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 1-2967

                             UNION ELECTRIC COMPANY
             (Exact name of registrant as specified in its charter)

                  Missouri                                 43-0559760
     (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 Union Electric Company's common stock as of
November 12, 2002: Common Stock, $5 par value, held by Ameren Corporation
(parent company of registrant) - 102,123,834

<PAGE>



                             UNION ELECTRIC COMPANY

                                      INDEX


                                                                          Page
                                                                        --------

PART I.   Financial Information

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

  ITEM 2. Management's Discussion and Analysis of Financial Condition
           and Results of Operations....................................   15

  ITEM 3. Quantitative and Qualitative Disclosures About Market Risk....   25

  ITEM 4. Controls and Procedures.......................................   26

PART II.  Other Information

  ITEM 1. Legal Proceedings.............................................   28

  ITEM 5. Other Information.............................................   28

  ITEM 6. Exhibits and Reports on Form 8-K..............................   28


SIGNATURE...............................................................   29
CERTIFICATIONS..........................................................   29




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.




                                       1


<PAGE>
<TABLE>
<CAPTION>
PART I.   FINANCIAL INFORMATION

ITEM 1.  Financial Statements

                             UNION ELECTRIC COMPANY
                                  BALANCE SHEET
               (Unaudited, in millions, except per share amounts)
<S>                                                              <C>                   <C>
                                                                   September 30,        December 31,
                                                                        2002                2001
                                                                   -------------        ------------
ASSETS:
Property and plant, at original cost:
   Electric                                                             $ 10,222           $ 9,828
   Gas                                                                       263               252
   Other                                                                      37                37
                                                                    ------------       -----------
                                                                          10,522            10,117
   Less accumulated depreciation and amortization                          4,978             4,802
                                                                    ------------       -----------
                                                                           5,544             5,315
Construction work in progress:
   Nuclear fuel in process                                                   124                97
   Other                                                                     207               298
                                                                    ------------       -----------
        Total property and plant, net                                      5,875             5,710
                                                                    ------------       -----------
Investments and other assets:
   Nuclear decommissioning trust fund                                        162               187
   Other                                                                      87                75
                                                                    ------------       -----------
         Total investments and other assets                                  249               262
                                                                    ------------       -----------
Current assets:
   Cash and cash equivalents                                                  13                15
   Accounts receivable - trade (less allowance for doubtful
         accounts of $6 and $7, respectively)                                223               144
   Unbilled revenue                                                           98                90
   Other accounts and notes receivable                                        27                73
   Intercompany notes receivable                                               -                84
   Materials and supplies, at average cost -
      Fossil fuel                                                             73                71
      Other                                                                   90                85
   Other                                                                      25                16
                                                                    ------------       -----------
         Total current assets                                                549               578
                                                                    ------------       -----------
Regulatory assets:
   Deferred income taxes                                                     552               604
   Other                                                                     131               134
                                                                    ------------       -----------
         Total regulatory assets                                             683               738
                                                                    ------------       -----------
Total Assets                                                             $ 7,356           $ 7,288
                                                                    ============       ===========

CAPITAL AND LIABILITIES:
Capitalization:
   Common stock, $5 par value, 150.0 shares authorized -
     102.1 shares outstanding                                              $ 511             $ 511
   Other paid-in capital, principally premium on common stock                702               702
   Retained earnings                                                       1,574             1,440
   Accumulated other comprehensive income                                      4                 1
                                                                    ------------       -----------
      Total common stockholder's equity                                    2,791             2,654
                                                                    ------------       -----------
   Preferred stock not subject to mandatory redemption                       114               155
   Long-term debt                                                          1,574             1,599
                                                                    ------------       -----------
         Total capitalization                                              4,479             4,408
                                                                    ------------       -----------
Current liabilities:
   Current maturities of long-term debt                                      195                92
   Short-term debt                                                             -               186
   Intercompany notes payable                                                109                 -
   Accounts and wages payable                                                136               305
   Accumulated deferred income taxes                                           3                35
   Taxes accrued                                                             311               104
   Other                                                                     126               128
                                                                    ------------       -----------
         Total current liabilities                                           880               850
                                                                    ------------       -----------
Accumulated deferred income taxes                                          1,315             1,326
Accumulated deferred investment tax credits                                  124               129
Regulatory liabilities                                                       130               137
Other deferred credits and liabilities                                       428               438
                                                                    ------------       -----------
Total Capital and Liabilities                                            $ 7,356           $ 7,288
                                                                    ============       ===========

See Notes to Financial Statements.
</TABLE>

                                       2
<PAGE>
<TABLE>
<CAPTION>

                             UNION ELECTRIC COMPANY
                               STATEMENT OF INCOME
                            (Unaudited, in millions)


                                                                 Three Months Ended           Nine Months Ended
                                                                      September 30,                September 30,
                                                             ---------------------------  ---------------------------
<S>                                                          <C>           <C>            <C>          <C>
                                                                 2002          2001           2002          2001
                                                             ------------- -------------  ------------- -------------
OPERATING REVENUES:
   Electric                                                     $ 882       $ 1,027        $ 2,229       $ 2,389
   Gas                                                             12            20             80           107
                                                             ------------- -------------  ------------- -------------
      Total operating revenues                                    894         1,047          2,309         2,496
                                                             ------------- -------------  ------------- -------------

OPERATING EXPENSES:
   Operations
      Fuel and purchased power                                    198           372            633           852
      Gas                                                           7             7             49            64
      Other                                                       142           125            410           388
                                                             ------------- -------------  ------------- -------------
                                                                  347           504          1,092         1,304
   Maintenance                                                     59            55            182           214
   Depreciation and amortization                                   70            70            211           209
   Income taxes                                                   120           134            211           213
   Other taxes                                                     67            63            174           166
                                                             ------------- -------------  ------------- -------------
      Total operating expenses                                    663           826          1,870         2,106
                                                             ------------- -------------  ------------- -------------

OPERATING INCOME                                                  231           221            439           390

OTHER INCOME AND (DEDUCTIONS):
   Allowance for equity funds used during construction              1             4              3             8
   Miscellaneous, net -
     Miscellaneous income                                           1             8             24            25
     Miscellaneous expense                                         (1)           (2)           (32)           (9)
     Income taxes                                                   -            (1)             8            (2)
                                                             ------------- -------------  ------------- -------------
      Total other income and (deductions)                           1             9              3            22
                                                             ------------- -------------  ------------- -------------

