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 The Quarterly Period Ended September 30, 2002

[  ]     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            .
                           ------------           -----------



     Shares outstanding of Ameren  Corporation's common stock as of November 12,
2002: Common Stock, $.01 par value - 153,613,096








                               AMEREN CORPORATION

                                      INDEX
                                                                           Page
                                                                           ----
                                                                      
PART I.      Financial Information

   ITEM 1.   Financial Statements (Unaudited)
             Consolidated Balance Sheet at September 30, 2002 and
             December 31, 2001 . . . . . . . . . . . . . . . . . . . . . .   2
             Consolidated Statement of Income for the three and nine
             months ended September 30, 2002 and 2001  . . . . . . . . . .   3
             Consolidated Statement of Cash Flows for the nine months
             ended September 30, 2002 and 2001 . . . . . . . . . . . . . .   4
             Consolidated Statement of Common Stockholders' Equity for
             the three and nine months ended September 30, 2002 and 2001 .   5
             Notes to Consolidated Financial Statements  . . . . . . . . .   6

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

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

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

PART II.     Other Information

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

   ITEM 5.   Other Information . . . . . . . . . . . . . . . . . . . . . .  33

   ITEM 6.   Exhibits and Reports on Form 8-K  . . . . . . . . . . . . . .  34

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

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



This Form 10-Q  contains  "forward-looking  statements"  within  the  meaning of
Section 21E of the Securities Exchange Act of 1934.  Forward-looking  statements
should be read with the cautionary  statements and important factors included in
this Form 10-Q at Item 2.  "Management's  Discussion  and  Analysis of Financial
Condition and Results of Operations," under the heading "Safe Harbor Statement."
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)
                                                      September 30, December 31,
                                                          2002        2001
                                                      -----------   ------------
                                                              
ASSETS:
Property and plant, at original cost:
   Electric                                              $ 14,245    $ 13,664
   Gas                                                        551         532
   Other                                                      144         105
                                                         --------    --------
                                                           14,940      14,301
   Less accumulated depreciation and amortization           6,808       6,535
                                                         --------    --------
                                                            8,132       7,766
Construction work in progress:
   Nuclear fuel in process                                    124          97
   Other                                                      433         564
                                                         --------    --------
         Total property and plant, net                      8,689       8,427
                                                         --------    --------
Investments and other assets:
   Investments                                                 38          39
   Nuclear decommissioning trust fund                         162         187
   Other                                                      153         114
                                                         --------    --------
         Total investments and other assets                   353         340
                                                         --------    --------
Current assets:
   Cash and cash equivalents                                  629          67
   Accounts receivable - trade (less allowance
         for doubtful accounts of $8 and $9, respectively)    323         218
   Unbilled revenue                                           159         171
   Other accounts and notes receivable                         27          71
   Materials and supplies, at average cost -
      Fossil fuel                                             148         159
      Other                                                   132         136
   Other                                                       42          41
                                                         --------    --------
         Total current assets                               1,460         863
                                                         --------    --------
Regulatory assets:
   Deferred income taxes                                      552         604
   Other                                                      160         167
                                                         --------    --------
     Total regulatory assets                                  712         771
                                                         --------    --------
Total Assets                                             $ 11,214    $ 10,401
                                                         ========    ========
CAPITAL AND LIABILITIES:
Capitalization:
   Common stock, $.01 par value, 400.0 shares
     authorized - shares outstanding of 153.5
     and 138.0, respectively                             $      2    $      1
   Other paid-in capital, principally premium on
     common stock                                           2,180       1,614
   Retained earnings                                        1,868       1,733
   Accumulated other comprehensive income                       7           5
   Other                                                      (10)         (4)
                                                         --------    --------
      Total common stockholders' equity                     4,047       3,349
                                                         --------    --------
   Preferred stock not subject to mandatory redemption        194         235
   Long-term debt                                           3,484       2,835
                                                         --------    --------
         Total capitalization                               7,725       6,419
                                                         --------    --------
Minority interest in consolidated subsidiaries                 14           4
Current liabilities:
   Current maturities of long-term debt                       255         139
   Short-term debt                                              6         641
   Accounts and wages payable                                 175         392
   Accumulated deferred income taxes                            5          58
   Taxes accrued                                              346         132
   Other                                                      243         219
                                                         --------    --------
         Total current liabilities                          1,030       1,581
                                                         --------    --------
Accumulated deferred income taxes                           1,602       1,563
Accumulated deferred investment tax credits                   152         158
Regulatory liabilities                                        153         172
Other deferred credits and liabilities                        538         504
                                                         --------    --------
Total Capital and Liabilities                            $ 11,214    $ 10,401
                                                         ========    ========
See Notes to Consolidated Financial Statements.




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

                                                          Three Months Ended      Nine Months Ended
                                                              September 30,          September 30,
                                                          ------------------     -------------------
                                                                               
                                                             2002       2001       2002       2001
OPERATING REVENUES:                                        -------    -------    -------    -------
   Electric                                                $ 1,201    $ 1,380    $ 3,132    $ 3,241
   Gas                                                          30         40        202        255
   Other                                                         1          2          4          7
                                                           -------    -------    -------    -------
      Total operating revenues                               1,232      1,422      3,338      3,503
                                                           -------    -------    -------    -------

OPERATING EXPENSES:
   Operations
      Fuel and purchased power                                 314        484        975      1,153
      Gas                                                       17         21        129        172
      Other                                                    197        173        567        518
                                                           -------    -------    -------    -------
                                                               528        678      1,671      1,843
   Maintenance                                                  81         78        268        296
   Depreciation and amortization                               108        104        321        303
   Income taxes                                                144        176        265        286
   Other taxes                                                  74         75        211        203
                                                           -------    -------    -------    -------
      Total operating expenses                                 935      1,111      2,736      2,931
                                                           -------    -------    -------    -------

OPERATING INCOME                                               297        311        602        572

OTHER INCOME AND (DEDUCTIONS):
   Allowance for equity funds used during construction           1          4          3          8
   Miscellaneous, net -
     Miscellaneous income                                        5         10         13         14
     Miscellaneous expense                                      (3)        (3)       (46)       (11)
     Income taxes                                               (1)        (4)         9         (4)
                                                           -------    -------    -------    -------
      Total other income and (deductions)                        2          7        (21)         7
                                                           -------    -------    -------    -------


INTEREST CHARGES AND PREFERRED DIVIDENDS:
   Interest                                                     57         51        162        149
   Allowance for borrowed funds used during construction        (1)        (3)        (4)        (6)
   Preferred dividends of subsidiaries                           3          3          9          9
                                                           -------    -------    -------    -------
      Net interest charges and preferred dividends              59         51        167        152
                                                           -------    -------    -------    -------

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
      ACCOUNTING PRINCIPLE                                     240        267        414        427

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
      PRINCIPLE, NET OF INCOME TAXES                             -          -          -         (7)
                                                           -------    -------    -------    -------

NET INCOME                                                 $   240    $   267    $   414    $   420
                                                           =======    =======    =======    =======

EARNINGS PER COMMON SHARE - BASIC:
    Income before cumulative effect of change
         in accounting principle                           $  1.64    $  1.94    $  2.88    $  3.11
    Cumulative effect of change in accounting
         principle, net of income taxes                        -          -          -        (0.05)
                                                           -------    -------    -------    -------
    Net income                                             $  1.64    $  1.94    $  2.88    $  3.06
                                                           =======    =======    =======    =======

EARNINGS PER COMMON SHARE -  ASSUMING DILUTION:
    Income before cumulative effect of change
         in accounting principle                           $  1.63    $  1.94    $  2.87    $  3.11
    Cumulative effect of change in accounting
         principle, net of income taxes                        -          -          -        (0.05)
                                                           -------    -------    -------    -------
    Net income                                             $  1.63    $  1.94    $  2.87    $  3.06
                                                           =======    =======    =======    =======

AVERAGE COMMON SHARES OUTSTANDING                            146.7      137.2      143.6      137.2

See Notes to Consolidated Financial Statements.


                                       3



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

                                                             Nine Months Ended
                                                                September 30,
                                                             -----------------
                                                                2002     2001
                                                               -----    -----
                                                                 
Cash Flows From Operating:
   Net income                                                  $ 414    $ 420
   Adjustments to reconcile net income to net cash
       provided by operating activities:
         Cumulative effect of change in accounting principle       -        7
         Depreciation and amortization                           321      303
         Amortization of nuclear fuel                             25       21
         Amortization of debt issuance costs and premium/
         discounts                                                 6        4
         Allowance for funds used during construction             (7)     (14)
         Deferred income taxes, net                               11       14
         Deferred investment tax credits, net                     (6)      (4)
         Other                                                     5      (11)
         Changes in assets and liabilities:
               Receivables, net                                  (49)     (28)
               Materials and supplies                             15      (50)
               Accounts and wages payable                       (217)    (176)
               Taxes accrued                                     214      265
               Assets, other                                     (16)       5
               Liabilities, other                                 17      (33)
                                                               -----    -----
Net cash provided by operating activities                        733      723
                                                               -----    -----
Cash Flows From Investing:
   Construction expenditures                                    (565)    (812)
   Allowance for funds used during construction                    7       14
   Nuclear fuel expenditures                                     (25)     (15)
   Other                                                           1        -
                                                               -----    -----
Net cash used in investing activities                           (582)    (813)
                                                               -----    -----

Cash Flows From Financing:
   Dividends on common stock                                    (279)    (261)
   Capital issuance costs                                        (35)       -
   Redemptions:
      Nuclear fuel lease                                           -      (64)
      Short-term debt                                           (635)       -
      Long-term debt                                            (158)     (30)
      Preferred stock                                            (41)       -
   Issuances:
      Common stock                                               635       12
      Nuclear fuel lease                                          31        3
      Short-term debt                                              -      255
      Long-term debt                                             893      161
                                                               -----    -----
Net cash provided by financing activities                        411       76
                                                               -----    -----

Net change in cash and cash equivalents                          562      (14)
Cash and cash equivalents at beginning of year                    67      126
                                                               -----    -----
Cash and cash equivalents at end of period                     $ 629    $ 112
                                                               =====    =====

Cash paid during the periods:
   Interest                                                    $ 142    $ 123
   Income taxes, net                                             111       78

See Notes to Consolidated Financial Statements.

                                       4



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



                                                                     Three Months Ended     Nine Months Ended
                                                                       September 30,           September 30,
                                                                     -------------------    -----------------
                                                                        2002       2001      2002     2001
                                                                      -------    ------     ------   -------
                                                                                        
Common stock
Beginning balance                                                     $     1    $    1     $    1   $     1
   Shares issued                                                            1         -          1         -
                                                                      -------    ------     ------   -------
                                                                            2         1          2         1
                                                                      -------    ------     ------   -------
Other paid-in capital
   Beginning balance                                                    1,826      1,581     1,614     1,581
   Shares issued (less issuance costs of $11, $ -, $20, and $ -,
   respectively)                                                          354         12       614        12
   Contracted stock purchase payment obligations                            -          -       (46)        -
   Employee stock awards                                                    -          -        (2)        -
                                                                      -------    -------    ------   -------
                                                                        2,180      1,593     2,180     1,593
                                                                      -------    -------    ------   -------

Retained earnings
   Beginning balance                                                    1,725      1,593      1,733    1,614
   Net income                                                             240        267        414      420
   Dividends                                                              (97)       (87)      (279)    (261)
                                                                      -------    -------    -------  -------
                                                                        1,868      1,773      1,868    1,773
                                                                      -------    -------    -------  -------

Accumulated other comprehensive income
   Beginning balance                                                        3         (6)         5        -
   Change in current period (see below)                                     4          1          2       (5)
                                                                      -------    -------    -------  -------
                                                                            7         (5)         7       (5)
                                                                      -------    -------    -------  -------

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

Total common stockholders' equity                                     $ 4,047    $ 3,357    $ 4,047  $ 3,357
                                                                      =======    =======    =======  =======


Comprehensive income, net of taxes
   Net income                                                         $   240    $   267    $   414  $   420
   Unrealized net gain/(loss) on derivative hedging instruments
        (net of income taxes of $3, $-, $4 and $(2), respectively)          3          -          4       (3)
   Reclassification adjustments for gains/(losses) included
        in net income (net of income taxes of $ -, $2, $(2) and $7,
        respectively)                                                       1          1         (2)       9
   Cumulative effect of accounting change, net of income taxes of
        $(7)                                                                -          -          -      (11)
                                                                      -------    -------    -------  -------
           Total comprehensive income, net of taxes                   $   244    $   268    $   416  $   415
                                                                      =======    =======    =======  =======

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

Common stock shares at beginning of period                              144.8      137.2      138.0    137.2
   Shares issued for financing purposes                                   8.0          -       13.8        -
   Shares issued for dividend reinvestment and stock purchase plan
   and 401K plans                                                         0.7          -        1.7        -
                                                                      -------    -------    -------  -------
Common stock shares at end of period                                    153.5      137.2      153.5    137.2
                                                                      =======    =======    =======  =======


See Notes to Consolidated Financial Statements.


