UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              WASHINGTON, DC 20549


                                    FORM 10-Q

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

         For Quarterly Period Ended March 31, 2003

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

         For The Transition Period From                      to

                          Commission file number 1-2967

                             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 ( ).

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

     Shares  outstanding  of the  registrant's  common stock as of May 14, 2003:
Common Stock, $5 par value,  held by Ameren  Corporation  (parent company of the
registrant) - 102,123,834.

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                             UNION ELECTRIC COMPANY

                                TABLE OF CONTENTS
                                                                                                                        Page
                                                                                                                        ----
<S>                                                                                                                    <C>
PART I       Financial Information

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

    ITEM 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations................       14

    ITEM 3.  Quantitative and Qualitative Disclosures About Market Risk...........................................       24

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

PART II      Other Information

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

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

SIGNATURE.........................................................................................................       30

CERTIFICATIONS....................................................................................................       30

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     This Form 10-Q contains "forward-looking  statements" within the meaning of
     Section  21E of  the  Securities  Exchange  Act  of  1934.  Forward-looking
     statements  should be read with the  cautionary  statements  and  important
     factors  included  in this  Form  10-Q at  Part  I,  Item 2.  "Management's
     Discussion and Analysis of Financial  Condition and Results of Operations,"
     under the heading "Forward-Looking  Statements." Forward-looking statements
     are all  statements  other than  statements of historical  fact,  including
     those statements that are identified by the use of the words "anticipates,"
     "estimates,"  "expects,"  "intends," "plans,"  "predicts,"  "projects," and
     similar expressions.

                                       1

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                          PART I. FINANCIAL INFORMATION

ITEM 1.  Financial Statements.

                             UNION ELECTRIC COMPANY
                           CONSOLIDATED BALANCE SHEET
               (Unaudited, in millions, except per share amounts)
<S>                                                                 <C>             <C>

                                                                      March 31,      December 31,
                                                                         2003            2002
                                                                     -----------     ------------
ASSETS:
Property and plant, net                                                $ 6,093          $ 5,991
Investments and other assets:
   Nuclear decommissioning trust fund                                      172              172
   Other assets                                                            238              235
                                                                     -----------     ------------
         Total investments and other assets                                410              407
                                                                     -----------     ------------
Current assets:
   Cash and cash equivalents                                               118                9
   Accounts receivable - trade (less allowance for doubtful
         accounts of $5 and $6, respectively)                              171              171
   Unbilled revenue                                                         89              101
   Miscellaneous accounts and notes receivable                              54               49
   Materials and supplies, at average cost                                 147              162
   Other current assets                                                     23               26
                                                                     -----------     ------------
         Total current assets                                              602              518
                                                                     -----------     ------------
Regulatory assets                                                          776              659
                                                                     -----------     ------------
Total Assets                                                           $ 7,881          $ 7,575
                                                                     ===========     ============

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                                                     1,462            1,477
   Accumulated other comprehensive income                                  (59)             (58)
                                                                     -----------     ------------
      Total common stockholder's equity                                  2,616            2,632
                                                                     -----------     ------------
   Preferred stock not subject to mandatory redemption                     113              113
   Long-term debt, net                                                   1,862            1,687
                                                                     -----------     ------------
         Total capitalization                                            4,591            4,432
                                                                     -----------     ------------
Current liabilities:
   Current maturities of long-term debt                                    135              130
   Short-term debt                                                           -              250
   Intercompany notes payable                                              332               15
   Accounts and wages payable                                              155              348
   Accumulated deferred income taxes                                         3                2
   Taxes accrued                                                           178              118
   Other current liabilities                                                96               94
                                                                     -----------     ------------
         Total current liabilities                                         899              957
                                                                     -----------     ------------
Accumulated deferred income taxes                                        1,320            1,344
Accumulated deferred investment tax credits                                120              121
Regulatory liabilities                                                     114              121
Asset retirement obligation                                                391              174
Accrued pension liabilities                                                261              252
Other deferred credits and liabilities                                     185              174
                                                                     -----------     ------------
Total Capital and Liabilities                                          $ 7,881          $ 7,575
                                                                     ===========     ============

See Notes to Consolidated Financial Statements.
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                                       2

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

                                                                        Three Months Ended
                                                                             March 31,
                                                                  -------------------------------
                                                                          2003              2002
                                                                  -------------     -------------
<S>                                                               <C>              <C>
OPERATING REVENUES:
   Electric                                                              $ 555             $ 534
   Gas                                                                      65                50
                                                                  -------------     -------------
      Total operating revenues                                             620               584
                                                                  -------------     -------------

OPERATING EXPENSES:
   Fuel and purchased power                                                141               144
   Gas                                                                      39                32
   Other operations and maintenance                                        186               184
   Depreciation and amortization                                            70                72
   Income taxes                                                             38                28
   Other taxes                                                              53                52
                                                                  -------------     -------------
      Total operating expenses                                             527               512
                                                                  -------------     -------------

OPERATING INCOME                                                            93                72

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

INTEREST CHARGES:
   Interest                                                                 26                27
   Allowance for borrowed funds used during construction                    (1)               (2)
                                                                  -------------     -------------
      Net interest charges                                                  25                25
                                                                  -------------     -------------

NET INCOME                                                                  68                51

PREFERRED STOCK DIVIDENDS                                                    1                 2
                                                                  -------------     -------------

NET INCOME AFTER PREFERRED STOCK DIVIDENDS                               $  67             $  49
                                                                  =============     =============

See Notes to Consolidated Financial Statements.
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                           UNION ELECTRIC COMPANY
                    CONSOLIDATED STATEMENT OF CASH FLOWS
                          (Unaudited, in millions)


                                                                                  Three Months Ended
                                                                                        March 31,
                                                                             ------------------------------
                                                                                  2003             2002
                                                                             ------------     -------------
<S>                                                                          <C>              <C>
Cash Flows From Operating:
   Net income                                                                    $  68            $  51
   Adjustments to reconcile net income to net cash
       provided by operating activities:
         Depreciation and amortization                                              70               72
         Amortization of nuclear fuel                                                7                7
         Amortization of debt issuance costs and premium/discounts                   1                1
         Allowance for funds used during construction                               (1)              (3)
         Deferred income taxes, net                                                 (5)              (4)
         Deferred investment tax credits, net                                       (1)              (2)
         Other                                                                      (1)              (2)
         Changes in assets and liabilities:
               Receivables, net                                                      7               55
               Materials and supplies                                               15               14
               Accounts and wages payable                                         (193)            (170)
               Taxes accrued                                                        60               54
               Assets, other                                                        (9)              (7)
               Liabilities, other                                                   26               19
                                                                             ------------     -------------
Net cash provided by operating activities                                           44               85
                                                                             ------------     -------------

Cash Flows From Investing:
   Construction expenditures                                                      (101)            (101)
   Allowance for funds used during construction                                      1                3
   Nuclear fuel expenditures                                                         -               (5)
   Intercompany notes receivable                                                     -               84
                                                                             ------------     -------------
Net cash used in investing activities                                             (100)             (19)
                                                                             ------------     -------------

Cash Flows From Financing:
   Dividends on common stock                                                       (82)             (76)
   Dividends on preferred stock                                                     (1)              (2)
   Capital issuance costs                                                           (1)               -
   Redemptions:
      Nuclear fuel lease                                                            (2)               -
      Short-term debt                                                             (250)            (186)
   Issuances:
      Nuclear fuel lease                                                             -                3
      Long-term debt                                                               184                -
      Intercompany notes payable                                                   317              192
                                                                             ------------     -------------
Net cash provided by (used in) financing activities                                165              (69)
                                                                             ------------     -------------

Net change in cash and cash equivalents                                            109               (3)
Cash and cash equivalents at beginning of year                                       9               15
                                                                             ------------     -------------
Cash and cash equivalents at end of period                                       $ 118            $  12
                                                                             ============     =============

Cash paid during the periods:
   Interest                                                                      $  23            $  19
   Income taxes, net                                                                 7                4

See Notes to Consolidated Financial Statements.