INTEREST CHARGES:
   Interest                                                        28            28             82            89
   Allowance for borrowed funds used during construction           (2)           (2)            (4)           (6)
                                                             ------------- -------------  ------------- -------------
      Net interest charges                                         26            26             78            83
                                                             ------------- -------------  ------------- -------------

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
      ACCOUNTING PRINCIPLE                                        206           204            364           329

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
      PRINCIPLE, NET OF INCOME TAXES                                -             -              -            (5)
                                                             ------------- -------------  ------------- -------------

NET INCOME                                                        206           204            364           324

PREFERRED STOCK DIVIDENDS                                           2             3              6             7
                                                             ------------- -------------  ------------- -------------

NET INCOME AFTER PREFERRED STOCK DIVIDENDS                      $ 204         $ 201          $ 358         $ 317
                                                             ============= =============  ============= =============
</TABLE>

See Notes to Financial Statements.


                                      3

<PAGE>
<TABLE>
<CAPTION>

                             UNION ELECTRIC COMPANY
                             STATEMENT OF CASH FLOWS
                            (Unaudited, in millions)

                                                                          Nine Months Ended
                                                                            September 30,
                                                                      ---------      ---------
<S>                                                                   <C>            <C>
                                                                         2002          2001
                                                                      ---------      ---------

Cash Flows From Operating:
   Net income                                                           $ 364         $ 324
   Adjustments to reconcile net income to net cash
       provided by operating activities:
         Cumulative effect of change in accounting principle                -             5
         Depreciation and amortization                                    211           209
         Amortization of nuclear fuel                                      25            21
         Amortization of debt issuance costs and premium/discounts          3             2
         Allowance for funds used during construction                      (7)          (14)
         Deferred income taxes, net                                         7            17
         Deferred investment tax credits, net                              (5)           (2)
         Other                                                              3            (1)
         Changes in assets and liabilities:
               Receivables, net                                           (41)          (81)
               Materials and supplies                                      (7)          (27)
               Accounts and wages payable                                (169)          (82)
               Taxes accrued                                              207           226
               Assets, other                                              (14)           11
               Liabilities, other                                         (18)          (53)
                                                                      ---------      ---------
Net cash provided by operating activities                                 559           555
                                                                      ---------      ---------

Cash Flows From Investing:
   Construction expenditures                                             (357)         (409)
   Allowance for funds used during construction                             7            14
   Nuclear fuel expenditures                                              (25)          (15)
   Intercompany notes receivable                                           84           165
                                                                      ---------      ---------
Net cash used in investing activities                                    (291)         (245)
                                                                      ---------      ---------

Cash Flows From Financing:
   Dividends on common stock                                             (224)         (215)
   Dividends on preferred stock                                            (6)           (7)
   Capital issuance costs                                                  (1)            -
   Redemptions:
      Nuclear fuel lease                                                    -           (64)
      Short-term debt                                                    (186)            -
      Long-term debt                                                     (125)            -
      Preferred stock                                                     (41)            -
   Issuances:
      Nuclear fuel lease                                                   31             3
      Long-term debt                                                      173            11
      Intercompany notes payable                                          109             -
                                                                      ---------      ---------
Net cash used in financing activities                                    (270)         (272)
                                                                      ---------      ---------

Net change in cash and cash equivalents                                    (2)           38
Cash and cash equivalents at beginning of year                             15            20
                                                                      ---------      ---------
Cash and cash equivalents at end of period                               $ 13          $ 58
                                                                      =========      =========

Cash paid during the periods:
   Interest                                                              $ 70          $ 73
   Income taxes, net                                                       62            41

See Notes to Financial Statements.

</TABLE>

                                       4

<PAGE>
<TABLE>
<CAPTION>

                             UNION ELECTRIC COMPANY
                    STATEMENT OF COMMON STOCKHOLDER'S EQUITY
                            (Unaudited, in millions)


                                                                           Three Months Ended                  Nine Months Ended
                                                                               September 30,                      September 30,
                                                                        ----------------------------     ---------------------------
<S>                                                                         <C>             <C>              <C>            <C>
                                                                                2002          2001              2002           2001
                                                                        -------------   ------------     ------------    -----------

Common stock                                                                   $ 511         $ 511             $ 511          $ 511

Other paid-in capital                                                            702           702               702            702

Retained earnings
   Beginning balance                                                           1,442         1,333             1,440          1,358
   Net income                                                                    206           204               364            324
   Common stock dividends                                                        (72)         (142)             (224)          (283)
   Preferred stock dividends                                                      (2)           (3)               (6)            (7)
                                                                          -----------   -----------       -----------    -----------
                                                                               1,574         1,392             1,574          1,392
                                                                          -----------   -----------       -----------    -----------

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


Total common stockholder's equity                                            $ 2,791       $ 2,603           $ 2,791        $ 2,603
                                                                          ===========   ===========       ===========    ===========


Comprehensive income, net of taxes
   Net income                                                                  $ 206         $ 204             $ 364          $ 324
   Unrealized net gain/(loss) on derivative hedging instruments
        (net of income taxes of $2, $1, $3 and $-, respectively)                   2             1                 4             (1)
   Reclassification adjustments for gains/(losses) included in net income
        (net of income taxes of $ -, $1, $(1) and $4, respectively)                1             1                (1)             7
   Cumulative effect of accounting change, net of income taxes of $(5)             -             -                 -             (8)
                                                                          -----------   -----------       -----------   ------------
           Total comprehensive income, net of taxes                            $ 209         $ 206             $ 367          $ 322
                                                                          ===========   ===========       ===========   ============

See Notes to Financial Statements.

</TABLE>



                                       5

<PAGE>

UNION ELECTRIC COMPANY
NOTES TO 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  AmerenUE,  our,  we or us,  we are  referring  to Union
Electric Company and in some cases our agents, AmerenEnergy, Inc. (AmerenEnergy)
and Ameren Energy Fuels and Services Company.  All tabular dollar amounts are in
millions, unless otherwise indicated.