                                       5


AMEREN CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
September 30, 2002


NOTE 1 - Summary of Significant Accounting Policies

Basis of Presentation

     Our financial  statements  reflect all  adjustments  (which include normal,
recurring adjustments) necessary, in our opinion, for a fair presentation of the
interim  results.  These  statements  should  be read in  conjunction  with  the
financial statements and the notes thereto included in our 2001 Annual Report on
Form 10-K.

     When we  refer  to  Ameren,  our,  we or us,  we are  referring  to  Ameren
Corporation 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.

Earnings Per Share

     The  calculation of earnings per share resulted in dilution of $.01 for the
quarter and nine months ended  September 30, 2002.  There was no dilution in the
prior year  periods.  The  reconciling  item in each of the  periods was assumed
stock option  conversions,  which increased the number of shares  outstanding in
the  diluted  earnings  per share  calculation  by 340,210  shares for the three
months ended September 30, 2002 (2001 - 296,137) and 345,650 shares for the nine
months ended September 30, 2002 (2001 - 339,714).

Accounting Changes and Other Matters

     In January 2001,  we adopted  Statement of Financial  Accounting  Standards
(SFAS) No. 133, "Accounting for Derivative  Instruments and Hedging Activities."
The  impact  of that  adoption  resulted  in a  cumulative  effect  charge of $7
million,  after  taxes,  to  the  income  statement,  and  a  cumulative  effect
adjustment of $11 million after taxes to Accumulated Other Comprehensive  Income
(OCI), which reduced common stockholders' equity.

     On January 1, 2002, we adopted SFAS No. 141,  "Business  Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS 141 requires business
combinations to be accounted for under the purchase method of accounting,  which
requires  one  party  in the  transaction  to be  identified  as  the  acquiring
enterprise  and for that party to allocate the purchase  price to the assets and
liabilities  of the acquired  enterprise  based on fair market  value.  SFAS 142
requires  goodwill  and  indefinite-lived  intangible  assets  recorded  in  the
financial statements to be tested for impairment at least annually,  rather than
amortized over a fixed period,  with  impairment  losses  recorded in the income
statement.  SFAS  141 and SFAS 142 did not  have  any  effect  on our  financial
position,  results of operations or liquidity  upon  adoption.  SFAS No. 141 and
SFAS No. 142 will be utilized for our acquisition of CILCORP Inc. and AES Medina
Valley (No. 4), L.L.C. See Note 7 - "CILCORP Acquisition."

     In July 2001, SFAS No. 143, "Accounting for Asset Retirement  Obligations,"
was issued.  SFAS 143 requires an entity to record a liability and corresponding
asset  representing the present value of legal  obligations  associated with the
retirement of tangible,  long-lived assets.  SFAS 143 is effective for Ameren on
January 1, 2003.  At this time,  we are  assessing the impact of SFAS 143 on our
financial position, results of operations and liquidity upon adoption.  However,
as a  result  of this new  standard,  we  expect  significant  increases  to our
reported assets and  liabilities,  including  those  resulting from  obligations
associated  with  our  Callaway  nuclear  plant's   decommissioning   costs  and
associated cost recovery at our regulated  subsidiary,  Union Electric  Company,
operating as AmerenUE.

     On January 1, 2002 we adopted SFAS No. 144,  "Accounting for the Impairment
or Disposal of Long-Lived  Assets." SFAS 144 addresses the financial  accounting
and reporting for the impairment or disposal of long-lived assets and supersedes
SFAS No.  121,  "Accounting  for the  Impairment  of  Long-Lived  Assets and for
Long-Lived  Assets to Be Disposed Of." SFAS 144 retains the guidance  related to
calculating and recording impairment losses, but adds guidance on the accounting
for  discontinued   operations,   previously

                                       6


accounted  for under  Accounting  Principles  Board  Opinion No. 30. We evaluate
long-lived  assets  for  impairment  when  events or  changes  in  circumstances
indicate  that the  carrying  value of such assets may not be  recoverable.  The
determination  of whether  impairment  has  occurred  is based on an estimate of
undiscounted  cash  flows  attributable  to the  assets,  as  compared  with the
carrying  value of the assets.  If impairment  has  occurred,  the amount of the
impairment  recognized is determined by estimating  the fair value of the assets
and  recording a provision  for loss if the  carrying  value is greater than the
fair value. SFAS 144 did not have any effect on our financial position,  results
of operations or liquidity upon adoption.

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

     During  the  third  quarter  ended  September  30,  2002,  we  adopted  the
provisions  of EITF Issue 02-3,  "Accounting  for  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 the third quarter of 2002, 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 and in Operating
Expenses -  Operations.  This meant that revenues were recorded for the notional
amount of the power sale contracts with a corresponding charge to income for the
costs  of the  energy  that  was  generated,  or for the  notional  amount  of a
purchased  power  contract.  We now report all  contracts  within our power risk
management  program  that have been  purchased in  anticipation  of future price
changes on a net basis as a component  of revenues in the income  statement.  We
have also  applied  this  guidance to all prior  periods  which had no impact on
previously  reported  earnings or  stockholders'  equity.  The  following  table
summarizes the impact of applying EITF Issue 02-3 on operating  revenues for the
three and nine month periods ended September 30, 2002:

--------------------------------------------------------------------------------
                                               Three Months       Nine Months
--------------------------------------------------------------------------------
                                              2002      2001     2002     2001
                                              ----      ----     ----     ----
Previously reported gross operating
    revenues                                $1,355    $1,432    $3,581   $3,513
Costs reclassified                             123        10       243       10
--------------------------------------------------------------------------------
Net operating revenues reported             $1,232    $1,422    $3,338   $3,503
--------------------------------------------------------------------------------

     In October  2002,  the EITF  reached a consensus  to rescind EITF Issue No.
98-10,  "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities."  The effective date for the full  rescission of Issue 98-10 will be
for fiscal  periods  beginning  after  December 15, 2002. In addition,  the EITF
reached  a  consensus  in  October  2002 that all SFAS 133  trading  derivatives
(subsequent  to the rescission of Issue 98-10) should be shown net in the income
statement,  whether or not physically settled. This consensus would apply to all
energy and non-energy related trading  derivatives that meet the definition of a
derivative  pursuant to SFAS 133. The FASB staff indicated that it would attempt
to address, through the October EITF meeting minutes process, the effective date
and transition  provisions  relating to this consensus.  The rescission of  EITF
98-10 and the related transition  guidance could result in additional netting of
certain  energy  contracts  beyond the netting  required by EITF 02-3  discussed
above and have the effect of lowering  our  reported  revenues and costs with no
impact on  earnings.  We are  evaluating  the  impact of this  consensus  on our
financial statements.

Interchange Revenues

     Interchange  revenues  included in Operating  Revenues - Electric were $106
million for the three months ended  September 30, 2002 (2001 - $300 million) and
$477 million for the nine months ended September 30, 2002 (2001 - $691 million).

                                       7


Purchased Power

     Purchased  power  included in  Operating  Expenses -  Operations - Fuel and
Purchased  Power was $85 million for the three months ended  September  30, 2002
(2001 - $295  million) and $420 million for the nine months ended  September 30,
2002 (2001 - $670 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 and
nine months ended  September  30, 2002 were $38 million  (2001- $36 million) and
$94 million  (2001 - $89  million),  respectively.  Excise taxes  applicable  to
Illinois electric customer bills are imposed on the consumer and are recorded as
tax collections payable.

Employee Benefit Plans

     We made cash  contributions  totaling  $15 million to our  defined  benefit
retirement  plans  during  the  third  quarter  of 2002  and we  expect  to make
additional cash contributions to the plans totaling approximately $15 million in
the fourth quarter of 2002. Future funding plans will be evaluated at the end of
2002.  Based on the  performance of plan assets  through  September 30, 2002, we
expect to be required under the Employee  Retirement Income Security Act of 1974
to fund $25 million to $50 million in 2004 and $150  million to $200  million in
2005 in order to maintain  minimum funding  levels.  These amounts are estimates
and may change  based on actual stock  market  performance,  changes in interest
rates,  any  plan  funding  in  2002  or  2003  and  finalization  of  actuarial
assumptions.  In addition,  we expect at December  31,  2002,  to be required to
record a  minimum  pension  liability  that  would  result in a charge to OCI in
stockholders'  equity.  The amount of the charge is expected to result in a less
than one percent change in debt to total capitalization ratios.


NOTE 2 - Rate and Regulatory Matters

Missouri Electric

     From July 1, 1995 through June 30, 2001, our subsidiary, AmerenUE, operated
under  experimental  alternative  regulation plans in Missouri that provided for
the  sharing of  earnings  with  customers  if our  regulatory  return on equity
exceeded defined threshold  levels.  After AmerenUE's  experimental  alternative
regulation plan for its Missouri retail electric customers expired, the Missouri
Public  Service  Commission  (MoPSC)  Staff filed an excess  earnings  complaint
against  AmerenUE  with the MoPSC in July 2001.  In March 2002,  the MoPSC Staff
filed a  recommendation  that  AmerenUE  reduce  its  annual  Missouri  electric
revenues by $246 million to $285 million.  The MoPSC Staff's  recommendation was
based on a return to traditional cost of service ratemaking, a lowered return on
equity, a reduction in AmerenUE's  depreciation  rates and other cost of service
adjustments. In May 2002, AmerenUE filed testimony supporting a rate increase of
at least $150  million  and  proposed  a new  alternative  regulation  plan that
included a rate decrease.

     On July 16, 2002, AmerenUE, the MoPSC Staff and all of the other parties to
the proceeding submitted to the MoPSC a stipulation and agreement resolving this
case. On July 25, 2002, the MoPSC approved the stipulation and agreement, and on
August 4, 2002, it became effective.  The stipulation and agreement includes the
following principal features:

o    the  phase-in of $110 million of electric  rate  reductions  through  April
     2004, $50 million of which was retroactively effective as of April 1, 2002,
     $30  million  of which will  become  effective  on April 1,  2003,  and $30
     million  of  which  will  become  effective  on  April  1,  2004,
o    a rate  moratorium  providing  for no requests  for  changes in  AmerenUE's
     electric  rates as  established  by the  stipulation  and agreement  before
     January 1, 2006 and no  resulting  changes in rates  before June 30,  2006,
     subject to certain statutory and other exceptions,
o    a  commitment  to  contribute  as early as September  2002,  $14 million to
     programs for low income energy assistance and weatherization,  promotion of
     energy efficiency and economic development in

                                       8


     AmerenUE's service territory,  with additional  payments of $3 million made
     annually on June 30, 2003 through June 30, 2006,
o    a  commitment  to make $2.25  billion to $2.75  billion in critical  energy
     infrastructure  investments  from  January 1, 2002  through  June 30, 2006,
     including,  among other things,  the addition of more than 700 megawatts of
     new  generation  capacity  and  the  replacement  of  steam  generators  at
     AmerenUE's  nuclear  power  plant.  The  700  megawatts  of new  generation
     includes 240  megawatts  already  added this year,  as well as the proposed
     transfer  at  net  book  value  to  AmerenUE  of  approximately  400 to 500
     megawatts  of   generation   assets  from  our   non-regulated   generation
     subsidiary,  AmerenEnergy Generating Company (Generating Company), which is
     subject to receipt of necessary  regulatory approvals and is expected to be
     completed   in  the  second   quarter   of  2003.   The  amount  of  energy
     infrastructure  investment  through June 2006 described in the  stipulation
     and agreement is consistent with our  previously-disclosed  estimate of the
     construction expenditures we expect to make over the same time period,
o    an  annual  reduction  in  AmerenUE's  depreciation  rates by $20  million,
     retroactive to April 1, 2002, based on an updated analysis of asset values,
     service lives and accumulated depreciation levels, and
o    a one-time credit of $40 million, which was accrued during the plan period.
     The entire amount was paid to AmerenUE's Missouri retail electric customers
     in the third quarter of 2002 for  settlement  of the final  sharing  period
     under the alternative regulation plan that expired June 30, 2001.

