UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              WASHINGTON, DC 20549


                                    FORM 10-Q

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

        For Quarterly Period Ended June 30, 2003

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

        For The Transition Period From                  to

                          Commission file number 1-2967

                             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 August 14, 2003:
Common Stock, $5 par value,  held by Ameren  Corporation  (parent company of the
registrant) - 102,123,834.


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<CAPTION>
                                                             UNION ELECTRIC COMPANY

                                                                TABLE OF CONTENTS


                                                                                                                               Page
                                                                                                                              ------
<S>  <C>           <C>                                                                                                       <C>
PART I              Financial Information

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

      ITEM 2.       Management's Discussion and Analysis of Financial Condition and Results of Operations.................       16

      ITEM 3.       Quantitative and Qualitative Disclosures About Market Risk............................................       23

      ITEM 4.       Controls and Procedures...............................................................................       25

                    Forward-Looking Statements............................................................................       25

PART II             Other Information

      ITEM 1.       Legal Proceedings.....................................................................................       27

      ITEM 4.       Submission of Matters to a Vote of Security Holders...................................................       28

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

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


SIGNATURE.................................................................................................................       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  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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<CAPTION>


                                          PART I. FINANCIAL INFORMATION

ITEM 1.  Financial Statements.

                                             UNION ELECTRIC COMPANY
                                           CONSOLIDATED BALANCE SHEET
                               (Unaudited, in millions, except per share amounts)
                                                                                                 June 30,       December 31,
                                                                                                   2003             2002
                                                                                                -----------     ------------
<S>                                                                                           <C>              <C>
ASSETS:
Property and plant, net                                                                           $ 6,094          $ 5,991
Investments and other assets:
   Nuclear decommissioning trust fund                                                                 191              172
   Other assets                                                                                       240              235
                                                                                                -----------     ------------
         Total investments and other assets                                                           431              407
                                                                                                -----------     ------------
Current assets:
   Cash and cash equivalents                                                                           21                9
   Accounts receivable - trade (less allowance for doubtful
         accounts of $5 and $6, respectively)                                                         156              171
   Unbilled revenue                                                                                   164              101
   Miscellaneous accounts and notes receivable                                                         41               49
   Materials and supplies, at average cost                                                            163              162
   Other current assets                                                                                21               26
                                                                                                -----------     ------------
         Total current assets                                                                         566              518
                                                                                                -----------     ------------
Regulatory assets                                                                                     746              659
                                                                                                -----------     ------------
Total Assets                                                                                      $ 7,837          $ 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                                                                                1,484            1,477
   Accumulated other comprehensive income (loss)                                                      (61)             (58)
                                                                                                -----------     ------------
      Total common stockholder's equity                                                             2,636            2,632
                                                                                                -----------     ------------
   Preferred stock not subject to mandatory redemption                                                113              113
   Long-term debt, net                                                                              1,765            1,687
                                                                                                -----------     ------------
         Total capitalization                                                                       4,514            4,432
                                                                                                -----------     ------------
Current liabilities:
   Current maturities of long-term debt                                                               141              130
   Short-term debt                                                                                    177              250
   Intercompany notes payable                                                                         169               15
   Accounts and wages payable                                                                         164              348
   Taxes accrued                                                                                      212              118
   Other current liabilities                                                                          103               96
                                                                                                -----------     ------------
         Total current liabilities                                                                    966              957
                                                                                                -----------     ------------
Accumulated deferred income taxes                                                                   1,290            1,344
Accumulated deferred investment tax credits                                                           118              121
Regulatory liabilities                                                                                108              121
Asset retirement obligations                                                                          397              174
Accrued pension liabilities                                                                           268              252
Other deferred credits and liabilities                                                                176              174
                                                                                                -----------     ------------
Total Capital and Liabilities                                                                     $ 7,837          $ 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            Six Months Ended
                                                                           June 30,                      June 30,
                                                                  ---------------------------  ---------------------------
                                                                      2003          2002            2003          2002
                                                                  ------------- -------------  ------------  -------------
<S>                                                              <C>           <C>            <C>           <C>
OPERATING REVENUES:
   Electric                                                          $ 616         $ 654         $ 1,171       $ 1,188
   Gas                                                                  20            18              85            68
                                                                  ------------- -------------  ------------  -------------
      Total operating revenues                                         636           672           1,256         1,256
                                                                  ------------- -------------  ------------  -------------