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 $5 million
after taxes to the income  statement,  and a cumulative  effect adjustment of $8
million,  after taxes, to Accumulated Other  Comprehensive  Income (OCI),  which
reduced common stockholder's 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.  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 us 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.

     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   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

                                       6

<PAGE>

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 - Electric and in
Operating  Expenses  -  Operations  - Fuel and  Purchased  Power  in our  income
statement. 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 stockholder's  equity.  The following table summarizes the impact of
applying  the EITF Issue 02-3 on electric  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                                $958     $1,034      $2,374    $2,396
Costs reclassified                           76          7         145         7
--------------------------------------------------------------------------------
Net operating revenues reported in the
   income statement                        $882     $1,027      $2,229    $2,389
--------------------------------------------------------------------------------

     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 $100
million for the three months ended  September 30, 2002 (2001 - $228 million) and
$400 million for the nine months ended September 30, 2002 (2001 - $552 million).

Purchased Power

     Purchased  power  included in  Operating  Expenses -  Operations - Fuel and
Purchased  Power was $99 million for the three months ended  September  30, 2002
(2001 - $274  million) and $376 million for the nine months ended  September 30,
2002 (2001 - $584 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 $36 million (2001 - $34 million) and
$85 million  (2001 - $80  million),  respectively.  Excise taxes  applicable  to
Illinois electric customer bills are imposed on the consumer and are recorded as
tax collections payable.

                                       7

<PAGE>

Employee Benefit Plans

     Ameren Corporation,  our parent company,  made cash contributions  totaling
$15  million to  Ameren's  defined  benefit  retirement  plans  during the third
quarter of 2002, and Ameren expects to make additional cash contributions to the
plans  totaling  approximately  $15 million in the fourth  quarter of 2002.  Our
share  of  the  cash  contribution  made  in  the  third  quarter  of  2002  was
approximately $9 million,  and we expect our share of the cash contribution that
may be made in the fourth  quarter  of 2002 will be  approximately  $9  million.
Future  funding  plans  will be  evaluated  at the  end of  2002.  Based  on the
performance  of plan assets  through  September 30, 2002,  Ameren  expects 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.  We expect our share of the funding to be
between $14 million to $28 million, and $85 million to $113 million for 2004 and
2005, respectively plus our share related to employees of our affiliate,  Ameren
Services  Company.  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  stockholder's  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,  we 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 our experimental  alternative  regulation plan for our
Missouri  retail  electric  customers  expired,   the  Missouri  Public  Service
Commission  (MoPSC) Staff filed an excess earnings complaint against us with the
MoPSC in July 2001. In March 2002, the MoPSC Staff filed a  recommendation  that
we reduce our 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 our depreciation
rates and other cost of service  adjustments.  In May 2002,  we 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 our 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 our 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 our
     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 us of approximately 400 to 500 megawatts of generation assets
     from  our  non-regulated  generation  affiliate,   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  investments 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,

                                       8

<PAGE>

o    an annual reduction in our 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 our Missouri retail electric customers in the
     third quarter 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.  Net earnings are expected to be reduced in 2002 due to
the rate  reduction  ($26 million,  net of taxes),  the expensing in the quarter
ended June 30,  2002 of the entire  obligation  to fund  certain  programs  ($15
million,  net of taxes),  offset,  in part,  by the  reduction  in  depreciation
expense  ($9  million,  net of taxes).  Net  earnings  were  reduced  due to the
stipulation and agreement by $11 million in the quarter ended September 30, 2002
and by $20 million in the quarter ended June 30, 2002.

     In  order  to  satisfy  our  regulatory  load  requirements  for  2001,  we
purchased,  under a one-year  contract  (the 2001  Marketing  Company - AmerenUE
agreement),   450   megawatts  of  capacity  and  energy  from  our   affiliate,
AmerenEnergy  Marketing Company (Marketing Company).  This agreement was entered
into through a competitive bidding process and reflected market-based rates. For
2002, we 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, we 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 us 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 us 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  us from
completing   the  purchases   contemplated   by  the  2001  and  2002  Marketing
Company-AmerenUE agreements 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.

     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  obtaining a broker's
quote to establish 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 us 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

                                       9

<PAGE>


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.
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,  we and our  Illinois-based  utility  affiliate,  Central
Illinois  Public  Service  Company,  operating  as Ameren  CIPS,  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
us.

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, we and  AmerenCIPS,  along with
several other  utilities,  were seeking approval from the FERC to participate in
an RTO known as the Alliance RTO. We had previously been a member of the Midwest
Independent  System  Operator  (Midwest  ISO) and  recorded  a pretax  charge to
earnings in 2000 of $17 million  ($10  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  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 the
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 fees  paid by us and  AmerenCIPS  to leave the
Midwest ISO,  provided we and AmerenCIPS  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,  we and AmerenCIPS  have made filings with
the FERC  indicating  that we would  return  to the  Midwest  ISO  through a new
independent transmission company,  GridAmerica LLC, that was agreed to be formed
by us and AmerenCIPS,  along with  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 the Ameren companies and other market participants
in previous filings.


                                       10

<PAGE>

     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 the Ameren  companies
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 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 - Related Party Transactions

     AmerenUE has transactions in the normal course of business with its parent,
Ameren  Corporation,  and Ameren's other  subsidiaries.  These  transactions are
primarily  comprised of power  purchases  and sales,  as well as other  services
received or rendered. Intercompany power purchases from joint dispatch and other
agreements were  approximately  $36 million for the three months ended September
30,  2002  (2001 - $78  million)  and $87  million  for the  nine  months  ended
September 30, 2002 (2001 - $122 million).  Intercompany  power sales totaled $21
million for the three months ended  September  30, 2002 (2001 - $17 million) and
$58 million for the nine months ended September 30, 2002 (2001 - $57 million).

     Support   services   provided  by  our  affiliates,   Ameren  Services  and
AmerenEnergy,  including wages,  employee benefits and professional services are
based on actual costs  incurred.  For the three months ended September 30, 2002,
Other Operating  Expenses  provided by Ameren Services and AmerenEnergy  totaled
$43 million  (2001 - $39 million) and $123 million (2001 - $129 million) for the
nine months ended September 30, 2002.