     In total,  the  stipulation  and  agreement is estimated to reduce 2002 net
earnings by $32 million,  or 22 cents per share. Net earnings are expected to be
reduced in 2002 due to the rate  reduction  ($26  million,  net of taxes,  or 18
cents per share), the expensing in the quarter ended June 30, 2002 of the entire
obligation to fund certain programs ($15 million,  net of taxes, or 10 cents per
share),  offset, in part, by the reduction in depreciation  expense ($9 million,
net of taxes,  or 6 cents per  share).  Net  earnings  were  reduced  due to the
stipulation  and agreement by $11 million,  or 7 cents per share, in the quarter
ended  September  30,  2002 and by $20  million,  or 14 cents per share,  in the
quarter ended June 30, 2002.

     In order to  satisfy  AmerenUE's  regulatory  load  requirements  for 2001,
AmerenUE  purchased,  under a one year  contract (the 2001  Marketing  Company -
AmerenUE  agreement),  450  megawatts of capacity and energy from another of our
subsidiaries, AmerenEnergy Marketing Company (Marketing Company). This agreement
was  entered  into  through  a   competitive   bidding   process  and  reflected
market-based  rates.  For  2002,  AmerenUE  similarly  entered  into a one  year
contract  (the 2002  Marketing  Company -  AmerenUE  agreement)  with  Marketing
Company for the purchase of 200  megawatts of capacity and energy.  For the four
summer months of 2002, AmerenUE also entered into contracts with two other power
suppliers for an aggregate 200 megawatts of additional capacity and energy.

     In May 2001,  the MoPSC filed a complaint  with the Securities and Exchange
Commission  (SEC) relating to the 2001 Marketing  Company - AmerenUE  agreement.
The  complaint  requested an  investigation  into the  contractual  relationship
between AmerenUE,  Marketing Company and Generating  Company,  in the context of
the 2001 Marketing Company - AmerenUE  agreement and requested that the SEC find
that such  relationship  violates  Section 32(k) of the Public  Utility  Holding
Company Act of 1935 (PUHCA), which requires state utility commission approval of
power sales  contracts  between an electric  utility  company and an  affiliated
electric wholesale generator, like Generating Company. We have asserted that the
MoPSC's  approval  of the power  sales  agreement  under  PUHCA is not  required
because  Generating  Company  is not a  party  to  the  agreement.  In  its  SEC
complaint, the MoPSC proposes that the SEC require AmerenUE to contract directly
with Generating Company and submit such contract to the MoPSC for review. On May
9, 2002,  the MoPSC filed a similar  complaint with the SEC relating to the 2002
Marketing  Company - AmerenUE  agreement.  While the SEC is still  investigating
these matters,  the MoPSC and AmerenUE have  tentatively  reached  agreement for
resolving these disputes. The tentative agreement requires AmerenUE to not enter
into any new  contracts to purchase  wholesale  electric  energy from any Ameren
affiliate that is an exempt wholesale  generator  without first obtaining,  on a
timely  basis,  the  determinations  required of the MoPSC that are specified in
Section 32(k) of PUHCA.  However, this commitment does not prevent AmerenUE from
completing the purchases  contemplated by the 2001 and 2002 Marketing  Company -
AmerenUE  agreement and making short term energy  purchases  (less than 90 days)
from an Ameren  affiliate,  without  prior  MoPSC  determination,  to prevent or
alleviate system emergencies.  As part of the tentative agreement, the MoPSC has
agreed to terminate its SEC complaints.

                                       9



     Also, with respect to the 2002 Marketing Company - AmerenUE  agreement,  on
May 31, 2002,  the Federal  Energy  Regulatory  Commission  (FERC)  accepted the
agreement,  subject  to refund,  and  scheduled  the  matter for a January  2003
hearing to assess the  appropriateness  of the rates  charged.  In October 2002,
Marketing Company and the FERC Staff jointly reported to the FERC that they have
negotiated  a  settlement  in  principle  of the  issues  that  had been set for
hearing,  and that they both expect  that the  settlement  will be  uncontested.
Other than a slight  modification  to the procedures for  establishing  off-peak
energy prices under the  agreement,  the  settlement  in principle  will have no
impact  on the  agreement's  price,  terms and  conditions.  The  settlement  in
principle also  establishes  guidelines  for AmerenUE to follow when  conducting
future  requests  for  proposals  for the  purpose of pursuing  long-term  power
purchases.

     Until  the SEC and the  FERC  issue  final  orders  in  these  proceedings,
management is unable to predict their  ultimate  impact on our future  financial
position, results of operations or liquidity.

Illinois Electric

     In December 1997, the Electric  Service Customer Choice and Rate Relief Law
of  1997  (the  Illinois  Law)  was  enacted   providing  for  electric  utility
restructuring  in Illinois.  This  legislation  introduced  competition into the
retail supply of electric  energy in Illinois.  Illinois  residential  customers
were  offered  choice in  suppliers  beginning  on May 1, 2002.  Industrial  and
commercial customers were previously offered this choice.

     The original  Illinois Law contained a provision  freezing  retail  bundled
electric  rates  through  January 1, 2005. In 2002,  legislation  was passed and
signed into law that extended the rate freeze period through January 1, 2007. As
a result of the  extension  through  January 1, 2007 of the electric rate freeze
related to the Illinois Law, we expect to seek to renew or extend a power supply
agreement between our Illinois-based utility subsidiary, Central Illinois Public
Service Company, operating as AmerenCIPS, and Marketing Company through the same
period.  A renewal or  extension of the power  supply  agreement  will depend on
compliance  with  regulatory  requirements  in effect at the time, and we cannot
predict whether we will be successful in securing a renewal or extension of this
agreement. The offering of choice to our industrial and commercial customers has
not had a  material  adverse  effect on our  business  and we do not  expect the
offering of choice to our  residential  customers,  or the extension of the rate
freeze, to have a material adverse effect on our business.

     In October 2002,  AmerenUE and AmerenCIPS filed with the Illinois  Commerce
Commission  (ICC)  a  proposal  to  suspend  collection  of  transition  charges
associated  with the Illinois Law for the period  commencing  June 2003 until at
least June 2005. The Illinois Law allows a utility to collect transition charges
from  customers  that elect to move from bundled  retail  rates to  market-based
rates.  Utilities have the right to collect  transition  charges  throughout the
transition  period that ends January 1, 2007.  The  suspension  of collection of
transition  charges is not expected to have a material impact on either AmerenUE
or AmerenCIPS.

Federal - Electric Transmission

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

     In late 2001,  the FERC issued an order that  rejected the formation of the
Alliance  RTO and  ordered the  Alliance  RTO  companies  and the Midwest ISO to
discuss how the  Alliance RTO business  model could be  accommodated  within the
Midwest ISO. On April 25, 2002, after the Alliance RTO and Midwest ISO failed to
reach an  agreement,  and after a series of filings by the two parties  with the
FERC,  the FERC

                                       10


issued a  declaratory  order  setting  forth the  division  of  responsibilities
between  the  Midwest  ISO  and  National  Grid  (the  managing  member  of  the
transmission  company  formed by the Alliance  companies)  and approved the rate
design  and  the  revenue  distribution  methodology  proposed  by the  Alliance
companies.  However,  the FERC denied a request by the  Alliance  companies  and
National Grid to purchase  certain  services from the Midwest ISO at incremental
cost rather than  Midwest  ISO's full tariff  rates.  The FERC also  ordered the
Midwest  ISO to return  the exit fee paid by the Ameren  companies  to leave the
Midwest ISO,  provided the Ameren  companies return to the Midwest ISO and agree
to pay their proportional share of the startup and ongoing operational  expenses
of the Midwest ISO. Moreover, the FERC required the Alliance companies to select
the RTO in which they will participate within thirty days of the order.

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

     Until the  reliability and  rate-barrier  issues are resolved as ordered by
the FERC,  and the  tariffs and other  material  terms of our  participation  in
GridAmerica,  and GridAmerica's  participation in the Midwest ISO, are finalized
and  approved  by the FERC,  we are  unable to  predict  whether we will in fact
become a member of  GridAmerica  or Midwest ISO, or the impact that on-going RTO
developments  will have on our  financial  condition,  results of  operation  or
liquidity.

     On July 31, 2002,  the FERC issued its  standard  market  design  notice of
proposed rulemaking (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.  We are  currently
evaluating  the NOPR and its possible  impact on  operations  and expect to file
comments  on the NOPR with the FERC in  November  2002.  Until the FERC issues a
final rule,  management  is unable to predict the ultimate  impact on our future
financial position, results of operations or liquidity.


NOTE 3 - Derivative Financial Instruments

     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  in the  value  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 or under the firm
     commitment; and
o    actual cash  outlays  for the  purchase  of these  commodities,  in certain
     circumstances, to differ from anticipated cash outlays.

                                       11



     The  derivatives  that we use to hedge  these  risks are  dictated  by risk
management  policies and include forward contracts,  futures contracts,  options
and swaps. We continually  assess our supply and delivery  commitment  positions
against  forward  market  prices and internal  forecasts of forward  prices.  We
actively  manage  our  exposure  to power  price  risk  through  our power  risk
management  program carried out under our risk  management  guidelines to modify
our exposure to market,  credit and  operational  risk by entering  into various
offsetting  transactions.  In general,  we believe these  transactions  serve to
reduce price risk for us.

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

     As of  September  30,  2002,  we  recorded  the fair  value  of  derivative
financial instrument assets of $12 million in Other Assets and the fair value of
derivative  financial  instrument  liabilities  of $7 million in Other  Deferred
Credits and Liabilities.

Cash Flow Hedges

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

     The pretax net gain or loss on power forward derivative instruments,  which
represented the impact of discontinued cash flow hedges, the ineffective portion
of cash flow hedges, as well as the reversal of amounts  previously  recorded in
OCI due to transactions going to delivery or settlement,  was approximately a $5
million  loss for the three  months  and a $4 million  loss for the nine  months
ended  September  30, 2002.  For the three and nine months ended  September  30,
2001, the above related amounts were a $13 million gain in each period.

     As of September 30, 2002, we had hedged a portion of the electricity  price
exposure  for  the  upcoming   twelve-month  period.  The  mark-to-market  value
accumulated  in OCI for the  effective  portion of hedges of  electricity  price
exposure was a net gain of approximately $1 million ($1 million, net of taxes).

     As of September 30, 2002, a gain of  approximately  $5 million ($3 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  covered the first ten years of debt that has a 30-year  maturity  and
the gain in OCI is being  amortized  over a ten-year  period  beginning  in June
2002.

     We also held three call options for coal with two suppliers.  These options
to purchase coal expire  October 2003,  July 2004 and July 2005. As of September
30, 2002, the mark-to-market gain accumulated in OCI was $6 million ($3 million,
net of taxes).  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.  Most 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
Revenues,  while the net change in the  market  value of coal,  heating  oil and
electricity  options is recorded

                                       12


as  Operating  Expense -  Operations  - 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 $1 million ($1 million, net of taxes)
for the three  months  ended  September  30,  2002 and a gain of $4 million  ($3
million,  net of taxes) for the nine months ended  September  30, 2002.  For the
three and nine months ended  September 30, 2001,  the above related items were a
loss of $6 million ($4 million, net of taxes) in each period.


NOTE 4 - Debt and Equity Financings

     In January 2002, Ameren  Corporation issued $100 million of 5.70% notes due
February 1, 2007.  The net proceeds were used to reduce  short-term  borrowings.
Interest is payable  semi-annually  on February 1 and August 1 of each year.  In
March 2002,  Ameren  Corporation  entered into interest  rate swaps  effectively
converting  the interest rate  associated  with these notes to three month LIBOR
plus 43 basis  points.  At September 30, 2002,  the effective  interest rate for
these notes was 2.248%.

     In March  2002,  Ameren  Corporation  issued  $345  million  of  adjustable
conversion-rate   equity  security  units  and  $227  million  of  common  stock
(5,000,000  shares at  $39.50  per share and  750,000  shares,  pursuant  to the
exercise of an option granted to the  underwriters,  at $38.865 per share).  The
$25 adjustable conversion-rate equity security units each consisted of an Ameren
Corporation  senior unsecured note with a principal amount of $25 and a contract
to  purchase,  for $25, a fraction of a share of Ameren  common stock on May 15,
2005.  The  senior  unsecured  notes were  recorded  at their fair value of $345
million  and will  mature on May 15,  2007.  Total  distributions  on the equity
security  units  will be at an annual  rate of 9.75%,  consisting  of  quarterly
interest  payments on the senior  unsecured  notes at the initial annual rate of
5.20% and adjustment  payments under the stock purchase  contracts at the annual
rate of 4.55%. The stock purchase  contracts require holders to purchase between
8.7 million and 7.4 million shares of Ameren common stock on May 15, 2005 at the
market  price at that  time,  subject to a minimum  share  price of $39.50 and a
maximum of $46.61.  The stock purchase  contracts include a pledge of the senior
unsecured  notes as collateral for the stock purchase  obligation.  The interest
rate on the  outstanding  senior  unsecured notes is subject to being reset by a
remarketing agent for quarterly  payments after May 15, 2005 until maturity.  We
recorded  the net present  value of the  contracted  stock  purchase  adjustment
payments of $46 million as an increase in Other Deferred Credits and Liabilities
to reflect our obligation and a decrease in Other Paid-in Capital to reflect the
fair value of the stock  purchase  contract.  The liability  for the  contracted
stock  purchase  adjustment  payments  will be reduced as such payments are made
through May 15, 2005. We used the net proceeds from these offerings to repay our
short-term indebtedness and for general corporate purposes.