OPERATING EXPENSES:
   Fuel and purchased power                                            122           132             263           276
   Gas                                                                  13            10              52            42
   Other operations and maintenance                                    188           207             374           391
   Depreciation and amortization                                        71            69             141           141
   Income taxes                                                         59            63              97            91
   Other taxes                                                          54            55             107           107
                                                                  ------------- -------------  ------------  -------------
      Total operating expenses                                         507           536           1,034         1,048
                                                                  ------------- -------------  ------------  -------------

OPERATING INCOME                                                       129           136             222           208

OTHER INCOME AND (DEDUCTIONS):
   Allowance for equity funds used during construction                   -             1               -             2
   Miscellaneous, net -
     Miscellaneous income                                                8            17               9            23
     Miscellaneous expense                                              (2)          (29)             (3)          (31)
     Income taxes                                                       (2)            9              (2)            8
                                                                  ------------- -------------  ------------  -------------
      Total other income and (deductions)                                4            (2)              4             2
                                                                  ------------- -------------  ------------  -------------

INTEREST CHARGES:
   Interest                                                             27            27              53            54
   Allowance for borrowed funds used during construction                (1)            -              (2)           (2)
                                                                  ------------- -------------  ------------  -------------
      Net interest charges                                              26            27              51            52
                                                                  ------------- -------------  ------------  -------------

NET INCOME                                                             107           107             175           158

PREFERRED STOCK DIVIDENDS                                                2             2               3             4
                                                                  ------------- -------------  ------------  -------------

NET INCOME AFTER PREFERRED STOCK DIVIDENDS                           $ 105         $ 105         $   172       $   154
                                                                  ============= =============  ============  =============

See Notes to Consolidated Financial Statements.

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                                       3
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<CAPTION>

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


                                                                                Six Months Ended
                                                                                     June 30,
                                                                           --------------------------
                                                                               2003          2002
                                                                           ------------  ------------
<S>                                                                       <C>            <C>
Cash Flows From Operating:
   Net income                                                                 $ 175         $ 158
   Adjustments to reconcile net income to net cash
       provided by operating activities:
         Depreciation and amortization                                          141           141
         Amortization of nuclear fuel                                            16            16
         Amortization of debt issuance costs and premium/discounts                2             2
         Allowance for funds used during construction                            (2)           (4)
         Deferred income taxes, net                                             (16)           (9)
         Deferred investment tax credits, net                                    (3)           (3)
         Other                                                                   (3)            -
         Changes in assets and liabilities:
               Receivables, net                                                 (40)          (63)
               Materials and supplies                                            (1)            8
               Accounts and wages payable                                      (147)         (119)
               Taxes accrued                                                     94            82
               Assets, other                                                    (14)           (9)
               Liabilities, other                                                36            43
                                                                           ------------  ------------
Net cash provided by operating activities                                       238           243
                                                                           ------------  ------------

Cash Flows From Investing:
   Construction expenditures                                                   (226)         (246)
   Allowance for funds used during construction                                   2             4
   Nuclear fuel expenditures                                                     (1)          (16)
   Intercompany notes receivable                                                  -            84
                                                                           ------------  ------------
Net cash used in investing activities                                          (225)         (174)
                                                                           ------------  ------------

Cash Flows From Financing:
   Dividends on common stock                                                   (165)         (152)
   Dividends on preferred stock                                                  (3)           (4)
   Capital issuance costs                                                        (3)            -
   Redemptions:
      Nuclear fuel lease                                                        (20)            -
      Short-term debt                                                           (73)         (186)
      Long-term debt                                                           (189)            -
   Issuances:
      Nuclear fuel lease                                                          -             6
      Long-term debt                                                            298             -
      Intercompany notes payable                                                154           260
                                                                           ------------  ------------
Net cash used in financing activities                                            (1)          (76)
                                                                           ------------  ------------

Net change in cash and cash equivalents                                          12            (7)
Cash and cash equivalents at beginning of year                                    9            15
                                                                           ------------  ------------
Cash and cash equivalents at end of period                                    $  21         $   8
                                                                           ============  ============

Cash paid during the periods:
   Interest                                                                   $  45         $  48
   Income taxes, net                                                             74            63

See Notes to Consolidated Financial Statements.