     Intercompany  receivables  included in Other Accounts and Notes  Receivable
were approximately $18 million as of September 30, 2002 (December 31, 2001 - $38
million).  Intercompany  payables included in Accounts and Wages Payable totaled
approximately  $46 million as of  September  30, 2002  (December  31, 2001 - $70
million).

     We have the  ability  to  borrow  from  Ameren  and  AmerenCIPS  through  a
regulated money pool agreement.  Ameren Services administers the regulated money
pool and tracks  internal  and external  funds  separately.  Internal  funds are
surplus  funds  contributed  to the money pool from  participants.  The  primary
source of external funds for the regulated  money pool at September 30, 2002 was
our  commercial  paper  program,  which  was  backed by bank  credit  agreements
totaling $430 million and credit agreements totaling $400 million at Ameren. The
total amount  available to us at any given time from the regulated money pool is
reduced by the amount of  borrowings  by our  affiliates,  but  increased to the
extent  Ameren,  AmerenCIPS  or  Ameren  Services  have  surplus  funds  and the
availability of other external borrowing  sources.  The availability of funds is
also determined by funding  requirement limits  established by PUHCA.  AmerenUE,
AmerenCIPS  and Ameren  Services rely on the regulated  money pool to coordinate
and provide  for  certain  short-term  cash and  working  capital  requirements.
Borrowers  receiving a loan under the regulated  money pool agreement must repay
the principal amount of such loan,  together with accrued interest.  Interest is
calculated at varying rates of interest depending on the composition of internal
and  external  funds in the  regulated  money pool.  For the three  months ended
September 30, 2002, the average  interest rate for the regulated  money pool was
1.73% (2001 - 3.67%) and for the nine months ended  September 30, 2002 was 1.75%
(2001 - 4.51%).  As of September  30,  2002,  we had the ability to borrow up to
$471 million, all of which was unused and available, through the regulated money
pool,  which  was in  addition  to  amounts  available  under  our $430  million
commercial paper program and cash balances at Ameren  Corporation.  At September
30, 2002, we had outstanding  intercompany payables of $109 million,  sourced by
internal funds through the money pool. At December 31, 2001, we had  outstanding
intercompany receivables of $84 million through the money pool.


                                       11

<PAGE>

     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  commercial  paper  programs.  These new credit
facilities  support our ability to borrow through the regulated  money pool. The
$400million 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 our existing $300 million revolving credit
facility.  At September 30, 2002, all of such borrowing capacity under these new
facilities was available.

     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, we were in compliance with these
provisions.


NOTE 4 - 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.

     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 $9 million in Other Assets and the fair value of
derivative  financial  instrument  liabilities  of $4 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.

     For the three and nine month periods ended  September 30, 2002,  the pretax
net loss on power forward derivative  instruments,  which represented the impact
of discontinued cash flow hedges,  the ineffective

                                       12

<PAGE>

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  $3 million.  The pretax net gain from these  transactions for the
same three months in the prior year was $2 million. In the prior year nine-month
period, we recognized a pretax net gain of $9 million.

     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).

     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,
while the net change in the market  value of coal,  heating oil and  electricity
options is recorded as  Operating  Expenses -  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 $4
million ($2 million, net of taxes) for the nine months ended September 30, 2002.
The change in market  values in the prior year  resulted in losses of $2 million
($1  million,  net of taxes)  for the  three-month  period  and $6  million  ($4
million, net of taxes) for the nine-month period.


NOTE 5 - Debt Financing

     In August 2002,  we 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 our first mortgage bonds until the release date as described
in the senior secured note indenture. Proceeds were used to redeem, in September
2002,  our $125  million  principal  amount of 8.75%  first  mortgage  bonds due
December  1, 2021 at a 4.38%  premium  and $41  million of our $1.735  series of
preferred stock at par.


NOTE 6 - Miscellaneous, Net

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

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                           Three Months          Nine Months
-----------------------------------------------------------------------------------------------
<S>                                                     <C>        <C>        <C>        <C>
                                                         2002       2001       2002       2001
                                                         ----       ----       ----       ----
Miscellaneous income:
   Interest and dividend income                           $ -        $ 1        $ 2        $ 7
   Equity in earnings of subsidiary                         1          1         13          3
   Gain on disposition of property and other assets         -          -          3          2
   Other                                                    -          6          6         13
-----------------------------------------------------------------------------------------------
Total miscellaneous income                                $ 1        $ 8       $ 24       $ 25
-----------------------------------------------------------------------------------------------

Miscellaneous expense:
   Plant acquisition amortization                         $ -       $  -       $ (1)      $ (1)
   Donations - rate settlement                              -          -        (26)         -
   Other                                                   (1)        (2)        (5)        (8)
------------------------------------------------------------------------------------------------
Total miscellaneous expense                               $(1)      $ (2)      $(32)      $ (9)
------------------------------------------------------------------------------------------------
</TABLE>

                                       13

<PAGE>

NOTE 7 - CILCORP Acquisition

     On  April  28,  2002,  Ameren  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. Ameren 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.  Ameren expects 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 SEC under PUHCA, the FERC, 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.  Ameren does not expect that this  extension
will impact the anticipated  transaction  closing date. In October 2002,  Ameren
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,  Ameren has 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.


NOTE 8 - Subsequent Event

     On November 4, 2002, Ameren announced a voluntary  retirement  program that
is being  offered  to  approximately  1,000  of its  7,400  employees  including
employees  providing  support  functions  to  us  through  Ameren  Services  and
approximately 250 AmerenUE  employees.  In addition,  Ameren announced limits on
its  contributions  and  increased  retiree  contributions  for certain  retiree
medical  benefit plans and a freeze on wage increases  beginning in 2003 for all
management  employees,  including AmerenUE  management  employees.  While we and
Ameren  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 for Ameren
could range between $30 million and $50 million,  based on voluntary retirements
ranging between 300 and 500,  respectively.  We expect to be allocated a portion
of this charge depending on the amount of retirements within AmerenUE and Ameren
Services.  In addition to the voluntary  retirement  program,  we and Ameren 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, we and Ameren will continue to seek other
ways to reduce staffing over the next year to reduce costs and gain efficiencies
in operations.