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                                       4

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


                                                                                  Three Months Ended
                                                                                       March 31,
                                                                           --------------------------------
                                                                                2003               2002
                                                                           -------------      -------------
<S>                                                                       <C>                 <C>

Common stock                                                                  $  511             $  511

Other paid-in capital                                                            702                702

Retained earnings
   Beginning balance                                                           1,477              1,440
   Net income                                                                     68                 51
   Common stock dividends                                                        (82)               (76)
   Preferred stock dividends                                                      (1)                (2)
                                                                           -------------      -------------
                                                                               1,462              1,413
                                                                           -------------      -------------

Accumulated other comprehensive income
   Beginning balance - derivative financial instruments                            4                  1
   Change in derivative financial instruments in current period                   (1)                (2)
                                                                           -------------      -------------
                                                                                   3                 (1)
                                                                           -------------      -------------
   Beginning balance - minimum pension liability                                 (62)                 -
   Change in minimum pension liability in current period                           -                  -
                                                                           -------------      -------------
                                                                                 (62)                 -
                                                                           -------------      -------------

                                                                                 (59)                (1)
                                                                           -------------      -------------


Total common stockholder's equity                                             $2,616             $2,625
                                                                           =============      =============


Comprehensive income, net of taxes
   Net income                                                                 $   68             $   51
   Unrealized net gain/(loss) on derivative hedging instruments,
        net of income taxes of $- and $-, respectively                             -                  1
   Reclassification adjustments for gains/(losses) included in net income,
        net of income taxes of $- and $(1), respectively                          (1)                (3)
                                                                           -------------      -------------
           Total comprehensive income, net of taxes                           $   67             $   49
                                                                           =============      =============

See Notes to Consolidated Financial Statements.

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                                       5

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UNION ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
March 31, 2003

NOTE 1 - Summary of Significant Accounting Policies

General

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

o    Central  Illinois Public Service  Company,  which operates a rate-regulated
     electric and natural gas transmission and distribution business in Illinois
     as AmerenCIPS.
o    Central  Illinois  Light Company,  a subsidiary of CILCORP Inc.  (CILCORP),
     which operates a  rate-regulated  electric  transmission  and  distribution
     business, an electric generation business, and a rate-regulated natural gas
     distribution  business in Illinois as  AmerenCILCO.  Ameren  completed  its
     acquisition of CILCORP on January 31, 2003.
o    AmerenEnergy  Resources Company (Resources Company),  which consists of non
     rate-regulated  operations.  Subsidiaries include  AmerenEnergy  Generating
     Company (Generating  Company),  which operates non rate-regulated  electric
     generation  in  Missouri  and  Illinois,   AmerenEnergy  Marketing  Company
     (Marketing  Company),  which  markets  power  for  periods  over one  year,
     AmerenEnergy  Fuels and Services  Company,  which procures fuel and manages
     the related risks for Ameren affiliated  companies and AmerenEnergy  Medina
     Valley Cogen (No. 4), LLC, which  indirectly owns a 40 megawatt,  gas-fired
     electric  generation  plant.  On February  4, 2003,  Ameren  completed  its
     acquisition  of AES Medina  Valley Cogen (No.  4), LLC (Medina  Valley) and
     renamed it AmerenEnergy Medina Valley Cogen (No. 4), LLC.
o    AmerenEnergy,  Inc.  (AmerenEnergy),  which serves as a power marketing and
     risk management agent for Ameren  affiliated  companies for transactions of
     primarily less than one year.
o    Electric  Energy,  Inc.  (EEI),  which  operates  electric  generation  and
     transmission  facilities in Illinois.  We have a 40% ownership  interest in
     EEI and have  accounted  for it under  the  equity  method  of  accounting.
     Resources Company also owns a 20% interest in EEI.
o    Ameren Services  Company (Ameren  Services),  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 the
     PUHCA.

     When we  refer  to  AmerenUE,  our,  we or us,  we are  referring  to Union
Electric Company and its subsidiary,  Union Electric Development Corporation, on
a consolidated basis. Union Electric Development Corporation owns and invests in
civic and community development enterprises.  In some cases, we are referring to
our agents,  Ameren  Energy and Ameren  Energy Fuels and Services  Company.  All
significant intercompany  transactions have been eliminated.  All tabular dollar
amounts are in millions, unless otherwise indicated.

     The  accounting   policies  of  AmerenUE  conform  to  generally   accepted
accounting  principles in the United  States  (GAAP).  Our financial  statements
reflect all adjustments (which include normal, recurring adjustments) necessary,
in our opinion, for a fair presentation of our interim results. These statements
should  be read in  conjunction  with the  financial  statements  and the  notes
thereto included in our 2002 Annual Report on Form 10-K.

     The  preparation of financial  statements in conformity  with GAAP requires
management  to make  certain  estimates  and  assumptions.  Such  estimates  and
assumptions  affect reported amounts of assets and liabilities and disclosure of
contingent  assets and  liabilities at the date of the financial  statements and
the reported amounts of revenues and expenses during the reported period. Actual
results could differ from those estimates.  Certain  reclassifications have been
made to prior years' financial statements to conform to 2003 reporting.

                                       6

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Accounting Changes and Other Matters

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

     We adopted the provisions of SFAS 143 on January 1, 2003. SFAS 143 requires
us to record the estimated fair value of legal  obligations  associated with the
retirement of tangible  long-lived assets in the period in which the liabilities
are incurred and to capitalize a corresponding  amount as part of the book value
of the related  long-lived  asset.  In  subsequent  periods,  we are required to
adjust asset  retirement  obligations  based on changes in estimated fair value,
and the  corresponding  increases in asset book values are depreciated  over the
useful life of the related asset. Uncertainties as to the probability, timing or
cash flows associated with an asset retirement obligation affect our estimate of
fair value.

     Upon adoption of this standard on January 1, 2003, we recognized additional
asset retirement obligations of approximately $213 million and a net increase in
net property and plant of  approximately  $76 million  related  primarily to the
Callaway  nuclear  decommissioning  costs  and  retirement  costs  for  a  river
structure.  The difference between the net asset and the liability recorded upon
adoption  of SFAS 143  related  to  rate-regulated  assets  was  recorded  as an
additional  regulatory asset of approximately  $136 million because we expect to
continue   to  recover  in  electric   rates  the  cost  of   Callaway   nuclear
decommissioning and other costs of removal.  These asset retirement  obligations
and associated  assets are in addition to assets and liabilities of $174 million
we previously  recorded related to our future  obligations and funds accumulated
to decommission  the Callaway nuclear plant.  Asset retirement  obligations also
increased during the quarter due to accretion of $4 million.