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                                       4

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<CAPTION>

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


                                                                               Three Months Ended          Six Months Ended
                                                                                     June 30,                   June 30,
                                                                            -------------------------- --------------------------
                                                                                2003         2002          2003          2002
                                                                            ------------ ------------- ------------  ------------
<S>                                                                        <C>           <C>           <C>          <C>
Common stock                                                                 $   511       $  511        $  511       $   511

Other paid-in capital                                                            702          702           702           702

Retained earnings
   Beginning balance                                                           1,462         1,413         1,477        1,440
   Net income                                                                    107           107           175          158
   Common stock dividends                                                        (83)          (76)         (165)        (152)
   Preferred stock dividends                                                      (2)           (2)           (3)          (4)
                                                                            ------------ ------------- ------------  ------------
                                                                               1,484         1,442         1,484        1,442
                                                                            ------------ ------------- ------------  ------------

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

                                                                                 (61)            1           (61)           1
                                                                            ------------ ------------- ------------  ------------


Total common stockholder's equity                                            $ 2,636       $ 2,656       $ 2,636      $ 2,656
                                                                            ============ ============= ============  ============


Comprehensive income, net of taxes
   Net income                                                                $   107       $   107       $   175      $   158
   Unrealized net gain/(loss) on derivative hedging instruments,
        net of income taxes of $(1), $1, $(1) and $1, respectively                (2)            1            (2)           2
   Reclassification adjustments for gains/(losses) included in net income,
        net of income taxes of $-, $-, $- and $(1), respectively                   -             1            (1)          (2)
                                                                            ------------ ------------- ------------  ------------
           Total comprehensive income, net of taxes                          $   105       $   109       $   172      $   158
                                                                            ============ ============= ============  ============

See Notes to Consolidated Financial Statements.

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                                       5

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UNION ELECTRIC COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
June 30, 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  primarily  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 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  AmerenEnergy  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

<PAGE>

Accounting Changes and Other Matters

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

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

     Upon adoption of this standard,  we recognized  additional asset retirement
obligations of approximately $213 million and a net increase in net property and
plant of  approximately  $77 million related  primarily to the Callaway  nuclear
plant  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 that we had recorded at
January 1, 2003,  related to our future  obligations  and funds  accumulated  to
decommission the Callaway nuclear plant.

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

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

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

     Historically,  our depreciation  methodology has included an estimated cost
of dismantling  and removing plant from service upon  retirement.  Because these
estimated  costs of removal have been included in the cost of service upon which
our present utility rates are based, and with the expectation that this practice
will continue in the jurisdictions in which we operate, adoption of SFAS 143 did
not  result  in any  change  in the  depreciation  accounting  practices  of our
rate-regulated  operations.  We have estimated  future removal costs embedded in
accumulated   depreciation   related  to   rate-regulated   plant   assets  were
approximately $542 million at June 30, 2003.

     The  following  table shows the asset  retirement  obligation  liability as
though SFAS 143 had been in effect for the two prior years.

====================================================
Pro forma Asset Retirement Obligation Liability
----------------------------------------------------
January 1, 2001                         $   346
December 31, 2001                           366
December 31, 2002                           387
====================================================

     There are no pro forma net  income  effects of  adopting  SFAS 143 since we
expect to  continue to recover in  electric  rates the cost of Callaway  nuclear
decommissioning and other costs of removal.

                                       7

<PAGE>

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 sum of the contract notional amounts of the power
sales  contracts  with a  corresponding  charge to  income  for the costs of the
energy that was generated,  or for the sum of the contract notional amounts of a
purchased power contract.

     In October  2002,  the EITF reached a consensus to rescind EITF 98-10.  The
effective  date for the full  rescission  of EITF 98-10 was for  fiscal  periods
beginning after December 15, 2002, with early adoption  permitted.  In addition,
the EITF reached a consensus in October 2002 that all SFAS No. 133  ("Accounting
for  Derivative   Instruments  and  Hedging   Activities")  trading  derivatives
(subsequent  to the  rescission of EITF 98-10) should be shown net in the income
statement,  whether or not physically  settled.  This  consensus  applies to all
energy and non-energy related trading  derivatives that meet the definition of a
derivative  pursuant to SFAS 133.  The  operating  revenues  and costs that were
netted for the three and six months  ended June 30,  2002 were $78  million  and
$228  million,  respectively,  which  reduced  Electric  Revenues  and  Fuel and
Purchased Power by equal amounts.  The adoption of EITF 02-3, the  rescission of
EITF 98-10 and the  related  transition  guidance  resulted in netting of energy
contracts  and  lowered  our  reported  revenues  and  costs  with no  impact on
earnings.

