources and our estimates.
     Also includes power forward values based on our estimates.



ITEM 4.  Controls and Procedures.

     (a) Evaluation of Disclosure Controls and Procedures

     As of  June  30,  2003,  the  principal  executive  officer  and  principal
financial  officer of Ameren have evaluated the  effectiveness of the design and
operation of Ameren's  disclosure  controls and  procedures (as defined in Rules
13a - 15(e) and 15d - 15 (e) of the Securities  Exchange Act of 1934, as amended
(Exchange Act)). Based upon that evaluation, the principal executive officer and
principal  financial  officer  of Ameren  have  concluded  that such  disclosure
controls and  procedures  are effective in timely  alerting them to any material
information  relating  to Ameren  and its  consolidated  subsidiaries,  which is
required  to be included in Ameren's  reports  filed or  submitted  with the SEC
under the Exchange Act.

     (b) Change in Internal Controls

     There has been no  significant  change in Ameren's  internal  control  over
financial  reporting  that occurred  during  Ameren's most recent fiscal quarter
that has  materially  affected,  or is reasonably  likely to materially  affect,
Ameren's internal control over financial reporting.


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;


                                       32



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;
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.

                                       33





                           PART II. OTHER INFORMATION

ITEM 1.  Legal Proceedings.

     On June 18,  2003,  twenty  retirees and  surviving  spouses of retirees of
Ameren  Corporation or our predecessors or subsidiaries (the plaintiffs) filed a
complaint in the U.S.  District Court,  Southern  District of Illinois,  against
Ameren,  and our subsidiaries,  Union Electric  Company,  operating as AmerenUE,
Central Illinois Public Service Company, operating as AmerenCIPS,  Ameren Energy
Resources Company, Ameren Energy Generating Company and Ameren Services Company,
and against our Retiree Medical Plan (the defendants). The retirees were members
of various  local labor unions of the  International  Brotherhood  of Electrical
Workers (IBEW) and the International  Union of Operating  Engineers (IUOE).  The
complaint alleges the following:

o    the labor  organizations which represented the plaintiffs have historically
     negotiated  retiree medical  benefits with the defendants and that pursuant
     to the negotiated  collective  bargaining  agreements and other  negotiated
     documents,  the plaintiffs are guaranteed medical benefits at no cost or at
     a fixed maximum cost during their retirement;
o    Ameren has unilaterally  announced that,  beginning in 2004,  retirees must
     pay a portion of their own health care  premiums  and either an  increasing
     portion  of  their  dependents'   premiums  or  newly  imposed  dependents'
     premiums,  and that surviving  spouses will be paying increased amounts for
     their medical benefits;
o    the defendants' actions deprive the plaintiffs of vested benefits and thus
     violate  the  Employee   Retirement  Income  Security  Act  and  the  Labor
     Management   Relations  Act  of  1947,  and  constitute  a  breach  of  the
     defendants' fiduciary duties; and
o    the defendants are estopped from changing the plan benefits.

     The  plaintiffs  have filed the  complaint on behalf of  themselves,  other
similarly situated former  non-management  employees and their surviving spouses
who retired from January 1, 1992 through  October 1, 2002,  and on behalf of all
subsequent  non-management  retirees and their  surviving  spouses  whose vested
medical  benefits are reduced or are threatened with  reduction.  The plaintiffs
seek to have this lawsuit  certified as a class action,  seek injunctive  relief
and declaratory relief, seek actual damages for any amounts they are made to pay
as a result of the  defendants'  actions,  and seek payment of attorney fees and
costs.  On August 11, 2003,  the  defendants  filed  motions to dismiss  various
counts of the complaint. We are unable to predict the outcome of this lawsuit or
the impact of the outcome on our  financial  position,  results of operations or
liquidity.

     Reference  is  made  to  Note  3 to the  Notes  to  Consolidated  Financial
Statements in our Form 10-Q for the quarterly  period ended March 31, 2003 for a
discussion  of the  Missouri  Supreme  Court's  opinion  issued  in  April  2003
upholding  the  adoption  of  affiliate  rules by the  Missouri  Public  Service
Commission for Missouri's  gas and electric  utilities.  AmerenUE had originally
appealed  the adoption of the  asymmetric  pricing  provisions  contained in the
affiliate  rules.  In May 2003,  the Missouri  Supreme  Court denied  AmerenUE's
Motion for  Reconsideration  of its April 2003 opinion which makes the affiliate
rules  applicable  to AmerenUE.  We do not expect these rules to have a material
adverse  impact on our  future  financial  position,  cash  flows or  results of
operations.

     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 (as amended by Form  10-K/A),  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,  and to  Item  1.  "Legal
Proceedings"  in Part II of our Form 10-Q for the  quarterly  period ended March
31, 2003,  for a discussion of a number of lawsuits that name our  subsidiaries,
AmerenCIPS,  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 our Form 10-Q for the quarterly period ended March 31, 2003,


                                       34


eleven additional  lawsuits have been filed against the Ameren companies.  These
lawsuits,  like the previous  cases,  were mostly filed in the Circuit  Court of
Madison County in 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 our Form 10-Q for
the quarterly period ended March 31, 2003, the Ameren companies have settled one
case. To date, a total of 164 asbestos-related  lawsuits have been filed against
the Ameren companies,  of which 84 are pending, 17 have been settled and 63 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 4.  Submission of Matters To a Vote of Security Holders.