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

     Historically,  we  have  included  an  estimated  cost of  dismantling  and
removing plant from service upon  retirement.  Because these  estimated costs of
removal have been included in the cost of service upon which our present utility
rates are based,  and with the  expectation  that this practice will continue in
the  jurisdictions  in which we operate,  adoption of SFAS 143 did not result in
any  change  in the  deprecation  accounting  practices  of  our  rate-regulated
operations.  We have  estimated  future  removal costs  embedded in  accumulated
depreciation  related to  rate-regulated  plant assets were  approximately  $534
million at March 31, 2003.

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

     In the quarters ended  September 30, 2002 and December 31, 2002, we adopted
the  provisions  of EITF 02-3,  "Issues  Involved in Accounting  for  Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management  Activities,"  that require  revenues and costs  associated with
certain  energy  contracts  to be shown on a net basis in the income  statement.
Prior to adopting EITF 02-3 and the  rescission of EITF 98-10,  "Accounting  for
Contracts  Involved  in Energy  Trading  and Risk  Management  Activities,"  our
accounting practice was to present all settled energy purchase or sale contracts
within our power risk management  program on a gross basis in Operating Revenues
- Electric and in Operating Expenses - Fuel and Purchased Power. This meant that
revenues were recorded for the notional amount of the power sales contracts with
a corresponding charge to income for the costs of the energy that was generated,
or for the notional amount of a purchased power contract.

     In October  2002,  the EITF reached a consensus to rescind EITF 98-10.  The
effective  date for the full  rescission  of EITF 98-10 was for  fiscal  periods
beginning after December 15, 2002, with early adoption  permitted.  In addition,
the EITF reached a consensus in October 2002 that all SFAS No. 133  ("Accounting
for  Derivative   Instruments  and  Hedging   Activities")  trading  derivatives
(subsequent  to the  rescission of EITF 98-10) should be shown net in the income
statement,  whether or not physically  settled.  This  consensus  applies to all
energy and non-energy related trading  derivatives that meet the definition of a
derivative  pursuant to SFAS 133. We have adopted and applied  this  guidance to
2002  and  2001,  which  had  no  impact  on  previously  reported  earnings  or
stockholder's  equity.  The  operating  revenues  and costs netted for the three
months  ended  March 31,  2002  were $150  million,  which  reduced  interchange
revenues and

                                       7

<PAGE>

purchased  power  costs  by  equal  amounts.  The  adoption  of EITF  02-3,  the
rescission of EITF 98-10 and the related transition guidance resulted in netting
of energy  contracts and lowered our reported  revenues and costs with no impact
on earnings.

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

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

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

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

Revenue

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

     Interchange  revenues  included in Operating  Revenues - Electric were $102
million for the three months ended March 31, 2003 (2002 - $78 million).

Purchased Power

     Purchased  power included in Operating  Expenses - Fuel and Purchased Power
was $45 million for the three months ended March 31, 2003 (2002 - $65 million).

Excise Taxes

     Excise taxes on Missouri  electric and gas, and Illinois gas customer bills
are imposed on us and are recorded gross in Operating  Revenues and Other Taxes.
Excise taxes recorded in Operating Revenues and Other Taxes for the three months
ended  March 31,  2003  were $23  million  (2002 - $22  million).  Excise  taxes
applicable to Illinois  electric  customer bills are imposed on the consumer and
are recorded as tax  collections  payable and  included in Taxes  Accrued on the
Consolidated Balance Sheet.


NOTE 2 - Rate and Regulatory Matters

Intercompany Purchase of Electric Generating Facilities

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

                                       8

<PAGE>

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

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

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

Affiliate Rules

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

Regional Transmission Organization

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

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

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

     Until  the  tariffs  and  other  material  terms  of ours  and  AmerenCIPS'
participation  in GridAmerica,  and  GridAmerica's  participation in the Midwest
ISO, are finalized and approved by the FERC, we are unable to

                                       9

<PAGE>

predict the impact that on-going regional transmission organization developments
will have on our financial  position,  results of  operations or liquidity.  Our
participation  in  GridAmerica is subject to MoPSC  approval.  An order from the
MoPSC is expected during 2003.

Standard Market Design Notice of Proposed Rulemaking (NOPR)

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

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

     Even though issuance of the final rule and its implementation  schedule are
still  unknown,  the  Midwest ISO is already in the  process of  implementing  a
market design similar to the proposed market design in the NOPR. The Midwest ISO
has  targeted  March  2004 as the start date for  implementation.  We are in the
process of reviewing the FERC's white paper. Until the FERC issues a final rule,
we are unable to predict the ultimate impact on our future  financial  position,
results of operations or liquidity.

Illinois Gas

     In November 2002, we filed a request with the ICC to increase  annual rates
for natural gas service by  approximately $4 million.  The ICC has until October
2003 to  render  a  decision  on this  gas  case;  however,  the ICC  Staff  has
recommended an annual increase of approximately $2 million.

Missouri Gas

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


NOTE 3 - Related Party Transactions

     We have  transactions  in the normal  course of  business  with our parent,
Ameren, and its 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  $27 million for the three months ended March 31, 2003 (2002 - $27
million).  Intercompany  power sales  totaled  $32 million for the three  months
ended March 31, 2003 (2002 - $20 million).

     Interchange  revenues  from outside sales of available  generation  through
AmerenEnergy  were $70 million for the three months ended March 31, 2003 (2002 -
$54 million).  Purchased power derived from AmerenEnergy was $17 million for the
three months ended March 31, 2003 (2002 - $37 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

                                       10

<PAGE>

March 31, 2003,  support  services  provided by Ameren Services and AmerenEnergy
included in Operating  Expenses - Other  Operations and Maintenance  totaled $50
million (2002 - $48 million).

     As of March 31, 2003,  intercompany  receivables  included in Miscellaneous
Accounts and Notes Receivable were  approximately $37 million (December 31, 2002
- $25 million). As of March 31, 2003, intercompany payables included in Accounts
and Wages Payable totaled  approximately  $45 million  (December 31, 2002 - $103
million).

     We have the ability to borrow from Ameren and AmerenCIPS  through a utility
money pool  agreement.  Ameren  Services  administers the utility money pool and
tracks internal and external funds separately.  Internal funds are surplus funds
contributed to the utility money pool from  participants.  The primary source of
external  funds for the utility money pool at March 31, 2003 was our  commercial
paper  program.  Through the utility money pool we can access  committed  credit
facilities  at Ameren and  AmerenCIPS,  which  totaled $615 million at March 31,
2003.  These  facilities  are in addition  to our own $79  million in  committed
credit  facilities.  The total amount available to us at any given time from the
utility 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.  Surplus  funds
providing  additional  liquidity  available to us through the utility money pool
totaled  $260  million  at March 31,  2003.  The  availability  of funds is also
determined by funding  requirement  limits  established by the PUHCA.  We, along
with  AmerenCIPS  and  Ameren  Services,  rely  on the  utility  money  pool  to
coordinate  and  provide  for  certain   short-term  cash  and  working  capital
requirements.  Borrowers receiving a loan under the utility 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 utility money pool.  For the three months
ended March 31, 2003,  the average  interest rate for the utility money pool was
1.32%  (2002 -  1.79%).  At March  31,  2003,  we had  outstanding  intercompany
payables of $332  million,  sourced by internal  funds through the utility money
pool (December 31, 2002 - $15 million).