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

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

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

     In May 2003, the FASB issued SFAS 150 that established standards for how an
issuer   classifies   and   measures   certain   financial    instruments   with
characteristics  of both  liabilities  and equity.  SFAS 150 requires  financial
instruments  that  were  issued  in the  form of  shares  with an  unconditional
obligation,  where the issuer must redeem the  instrument  by  transferring  its
assets on a specified date, be classified as liabilities.  Accordingly, SFAS 150
requires issuers to classify  mandatorily  redeemable  financial  instruments as
liabilities. SFAS 150 also requires such financial instruments to be measured at
fair value and a cumulative  effect adjustment to be recognized in the statement
of income for any difference between the carrying amount and fair value.

     SFAS 150 will be effective in the third  quarter of 2003.  We do not expect
SFAS 150 to have any impact on our financial position,  results of operations or
liquidity upon adoption in the third quarter of 2003.

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

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

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

                                       8

<PAGE>

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

Interchange Revenues

     Interchange  revenues  included in Operating  Revenues - Electric  were $65
million for the three  months  ended June 30, 2003 (2002 - $62 million) and $167
million for the six months ended June 30, 2003 (2002 - $140 million).

Purchased Power

     Purchased  power included in Operating  Expenses - Fuel and Purchased Power
was $36 million for the three  months  ended June 30, 2003 (2002 - $53  million)
and $81 million for the six months ended June 30, 2003 (2002 - $118 million).

Excise Taxes

     Excise taxes on Missouri  electric and gas, and Illinois gas customer bills
are imposed on us and are recorded gross in Operating  Revenues and Other Taxes.
Excise taxes recorded in Operating Revenues and Other Taxes for the three months
ended June 30, 2003 were $24 million  (2002 - $28  million)  and $47 million for
the six months ended June 30, 2003 (2002 - $49 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.

Pensions

     At  December  31,  2002,  Ameren  recorded  a minimum  accumulated  pension
liability  of  $102  million,  after  taxes,  which  resulted  in  a  charge  to
Accumulated  Other  Comprehensive   Income  (Loss)  (OCI)  and  a  reduction  in
stockholder's   equity.   Our  share  of  the  minimum  pension   liability  was
approximately  $62  million,  after taxes.  Based on changes in interest  rates,
Ameren may need to change its  actuarial  assumptions  for its  pension  plan at
December 31, 2003,  which could result in a requirement  to record an additional
minimum pension liability.


NOTE 2 - Rate and Regulatory Matters

Intercompany  Purchase of Electric  Generating  Facilities  and Sale of Illinois
Service Territory

     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 by us, at net book value, of approximately  550 megawatts
(approximately   $260  million)  of  combustion   turbine  generating  units  at
Pinckneyville and Kinmundy,  Illinois from Generating  Company.  The purchase is
subject to receipt of necessary  regulatory  approvals  and would be funded with
available  liquidity and  borrowings.  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.

     In February  2003, we sought  approval from the Federal  Energy  Regulatory
Commission (FERC) and the Illinois Commerce Commission (ICC) to purchase the 550
megawatts of generating  assets from  Generating  Company.  Several  independent
power  producers  have objected to our request to 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 in
the ICC proceeding  contending  that NRG's 640 megawatt  generating  facility at
Vandalia,  Missouri, known as the Audrain Facility, was a better resource for us
to acquire as compared to the  Kinmundy  and  Pinckneyville  combustion  turbine
generating  units.  In addition,  the ICC Staff filed  testimony  that expressed
concerns about whether the

                                       9

<PAGE>

purchase is the least cost generating  resource for us, and recommended that the
ICC deny approval of the purchase.

     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.  On June
4, 2003, we filed a Motion for Reconsideration of this order contending that the
FERC erred in setting this matter for hearing. On June 10, 2003, we filed direct
testimony with the FERC in support of the proposed purchase.  On August 8, 2003,
two intervenors, NRG and The Electric Power Supply Association,  filed testimony
opposing the proposed purchase.