                                       14

<PAGE>

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

OVERVIEW

     Union Electric Company is a wholly-owned  subsidiary of Ameren  Corporation
and operates as AmerenUE.  Our principal  business is the regulated  generation,
transmission and distribution of electricity,  and the regulated distribution of
natural  gas to  residential,  commercial,  industrial  and  wholesale  users in
Missouri and Illinois.  Ameren Corporation is a holding company registered under
the Public  Utility  Holding  Company Act of 1935  (PUHCA).  Ameren's  principal
business is the generation,  transmission and  distribution of electricity,  and
the  distribution  of natural gas to  residential,  commercial,  industrial  and
wholesale  users in the central  United  States.  In  addition  to us,  Ameren's
principal subsidiaries and our affiliates are as follows:

o    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 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 Ameren affiliated companies.
o    AmerenEnergy,  Inc.  (AmerenEnergy)  which serves as a power  marketing and
     risk management agent for Ameren  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 40% ownership interest
     in EEI and have accounted for it under the equity method of accounting. Our
     affiliate, Resources Company, also owns a 20% interest.
o    Ameren Services  Company,  which provides shared support services to Ameren
     and its subsidiaries, including us. Charges are based upon the actual costs
     incurred by Ameren Services, as required by PUHCA.

     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 included 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  appears  in our  Annual  Report on Form 10-K for the year
     ended December 31, 2001.

     When we  refer  to  AmerenUE,  our,  we or us,  we are  referring  to Union
Electric  Company and in some cases our agents,  AmerenEnergy  and  AmerenEnergy
Fuels and Services Company.  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 nearly all 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.


                                       15

<PAGE>

RESULTS OF OPERATIONS

Summary

     Our net income increased to $206 million in the third quarter of 2002, from
$204 million in the third quarter of 2001.  Net income for the nine months ended
September  30, 2002,  was $364  million,  an increase of 12% from the first nine
months of 2001.  The increases in 2002 were  primarily due to favorable  weather
conditions  (third  quarter  - $15  million,  net of  taxes;  year to date - $18
million,  net of taxes),  increased  sales of emission  credits,  including such
sales by EEI (year to date - $12 million,  net of taxes), the lack of a Callaway
nuclear plant refueling outage to date in 2002 (year to date - $19 million,  net
of taxes)  and lower  fuel and  purchased  power  costs.  These  increases  were
partially  offset by the impact of the settlement of our Missouri  electric rate
case (third quarter - $11 million, net of taxes; year to date - $31 million, net
of taxes) (see below),  increased employee benefits expenses (third quarter - $3
million,  net of taxes;  year to date - $8  million,  net of  taxes),  decreased
interchange  revenues,  increased  sales of  emission  credits in the prior year
(third quarter - $5 million, net of taxes) and a reduction of an accrual in 2001
for expected customer sharing credits under the Missouri  electric  experimental
alternative  regulation  plan  that  expired  in June  2001  (year  to date - $6
million,  net of  taxes)  (see  Note 2 - "Rate and  Regulatory  Matters"  to our
financial statements).  In January 2001, we also recorded a charge of $5 million
due to the adoption of Statement of Financial  Accounting  Standards  (SFAS) No.
133, "Accounting for Derivative Instruments and Hedging Activities."

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  Ameren  employees in
early November 2002 and is expected to result in a fourth quarter 2002 after-tax
charge to Ameren of between $30 million and $50 million.

Missouri Electric Rate Case

     From July 1, 1995  through June 30, 2001,  we 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 our experimental  alternative  regulation plan for our
Missouri  retail  electric  customers  expired,   the  Missouri  Public  Service
Commission  (MoPSC) Staff filed an excess earnings complaint against us with the
MoPSC in July 2001. In March 2002, the MoPSC Staff filed a  recommendation  that
we reduce our 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 our depreciation
rates and other cost of service  adjustments.  In May 2002,  we 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 our 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 our 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 our
     nuclear power

                                       16

<PAGE>

     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 us
     of  approximately  400 to 500  megawatts  of  generation  assets  from  our
     non-regulated generation affiliate, 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
     investments 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 our 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 our 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.  Net earnings are expected to be reduced in 2002 due to
the rate  reduction  ($26 million,  net of taxes),  the expensing in the quarter
ended June 30,  2002 of the entire  obligation  to fund  certain  programs  ($15
million,  net of taxes),  offset,  in part,  by the  reduction  in  depreciation
expense  ($9  million,  net of taxes).  Net  earnings  were  reduced  due to the
stipulation and agreement by $11 million in the quarter ended September 30, 2002
and by $20 million in the quarter ended June 30, 2002.

CILCORP Acquisition

     On  April  28,  2002,  Ameren  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. Ameren 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.  Ameren expects 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 Securities and Exchange Commission (SEC)
under PUHCA, the Federal Energy Regulatory  Commission  (FERC),  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.  Ameren
does not expect  that this  extension  will impact the  anticipated  transaction
closing date. In October 2002, Ameren 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,  Ameren  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 June 30,  2002 had total  assets of $1.9
billion.  For the year ended  December  31,  2001,  CILCORP had revenues

                                       17

<PAGE>


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 our 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,  while AmerenUE's corporate credit rating is "A+" at Standard &
Poor's and its issuer rating is "A1" 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 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-month  periods ended  September 30, 2002 from the comparable
periods in 2001:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------
                                                           Three Months          Nine Months
-----------------------------------------------------------------------------------------------
<S>                                                         <C>                    <C>
Operating Revenues:
   Effect of abnormal weather (estimate)............         $   35                $  45
   Growth and other (estimate)......................            (29)                  (7)
   Rate reductions..................................            (23)                 (36)
   Credit to customers..............................              -                  (10)
   Interchange sales................................           (128)                (152)
-----------------------------------------------------------------------------------------------
                                                               (145)                (160)
Fuel and Purchased Power:
   Fuel:
     Generation.....................................          $  (7)              $  (12)
     Price..........................................              6                   23
   Purchased power .................................            175                  208
-----------------------------------------------------------------------------------------------
                                                                174                  219
-----------------------------------------------------------------------------------------------
Change in electric margin                                     $  29               $   59
-----------------------------------------------------------------------------------------------
</TABLE>