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


NOTE 4 - Derivative Financial Instruments

     As of March 31, 2003,  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 $3 million in Other  Deferred  Credits and
Liabilities.

Cash Flow Hedges

     The pretax net gain or loss on power forward derivative instruments,  which
represented the impact of discontinued cash flow hedges, the ineffective portion
of cash flow hedges, as well as the reversal of amounts  previously  recorded in
Accumulated  Other  Comprehensive  Income  (OCI)  due to  transactions  going to
delivery or settlement, was approximately a $1 million loss for the three months
ended March 31, 2003 (2002 - $1 million gain).

     As of March 31,  2003,  we had  hedged a portion of the  electricity  price
exposure  for  the  upcoming   twelve-month  period.  The  mark-to-market  value
accumulated  in OCI for the  effective  portion of hedges of  electricity  price
exposure was a net gain of approximately  $1 million (less than $1 million,  net
of taxes).

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

Other Derivatives

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

                                       11

<PAGE>

change in the market value of these options is recorded as Miscellaneous, Net in
the income  statement.  The net change in the market  values of sulfur  dioxide,
coal and  electricity  options was a gain of $0.1  million for the three  months
ended March 31, 2003 (2002 - gain of $1 million).


NOTE 5 - Property and Plant, Net

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

================================================================================
                                                      March 31,     December 31,
                                                        2003            2002
--------------------------------------------------------------------------------
Property and plant, at original cost:
  Electric                                            $10,494           $10,294
  Gas                                                     271               268
  Other                                                    37                36
--------------------------------------------------------------------------------
                                                       10,802            10,598
     Less accumulated depreciation and amortization     5,088             4,968
--------------------------------------------------------------------------------
                                                        5,714             5,630
Construction work in progress:
  Nuclear fuel in process                                  82                81
  Other                                                   297               280
--------------------------------------------------------------------------------
Property and plant, net                               $ 6,093            $5,991
--------------------------------------------------------------------------------

NOTE 6 - Debt Financings

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

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

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

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

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

     Amortization  of debt  issuance  costs and any premium or discounts for the
three months  ended March 31, 2003 were $1 million  (2002 - $1 million) and were
included in interest expense in the income statement.

     At March 31,  2003,  Ameren and its  subsidiaries,  including  us,  were in
compliance with their financial agreement provisions and covenants.

                                       12

<PAGE>

NOTE 7 - Miscellaneous, Net

     Miscellaneous,  net for the three  months  ended  March  31,  2003 and 2002
consisted of the following:

================================================================================
                                                           Three Months
--------------------------------------------------------------------------------
                                                      2003             2002
Miscellaneous income:
   Equity in earnings of subsidiaries               $    1            $   1
   Other                                                 -                5
--------------------------------------------------------------------------------
Total miscellaneous income                          $    1            $   6
================================================================================

Miscellaneous expense:
   Other                                            $   (1)           $  (2)
--------------------------------------------------------------------------------
Total miscellaneous expense                         $   (1)           $  (2)
================================================================================



                                       13

<PAGE>

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

OVERVIEW

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

o    Central  Illinois Public Service  Company,  which operates a rate-regulated
     electric and natural gas transmission and distribution business in Illinois
     as AmerenCIPS.
o    Central  Illinois  Light Company,  a subsidiary of CILCORP Inc.  (CILCORP),
     which operates a  rate-regulated  electric  transmission  and  distribution
     business, an electric generation business, and a rate-regulated natural gas
     distribution  business in Illinois as  AmerenCILCO.  Ameren  completed  its
     acquisition  of CILCORP on January 31, 2003.  See Recent  Developments  for
     further information.
o    AmerenEnergy  Resources Company (Resources Company),  which consists of non
     rate-regulated  operations.  Subsidiaries include  AmerenEnergy  Generating
     Company (Generating  Company),  which operates non rate-regulated  electric
     generation  in  Missouri  and  Illinois,   AmerenEnergy  Marketing  Company
     (Marketing  Company),  which  markets  power  for  periods  over one  year,
     AmerenEnergy  Fuels and Services  Company,  which procures fuel and manages
     the related risks for Ameren affiliated  companies and AmerenEnergy  Medina
     Valley Cogen (No. 4), LLC, which  indirectly owns a 40 megawatt,  gas-fired
     electric  generation  plant.  On February  4, 2003,  Ameren  completed  its
     acquisition  of AES Medina  Valley Cogen (No.  4), LLC (Medina  Valley) and
     renamed it  AmerenEnergy  Medina  Valley  Cogen (No.  4),  LLC.  See Recent
     Developments for further information.
o    AmerenEnergy,  Inc.  (AmerenEnergy),  which serves as a power marketing and
     risk management agent for Ameren  affiliated  companies for transactions of
     primarily less than one year.
o    Electric  Energy,  Inc.  (EEI),  which  operates  electric  generation  and
     transmission  facilities in Illinois.  We have a 40% ownership  interest in
     EEI and have  accounted  for it under  the  equity  method  of  accounting.
     Resources Company also owns a 20% interest in EEI.
o    Ameren Services  Company (Ameren  Services),  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 the
     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    Management's  Discussion and Analysis of Financial Condition and Results of
     Operations  that  appears in our Annual  Report on Form 10-K for the period
     ended December 31, 2002.
o    The  audited  financial  statements  and  related  notes that appear in our
     Annual Report on Form 10-K for the period ended December 31, 2002.

     When we  refer  to  AmerenUE,  our,  we or us,  we are  referring  to Union
Electric Company and its subsidiary, Union Electric Development Corporation on a
consolidated basis. Union Electric  Development  Corporation owns and invests in
civic and community development enterprises.  In some cases, we are referring to
our agents,  Ameren  Energy and Ameren  Energy 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,
natural  gas and oil in our  operations.  The prices for these  commodities  can
fluctuate  significantly  due to the world  economic and political  environment,
weather,  production levels and many other factors. We do not have fuel recovery
mechanisms in Missouri or Illinois for our electric utility  businesses,  but we
do have  gas  cost  recovery  mechanisms  in  each  state  for  our gas  utility
businesses. In addition, our electric rates in

                                       14

<PAGE>

Missouri  and  Illinois  are largely set through  2006.  We employ  various risk
management  strategies in order to try to reduce our exposure to commodity risks
and other risks inherent in our business.  The  reliability of our power plants,
and  transmission  and  distribution  systems,  and the level of  operating  and
administrative  costs,  and capital  investment  are key factors that we seek to
control in order to optimize our results of operations, cash flows and financial
position.