     In June 2002,  Generating Company issued $275 million of 7.95% Senior Notes
due June 1, 2032. Interest is payable  semi-annually on June 1 and December 1 of
each year, beginning December 1, 2002.  Generating Company received net proceeds
of $271 million,  after debt discount and underwriters'  fees, that were used to
reduce short-term  borrowings  incurred to finance previous  generating capacity
additions and for general corporate purposes.

     In July 2002,  Ameren  Corporation  entered into new credit  agreements for
$400 million in revolving  credit  facilities  to be used for general  corporate
purposes,  including support of our commercial paper programs.  The $400 million
in new facilities  includes a $270 million 364-day revolving credit facility and
a $130 million 3-year revolving  credit facility.  The 3-year facility has a $50
million  sub-limit  for the  issuance  of letters  of  credit.  These new credit
facilities  replaced  AmerenUE's  $300 million  revolving  credit  facility.  At
September 30, 2002,  all of such  borrowing  capacity under these new facilities
was available.

     In August 2002,  AmerenUE issued $173 million of 5.25% Senior Secured Notes
due  September  1,  2012.  Interest  is  payable  semi-annually  on  March 1 and
September  1 of each year,  beginning  March 1,  2003.  Net  proceeds  were $172
million,  after debt discount and underwriters' fees. These senior secured notes
are secured by a related  series of AmerenUE's  first  mortgage  bonds until the
release date as described in the senior  secured note  indenture.  Proceeds were
used to redeem,  in September  2002,  AmerenUE's $125 million  principal  amount
8.75%  first  mortgage  bonds  due  December  1,  2021  at a 4.38%  premium  and
AmerenUE's $41 million $1.735 series preferred stock at par.

                                       13


     In September 2002, Ameren  Corporation  issued $338 million of common stock
(8,050,000  shares at $42.00 per share,  including  1,050,000 shares pursuant to
the exercise of an option granted to the  underwriters).  Net proceeds were $327
million after underwriters' fees. We anticipate using the net proceeds from this
offering  to  fund  part of the  cash  portion  of the  purchase  price  for our
acquisition of CILCORP Inc. (see Note 7 - "CILCORP Acquisition") and for general
corporate  purposes.  Pending such uses,  we are  investing  the net proceeds in
short-term instruments.

     Amortization of debt issuance costs and  premium/discount for the three and
nine months  ending  September 30, 2002 of $2 million (2001 - $1 million) and $6
million  (2001 - $4 million)  were  included  in interest  expense in the income
statement.


NOTE 5 - Miscellaneous, Net

     Miscellaneous,  net for the three and nine months ended  September 30, 2002
and 2001 consisted of the following:

--------------------------------------------------------------------------------
                                                  Three Months     Nine Months
--------------------------------------------------------------------------------
                                                 2002      2001    2002    2001
                                                 ----      ----    ----    ----
Miscellaneous income:
   Interest and dividend income                  $ 4       $ -     $ 6     $ 1
   Gain on disposition of property                 -         1       3       2
   Other                                           1         9       4      11
--------------------------------------------------------------------------------
Total miscellaneous income                       $ 5       $10     $13     $14
--------------------------------------------------------------------------------

Miscellaneous expense:
   Minority interest in subsidiary              $ (2)     $(1)    $(13)    $(3)
   Loss on disposition of property                 -        -        -      (2)
   Donations - rate settlement                     -        -      (26)     (1)
   Other                                          (1)      (2)      (7)     (5)
--------------------------------------------------------------------------------
Total miscellaneous expense                     $ (3)     $(3)    $(46)   $(11)
--------------------------------------------------------------------------------


NOTE 6 - Segment Information



     Segment  information for the three and nine months ended September 30, 2002
and 2001 was as follows:

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

     Three months ended September 30, 2002:
                                                            
Revenues                                      $1,368   $87     $(223)   $1,232
Net income                                       238     2         -       240
--------------------------------------------------------------------------------

     Three months ended September 30, 2001:

Revenues                                      $1,619   $60     $(257)   $1,422
Net income                                       267     -         -       267
--------------------------------------------------------------------------------


                                       14



     Nine months ended September 30, 2002:

Revenues                                      $3,663   $262    $(587)   $3,338
Net income                                       397     17        -       414
--------------------------------------------------------------------------------

     Nine months ended September 30, 2001:

Revenues                                      $3,952   $193    $(642)   $3,503
Net income                                       419      1        -       420
--------------------------------------------------------------------------------


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


NOTE 7 - CILCORP Acquisition


     On April 28, 2002,  we entered into an agreement  with The AES  Corporation
(AES) to purchase all of the outstanding common stock of CILCORP Inc. CILCORP is
the parent  company of Peoria,  Illinois-based  Central  Illinois Light Company,
which  operates as CILCO.  We also agreed to acquire AES Medina  Valley (No. 4),
L.L.C. which indirectly owns a 40 megawatt, gas-fired electric generation plant.
The total purchase price is  approximately  $1.4 billion,  subject to adjustment
for changes in CILCORP's working capital, and includes the assumption of CILCORP
and AES Medina Valley debt at closing,  estimated at approximately $900 million,
with the balance of the purchase  price  payable in cash. We expect to finance a
significant  portion of the cash  component of the purchase  price through prior
and future issuances of new common equity.

     The purchase  will  include  CILCORP's  regulated  natural gas and electric
businesses  in Illinois  serving  approximately  205,000 and 200,000  customers,
respectively,  of which approximately  150,000 are combination  electric and gas
customers.  CILCO's service territory is contiguous to our service territory. In
addition,  the  purchase  includes  approximately  1,200  megawatts  of  largely
coal-fired generating capacity, most of which is expected to be non-regulated in
2003.

     Upon  completion  of the  acquisition,  expected by March 2003,  CILCO will
become  an  Ameren  subsidiary,  but will  remain a  separate  utility  company,
operating as AmerenCILCO. The transaction is subject to the approval of the ICC,
the FERC, the SEC under PUHCA,  and the Federal  Communications  Commission,  as
well  as the  expiration  of the  waiting  period  under  the  Hart-Scott-Rodino
Antitrust Improvements Act and other customary closing conditions.  Applications
to all applicable  regulatory  agencies were made and are proceeding through the
approval  process.  On August 30, 2002,  Ameren and AES  received  from the U.S.
Department  of Justice  (DOJ),  a Request  for  Additional  Information  (Second
Request) under the  Hart-Scott-Rodino Act pertaining to the CILCORP acquisition.
Ameren  intends to respond to the Second  Request by the end of November.  Under
the stock purchase agreement with AES, Ameren is obligated to resolve any issues
raised by the DOJ in  connection  with the  Hart-Scott-Rodino  filing.  Although
issuance of a Second  Request is not unusual for  transactions  of this size, it
does extend the review and waiting  period  under the Act. We do not expect that
this extension will impact the anticipated  transaction closing date. In October
2002, we resolved all outstanding issues related to the CILCORP acquisition with
the ICC  Staff  and all  interveners  that  filed  testimony  in the  case.  The
principal issue, among other things, related to the potential exercise of market
power within the CILCO service territory.  To address this issue, we have agreed
to invest  approximately  $23 million by December 31, 2008 to increase the power
import  capability into CILCO's service  territory.  The parties expect to agree
upon a draft proposed Order for  presentation  to the ICC in November,  which is
expected to issue a final Order by the end of the year.

     For the nine-month period ended September 30, 2002, CILCORP had revenues of
$579 million,  operating  income of $79 million,  and net income from continuing
operations of $29 million, and as of September 30, 2002 had total assets of $1.9
billion.  For the year ended  December  31,  2001,  CILCORP had revenues of $815
million,  operating  income of $126  million,  and net  income  from  continuing
operations of $28 million,  and as of December 31, 2001 had total assets of $1.8
billion.

                                       15



NOTE 8 - Subsequent Event

     On November 4, 2002,  we announced a voluntary  retirement  program that is
being offered to  approximately  1,000 of our 7,400 employees.  In addition,  we
announced limits on our contributions  and and increased  retiree  contributions
for  certain  retiree  medical  benefit  plans  and a freeze  on wage  increases
beginning  in 2003 for all  management  employees.  While we expect  to  realize
significant  long-term savings as a result of this program, we expect to incur a
one-time,  after-tax  charge  in the  fourth  quarter  of  2002  related  to the
voluntary  retirement  program.  That charge could range between $30 million and
$50  million,  based  on  voluntary  retirements  ranging  between  300 and 500,
respectively.  In addition to the voluntary  retirement program, we may consider
implementing  an  involuntary   severance  program  if  it  is  determined  that
additional  positions  must be  eliminated  to  achieve  optimum  organizational
efficiency and effectiveness.  Further,  the company will continue to seek other
ways to reduce staffing over the next year to reduce costs and gain efficiencies
in operations.

                                       16



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

OVERVIEW

     Ameren Corporation is a holding company registered under the Public Utility
Holding Company Act of 1935 (PUHCA).  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 regulated  electric  generation,
     transmission  and  distribution  business,  and  a  regulated  natural  gas
     distribution business in Missouri and Illinois as AmerenUE.
o    Central  Illinois  Public  Service  Company,  which  operates  a  regulated
     electric and natural gas transmission and distribution business in Illinois
     as AmerenCIPS.
o    AmerenEnergy  Resources Company (Resources Company),  which consists of non
     rate-regulated  operations.  Subsidiaries include  AmerenEnergy  Generating
     Company (Generating Company) that operates our non rate-regulated  electric
     generation  in  Missouri  and  Illinois,   AmerenEnergy  Marketing  Company
     (Marketing  Company),  which markets  power for periods over one year,  and
     AmerenEnergy  Fuels and Services  Company,  which procures fuel and manages
     the related risks for our affiliated companies.
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 owns and/or 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 us and
     our 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 audited financial statements and related notes that are incorporated by
     reference  from our Annual Report to  Stockholders  in our Annual Report on
     Form 10-K for the year ended December 31, 2001.
o    Management's  Discussion and Analysis of Financial Condition and Results of
     Operations  that is  incorporated  by reference  from our Annual  Report to
     Stockholders  in our Annual Report on Form 10-K for the year ended December
     31, 2001.

     When we  refer  to  Ameren,  our,  we or us,  we are  referring  to  Ameren
Corporation 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.

     Our results of  operations  and  financial  position  are  impacted by many
factors,  including  both  controllable  and  uncontrollable  factors.  Weather,
economic  conditions,  and the  actions  of key  customers  or  competitors  can
significantly impact the demand for our services.  Our results are also impacted
by seasonal  fluctuations caused by winter heating, and summer cooling,  demand.
With approximately 85% of our revenues directly subject to regulation by various
state and federal  agencies,  decisions by regulators can have a material impact
on the price we charge for our services.  We principally  utilize coal,  nuclear
fuel and natural gas 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 recovery
mechanisms in Missouri and Illinois for our electric utility businesses,  but do
have gas cost recovery  mechanisms in each state for our gas utility businesses.
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.


                                       17


RESULTS OF OPERATIONS

Summary

     Our net income  decreased $27 million to $240  million,  or $1.64 per share
($1.63 per share  diluted),  in the third quarter of 2002 from $267 million,  or
$1.94 per share,  in the third  quarter of 2001.  Earnings  for the nine  months
ended  September  30, 2002 totaled $414  million,  or $2.88 per share ($2.87 per
share diluted),  compared to the year-ago earnings of $420 million, or $3.06 per
share.  The decrease in both periods in 2002 was  primarily due to the impact of
the  settlement of our Missouri  electric rate case (third quarter - 7 cents per
share; year to date - 21 cents per share),  increased costs of employee benefits
(third quarter - 4 cents per share;  year to date - 11 cents per share),  higher
depreciation,  and a  decline  in  industrial  sales due to the  continued  soft
economy.  Increased  average  shares  outstanding  (third  quarter - 9.5 million
shares;  year to date - 6.4 million shares) and financing costs reduced earnings
per share in 2002 by  approximately  14 cents in the third  quarter and 20 cents
year to date. The nine-month  period comparison was also affected by a reduction
of the accrual in 2001 for expected  customer sharing credits under the Missouri
electric experimental alternative regulation plan that expired in June 2001 (see
Note  2  -  "Rate  and  Regulatory   Matters"  to  our  consolidated   financial
statements).