     Electric margin  increased $29 million for the three months ended September
30, 2002 and $59 million for the nine months ended September 30, 2002,  compared
to the same prior year  periods.  Favorable  weather  conditions  resulted in an
increase  in  weather-sensitive  residential  kilowatt-hour  sales of 8% for the
quarter and 4%  year-to-date  and commercial  kilowatt-hour  sales of 5% for the
quarter and 4% year-to-date compared to prior year periods. However,  industrial
kilowatt-hour  sales decreased 4% for the quarter and 10% year-to-date  compared
to the prior year  periods,  primarily  due to the soft  economy.  Revenues were
reduced by $23  million  for the third  quarter of 2002 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.  Decreased  interchange  revenues and sales were  attributable  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 costs decreased in the third quarter  primarily due to the lower
interchange  sales and lower  prices.  Purchased  power was reduced in the first
nine  months of 2002 due to lower  interchange  sales and the lack of a Callaway
nuclear plant  refueling,  partially  offset by unscheduled  coal plant outages.
Another

                                       18

<PAGE>

refueling  outage at Callaway began in mid-October,  is expected to last 35 days
and is estimated to reduce fourth quarter 2002 net earnings by $14 million,  net
of taxes.

     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  the  financial
statements.  The above interchange revenues and fuel and purchased power amounts
include  transactions  with  our  affiliates.   See  Note  3  -  "Related  Party
Transactions" to our financial statements for further details.

Gas Operations

     Our gas  margins  decreased  $8  million  in the third  quarter  of 2002 as
compared to the same period in 2001 with gas revenues decreasing $8 million, due
to a 20% decrease in sales. The prior year third quarter included the benefit of
the recovery of gas costs from our customers  under a purchased  gas  adjustment
clause.  Gas margins  decreased $12 million for the first nine months of 2002 as
compared to the same period in 2001 with gas  revenues  decreasing  $27 million,
primarily due to a 7% reduction caused by milder winter weather at the beginning
of the year and the favorable purchased gas adjustment in the prior year.

Other Operating Expenses

     Operating  Expenses - Operations - Other increased $17 million in the third
quarter of 2002 and $22  million in the first nine  months of 2002,  compared to
the year-ago periods,  primarily due to higher employee benefit costs related to
the investment  performance of pension plan assets,  increasing healthcare costs
and increased legal expenses related to the Missouri electric rate case that was
settled in July 2002. 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.

     Ameren Services and AmerenEnergy  provided services to us, including wages,
employee  benefits,  and  professional  services  that  were  included  in Other
Operating  Expenses.  See Note 3 - "Related Party Transactions" to our financial
statements.

     Maintenance  expenses  increased  $4 million in the third  quarter of 2002,
compared to the same prior year period,  primarily due to increased  expenses in
preparation  for the Callaway  nuclear plant refueling that began in mid-October
2002.  Maintenance  expenses  decreased  $32 million in the first nine months of
2002,  compared to the same prior year  period,  primarily  due to the lack of a
Callaway  nuclear plant refueling outage in the first nine months of 2002, along
with decreased maintenance at our coal-fired power plants.

     Depreciation and amortization  expenses  remained  comparable for the third
quarter compared to same year-ago period.  Expenses  increased $2 million in the
first nine months of 2002,  compared to the year-ago  periods,  primarily due to
our  investment in coal-fired  power plants.  The increase in 2002 was partially
offset by a reduction  in  depreciation  rates  based on an updated  analysis of
asset values, service lives and accumulated depreciation levels 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  $15 million in the third quarter of 2002 due
to lower pretax  income.  Income tax expense  decreased $12 million in the first
nine months of 2002 primarily due to the lower effective tax rate.  Income taxes
related  to our  non-regulated  operations  are  recorded  in Other  Income  and
Deductions.

     Other tax expense  increased $4 million in the third quarter of 2002 and $8
million in the first nine  months of 2002,  compared  to the  year-ago  periods,
primarily due to higher gross receipts taxes  resulting from increased  electric
residential and commercial sales.

Other Income and Deductions

     Other income and deductions  (excluding  income taxes) decreased $9 million
in the third  quarter of 2002 and $29  million in the first nine months of 2002,
compared to the same periods last year,  primarily due to the commitment to fund
certain  programs as part of the  settlement of the Missouri  electric rate case
($26 million),  lower intercompany  interest earned in the first quarter of 2002
on funds  loaned to the  regulated  money  pool  resulting  from  lower  average
intercompany notes receivable balances and increased

                                       19

<PAGE>

coal supply risk management  costs.  These decreases were partially offset by an
increase in earnings from our ownership interest in EEI primarily resulting from
its sale of emission  credits  (year-to-date - $10 million) along with increased
gains on asset  disposals.  See Note 6 -  "Miscellaneous,  Net" to our financial
statements.

Interest

     Interest  expense for the third quarter 2002 was flat compared to 2001, but
decreased $7 million in the first nine months of 2002,  compared to the year-ago
period, primarily due to lower interest rates on our variable rate environmental
debt obligations and lower interest expense  associated with a decreased balance
under  our  nuclear  fuel  lease,   partially  offset  by  increased  short-term
intercompany  interest as a result of our borrowings  from the money pool in the
current year.  Amortization of debt issuance costs and premium/discounts for the
three and nine months ending  September 30, 2002 of $1 million (2001 - less than
$1 million) and $3 million (2001 - $2 million) were included in interest expense
in the income statement.


LIQUIDITY AND CAPITAL RESOURCES

Operating

     Our cash flows  provided by  operating  activities  increased $4 million to
$559 million in the first nine months of 2002  compared to the year-ago  period.
Cash provided by operations increased primarily due to higher net income despite
lower rates  associated with our Missouri rate case settlement and a decrease in
materials  and supplies  due to higher than normal  amounts at December 31, 2001
due to the warm winter and  anticipation  of a potential coal supply  disruption
that  ultimately  did not occur  which  was  partially  offset by the  timing of
payments  on  accounts  payable  and accrued  taxes  including  the  payments of
customer sharing credits under our now-expired electric  alternative  regulation
plan.

     Our tariff-based  gross margins 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.  AmerenUE  is  authorized  by the SEC under PUHCA to have up to $1
billion of short-term  unsecured debt  instruments  outstanding at any one time.
Short-term  borrowings  typically  consist of commercial  paper with  maturities
generally within 1 to 45 days.