RESULTS OF OPERATIONS

Earnings Summary

     Our net income  increased to $68 million in the first  quarter of 2003 from
$51 million in the first  quarter of 2002.  The  increase was  primarily  due to
favorable  weather  conditions in our service  territory  ($15  million,  net of
taxes),  increased  electric  margin due to greater use of  low-cost  generating
units to serve  native  customers  ($2  million,  net of  taxes)  and  increased
earnings from interchange sales ($17 million, net of taxes) due to approximately
90%  higher  power  prices  in  the  energy   markets  than  the  prior  period.
Weather-sensitive  residential  electric  kilowatthour  sales  increased by 14%,
commercial  electric  kilowatthour sales increased by 8% and gas sales increased
by 7% in the  first  quarter  of 2003  compared  to the first  quarter  of 2002.
Partially  offsetting the benefit on net income of weather,  interchange  margin
and generation  availability  in the first quarter of 2003 were higher  employee
benefit costs ($4 million, net of taxes) related to benefit plan performance and
increasing  healthcare  costs, no sales of emission credits in the first quarter
of 2003 ($8 million,  net of taxes) and the impact of the 2002 settlement of the
Missouri electric rate case ($4 million, net of taxes).

Recent Developments

Acquisitions

     On  January  31,  2003,  Ameren  completed  its  acquisition  of all of the
outstanding  common  stock of CILCORP from The AES  Corporation.  CILCORP is the
parent company of Peoria,  Illinois-based  Central Illinois Light Company, which
operated as CILCO. With the acquisition,  CILCO became an Ameren subsidiary, but
remains a separate  utility  company,  operating as AmerenCILCO.  On February 4,
2003,  Ameren also completed its acquisition of AES Medina Valley Cogen (No. 4),
LLC (Medina  Valley),  which indirectly owns a 40 megawatt,  gas-fired  electric
generation  plant.  With the  acquisition,  Medina Valley,  which was renamed as
AmerenEnergy Medina Valley Cogen (No. 4), LLC, became a wholly-owned  subsidiary
of Resources  Company.  The results of operations  for CILCORP and  AmerenEnergy
Medina  Valley  Cogen  (No.  4),  LLC were  included  in  Ameren's  consolidated
financial  statements  effective with the January and February 2003  acquisition
dates.  Our results of operations  for the quarter ended March 31, 2003 were not
impacted by these acquisitions.

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

     The total  purchase price was  approximately  $1.4 billion and included the
assumption of CILCORP and Medina  Valley debt and preferred  stock at closing of
$895  million  and  consideration  of $488  million in cash,  including  related
acquisition  costs,  net of cash  acquired.  The  purchase  price is  subject to
certain   adjustments   for  working  capital  and  other  changes  pending  the
finalization  of CILCORP's  closing  balance  sheet.  The cash  component of the
purchase  price came from Ameren's  issuances in September  2002 of 8.05 million
common  shares and its  issuance in early 2003 of an  additional  6.325  million
common shares which together generated aggregate net proceeds of $575 million.

Debt Issuances

     In March 2003,  we issued $184  million of 5.50% Senior  Secured  Notes due
March 15,  2034.  We received net proceeds  after fees of $180  million,  which,
along with other  funds,  were used to redeem $104 million  principal  amount of
outstanding 8.25% first mortgage bonds due October 15, 2022, at a redemption

                                       15

<PAGE>

price  of  103.61%  of par,  plus  accrued  interest,  in April  2003,  prior to
maturity,  and to repay  short-term debt incurred to pay at maturity $75 million
principal amount of 8.33% first mortgage bonds due in December 2002.

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

Credit Ratings

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

     As of April 30,  2003,  selected  ratings by Moody's and  Standard & Poor's
were as follows:
================================================================================
                                               Moody's         Standard & Poor's
--------------------------------------------------------------------------------
Ameren Corporation:
     Issuer/Corporate credit rating                A3                  A-
     Unsecured debt                                A3                BBB+
     Commercial paper                             P-2                 A-2

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

CILCORP:
     Unsecured debt                              Baa2                BBB+

AmerenCILCO:
     Secured debt                                  A2                  A-

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

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

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



                                       16

<PAGE>

Electric Operations

     The following  table  represents the favorable  (unfavorable)  variation on
electric  margins for the three months ended March 31, 2003 from the  comparable
period in 2002:

================================================================================
                                                              Three Months
--------------------------------------------------------------------------------
Electric Revenues:
   Interchange revenues                                          $  24
   Effect of weather (estimate)                                     21
   Rate reductions                                                 (11)
   Growth and other (estimate)                                     (13)
--------------------------------------------------------------------------------
   Total variation in electric operating revenues                   21
Fuel and Purchased Power:
   Fuel:
     Generation                                                  $ (16)
     Price                                                           -
       Generation efficiencies and other                            (1)
   Purchased power                                                  20
--------------------------------------------------------------------------------
   Total variation in fuel and purchased power                       3
================================================================================
Change in electric margin                                        $  24
================================================================================

     Electric margin  increased $24 million for the three months ended March 31,
2003  compared to the same period in 2002.  Increases in electric  margin in the
first  quarter of 2003 were  primarily  attributable  to  increased  interchange
margins and higher  native load  customer  demand  resulting  from colder winter
weather.   Residential   kilowatthour   sales   increased  14%  and   commercial
kilowatthour  sales  increased  8% in the  first  quarter  of 2003.  Interchange
margins  increased due to improved  power prices in the energy markets and solid
low-cost   generation   availability.   Average  power  prices   increased  from
approximately $22 per megawatthour in the first quarter of 2002 to approximately
$42 per  megawatthour  in the first quarter of 2003.  Partially  offsetting  the
benefit of these  increases in electric  margin were an 8% decline in industrial
sales in the first quarter of 2003 due to the continued  soft economy,  no sales
of emission  credits in the first  quarter of 2003 (2002 - $13 million) and rate
reductions  in  Missouri  relating  to a 2002  rate  settlement  ($11  million).
Revenues  will  continue  to be  negatively  affected by the  settlement  of the
Missouri  electric  rate case,  which  requires  the  phase-in of $30 million of
electric rate reductions effective April 1, 2003 and $30 million effective April
1, 2004.

     During 2002, we adopted the provisions of Emerging Issues Task Force (EITF)
Issue 02-3,  "Issues  Involved in Accounting for  Derivative  Contracts Held for
Trading  Purposes and Contracts  Involved in Energy Trading and Risk  Management
Activities,"  that required  revenues and costs  associated  with certain energy
contracts  to be shown on a net basis in the  income  statement.  The  operating
revenues  and costs  netted for the three  months ended March 31, 2002 were $150
million,  which reduced interchange  revenues and purchased power costs by equal
amounts.  See  Note  1 -  Summary  of  Significant  Accounting  Policies  to our
Consolidated  Financial  Statements  under  Item 1 of Part I of this  report for
further information.

Gas Operations

     Our gas margin increased $8 million in the first quarter of 2003,  compared
to the first quarter of 2002, with revenues  increasing by $15 million and costs
increasing by $7 million.  The increase in margin was primarily due to increased
customer demand resulting from colder winter weather and the prior year's warmer
than normal conditions.

Other Operating Expenses

Other Operations and Maintenance

     Other operations and maintenance expenses increased $2 million in the first
quarter of 2003, compared to the first quarter of 2002,  primarily due to higher
employee benefit costs related to increasing healthcare costs and the investment
performance of employee benefit plans' assets ($7 million),  partially offset by
higher  tree-trimming  expenses  in  the  first  quarter  of  2002,  which  were
accelerated, in part, to take advantage of mild weather.