     The decreases in both periods were  partially  offset by favorable  weather
conditions  (third  quarter  - 11 cents per  share;  year to date - 14 cents per
share).  The nine-month period in 2002 was also favorably  affected by increased
sales of emission credits,  including such sales by EEI (12 cents per share) and
the lack of a Callaway  nuclear plant refueling outage to date in 2002 (14 cents
per share).  In January 2001, we recorded a charge of $7 million,  or five cents
per share,  due to the adoption of Statement of Financial  Accounting  Standards
(SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities."

     As a holding company, our net income and cash flows are primarily generated
by our principal operating subsidiaries,  AmerenUE,  AmerenCIPS and AmerenEnergy
Generating  Company.  These  subsidiaries also file quarterly and annual reports
with the Securities and Exchange  Commission.  The contribution by our principal
operating  subsidiaries  to net  income  for the  three  and nine  months  ended
September 30, 2002 was as follows:

--------------------------------------------------------------------------------
                                              Three Months     Nine Months
--------------------------------------------------------------------------------
                                               2002    2001    2002    2001
                                               ----    ----    ----    ----
Primarily rate-regulated operations
      AmerenUE (a)                             $204    $201    $358    $317
      AmerenCIPS                                 23      24      31      43
--------------------------------------------------------------------------------
                                               $227    $225    $389    $360
--------------------------------------------------------------------------------

Primarily non rate-regulated operations
      AmerenEnergy Generating (a)(b)             15      43      31      68

Other                                            (2)     (1)     (6)     (8)

--------------------------------------------------------------------------------
Ameren net income                              $240    $267    $414    $420
--------------------------------------------------------------------------------

(a) includes earnings from interchange sales by AmerenEnergy.
(b) includes earnings from contract to supply power to AmerenCIPS customers.


Recent Developments

2003 Outlook and Voluntary Retirement Plan

     See  "Liquidity  and  Capital  Resources  - Outlook"  for a  discussion  of
expected  challenges  to net income in 2003 and  beyond,  along with a voluntary
retirement  plan that was  offered to  approximately  1,000  employees  in early
November  2002 and is  expected  to result in a fourth  quarter  2002  after-tax
charge of between $30 million and $50 million.


                                       18


Missouri Electric Rate Case

     From July 1, 1995 through June 30, 2001, our subsidiary, AmerenUE, operated
under  experimental  alternative  regulation plans in Missouri that provided for
the  sharing of  earnings  with  customers  if our  regulatory  return on equity
exceeded defined threshold  levels.  After AmerenUE's  experimental  alternative
regulation plan for its Missouri retail electric customers expired, the Missouri
Public  Service  Commission  (MoPSC)  Staff filed an excess  earnings  complaint
against  AmerenUE  with the MoPSC in July 2001.  In March 2002,  the MoPSC Staff
filed a  recommendation  that  AmerenUE  reduce  its  annual  Missouri  electric
revenues by $246 million to $285 million.  The MoPSC Staff's  recommendation was
based on a return to traditional cost of service ratemaking, a lowered return on
equity, a reduction in AmerenUE's  depreciation  rates and other cost of service
adjustments. In May 2002, AmerenUE filed testimony supporting a rate increase of
at least $150  million  and  proposed  a new  alternative  regulation  plan that
included a rate decrease.

     On July 16, 2002, AmerenUE, the MoPSC Staff and all of the other parties to
the proceeding submitted to the MoPSC a stipulation and agreement resolving this
case. On July 25, 2002, the MoPSC approved the stipulation and agreement, and on
August 4, 2002, it became effective.  The stipulation and agreement includes the
following principal features:

o    the  phase-in of $110 million of electric  rate  reductions  through  April
     2004, $50 million of which was retroactively effective as of April 1, 2002,
     $30  million  of which will  become  effective  on April 1,  2003,  and $30
     million of which will become effective on April 1, 2004,
o    a rate  moratorium  providing  for no requests  for  changes in  AmerenUE's
     electric  rates as  established  by the  stipulation  and agreement  before
     January 1, 2006 and no  resulting  changes in rates  before June 30,  2006,
     subject to certain statutory and other exceptions,
o    a  commitment  to  contribute  as early as September  2002,  $14 million to
     programs for low income energy assistance and weatherization,  promotion of
     energy efficiency and economic development in AmerenUE's service territory,
     with  additional  payments  of $3 million  made  annually  on June 30, 2003
     through June 30, 2006,
o    a  commitment  to make $2.25  billion to $2.75  billion in critical  energy
     infrastructure  investments  from  January 1, 2002  through  June 30, 2006,
     including,  among other things,  the addition of more than 700 megawatts of
     new  generation  capacity  and  the  replacement  of  steam  generators  at
     AmerenUE's  nuclear  power  plant.  The  700  megawatts  of new  generation
     includes 240  megawatts  already  added this year,  as well as the proposed
     transfer  at  net  book  value  to  AmerenUE  of  approximately  400 to 500
     megawatts  of   generation   assets  from  our   non-regulated   generation
     subsidiary,  Generating  Company,  which is subject to receipt of necessary
     regulatory  approvals and is expected to be completed in the second quarter
     of 2003. The amount of energy  infrastructure  investment through June 2006
     described  in  the   stipulation  and  agreement  is  consistent  with  our
     previously-disclosed estimate of the construction expenditures we expect to
     make over the same time period,
o    an  annual  reduction  in  AmerenUE's  depreciation  rates by $20  million,
     retroactive to April 1, 2002 based on an updated  analysis of asset values,
     service lives and accumulated depreciation levels, and
o    a one-time credit of $40 million, which was accrued during the plan period.
     The entire amount was paid to AmerenUE's Missouri retail electric customers
     in the third quarter of 2002 for  settlement  of the final  sharing  period
     under the alternative regulation plan that expired June 30, 2001.

     In total,  the  stipulation  and  agreement is estimated to reduce 2002 net
earnings by $32 million,  or 22 cents per share. Net earnings are expected to be
reduced in 2002 due to the rate  reduction  ($26  million,  net of taxes,  or 18
cents per share), the expensing in the quarter ended June 30, 2002 of the entire
obligation to fund certain programs ($15 million,  net of taxes, or 10 cents per
share),  offset, in part, by the reduction in depreciation  expense ($9 million,
net of  taxes,  6  cents  per  share).  Net  earnings  were  reduced  due to the
stipulation  and agreement by $11 million,  or 7 cents per share, in the quarter
ended  September  30,  2002 and by $20  million,  or 14 cents per share,  in the
quarter ended June 30, 2002.

                                       19



CILCORP Acquisition

     On April 28, 2002,  we entered into an agreement  with The AES  Corporation
(AES) to purchase all of the outstanding common stock of CILCORP Inc. CILCORP is
the parent  company of Peoria,  Illinois-based  Central  Illinois Light Company,
which  operates as CILCO.  We also agreed to acquire AES Medina  Valley (No. 4),
L.L.C. which indirectly owns a 40 megawatt, gas-fired electric generation plant.
The total purchase price is  approximately  $1.4 billion,  subject to adjustment
for changes in CILCORP's working capital, and includes the assumption of CILCORP
and AES Medina Valley debt at closing,  estimated at approximately $900 million,
with the balance of the purchase  price  payable in cash. We expect to finance a
significant  portion of the cash  component of the purchase  price through prior
and future issuances of new common equity.

     The purchase  will  include  CILCORP's  regulated  natural gas and electric
businesses  in Illinois  serving  approximately  205,000 and 200,000  customers,
respectively,  of which approximately  150,000 are combination  electric and gas
customers.  CILCO's service territory is contiguous to our service territory. In
addition,  the  purchase  includes  approximately  1,200  megawatts  of  largely
coal-fired generating capacity, most of which is expected to be non-regulated in
2003.

     Upon  completion  of the  acquisition,  expected by March 2003,  CILCO will
become  an  Ameren  subsidiary,  but will  remain a  separate  utility  company,
operating  as  AmerenCILCO.  The  transaction  is subject to the approval of the
Illinois Commerce  Commission  (ICC), the Federal Energy  Regulatory  Commission
(FERC),  the  Securities  and Exchange  Commission  (SEC) under  PUHCA,  and the
Federal  Communications  Commission,  as well as the  expiration  of the waiting
period  under  the  Hart-Scott-Rodino   Antitrust  Improvements  Act  and  other
customary closing conditions. Applications to all applicable regulatory agencies
were made and are proceeding  through the approval process.  On August 30, 2002,
Ameren and AES received from the U.S. Department of Justice (DOJ), a Request for
Additional   Information  (Second  Request)  under  the   Hart-Scott-Rodino  Act
pertaining to the CILCORP  acquisition.  Ameren intends to respond to the Second
Request by the end of November.  Under the stock  purchase  agreement  with AES,
Ameren is obligated to resolve any issues raised by the DOJ in  connection  with
the  Hart-Scott-Rodino  filing.  Although  issuance  of a Second  Request is not
unusual  for  transactions  of this size,  it does extend the review and waiting
period  under the Act.  We do not expect  that this  extension  will  impact the
anticipated   transaction  closing  date.  In  October  2002,  we  resolved  all
outstanding issues related to the CILCORP acquisition with the ICC Staff and all
interveners that filed testimony in the case. The principal  issue,  among other
things,  related to the  potential  exercise  of market  power  within the CILCO
service territory.  To address this issue we have agreed to invest approximately
$23 million by December 31, 2008 to increase the power  import  capability  into
CILCO'  service  territory.  The parties  expect to agree upon a draft  proposed
Order for  presentation  to the ICC in  November,  which is  expected to issue a
final Order by the end of the year.

     For the nine-month period ended September 30, 2002, CILCORP had revenues of
$579 million,  operating  income of $79 million,  and net income from continuing
operations of $29 million, and as of September 30, 2002 had total assets of $1.9
billion.  For the year ended  December  31,  2001,  CILCORP had revenues of $815
million,  operating  income of $126  million,  and net  income  from  continuing
operations of $28 million,  and as of December 31, 2001 had total assets of $1.8
billion.

     In April 2002, as a result of  AmerenUE's  then pending  Missouri  electric
earnings  complaint case and the CILCORP  transaction and related  assumption of
debt, credit rating agencies placed Ameren  Corporation's  debt under review for
possible  downgrade  or  negative  credit  watch.  Standard & Poor's  placed the
ratings of AmerenUE and AmerenCIPS  debt on negative credit watch and placed the
ratings of Generating Company's debt on positive credit watch. However, Standard
& Poor's  stated it  expects  the  corporate  credit  ratings  of Ameren and its
subsidiaries  to be in the  "A"  rating  category  following  completion  of the
acquisition. Moody's Investor Service stated it envisioned a one notch downgrade
of Ameren's issuer, senior unsecured debt and commercial paper ratings. Ameren's
corporate  credit  rating is "A+" at Standard & Poor's and its issuer  rating is
"A2" at Moody's.  In July 2002, AmerenUE settled its electric earnings complaint
case.  Neither  Standard & Poor's nor  Moody's has  changed  the  assignment  of
negative or positive watch, review for possible downgrade or negative outlook to
any of their ratings nor have the ratings themselves changed.  Subsequent to the
settlement  of the Missouri  electric  earnings  complaint  case,  Fitch Ratings
reduced  AmerenUE's  ratings by one notch (from "AA" to "AA-" in the case of its
first  mortgage  bonds) and changed the outlook  assigned to AmerenUE's  ratings
from negative to


                                       20


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

Electric Operations

     The following table represents the favorable  (unfavorable)  variations for
the three and nine months ended  September 30, 2002 from the comparable  periods
in 2001:

--------------------------------------------------------------------------------
                                           Three Months         Nine Months
--------------------------------------------------------------------------------
Operating Revenues:
   Effect of abnormal weather (estimate)     $  47               $  58
   Growth and other (estimate)                 (34)                 16
   Rate reductions                             (23)                (36)
   Credit to customers                           -                 (10)
   Interchange revenues                       (194)               (214)
   EEI                                          25                  77
--------------------------------------------------------------------------------
                                              (179)               (109)
--------------------------------------------------------------------------------
Fuel and Purchased Power:
   Fuel:
     Generation                                (15)                (37)
     Price                                       3                  11
     Generation efficiencies and other          (2)                 (2)
   Purchased power                             210                 250
   EEI                                         (26)                (44)
--------------------------------------------------------------------------------
                                               170                 178
--------------------------------------------------------------------------------
Change in electric margin                    $  (9)              $  69
--------------------------------------------------------------------------------

     Electric  margin  decreased $9 million for the three months ended September
30, 2002, but increased $69 million for the nine months ended September 30, 2002
compared to the same year-ago  periods.  Increases in margin for the  nine-month
period  were  primarily  attributable  to  more  favorable  weather  conditions,
increased sales of emission credits,  lack of a Callaway nuclear plant refueling
outage to date in 2002,  and lower  fuel  costs.  Our  region  also  experienced
favorable weather conditions during the third quarter of 2002. Weather-sensitive
residential  electric  kilowatt-hour  sales in 2002 increased by 9% in the third
quarter and 5% for the year to date, and commercial electric kilowatt-hour sales
increased  by 4% in the  quarter and 2% for the year to date.  Industrial  sales
were 3% lower in the third quarter and 6% lower in the first nine months of 2002
as compared to 2001 due primarily to the impact of the soft  economy.  The third
quarter of 2001  benefited  from emission sales of $9 million and a FAS 133 gain
of $3 million (2002 - loss of $4 million).  Revenues were reduced by $23 million
for the three  months and $36 million for the nine months  ended  September  30,
2002 due to the settlement of the Missouri electric rate case.  Revenues in 2001
were increased by $10 million in the first nine months due to a reduction in the
accrual for expected  customer  sharing credits under the Missouri  experimental
alternative regulation plan that expired in June 2001.  Contribution to electric
margin from EEI increased in the nine-month  period of 2002  principally  due to
EEI's sale of $38 million in emission credits.  Interchange  revenues  decreased
due to lower energy  prices and less  low-cost  generation  available  for sale,
resulting  primarily  from  increased  demand for  generation  from  native load
customers.  Purchased  power was reduced in the first nine months of 2002 due to
lower interchange sales and the lack of a Callaway  refueling,  partially offset
by unscheduled coal plant outages. Another refueling outage at Callaway began in
mid-October  which is expected to last 35 days and is estimated to reduce fourth
quarter 2002 earnings by 9 cents per share.

     During the third quarter ended September 30, 2002, we adopted the provision
of Emerging  Issues Task Force  (EITF)  Issue 02-3,  "Accounting  for  Contracts
Involved  in Energy  Trading  and Risk  Management  Activities,"  that  requires
certain energy contracts to be shown on a net basis in the income statement (see
Note 1 -  "Summary  of  Significant  Accounting  Policies"  to our  consolidated
financial statements).


                                       21



Gas Operations

     Our gas  margins  decreased  $6  million  in the third  quarter  of 2002 as
compared to the same period in 2001 with revenues  decreasing by $10 million and
costs  decreasing  by $4  million.  The prior year third  quarter  included  the
benefit of the recovery of gas costs from our  customers  under a purchased  gas
adjustment  clause.  Warmer winter weather early in 2002 resulted in margins for
the first nine months of 2002 being $10 million below the year-ago  period.  Gas
revenues decreased $53 million, and gas costs decreased $43 million in the first
nine months of 2002 as compared to the year-ago  period  primarily  due to lower
natural gas prices and the warmer winter.

Other Operating Expenses

     Operating  Expenses - Operations - Other increased $24 million in the third
quarter and $49  million in the first nine months of 2002  compared to the prior
year  periods,  primarily  due to higher  employee  benefit costs related to the
investment  performance of pension plan assets and increasing  healthcare costs.
See "Liquidity and Capital  Resources - Outlook" and Item 3. "Equity Price Risk"
below  for a  discussion  of our  expectations  and  plans  regarding  trends in
employee benefit costs.

     Maintenance expenses increased $3 million in the third quarter of 2002, but
decreased  $28 million in the first nine  months of 2002,  compared to the prior
year  periods.  The decrease for the nine months  ended  September  30, 2002 was
primarily  due to the lack of a  Callaway  refueling  outage in the  first  nine
months of 2002.

     Depreciation  and amortization  expenses  increased $4 million in the third
quarter of 2002 and $18  million in the first nine  months of 2002,  compared to
the year-ago  periods.  This net increase was primarily due to our investment in
coal  power  plants and  combustion  turbine  electric  generating  plants.  The
increase in 2002 was partially offset by a reduction of depreciation rates based
on  an  updated  analysis  of  asset  values,   service  lives  and  accumulated
depreciation  levels and agreed to in the stipulation  and agreement  associated
with the Missouri electric rate case (third quarter - $5 million; year to date -
$10 million).

     Income tax expense  decreased  $35 million in the third quarter of 2002 and
$34 million in the first nine months of 2002,  compared to the year-ago periods,
primarily due to lower pretax income.  Income taxes related to our non-regulated
operations are recorded in Other Income and Deductions.

     Other taxes expense  decreased $1 million in the third quarter of 2002, but
increased $8 million in the first nine months of 2002,  compared to the year-ago
periods.  The  increase  for the nine months was  primarily  due to higher gross
receipts taxes  resulting from increased  electric sales in 2002 and adjustments
related to revised property tax assessments in the prior year.

Other Income and Deductions

     Other income and deductions  (excluding  income taxes) decreased $8 million
in the third  quarter of 2002 and $41  million in the first nine months of 2002,
compared to the same periods last year. The decrease for the  nine-month  period
was  primarily  due to the  commitment  to fund certain  programs as part of the
settlement of the Missouri electric rate case ($26 million),  and an increase in
the minority interest principally related to EEI's sale of emission credits ($10
million).  See  Note 5 -  "Miscellaneous,  net"  to our  consolidated  financial
statements.

Interest

     Interest expense  increased $6 million in the third quarter of 2002 and $13
million in the first nine  months of 2002,  compared  to the  year-ago  periods,
primarily  due to our issuance of $345  million of  adjustable  conversion  rate
equity  security units in March 2002 and Generating  Company's  issuance of $275
million of 7.95% notes in June 2002. A  significant  amount of the proceeds from
these offerings was used to repay lower cost short-term borrowings.

                                       22



LIQUIDITY AND CAPITAL RESOURCES

Operating

     Our cash flows  provided by operating  activities  increased $10 million to
$733  million for the nine months  ended  September  30,  2002,  compared to the
year-ago period.  Cash provided from operations  increased primarily as a result
of  favorable  weather and a net decrease in  materials  and supplies  primarily
associated  with  decreased  coal  inventories  and gas storage.  Materials  and
supplies  were higher than normal at December 31,  2001,  due to the warm winter
and  anticipation of a potential coal supply  disruption that ultimately did not
occur.  These  increases were partially  offset by payments of customer  sharing
credits under AmerenUE's now-expired electric alternative regulation plan, lower
rates associated with our Missouri rate case settlement,  and timing of payments
on accounts payable and accrued taxes.

     The tariff-based gross margins of our utility operating  companies continue
to be our principal  source of cash from operating  activities.  Our diversified
retail  customer mix of  residential,  commercial and  industrial  classes and a
commodity  mix of gas and  electric  service  provide a  reasonably  predictable
source of cash  flows.  We plan to utilize  short-term  debt to  support  normal
operations and other temporary capital requirements. Ameren is authorized by the
SEC under PUHCA to have up to an aggregate $2.8 billion of short-term  unsecured
debt instruments  outstanding at any one time.  Short-term borrowings consist of
commercial paper  (maturities  generally within 1 to 45 days) and bank loans. At
September 30, 2002, Ameren had bank credit agreements, expiring at various dates
during 2002 and 2003, which supported  commercial  paper programs  totaling $830
million, of which $400 million was for the use by us and any of our wholly-owned
subsidiaries,  and the  remaining  $430  million  was  for use by our  regulated
subsidiaries. At September 30, 2002, all $830 million of such borrowing capacity
was available. At September 30, 2002, we also had committed bank lines of credit
aggregating $71 million not supporting  commercial paper programs,  all of which
were unused and available at such date for use by us and any of our wholly-owned
subsidiaries.  There were no borrowings  under these  agreements as of September
30, 2002.

     In July 2002,  Ameren  Corporation  entered into new credit  agreements for
$400 million in revolving  credit  facilities  to be used for general  corporate
purposes,  including support of our commercial paper programs,  all of which was
available as of September 30, 2002. The $400 million in new facilities  includes
a $270 million  364-day  revolving  credit  facility  and a $130 million  3-year
revolving credit facility.  The 3-year facility has a $50 million  sub-limit for
the  issuance  of  letters  of  credit.  These new  credit  facilities  replaced
AmerenUE's $300 million  revolving  credit facility that was in place as of June
30, 2002. Ameren  Corporation has a $200 million revolving credit facility which
will mature in December  2002.  We expect to replace  these  various bank credit
agreements prior to their maturity. These bank facilities make available interim
financing at various rates of interest based on LIBOR,  the bank  certificate of
deposit rate or other options.

     AmerenUE  also has a lease  agreement  that  provides for the  financing of
nuclear fuel. At September 30, 2002,  the maximum  amount that could be financed
under the  agreement was $120  million.  At September 30, 2002,  $94 million was
financed under the lease.

     Our financial  agreements  include customary default  provisions that could
impact the continued  availability  of credit or result in the  acceleration  of
repayment.  These  events  include  bankruptcy,  defaults  in  payment  of other
indebtedness, certain judgments that are not paid or insured, or failure to meet
or maintain  covenants.  At September 30, 2002, Ameren and its subsidiaries were
in compliance with these provisions.

     At September 30, 2002, neither Ameren, nor any of its subsidiaries, had any
off-balance sheet financing arrangements.

     We made cash  contributions  totaling  $15 million to our  defined  benefit
retirement  plans  during  the  third  quarter  of 2002  and we  expect  to make
additional cash contributions to the plans totaling approximately $15 million in
the fourth quarter of 2002. Future funding plans will be evaluated at the end of
2002.  Based on the  performance of plan assets  through  September 30, 2002, we
expect to be required under the Employee  Retirement Income Security Act of 1974
to fund $25 million to $50 million in 2004 and $150  million to $200  million in
2005 in order to maintain  minimum funding  levels.  These amounts are estimates
and may change  based on actual stock  market  performance,  changes in interest
rates, any plan

                                       23


funding in 2002 or 2003 and finalization of actuarial assumptions.  In addition,
we expect at December  31,  2002,  to be  required  to record a minimum  pension
liability  that  would  result in a charge to  Accumulated  Other  Comprehensive
Income (OCI) in  stockholders'  equity.  The amount of the charge is expected to
result in a less than one percent change in debt to total capitalization ratios.

Investing

     Our net cash used in  investing  activities  was $582  million in the first
nine months of 2002  compared to $813  million in the first nine months of 2001.
In the first nine months of 2002,  construction  expenditures  were $419 million
(2001 - $468 million) in our regulated operations,  primarily related to various
upgrades at our coal power plants and further construction of combustion turbine
generating  units,  and $146 million (2001 - $344 million) in our  non-regulated
operations,   primarily  related  to  the  construction  of  combustion  turbine
generating  units.  In the first nine months of 2002, we placed into service 240
megawatts of combustion  turbine electric  generation  capacity in our regulated
operations and 351 megawatts in our non-regulated operations.  Regulated capital
expenditures are expected to approximate $170 million and non-regulated  capital
expenditures  are expected to  approximate  $40 million in the fourth quarter of
2002.

     As a part of the  settlement of the Missouri  electric  earnings  complaint
case (see Note 2 - "Rate and Regulatory  Matters" to our consolidated  financial
statements),  AmerenUE  committed  to making $2.25  billion to $2.75  billion in
infrastructure  investments  from January 1, 2002  through June 30, 2006.  These
investments include, among other things, the addition of more than 700 megawatts
of new generation capacity and the replacement of steam generators at AmerenUE's
Callaway nuclear power plant.  The 700 megawatts of new generation  includes 240
megawatts  already  added  this  year,  as  well  as the  proposed  transfer  of
approximately  400 to 500  megawatts  of  generation  assets  to  AmerenUE  from
Generating  Company.  The  transfer,  which is subject to  necessary  regulatory
approvals, is expected to be completed in the second quarter of 2003.