     As of September 30, 2002, we had several bank credit agreements expiring in
2002 that supported our $430 million commercial paper program, all of which were
unused and available. We also had the ability to borrow up to approximately $471
million  from Ameren,  through a regulated  money pool  agreement.  See Note 3 -
"Related Party Transactions" to our financial statements.

     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  commercial  paper  programs,  all of which was
available at September 30, 2002. These new credit facilities support our ability
to borrow  through the regulated  money pool. 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 our $300 million revolving credit facility that was in place as of June
30, 2002.

     We also have 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, we were in compliance with these
provisions.

     At September  30, 2002,  we did not have any  off-balance  sheet  financing
arrangements.

                                       20

<PAGE>

     Ameren Corporation made cash contributions totaling $15 million to Ameren's
defined benefit retirement plans during the third quarter of 2002 and expects to
make  additional  cash  contributions  to the plans totaling  approximately  $15
million in the fourth quarter of 2002. Our share of the cash  contribution  made
in the third  quarter of 2002 was  approximately  $9 million,  and we expect our
share of the cash  contribution  that may be made in the fourth  quarter of 2002
will be approximately $9 million.  Future funding plans will be evaluated at the
end of 2002. Based on the performance of plan assets through September 30, 2002,
Ameren expects 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. We expect our share
of the funding to be between $14 million to $28 million, and $85 million to $113
million for 2004 and 2005,  respectively  plus our share related to employees of
Ameren  Services.  These  amounts are  estimates  and may change based on actual
stock market performance, changes in interest rates, 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  Accumulated  Other  Comprehensive  Income (OCI) in
stockholder's  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 $291  million in the first
nine months of 2002  compared to $245  million in the first nine months of 2001.
Construction expenditures were incurred primarily for upgrades at our coal power
plants and  construction of combustion  turbine  generating  units.  Our capital
expenditures  are expected to approximate  $145 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 financial  statements),
we  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 our Callaway
nuclear power plant. The 700 megawatts of new generation  includes 240 megawatts
already  added  this  year,  as  well  as the  proposed  transfer  of 400 to 500
megawatts  of  combustion  turbine  units  to us from  Generating  Company.  The
transfer which is subject to necessary regulatory  approvals,  is expected to be
completed in the second quarter of 2003.

     Due to expected increased demand and the need to maintain appropriate power
reserve margins,  we believe we will need additional  generating capacity in the
future.  We have an equipment  supply agreement in place 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.

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

Financing

     Our cash flows used in financing  activities were $270 million in the first
nine  months of 2002  compared  to $272  million  in the  year-ago  period.  Our
principal  financing  activities for the current period included the redemptions
of  short-term  debt,  long-term  debt and  preferred  stock and the  payment of
dividends,  partially  offset by the issuance of long-term debt and intercompany
notes payable.

     In May 2002, we 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, as well as 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

                                       21

<PAGE>

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 our first mortgage bonds until the release date as described
in the senior secured note indenture. Proceeds were used to redeem, in September
2002,  our $125  million  principal  amount of 8.75%  first  mortgage  bonds due
December  1, 2021 at a 4.38%  premium  and $41  million of our $1.735  series of
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.

Outlook

     We  currently  believe  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  and the  impact of our  Missouri  electric  rate case
settlement,  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 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    Other initiatives

     On November 4, 2002, Ameren announced a voluntary  retirement  program that
is being  offered  to  approximately  1,000  of its  7,400  employees  including
approximately 250 AmerenUE  employees and employees  providing support functions
to us through  Ameren  Services.  In addition,  Ameren  announced  limits on its
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  and  Ameren  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  program.  That
charge for Ameren  could range  between $30  million and $50  million,  based on
voluntary retirements ranging between 300 and 500, respectively. We expect to be
allocated a portion of this charge depending on the amount of retirements within
AmerenUE and Ameren Services.  In addition to the voluntary  retirement program,
we and Ameren 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,  we  and  Ameren  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.

Electric Industry Restructuring and Regulatory Matters

Illinois

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


Federal - Electric Transmission

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


                                       22

<PAGE>

ACCOUNTING MATTERS

Critical Accounting Policies

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

<TABLE>
<CAPTION>

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

Regulatory Mechanisms & Cost Recovery
  <S>                                             <C>
   We defer costs as regulatory assets in          o    Regulatory environment, external regulatory
   accordance with SFAS 71 and make investments         decisions and requirements
   that we assume we will be able to collect in    o    Anticipated future regulatory decisions and their
   future rates.                                        impact
                                                   o    Impact of deregulation and competition on
                                                        ratemaking process and ability to recover costs
   Basis for Judgment
   We determine that costs are recoverable based on previous rulings by state regulatory authorities in
   jurisdictions where we operate or other factors that lead us to believe that cost recovery is probable.
</TABLE>

<TABLE>

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

   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.
</TABLE>

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

                                       23

<PAGE>
   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.
</TABLE>

<TABLE>
Unbilled Revenue
  <S>                                             <C>
   At the end of each period, we estimate, based   o    Projecting customer energy usage
   on expected usage, the amount of revenue to     o    Estimating impacts of weather and other
   record for services that have been provided          usage-affecting factors for the unbilled period
   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.
</TABLE>

<TABLE>
Benefit Plan Accounting
  <S>                                             <C>
   Based on actuarial calculations, we accrue      o    Future rate of return on pension and other plan assets
   costs of providing future employee benefits     o    Interest rates used in valuing benefit obligations
   in accordance with SFAS 87, 106, and 112.       o    Healthcare cost trend rates
   See Note 10 to our 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.
</TABLE>

<TABLE>
Derivative Financial Instruments
  <S>                                             <C>
   We record all derivatives at their fair market  o    Market conditions in the energy industry, especially
   value in accordance with SFAS 133.  The              the effects of price volatility on contractual
   identification and classification of a               commodity commitments
   derivative, and the fair value of such          o    Regulatory and political environments and
   derivative must be determined.  See Note 4           requirements
   to our financial statements for the year        o    Fair value estimations on longer term contracts
   ended December 31, 2001 and Note 4 -
   "Derivative Financial Instruments" to our
   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 financial statements.