                                       17

<PAGE>

     Ameren Services and AmerenEnergy  provided services to us, including wages,
employee  benefits  and  professional  services  that  were  included  in  other
operations and maintenance expenses.  See Note 3 - Related Party Transactions to
our Consolidated  Financial Statements under Item 1 of Part I of this report for
further information.

Depreciation and Amortization

     Depreciation  and amortization  expenses  decreased $2 million in the first
quarter of 2003 compared to the prior period.  The decrease was primarily due to
a reduction of depreciation  rates based on an updated analysis of asset values,
service lives and accumulated  depreciation levels that was included in our 2002
Missouri electric rate case settlement ($5 million), partially offset by capital
additions in 2002.

Income Taxes

     Income tax  expense  increased  $9  million  in the first  quarter of 2003,
compared to the 2002 period, primarily due to higher pretax income.

Other Taxes

     Other  taxes  expense  increased  $1 million in the first  quarter of 2003,
compared to the 2002  period,  primarily  due to an  increase in gross  receipts
taxes related to increased native sales.

Other Income and Deductions

     Other income and deductions  (excluding  income taxes) for the three months
ended March 31, 2003 decreased $4 million, compared to the first quarter of 2002
primarily  due  to  decreased  gains  on  derivative  contracts.  See  Note  7 -
Miscellaneous, Net to our Consolidated Financial Statements under Item 1 of Part
I of this report for further information.

Interest

     Interest expense decreased $1 million in the first quarter of 2003 compared
to the 2002 period,  primarily due to lower  interest  rates on new issuances of
first mortgage bonds as compared to the issues redeemed.


LIQUIDITY AND CAPITAL RESOURCES

Operating

     Our cash flows  provided by operating  activities  were $44 million for the
first quarter of 2003, compared to $85 million for the same period in 2002. Cash
provided by operations  decreased in the first  quarter of 2003,  primarily as a
result of the timing of receipts on  receivables,  net and  payments on accounts
and wages payable, partially offset by higher cash earnings from higher electric
and gas margins.

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

Investing

     Our net cash used in  investing  activities  was $100  million in the first
quarter  of 2003  compared  to $19  million  for the same  period  in 2002.  The
increase  over the prior year period was due to first quarter of 2002 receipt of
$84 million previously  invested in the utility money pool. In the first quarter
of 2003,  construction  expenditures  were $101 million  (2002 - $101  million),
primarily  related  to  various  upgrades  at  our  power  plants.  Our  capital
expenditures are expected to approximate $485 million in 2003.

     We  continually  review our  generation  portfolio and expected  electrical
needs and, as a result, we could modify our plan for generation asset purchases,
which  could  include  the timing of when  certain  assets  will

                                       18

<PAGE>

be added  to,  or  removed  from our  portfolio,  the type of  generation  asset
technology that will be employed,  or whether  capacity may be purchased,  among
other things.  Any changes that we may plan to make for future  generating needs
could result in significant capital expenditures or losses being incurred, which
could be material.

Financing

     Our cash flows provided by financing activities totaled $165 million in the
first quarter of 2003 compared to cash flows used in financing activities of $69
million in the first quarter of 2002. Our principal financing activities for the
first quarter of 2003 included the issuances of  intercompany  notes payable and
long-term  debt,  partially  offset by the redemption of short-term debt and the
payment of dividends.

     We are  authorized  by the SEC under the PUHCA to have up to $1  billion of
short-term unsecured debt instruments outstanding at any time.

Short-Term Debt and Liquidity

     Short-term  debt  consists of  commercial  paper,  intercompany  borrowings
through Ameren's utility money pool and bank loans (maturities  generally within
1 to 45 days).  At March 31, 2003,  Ameren and its  subsidiaries  had  committed
credit  facilities,  expiring at various dates  between 2003 and 2005,  totaling
$694 million, excluding AmerenCILCO facilities of $60 million, EEI facilities of
$45 million and our nuclear fuel lease  facilities of $120 million.  This amount
includes  $79 million of our  committed  credit  facilities  and $615 million of
committed credit  facilities at Ameren and AmerenCIPS.  We access these combined
facilities  through  Ameren's  utility money pool  arrangement.  AmerenCIPS  and
Ameren Services may also borrow under this  arrangement.  These committed credit
facilities  are used to support our  commercial  paper  program,  under which no
amounts were  outstanding at March 31, 2003. At March 31, 2003, $694 million was
unused and available under these committed credit facilities.

     Subject to the  receipt of  regulatory  approval,  which is being  pursued,
AmerenCILCO will participate in Ameren's utility money pool  arrangement.  Under
this  arrangement,  AmerenCILCO  will  have  access  to up to  $694  million  of
additional committed  liquidity,  subject to reduction based on the use by other
utility  money  pool  participants,  but  increased  to the  extent  other  pool
participants  have surplus cash balances,  which may be used to fund pool needs.
At March 31, 2003,  AmerenCILCO  had committed  credit  facilities,  expiring at
various  dates during 2003,  totaling  $60  million,  one of which  totaling $25
million was subsequently renewed to 2004.

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

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

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

     In addition to committed credit  facilities,  a further source of liquidity
for Ameren is available cash and cash equivalents. At March 31, 2003, Ameren had
$260 million of cash,  all of which was available for borrowings by us under the
utility money pool.  In the first  quarter of 2003,  Ameren paid a total of $488
million  of cash on  hand,  including  related  acquisition  costs,  net of cash
acquired, to acquire CILCORP and Medina Valley.

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

                                       19

<PAGE>

in the  capital  markets  such that our cost of capital  would  increase  or our
ability to access the capital markets would be adversely affected.

Financial Agreement Provisions and Covenants

     Ameren's and our financial  agreements  include  customary default or cross
default  provisions  that could impact the continued  availability  of credit or
result  in  the  acceleration  of  repayment.  Ameren's  and  its  subsidiaries'
committed  credit  facilities  require the borrower to represent,  in connection
with any  borrowing  under the  facility  that no  material  adverse  change has
occurred since certain dates. None of our, Ameren's nor its other  subsidiaries'
financing  arrangements contain credit rating triggers,  except for three funded
bank term loans at AmerenCILCO totaling $105 million at March 31, 2003.

     Ameren's  and  its  subsidiaries'   committed  credit  facilities   include
provisions  related  to the  funded  status  of  Ameren's  pension  plan.  These
provisions  either require  Ameren to meet minimum  Employee  Retirement  Income
Security Act of 1974 funding requirements or limit the unfunded liability status
of the plan.  Under the most  restrictive of these  provisions  impacting Ameren
facilities  totaling  $400  million,  an event of  default  will  result  if the
unfunded  liability status (as defined in the underlying  credit  agreements) of
Ameren's  pension plan exceeds $300 million in the aggregate.  Based on the most
recent  valuation  report  available to Ameren at December  31, 2002,  which was
based on January 2002 asset and  liability  valuations,  the unfunded  liability
status (as defined) was $31 million.  While an updated valuation report will not
be available  until the second half of 2003,  Ameren  believes that the unfunded
liability  status of its pension  plans (as  defined)  could exceed $300 million
based on the investment performance of the pension plan assets and interest rate
changes since January 1, 2002. As a result,  Ameren may need to renegotiate  the
facility provisions,  terminate or replace the affected facilities,  or fund any
unfunded liability shortfall. Should Ameren elect to terminate these facilities,
Ameren  believes it would  otherwise  have  sufficient  liquidity  to manage its
short-term funding requirements.