     Ameren completed  construction of one combustion turbine generating unit at
Elgin,  Illinois  during the third quarter of 2002 and two  additional  units in
October 2002. The total  installed  cost of these three units was  approximately
$156 million representing 351 megawatts of capacity.  Ameren expects to complete
construction of an additional unit at Elgin by the end of 2002, which is planned
to provide 117 megawatts of additional  capacity at a cost of approximately  $50
million. The Elgin facility will be owned by Ameren's non-regulated  subsidiary,
Generating Company.

     As of September 30, 2002,  Resources  Company had invested $28 million in a
117  megawatt   combustion   turbine  generating  unit  originally  planned  for
installation  in 2002. We are evaluating  using this unit within  Ameren's power
system in the future or selling it to a third party.

     Due to expected increased demand and the need to maintain appropriate power
reserve  margins,  Ameren  believes  AmerenUE  will need  additional  generating
capacity  in the  future.  We have an  equipment  supply  agreement  in place at
AmerenUE  for the addition of two  combustion  turbine  generating  units with a
total installed  capacity of 330 megawatts.  These units are expected to replace
the  existing  Venice  steam plant  generating  units  which are  expected to be
retired by  mid-2005.  Non-cancelable  reservation  commitment  fees paid of $22
million will be applied to our total cost of these two units.

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

Financing

     Our cash flows provided by financing activities totaled $411 million in the
first nine months of 2002,  compared to $76 million in the year-ago period.  Our
principal financing activities for the period included the issuance of long-term
debt, equity security units and common stock, partially offset by redemptions of
short-term  debt,  long-term  debt, and preferred  stock, as well as payments of
dividends.

                                       24



     In January 2002, Ameren  Corporation issued $100 million of 5.70% notes due
February 1, 2007.  The net proceeds were used to reduce  short-term  borrowings.
Interest is payable  semi-annually  on February 1 and August 1 of each year.  In
March 2002,  Ameren  Corporation  entered into interest  rate swaps  effectively
converting  the interest rate  associated  with these notes to three month LIBOR
plus 43 basis  points.  At September 30, 2002,  the effective  interest rate for
these notes was 2.248%.

     In March  2002,  Ameren  Corporation  issued  $345  million  of  adjustable
conversion-rate   equity  security  units  and  $227  million  of  common  stock
(5,000,000  shares at  $39.50  per share and  750,000  shares,  pursuant  to the
exercise of an option granted to the  underwriters,  at $38.865 per share).  The
$25 adjustable conversion-rate equity security units each consisted of an Ameren
Corporation  senior unsecured note with a principal amount of $25 and a contract
to  purchase,  for $25, a fraction of a share of Ameren  common stock on May 15,
2005.  The  senior  unsecured  notes were  recorded  at their fair value of $345
million  and will  mature on May 15,  2007.  Total  distributions  on the equity
security  units  will be at an annual  rate of 9.75%,  consisting  of  quarterly
interest  payments on the senior  unsecured  notes at the initial annual rate of
5.20% and adjustment  payments under the stock purchase  contracts at the annual
rate of 4.55%. The stock purchase  contracts require holders to purchase between
8.7 million and 7.4 million shares of Ameren common stock on May 15, 2005 at the
market  price at that  time,  subject to a minimum  share  price of $39.50 and a
maximum of $46.61.  The stock purchase  contracts include a pledge of the senior
unsecured  notes as collateral for the stock purchase  obligation.  The interest
rate on the  outstanding  senior  unsecured notes is subject to being reset by a
remarketing agent for quarterly  payments after May 15, 2005 until maturity.  We
recorded the net present value of the contracted stock purchase  payments of $46
million as an increase in Other Deferred  Credits and Liabilities to reflect our
obligation and a decrease in Other Paid-in  Capital to reflect the fair value of
the stock purchase  contract.  The liability for the  contracted  stock purchase
adjustment  payments  will be reduced as such  payments are made through May 15,
2005.  We used the net proceeds  from these  offerings  to repay our  short-term
indebtedness and for general corporate purposes.

     In May 2002, AmerenUE filed a shelf registration  statement with the SEC on
Form S-3  authorizing  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.  The SEC declared the  registration  statement
effective in August 2002.

     In  August  2002,  AmerenUE  issued,  pursuant  to the  shelf  registration
statement,  $173 million of 5.25% Senior  Secured  Notes due  September 1, 2012.
Interest  is  payable  semi-annually  on March 1 and  September  1 of each year,
beginning March 1, 2003. Net proceeds were $172 million, after debt discount and
underwriters'  fees.  These senior secured notes are secured by a related series
of AmerenUE's  first  mortgage  bonds until the release date as described in the
senior secured note indenture.  Proceeds were used to redeem, in September 2002,
AmerenUE's $125 million principal amount 8.75% first mortgage bonds due December
1, 2021 at a 4.38% premium and AmerenUE's  $41 million  $1.735 series  preferred
stock at par.  We may sell  all,  or a  portion  of,  the  remaining  registered
securities  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 June 2002, Ameren Corporation filed a shelf registration  statement with
the SEC on Form S-3  authorizing  the offering from time to time of up to $1.473
billion of various forms of securities including long-term debt, trust preferred
and equity securities to finance ongoing construction and maintenance  programs,
to redeem,  repurchase,  repay, or retire outstanding debt, to finance strategic
investments,  including our pending acquisition of CILCORP Inc., and for general
corporate  purposes.  The SEC declared the registration  statement  effective in
August 2002.

     In  September  2002,  Ameren  Corporation  issued,  pursuant  to the  shelf
registration statement, $338 million of common stock (8,050,000 shares at $42.00
per share,  including  1,050,000  shares  pursuant to the  exercise of an option
granted to the underwriters). Net proceeds were $327 million after underwriters'
fees.  We  anticipate  using the net proceeds from this offering to fund part of
the cash portion of the purchase price for our  acquisition of CILCORP Inc. (see
Note 7 - "CILCORP Acquisition" to our consolidated financial statements) and for
general corporate purposes. Pending such uses, we are investing the net proceeds
in short-term instruments.  The proceeds from this financing along with existing
credit

                                       25


lines  are  expected  to be  adequate  to fund  the  completion  of the  CILCORP
acquisition.  However, within one year of the completion of the acquisition,  we
believe we will need to issue additional  common stock to provide proceeds of up
to $150 million to $175 million in order to permanently fund the cash portion of
the purchase price.  We may sell all, or a portion of, the remaining  registered
securities  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 June 2002,  Generating Company issued $275 million of 7.95% Senior Notes
due June 1, 2032 in a private placement to qualified  investors under Rule 144A.
Interest  is  payable  semi-annually  on June 1 and  December  1 of  each  year,
beginning  December 1, 2002.  Generating  Company  received net proceeds of $271
million,  after debt discount and  underwriters'  fees, that were used to reduce
short-term borrowings incurred to finance previous generating capacity additions
and for general corporate purposes.  In October 2002, Generating Company filed a
registration  statement  with the SEC on Form S-4 to permit an exchange offer of
the senior notes.

     Long-term  debt  maturities  are  expected  to be $89 million in the fourth
quarter  of 2002  and $403  million  in  2003.  We  expect  to  refinance  these
maturities through the issuance of new debt or equity securities.

     On August 23,  2002,  our Board of  Directors  declared a quarterly  common
stock  dividend of 63.5 cents per share that was paid on  September  30, 2002 to
shareholders of record on September 11, 2002.

Outlook

     Ameren currently  believes there will be challenges to earnings in 2003 and
beyond due to continued weak energy  markets,  a soft economy,  higher  employee
benefit costs, and escalating insurance and security costs associated with world
events.  These  industry-wide  trends,  coupled  with an assumed  return to more
normal  weather  patterns,  the  impact  of  our  Missouri  electric  rate  case
settlement and the incremental dilution from equity issued in 2002, are expected
to put  pressure on earnings in 2003 and beyond.  As we complete our analysis of
these  challenges as part of our overall budget  process,  we will be evaluating
several  initiatives  to enhance  revenues and reduce costs for 2003 and beyond.
These initiatives may include any or all of the following:

o    Actively managing employee headcount
o    Modifying employee benefit plans
o    Assessing the necessity of certain plant  operations  and business  support
     functions
o    Reviewing capital expenditure plans
o    Accelerating synergy opportunities related to the CILCORP acquisition
o    Other initiatives

     On November 4, 2002,  we announced a voluntary  retirement  program that is
being offered to  approximately  1,000 of our 7,400 employees.  In addition,  we
announced limits on our contributions  and increased  retiree  contributions for
certain retiree  medical benefit plans and a freeze on wage increases  beginning
in 2003 for all  management  employees.  While we expect to realize  significant
long-term  savings as a result of this  program,  we expect to incur a one-time,
after-tax  charge  in the  fourth  quarter  of  2002  related  to the  voluntary
retirement program. That charge could range between $30 million and $50 million,
based on voluntary  retirements  ranging between 300 and 500,  respectively.  In
addition to the voluntary  retirement program,  we may consider  implementing an
involuntary severance program if it is determined that additional positions must
be eliminated to achieve optimum  organizational  efficiency and  effectiveness.
Further,  the company will  continue to seek other ways to reduce  staffing over
the next year to reduce costs and gain efficiencies in operations.

     In the  ordinary  course of business,  we evaluate  several  strategies  to
enhance our financial  position,  earnings and liquidity.  These  strategies may
include potential acquisitions,  divestitures,  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.


                                       26


Electric Industry Restructuring and Regulatory Matters

Illinois

     See Note 2 - "Rate and Regulatory  Matters" to our  consolidated  financial
     statements.

Federal - Electric Transmission

     See Note 2 - "Rate and Regulatory  Matters" to our  consolidated  financial
     statements.


ACCOUNTING MATTERS

Critical Accounting Policies

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




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


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




Nuclear Plant Decommissioning Costs
                                               
   In our rates and earnings we assume the        o  Estimates of future decommissioning costs
   Department of Energy will develop a            o  Availability of facilities for waste disposal
   permanent storage site for spent nuclear       o  Approved methods for waste disposal and
   fuel, the Callaway plant will have a useful       decommissioning
   life of 40 years and estimated costs to        o  Useful lives of nuclear power plants
   dismantle the plant are accurate.  See Note
   12 to our consolidated financial statements
   for the year ended December 31, 2001.




                                       27


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




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


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




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


   Basis for Judgment

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




Benefit Plan Accounting
                                               
    Based on actuarial calculations, we accrue     o  Future rate of return on pension and other plan
    costs of providing future employee benefits       assets
    in accordance with SFAS 87, 106 and            o  Interest rates used in valuing benefit obligations
    112.  See Note 9 to our consolidated           o  Healthcare cost trend rates
    financial statements for the year ended
    December 31, 2001.



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


                                       28





Derivative Financial Instruments
                                               
   We record all derivatives at their fair         o  Market conditions in the energy industry, especially
   market value in accordance with SFAS               the effects of price volatility on contractual
   133.  The identification and classification        commodity commitments
   of a derivative, and the fair value of such     o  Regulatory and political environments and
   derivative must be determined.  See Note 3         requirements
   to our consolidated financial statements for    o  Fair value estimations on longer term contracts
   the year ended December 31, 2001 and
   Note 3 - "Derivative Financial
   Instruments" to our consolidated financial
   statements in this report.


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

Impact of Future Accounting Pronouncements

     See  Note  1  -  "Summary  of  Significant   Accounting  Policies"  to  our
     consolidated financial statements.


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  risk and are not  represented in the
following analysis.

     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 the  issuance  of 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 September  30, 2002, if interest  rates
increased by 1%, our annual interest  expense would increase by approximately $8
million and net income would  decrease by  approximately  $5 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.


                                       29


Fuel Price Risk

     100% of the required  2002 and 98% of the required  2003 supply of coal for
our coal power  plants  has been  acquired  at fixed  prices.  As such,  we have
minimal coal price risk for the remainder of 2002 and 2003. Approximately 62% of
our coal requirements for 2003 through 2006 are covered by contracts.

     Our gas  business  is not  subject  to fuel  price risk as we have gas cost
recovery mechanisms in both Missouri and Illinois.

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 3 - "Derivative  Financial  Instruments"  to our
consolidated financial statements for additional information.