     At our annual meeting of stockholders held on April 22, 2003, the following
matters were  presented to the meeting for a vote and the results of such voting
are as follows:



     Item (1): Election of Directors.

                                                                                               Non-Voted
                  Name                                    For                Withheld           Brokers
                  ----                                    ---                --------           ---------
                                                                                           
                  William E. Cornelius                119,277,149           19,346,548               0
                  Clifford L. Greenwalt               134,924,430            3,699,267               0
                  Thomas A. Hays                      135,025,530            3,598,167               0
                  Richard A. Liddy                    134,422,688            4,201,009               0
                  Gordon R. Lohman                    135,085,800            3,537,897               0
                  Richard A. Lumpkin                  134,611,968            4,011,729               0
                  John Peters MacCarthy               135,077,727            3,545,970               0
                  Hanne M. Merriman                   135,046,806            3,576,891               0
                  Paul L. Miller, Jr.                 134,794,875            3,828,822               0
                  Charles W. Mueller                  134,638,714            3,984,983               0
                  Douglas R. Oberhelman               134,492,968            4,130,729               0
                  Harvey Saligman                     134,620,991            4,002,706               0




     Item (2): Stockholder Proposal Relating to the Storage of Irradiated Fuel Rods at the Callaway
               Nuclear Plant.
                                                                                           Non-Voted
                     For                  Against               Abstain                     Brokers
                     ---                  -------               -------                    ---------
                                                                                
                  12,904,334              88,363,511            7,711,721                 46,020,667

                  
                   Broker shares included in the quorum but not voting on the item.
                  



ITEM 5.  Other Information.

     Ms. Hanne M. Merriman,  a director of Ameren  Corporation,  died on July 4,
2003.  No decision  has been made as to who,  if anyone,  will be  appointed  to
replace Ms. Merriman.

     Reference  is made to Item 2.  "Properties"  in Part I of our  2002  Annual
Report on Form 10-K for a  discussion  of our  membership  in MAIN  (Mid-America
Interconnected  Network),  which  is one of the  regional  electric  reliability
councils  organized for  coordinating the planning and operation of the nation's
bulk power supply.  In response to the withdrawal  notices filed by Commonwealth
Edison and  Illinois


                                       35


Power,  also members of MAIN,  AmerenUE,  AmerenCIPS  and  AmerenCILCO  provided
formal  written  notice to the MAIN Board of Directors on June 23, 2003 of their
intent to withdraw from MAIN effective  January 1, 2005.  These Ameren companies
intend to join another Regional  Reliability  Organization  (RRO) prior to their
withdrawal from MAIN becoming  effective.  Until their  withdrawal is effective,
they will  continue  to honor all of their  obligations  as members of MAIN.  If
these Ameren  companies do not join another RRO, they may withdraw  their notice
of intent to withdraw from MAIN.

     Any stockholder  proposal  intended for inclusion in the proxy material for
our 2004 annual meeting of  stockholders  must be received by us by November 15,
2003.  In  addition,  under our  By-Laws,  stockholders  who  intend to submit a
proposal in person at an annual meeting, or who intend to nominate a director at
a meeting,  must provide  advance  written  notice  along with other  prescribed
information. In general, such notice must be received by our Secretary not later
than 60 nor  earlier  than 90 days  prior to the  anniversary  of the  preceding
year's annual  meeting.  For our 2004 annual  meeting of  stockholders,  written
notice of any  in-person  stockholder  proposal or director  nomination  must be
received not later than February 22, 2004 or earlier than January 23, 2004.  Our
2004 annual meeting of stockholders is scheduled to be held on April 27, 2004.

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

      (a)(i) Exhibits filed herewith.

             31.1 - Rule  13a   -14(a)/15d-14(a)   Certification   of  Principal
                    Executive   Officer   (required   by  Section   302  of  the
                    Sarbanes-Oxley Act of 2002).

             31.2 - Rule   13a-14(a)/15d-14(a)    Certification   of   Principal
                    Financial   Officer   (required   by  Section   302  of  the
                    Sarbanes-Oxley Act of 2002).

             32.1 - Section 1350  Certification of Principal  Executive  Officer
                    (required by Section 906 of the Sarbanes-Oxley Act of 2002).

             32.2 - Section 1350  Certification of Principal  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 July 28, 2003  establishing the
                    5.10% Senior Secured Notes due 2018 (AmerenUE Form 8-K dated
                    July 28, 2003, Exhibit 4.2).

             4.2 -  Supplemental  Indenture  dated July 15, 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 DD,
                    5.10%  due 2018  (AmerenUE  Form 8-K  dated  July 28,  2003,
                    Exhibit 4.4).

     (b) Reports on Form 8-K. Ameren  Corporation filed the following reports on
         Form 8-K during the quarterly period ended June 30, 2003:

         -----------------------------------------------------------------------
                                                    Items        Financial
                   Date of Report                Reported     Statements Filed
         -----------------------------------------------------------------------
                   April 30, 2003                 7, 9, 12          (a)
                   May 23, 2003                     5, 7            None
                   May 30, 2003                      5              None

               (a) Unaudited  consolidated  operating  statistics,  consolidated
               statement of income,  consolidated balance sheet and consolidated
               statement of cash flows for three months ended March 31, 2003 and
               2002.

         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.


                                       36




               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.


                                       37






                                    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:  August 14, 2003









                                       38