     At March 31,  2003,  Ameren and its  subsidiaries,  including  us,  were in
compliance with their financial agreement provisions and covenants.

Debt Financings

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

Off-Balance Sheet Arrangements

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


OUTLOOK

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

o    Weak economic conditions, which impacts native load demand;

o    Power  prices in the  Midwest  will  impact the amount of  revenues  we can
     generate  by  marketing  any  excess  power into the  interchange  markets.
     Long-term  power  prices  continue  to be  generally  soft in the  Midwest,
     despite  the  fact  that   short-term   power   prices  have   strengthened
     significantly  from  the  prior  year in the  first  quarter  of  2003  due
     primarily to higher prices for natural gas;

o    A  rate  settlement  approved  in  2002  by  the  Missouri  Public  Service
     Commission  that required  electric rate reductions of $50 million on April
     1, 2002 and $30  million on April 1, 2003 with an  additional  $30  million
     reduction required for April 1, 2004;

o    The adverse  effects of rising  employee  benefit costs,  higher  insurance
     costs and increased  security costs associated with additional  measures we
     have taken,  or may have to take, at our Callaway  nuclear plant related to
     world events; and

o    An assumed return to more normal weather patterns relative to 2002.


                                       20

<PAGE>

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

o    A voluntary  retirement  program  that was  accepted by  approximately  550
     Ameren  employees,   including  approximately  230  of  our  employees  and
     additional  employees  providing  support  functions  to us through  Ameren
     Services;
o    Modifications to retiree employee benefit plans to increase co-payments and
     limit our overall cost;
o    A wage freeze in 2003 for all management employees;
o    Suspension  of  operations  at two  1940's-era  Ameren  generating  plants,
     including our Venice, Illinois plant, to reduce operating costs; and
o    Reductions of 2003 expected capital expenditures.

     We are pursuing an annual gas rate increase of  approximately $4 million in
Illinois and we expect to file an annual gas rate  increase in Missouri.  Ameren
is also  considering  additional  actions,  including  modifications  to  active
employee benefits, further staffing reductions and other initiatives.

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

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


REGULATORY MATTERS

     See Note 2 - Rate and  Regulatory  Matters  to our  Consolidated  Financial
Statements under Item 1 of Part I of this report for information.


ACCOUNTING MATTERS

Critical Accounting Policies

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

<TABLE>
<S>                                              <C>

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

Regulatory Mechanisms and Cost Recovery

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

</TABLE>

   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.

                                       21

<PAGE>
<TABLE>
<S>                                              <C>

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

Nuclear Plant Decommissioning Costs

   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 nuclear plant will have a useful           decommissioning
   life of 40 years and estimated costs of         o   Useful lives of nuclear power plants
   approximately $515 million to dismantle the
   plant are accurate.  See Note 15 - Callaway
   Nuclear Plant to our Financial Statements in
   our 2002 Annual Report on Form 10-K.

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


Environmental Costs

   We accrue for all known environmental           o   Extent of contamination
   contamination where remediation can be          o   Responsible party determination
   reasonably estimated, but some of our           o   Approved methods for cleanup
   operations have existed for over 100 years      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
   Basis for Judgment
   We determine the proper amounts to accrue for environmental contamination
   based on  internal  and  third  party  estimates  of  clean-up  costs in the
   context of current remediation standards and available technology.


Unbilled Revenue

   At the end of each period, we estimate, based   o   Projecting customer energy usage
   on expected usage, the amount of revenue to     o   Estimating impacts of weather and other
   record for services that have been provided         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>


                                       22

<PAGE>
<TABLE>
<S>                                              <C>
Accounting Policy (Continued)                      Uncertainties Affecting Application (Continued)
-----------------------------                      -----------------------------------------------

Benefit Plan Accounting

   Based on actuarial calculations, we accrue      o   Future rate of return on pension and other plan
   costs of providing future employee benefits         assets
   in accordance with SFAS 87, 106 and 112.  See   o   Interest rates used in valuing benefit
   Note 13 - Retirement Benefits to our                obligations
   Financial Statements in our 2002 Annual         o   Healthcare cost trend rates
   Report on Form 10-K.                            o   Timing of employee retirements


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


Derivative Financial Instruments

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

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

</TABLE>

Impact of Future Accounting Pronouncements

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




                                       23

<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 handles market risks in accordance with established policies,
which may include entering into various derivative  transactions.  In the normal
course of  business,  Ameren  and  AmerenUE  also  face  risks  that are  either
non-financial or  non-quantifiable.  Such risks  principally  include  business,
legal and operational risks and are not represented in the following discussion.

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

Interest Rate Risk

     We are exposed to market risk through changes in interest rates  associated
with both  long-term and  short-term  variable-rate  debt,  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 March  31,  2003,  if  interest  rates
increase by 1%, our annual interest  expense would increase by  approximately $9
million and net income would  decrease by  approximately  $6 million.  The model
does not consider the effects of the reduced level of potential overall economic
activity that would exist in such an environment.  In the event of a significant
change in  interest  rates,  management  would  likely  take  actions to further
mitigate our exposure to this market risk.  However,  due to the  uncertainty of
the  specific  actions  that  would be taken and  their  possible  effects,  the
sensitivity analysis assumes no change in our financial structure.

Credit Risk

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

     Our  physical  and  financial   instruments  are  subject  to  credit  risk
consisting of trade  accounts  receivables  and executory  contracts with market
risk exposures.  The risk associated with trade  receivables is mitigated by the
large  number of customers in a broad range of industry  groups  comprising  our
customer  base.  No  customer  represents  greater  than  10%  of  our  accounts
receivable.  Our revenues are primarily  derived from sales of  electricity  and
natural  gas  to   customers  in  Missouri   and   Illinois.   We  analyze  each
counterparty's  financial  condition  prior to entering  into  sales,  forwards,
swaps,  futures or option  contracts.  We also establish credit limits for these
counterparties  and monitor the  appropriateness  of these  limits on an ongoing
basis through a credit risk  management  program which  involves  daily exposure
reporting  to senior  management,  master  trading and netting  agreements,  and
credit support management such as letters of credit and parental guarantees.

Equity Price Risk

     We, along with other  subsidiaries of Ameren, are a participant in Ameren's
defined benefit plans and  postretirement  benefit plans and are responsible for
our   proportional   share  of  the   costs.   Ameren's   costs   of   providing
non-contributory defined benefit retirement and postretirement benefit plans are
dependent upon a number of factors,  such as the rates of return on plan assets,
discount rate, the rate of increase in health care costs and contributions  made
to the plans.  The market  value of Ameren's  plan  assets has been  affected by
declines in the equity  market  since 2000 for the  pension  and  postretirement
plans. As a result, at December 31, 2002, Ameren and its subsidiaries, including
us, recognized an additional minimum pension liability as prescribed by SFAS No.
87, "Employers'  Accounting for Pensions." The liability resulted in a reduction
to equity as a result of a charge to Ameren's  Accumulated  Other  Comprehensive
Income (OCI)

                                       24

<PAGE>

of $102  million,  net of  taxes.  Our  portion  of this  charge  to OCI was $62
million,  net of taxes.  The  amount of the  liability  was the  result of asset
returns experienced  through 2002, interest rates and Ameren's  contributions to
the plan during 2002.  Neither  Ameren's nor our portion of the minimum  pension
liability  changed at March 31, 2003. In future years,  the liability  recorded,
the costs  reflected  in net income or OCI, or cash  contributions  to the plans
could increase  materially without a recovery in equity markets in excess of our
assumed return on plan assets. If the fair value of the plan assets were to grow
and exceed the accumulated  benefit obligations in the future, then the recorded
liability  would be  reduced  and a  corresponding  amount  of  equity  would be
restored in the Consolidated Balance Sheet.