     The following  summarizes changes in the fair value of all contracts marked
to market during the three and nine months ended September 30, 2002:



--------------------------------------------------------------------------------------------------
                                                                                Three      Nine
                                                                                months    months
--------------------------------------------------------------------------------------------------
                                                                                   
Fair value of contracts at beginning of period, net                             $ -      $ (1)
   Contracts which were realized or otherwise settled during the period           1        (7)
   Changes in fair values attributable to changes in valuation techniques and
   assumptions                                                                    -         -
   Fair value of new contracts entered into during the period                     -         1
   Other changes in fair value                                                    3        11
--------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at September 30, 2002, net                  $ 4      $  4
--------------------------------------------------------------------------------------------------





     Maturities of contracts as of September 30, 2002 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                    $(2)          $ -            $ -          $ -           $(2)
Prices provided by other external
   sources (b)                              2             -              -            -             2
Prices based on models and other
   valuation methods (c)                   (1)            5              -            -             4
-----------------------------------------------------------------------------------------------------------
Total                                     $(1)          $ 5            $ -          $ -           $ 4
-----------------------------------------------------------------------------------------------------------


(a)  Contracts  of  approximately  24% of the  absolute  fair  value  were  with
     non-investment-grade rated counterparties.
(b)  Principally power forward values based on NYMEX prices for over-the-counter
     contracts.
(c)  Principally  coal and sulfur dioxide option values based on a Black-Scholes
     model that includes information from external sources and our estimates.

                                       30


Equity Price Risk

     Our costs of providing  non-contributory  defined  benefit  retirement  and
postretirement benefit plans are dependent upon a number of factors, such as the
rates of return on plan assets,  discount  rate,  the rate of increase in health
care costs and  contributions  made to the plans.  The market  value of our plan
assets has been  affected by declines in the equity  market  since 2001 and 2000
for the pension and postretirement  plans. As a result, at December 31, 2002, we
could be required to  recognize  an  additional  minimum  pension  liability  as
prescribed  by SFAS No. 87,  "Employers'  Accounting  for Pensions" and SFAS No.
132,  "Employers'  Disclosures about Pensions and Postretirement  Benefits." The
liability  would be  recorded  as a  reduction  to OCI and would not  affect net
income for 2002.  The amount of the  liability  will depend  upon asset  returns
experienced in 2002,  interest rates and our  contributions  to the plans during
2002.  The  liability  recorded  and cash  contributions  to the plans  could be
material in future years without a substantial  recovery in equity  markets.  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 OCI would be restored in the Consolidated Balance
Sheet.  See "Liquidity and Capital  Resources - Operating" and Note 1 - "Summary
of Significant Accounting Policies" to our consolidated financial statements.


ITEM 4.  Controls and Procedures

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

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


SAFE HARBOR STATEMENT

     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 the Annual Report on
Form 10-K for the year ended  December 31, 2001,  and in  subsequent  securities
filings,  could cause results to differ materially from management  expectations
as suggested by such "forward-looking" statements:

o    the effects of the  stipulation  and  agreement  relating  to the  AmerenUE
     Missouri  electric  excess  earnings  complaint  case and other  regulatory
     actions, including changes in regulatory policy;
o    changes in laws and other  governmental  actions,  including  monetary  and
     fiscal policies;
o    the impact on us of current  regulations  related  to the  opportunity  for
     customers to choose alternative energy suppliers in Illinois;
o    the  effects of  increased  competition  in the future due to,  among other
     things,  deregulation  of certain aspects of our business at both the state
     and federal levels;
o    the  effects of  participation  in a FERC  approved  Regional  Transmission
     Organization  (RTO),  including  activities  associated  with  the  Midwest
     Independent System Operator;
o    availability  and  future  market  prices  for  fuel and  purchased  power,
     electricity and natural gas,  including the use of financial and derivative
     instruments and volatility of changes in market prices;

                                       31


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    the  effects  of  strategic   initiatives,   including   acquisitions   and
     divestitures;
o    operation of nuclear power facilities and decommissioning costs;
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  benefits 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    delays in receipt of regulatory approvals for the acquisition of CILCORP or
     unexpected adverse conditions or terms of those approvals;
o    difficulties in integrating CILCO with Ameren's other businesses;
o    changes in the coal markets,  environmental  laws or  regulations  or other
     factors  adversely  impacting  synergy  assumptions in connection  with the
     CILCORP acquisition;
o    cost and availability of transmission  capacity for the energy generated by
     our  generating  facilities  or  required to satisfy  energy  sales made by
     Ameren; and
o    legal and administrative proceedings.

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



                                       32


PART II.  OTHER INFORMATION

ITEM 1.  Legal Proceedings

     Reference  is  made  to  Note 11 to the  Notes  to  Consolidated  Financial
Statements  on page 46 of our  2001  Annual  Report  to  Stockholders  which  is
incorporated  by  reference  into  Item 1.  "Business,  Rates and  Regulation  -
Environmental  Matters"  in Part I of our Form 10-K for the year ended  December
31, 2001 for a discussion of environmental proceedings involving our subsidiary,
Union Electric Company,  operating as AmerenUE, which relate to sites located in
Sauget,  Illinois.  On  September  30,  2002,  the United  States  Environmental
Protection  Agency  (EPA) issued a  unilateral  administrative  order (UAO) with
respect  to a  portion  of Sauget  Area 2. The EPA has  ordered  Solutia,  Inc.,
formerly known as Monsanto Chemical Company,  to construct a barrier wall around
a  former  chemical  landfill  as  an  interim  remedy  to  address  groundwater
contamination.  The EPA  issued  the UAO to  approximately  75  parties  whom it
considers to be potentially responsible parties (PRPs) at the Sauget Area 2 site
including AmerenUE.  The UAO directs the PRPs to participate with Solutia,  Inc.
in performing  the work  mandated by the UAO. The Company  believes that the UAO
has been improperly directed to AmerenUE and has submitted a response to the EPA
regarding its good faith defenses to the UAO.

     Reference is made to Item 3. "Legal Proceedings" in Part I of our Form 10-K
for the year ended December 31, 2001 and to Item 1. "Legal  Proceedings" in Part
II of our Form 10-Qs for the quarterly periods ended March 31, 2002 and June 30,
2002 for a  discussion  of a number  of  lawsuits  that  name our  subsidiaries,
Central Illinois Public Service Company,  operating as AmerenCIPS, and AmerenUE,
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 June 30, 2002, 29 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,  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 June 30, 2002,
the Ameren companies have been voluntarily dismissed in two cases.

     To date, a total of 107  asbestos-related  lawsuits have been filed against
the Ameren companies, of which 91 are pending, 10 have been settled and six 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.


ITEM 5.  Other Information

     At our Board of  Directors  meeting  held on  August  23,  2002,  our Board
decided  not to replace  Director  Thomas H.  Jacobsen,  who passed away in July
2002. Our Board decided to reduce its membership to twelve directors.

     Reference  is made to Item 5.  "Other  Information"  in Part II of our Form
10-Q for the quarterly period ended June 30, 2002 for a listing of the audit and
non-audit  services  that the Auditing  Committee of our Board of Directors  has
pre-approved     for    performance    by    our    independent     accountants,
PricewaterhouseCoopers, LLP. At its October 2002 meeting, the Auditing Committee
also pre-approved PricewaterhouseCoopers,  LLP to perform audits of two AmerenUE
coal supply contracts with respect to the handling of prepaid reclamation funds.

     Reference  is  made  to  Note 11 in the  Notes  to  Consolidated  Financial
Statements  on page 46 of our  2001  Annual  Report  to  Stockholders,  which is
incorporated  by  reference  into our Form 10-K for the year ended  December 31,
2001, for a discussion of the Price-Anderson Act which, as indicated, limits the
liability  for claims from an  incident  involving  any  licensed  U.S.  nuclear
facility  such as  AmerenUE's  Callaway  nuclear  power plant.  This federal law
expired in August 2002 and renewal legislation is pending before Congress. Until
the Price-Anderson Act is extended, its provisions continue to apply to existing
nuclear plants such as Callaway.

                                       33


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

     (a)(i)  Exhibits.

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

        99.2 - Certificate of Chief Financial  Officer required by Section 906
               of the Sarbanes-Oxley Act of 2002.

     (a)(ii) Exhibits Incorporated by Reference.

         4.1 - Indenture dated as of August 15, 2002 from AmerenUE to The Bank
               of  New  York,  as  Trustee,  relating  to  senior  secured  debt
               securities (including the forms of senior secured debt securities
               as  exhibits)(AmerenUE  Form 8-K dated August 22,  2002,  Exhibit
               4.1).

         4.2 - AmerenUE  Company Order dated August 22, 2002  establishing the
               5.25%  Senior  Secured  Notes due 2012  (AmerenUE  Form 8-K dated
               August 22, 2002, Exhibit 4.2).

         4.3 - Supplemental  Indenture  dated August 15, 2002 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 AA, 5.25% due 2012
               (AmerenUE Form 8-K dated August 22, 2002, Exhibit 4.3).

     (b)       Reports on Form 8-K. Ameren Corporation filed reports on Form 8-K
               as follows: (i) dated July 12, 2002 incorporating a press release
               stating that an  agreement  in principle  had been reached in the
               earnings  complaint  case filed by the  Missouri  Public  Service
               Commission  (MoPSC) staff against  AmerenUE;  (ii) dated July 16,
               2002  incorporating a press release  outlining the details of the
               settlement  reached in the MoPSC earnings  complaint case;  (iii)
               dated July 25, 2002  incorporating  a press release  stating that
               the MoPSC had  approved  the  settlement  reached in the earnings
               complaint  case; and (iv) dated August 30, 2002  incorporating  a
               press release announcing the receipt from the U.S.  Department of
               Justice  of  a  Request  for  Additional  Information  under  the
               Hart-Scott-Rodino  Antitrust  Improvements  Act pertaining to the
               pending acquisition of CILCORP Inc.

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

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

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

                                       34




                                    SIGNATURE

     Pursuant to the  requirements  of the Securities  Exchange Act of 1934, the
Registrant  has duly  caused  this  report  to be  signed  on its  behalf by the
undersigned thereunto duly authorized.

                                           AMEREN CORPORATION
                                            (Registrant)

                                           By        /s/ Martin J. Lyons
                                              ------------------------------
                                                         Martin J. Lyons
                                                           Controller
                                                 (Principal Accounting Officer)
Date:  November 14, 2002



                                 CERTIFICATIONS

          I, Charles W. Mueller, certify that:

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

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

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

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

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

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

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

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

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

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


                                       35



       6. The registrant's  other certifying  officers and I have indicated
in this  quarterly  report  whether  or not there  were  significant  changes in
internal controls or in other factors that could  significantly  affect internal
controls  subsequent  to the date of our most recent  evaluation,  including any
corrective  actions  with  regard  to  significant   deficiencies  and  material
weaknesses.




Date:  November 14, 2002                      /s/ Charles W. Mueller
                                              -------------------------
                                              Charles W. Mueller
                                              Chief Executive Officer




          I, Warner L. Baxter, certify that:

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

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

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

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

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

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

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

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

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

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

       6. The  registrant's  other  certifying  officers and I have indicated in
this quarterly report whether or not there were significant  changes in internal
controls or in other factors that could  significantly  affect


                                       36


internal  controls  subsequent  to the  date  of  our  most  recent  evaluation,
including any  corrective  actions with regard to significant  deficiencies  and
material weaknesses.




Date:  November 14, 2002                      /s/ Warner L. Baxter
                                              -------------------------
                                              Warner L. Baxter
                                              Chief Financial Officer

                                       37


Exhibit 99.1





                                   CERTIFICATE
                                 furnished under
                  Section 906 of the Sarbanes-Oxley Act of 2002

     I,  Charles W.  Mueller,  chief  executive  officer of Ameren  Corporation,
hereby  certify that to the best of my  knowledge,  the  accompanying  Report of
Ameren  Corporation on Form 10-Q for the quarter ended  September 30, 2002 fully
complies  with the  requirements  of  Section  13(a) or 15(d) of the  Securities
Exchange  Act of 1934 and  that  information  contained  in such  Report  fairly
presents,  in all material  respects,  the  financial  condition  and results of
operations of Ameren Corporation.




                                              /s/ Charles W. Mueller
                                              -------------------------
                                              Charles W. Mueller
                                              Chief Executive Officer

Date:  November 14, 2002




Exhibit 99.2





                                   CERTIFICATE
                                 furnished under
                  Section 906 of the Sarbanes-Oxley Act of 2002

     I, Warner L. Baxter, chief financial officer of Ameren Corporation,  hereby
certify  that to the best of my  knowledge,  the  accompanying  Report of Ameren
Corporation on Form 10-Q for the quarter ended September 30, 2002 fully complies
with the  requirements of Section 13(a) or 15(d) of the Securities  Exchange Act
of 1934 and that information  contained in such Report fairly  presents,  in all
material respects,  the financial  condition and results of operations of Ameren
Corporation.




                                              /s/ Warner L. Baxter
                                             -------------------------
                                              Warner L. Baxter
                                              Chief Financial Officer

Date:  November 14, 2002