</TABLE>

                                       24


<PAGE>

ITEM 3.  Quantitative and Qualitative Disclosures about Market Risk

     Market risk  represents the risk of changes in value of a physical asset or
financial  instrument,  derivative or non-derivative,  caused by fluctuations in
market  variables  (e.g.  interest  rates,  etc.).  The following  discussion of
Ameren's,    including   AmerenUE's,   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. Ameren manages market risks in accordance with established policies,
which may include entering into various derivative  transactions.  In the normal
course of  business,  Ameren  and our  company  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.

     Ameren's risk management  objective is to optimize its physical  generating
assets within prudent risk  parameters.  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  our  issuance  of  both  long-term  and  short-term   variable-rate  debt,
fixed-rate  debt and commercial  paper.  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 $6
million and net income would  decrease by  approximately  $4 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.

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 59% 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  and under  firm
     commitment; and
o    actual cash  outlays for the purchase of these  commodities  to differ from
     anticipated cash outlays.

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


                                       25

<PAGE>

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

<TABLE>
<CAPTION>
-------------------------------------------------------------------------------------------------------
<S>                                                                                 <C>        <C>
                                                                                     Three       Nine
                                                                                     months     months
-------------------------------------------------------------------------------------------------------
Fair value of contracts at beginning of period, net                                   $ 2      $ (2)
   Contracts which were realized or otherwise settled during the period                 -        (5)
   Changes in fair values attributable to changes in valuation techniques and           -         -
     assumptions
   Fair value of new contracts entered into during the period                           -         -
   Other changes in fair value                                                          3        12
-------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at September 30, 2002, net                        $ 5       $ 5
=======================================================================================================
</TABLE>

     Maturities of contracts as of September 30, 2002 were as follows:

<TABLE>
<CAPTION>
-----------------------------------------------------------------------------------------------------------
<S>                                   <C>           <C>           <C>          <C>            <C>
                                        Maturity                                Maturity in
                                       less than      Maturity      Maturity    excess of 5    Total fair
Sources of fair value                    1 year      1-3 years     4-5 years       years       value (a)
-----------------------------------------------------------------------------------------------------------
Prices actively quoted                  $  -            $ -            -             -            $ -
Prices provided by other external
   sources (b)                             1              -            -             -              1
Prices based on models and other
   valuation methods (c)                  (2)             6            -             -              4
-----------------------------------------------------------------------------------------------------------
Total                                   $ (1)           $ 6            -             -            $ 5
===========================================================================================================
(a)  Nearly 100% of contracts were with 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.
</TABLE>

Equity Price Risk

     We, along with other  subsidiaries of Ameren, are a participant in Ameren's
defined benefit plans and  postretirement  benefit plans and are responsible for
our   proportional   share  of  the   costs.   Ameren's   costs   of   providing
non-contributory defined benefit retirement and postretirement benefit plans are
dependent upon a number of factors,  such as the rates of return on plan assets,
discount rate, the rate of increase in health care costs and contributions  made
to the plans.  The market value of 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, Ameren and its subsidiaries, including
AmerenUE, 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, changes in interest rates and Ameren's contributions to the
plan 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,  if
any, would be reduced and a corresponding amount of OCI would be restored in the
Balance Sheet.  See  "Liquidity and Capital  Resources - Operating" and Note 1 -
"Summary of Significant Accounting Policies" to our 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 the 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 AmerenUE
required to be included in our periodic SEC filings.


                                       26

<PAGE>


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

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 our  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;
o    average rates for electricity in the Midwest;
o    business and economic conditions;
o    the impact of the adoption of new accounting  standards on the  application
     of appropriate technical accounting rules and guidance;
o    interest rates and the availability of capital;
o    actions of rating agencies and the effects of such actions;
o    weather conditions;
o    generation plant construction, installation and performance;
o    operation of nuclear power facilities and decommissioning costs;
o    the 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    competition from other generating  facilities including new facilities that
     may be developed in the future;
o    disruptions of the capital  markets or other events making Ameren's and our
     access to necessary capital more difficult or costly;
o    cost and availability of transmission  capacity for the energy generated by
     our generating facilities or required to satisfy our energy sales; 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.



                                       27

<PAGE>


PART II.  OTHER INFORMATION

ITEM 1.  Legal Proceedings

     Reference  is made to Note 11 to the Notes to  Financial  Statements  under
Item 8.  "Financial  Statements and  Supplementary  Data" in Part II of our Form
10-K for the year ended  December  31, 2001 for a  discussion  of  environmental
proceedings 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  us. The UAO  directs  the PRPs to
participate  with Solutia,  Inc. in performing  the work mandated by the UAO. We
believe  that the UAO has been  improperly  directed to us and have  submitted a
response to the EPA regarding our 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 10Qs for the quarterly  periods ended March 31, 2002 and June 30,
2002 for a discussion of a number of lawsuits that name our  affiliate,  Central
Illinois  Public Service  Company  operating as AmerenCIPS,  our parent,  Ameren
Corporation,  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

     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 the Ameren 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 to the Notes to  Financial  Statements  under
Item 8.  "Financial  Statements and  Supplementary  Data" in Part II of 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.

ITEM 6.  Exhibits and Reports on Form 8-K

         (a)   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.


                                       28

<PAGE>

          (b)  Reports  on Form  8-K.  AmerenUE  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  22,  2002  reporting
               AmerenUE's issuance and sale of $173,000,000  principal amount of
               its 5.25%  Senior  Secured  Notes due 2012 and filing as exhibits
               certain documents in connection with that offering.

       Note:   Reports of Ameren Corporation on Forms 8-K, 10-Q and 10-K are on
               file with the SEC under File Number 1-14756.

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


                                    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.

                                                 UNION ELECTRIC COMPANY
                                                      (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 Union Electric
Company;

     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;

                                       29

<PAGE>

          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 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 Union Electric
Company;

     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;

                                       30

<PAGE>

     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 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





                                       31

<PAGE>



Exhibit 99.1





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

     I, Charles W. Mueller,  chief executive  officer of Union Electric Company,
hereby  certify that to the best of my  knowledge,  the  accompanying  Report of
Union  Electric  Company 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 Union Electric Company.




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

Date:  November 14, 2002


<PAGE>


Exhibit 99.2



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

     I, Warner L. Baxter,  chief  financial  officer of Union Electric  Company,
hereby  certify that to the best of my  knowledge,  the  accompanying  Report of
Union  Electric  Company 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 Union Electric Company.




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

Date:  November 14, 2002