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

Fair Value of Contracts

     We utilize derivatives  principally to manage the risk of changes in market
prices  for  natural  gas,  fuel,   electricity  and  emission  credits.   Price
fluctuations in natural gas, fuel and electricity cause:

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

     The  derivatives  that we use to hedge  these  risks are  dictated  by risk
management  policies and include forward contracts,  futures contracts,  options
and swaps. We continually  assess our supply and delivery  commitment  positions
against forward market prices and internally  forecast forward prices and modify
our exposure to market,  credit and  operational  risk by entering  into various
offsetting  transactions.  In general,  we believe these  transactions  serve to
reduce our price risk.  See Note 4 -  Derivative  Financial  Instruments  to our
Consolidated  Financial  Statements  under  Item 1 of Part I of this  report for
further information.

<TABLE>

     The following  summarizes the favorable  (unfavorable)  changes in the fair
value of all contracts marked-to-market during the first quarter of 2003:
<S>                                                                                                <C>
-------------------------------------------------------------------------------------------------------------
Fair value of contracts at beginning of period, net                                                 $ 6
     Contracts which were realized or otherwise settled during the period                            (1)
     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                                                                      -
-------------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at end of period, net                                           $ 5
-------------------------------------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>

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

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

(a)  Contracts  of  approximately  5% of  the  absolute  fair  value  were  with
     non-investment-grade rated counterparties.
(b)  Principally power forward values based on NYMEX prices for over-the-counter
     contracts.
(c)  Principally coal and sulfur dioxide options valued based on a Black-Scholes
     model that includes information from external sources and our estimates.

                                       25

<PAGE>

ITEM 4.  Controls and Procedures.

     (a)  Evaluation of Disclosure Controls and Procedures

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

     (b)  Change in Internal Controls

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


FORWARD-LOOKING STATEMENTS

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

     o    the effects of the stipulation and agreement  relating to 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  Federal  Energy   Regulatory
          Commission-approved  Regional  Transmission  Organization,   including
          activities associated with the Midwest System Independent Operator;
     o    availability  and future market prices for fuel for the  production of
          electricity,   such  as  coal  and  natural  gas,   purchased   power,
          electricity  and natural gas for  distribution,  including  the use of
          financial and  derivative  instruments,  the  volatility of changes in
          market prices and the ability to recover increased costs;
     o    average rates for electricity in the Midwest;
     o    business and economic conditions;
     o    the  impact  of  the  adoption  of  new  accounting  standards  on the
          application of appropriate technical accounting rules and guidance;
     o    interest rates and the availability of capital;
     o    actions of rating agencies and the effects of such actions;
     o    weather conditions;
     o    generation plant construction, installation and performance;
     o    operation of nuclear power facilities and decommissioning costs;
     o    the  effects of  strategic  initiatives,  including  acquisitions  and
          divestitures;

                                       26

<PAGE>

     o    the impact of  current  environmental  regulations  on  utilities  and
          generating   companies  and  the   expectation   that  more  stringent
          requirements  will be introduced  over time,  which could  potentially
          have a negative financial effect;
     o    future wages and employee benefit costs,  including changes in returns
          of benefit plan assets;
     o    disruptions of the capital  markets or other events making Ameren's or
          our access to necessary capital more difficult or costly;
     o    competition from other generating facilities, including new facilities
          that may be developed in the future;
     o    cost  and  availability  of  transmission   capacity  for  the  energy
          generated  by our  generating  facilities  or  required to satisfy 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 14  under  Item 8  "Financial  Statements  and
Supplementary Data" in Part II of our 2002 Annual Report on Form 10-K and Note 7
under Item 8 "Financial  Statements  and  Supplementary  Data" in Part II of the
2002 Annual  Report on Form 10-K of our  affiliates,  CILCORP  Inc.  and Central
Illinois Light Company,  operating as AmerenCILCO,  for a discussion of a number
of lawsuits that name our affiliates,  Central  Illinois Public Service Company,
operating as AmerenCIPS and AmerenCILCO,  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 the 2002 Annual  Reports on
Form 10-K,  25  additional  lawsuits  have been  filed  against  AmerenCIPS  and
AmerenUE, but no additional lawsuits have been filed against AmerenCILCO.  These
lawsuits,  like the previous  cases,  were mostly filed in the Circuit  Court of
Madison County,  Illinois,  involve a large number of total  defendants and seek
unspecified damages in excess of $50,000,  which, if proved,  typically would be
shared  among the named  defendants.  Also since the  filing of the 2002  Annual
Reports on Form 10-K, the Ameren companies have been voluntarily dismissed in 58
cases and have settled six cases.

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

     Note  2 -  Rate  and  Regulatory  Matters  to  our  Consolidated  Financial
Statements under Item 1 of Part I of this report contains additional information
on legal and administrative proceedings which is incorporated by reference under
this item.


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

         (a)(i) Exhibits filed herewith.

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

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

         (a)(ii) Exhibits incorporated by reference.

                 10.1   - * 2003 Ameren Executive Incentive Plan (Ameren
                          Corporation quarterly report on Form 10-Q for the
                          quarter ended March 31, 2003, Exhibit 10.1)


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




                                       28

<PAGE>


         (b)  Reports on Form 8-K. Union Electric Company filed the following
              report on Form 8-K during the quarterly period ended March 31,
              2003:

          ======================================================================
                                             Items Reported        Financial
               Date of Report                                  Statements Filed
          ----------------------------------------------------------------------
               March 10, 2003                     5, 7               None

         Note: Reports of Ameren Corporation on Forms 8-K, 10-Q and 10-K are on
               file with the SEC under File Number 1-4756.

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

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

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





                                       29

<PAGE>


                                    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
                                                  Vice President and Controller
                                                  (Principal Accounting Officer)
Date:  May 14, 2003



                                 CERTIFICATIONS

     I, Charles W. Mueller, certify that:

     1.   I have reviewed this  quarterly  report on Form 10-Q of 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  officer and I are responsible for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

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

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

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

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

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



                                       30

<PAGE>


                           CERTIFICATIONS (CONTINUED)

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

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




Date:  May 14, 2003                         /s/ Charles W. Mueller
                                            ------------------------------------
                                            Charles W. Mueller
                                            Chairman and Chief Executive Officer
                                            (Principal 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  officer and I are responsible for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

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

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

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

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

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




                                       31

<PAGE>


                           CERTIFICATIONS (CONTINUED)

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

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




Date:  May 14, 2003                               /s/ Warner L. Baxter
                                                  ------------------------------
                                                  Warner L. Baxter
                                                  Senior Vice President, Finance
                                                  (Principal Financial Officer)






                                       32