     On May 30, 2003, we filed a Notice of Withdrawal  with the ICC stating that
we elected  not to pursue  approval of the  purchase  and were  withdrawing  our
request.  In the Notice, we stated that the concerns  expressed by the ICC Staff
regarding our means of satisfying our generating  capacity needs, as well as the
MoPSC's  views  of  the  appropriate  means  of  meeting   generating   capacity
obligations,  have  demonstrated  to  us  the  difficulty  of a  single  company
operating  as an electric  utility in both a regulated  generation  jurisdiction
such as Missouri and an unregulated generation jurisdiction such as Illinois. To
remedy this difficulty,  we announced in the Notice our plan to limit our public
utility  operations to the State of Missouri and to  discontinue  operating as a
public utility subject to ICC  regulation.  We intend to accomplish this plan by
selling our  Illinois-based  electric and natural gas businesses,  including our
Illinois-based  distribution  assets and certain of our transmission  assets, to
AmerenCIPS.  Our  electric  generating  facilities  and certain of our  electric
transmission facilities in Illinois would not be part of the sale. We propose to
sell the assets at their net book value. In 2002, our Illinois service territory
generated  revenues of $166 million and is estimated to have a net book value of
$138  million at  December  31,  2003.  The sale of our  Illinois-based  utility
businesses will require the approval of the ICC, the FERC, the MoPSC and the SEC
under the  provisions  of the PUHCA.  On June 13,  2003,  the ICC Staff  filed a
response  to our  Notice  of  Withdrawal  indicating  that the ICC Staff did not
object  to it and on July  23,  2003,  the ICC  issued  an order  accepting  the
withdrawal.  In the third quarter of 2003, we expect to file with the MoPSC, the
ICC,  the FERC and the SEC for  authority  to sell  our  Illinois-based  utility
businesses to AmerenCIPS.  We propose to transfer  approximately one-half of the
assets  directly to AmerenCIPS  in  consideration  for an AmerenCIPS  promissory
note, and approximately one-half of the assets by means of a dividend in kind to
Ameren followed by a capital contribution by Ameren to AmerenCIPS.

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

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

Regional Transmission Organization (RTO)

     Since  April  2002,  we,   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.

                                       10

<PAGE>

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

     Once  GridAmerica  becomes  operational and Ameren has secured  approval to
participate  in GridAmerica  from the MoPSC,  the FERC has ordered the return of
the $18 million exit fee, with interest,  paid by Ameren when it previously left
the Midwest ISO. Our share of the exit fee to be returned is $13 million.  Until
the tariffs and other material  terms of our and  AmerenCIPS'  participation  in
GridAmerica,  and GridAmerica's  participation in the Midwest ISO, are finalized
and  approved  by the FERC,  we are unable to predict the  ultimate  impact that
on-going  regional  transmission  organization  developments  will  have  on our
financial  position,  results of operations or liquidity.  Our  participation in
GridAmerica is also subject to MoPSC approval.  We expect  GridAmerica to become
operational by later in 2003, subject to regulatory approvals.

     In July 2003, the FERC issued an Order (July Order) that could  potentially
reduce our, as well as other utilities', "through and out" transmission revenues
effective  November 1, 2003,  reversing an  Administrative  Law Judge's previous
decision on this matter.  The revenues  subject to elimination by the July Order
are those revenues from transmission  reservations that travel through or out of
our transmission  system and are also used to provide electricity to load within
the  Midwest  ISO or PJM  Interconnection  LLC  systems.  The  magnitude  of the
potential  net revenue  reduction  resulting  from the July Order is still being
evaluated,  but could be up to $20 to $25 million annually for Ameren.  While it
is anticipated that Ameren's  transmission revenues could be reduced by the July
Order,  transmission  expenses  for our  affiliates  could also be reduced.  Our
portion of the potential net revenue reduction could be up to $14 to $17 million
annually.  Moreover, the FERC's Order explicitly permits companies participating
in an RTO to seek  collection  of the lost  "through and out"  revenues  through
other rate  mechanisms.  At this time,  we intend to seek  rehearing of the July
Order.  We also intend to seek recovery of any potential  lost "through and out"
revenues through rate mechanisms acknowledged by the FERC in the July Order.

Standard Market Design Notice of Proposed Rulemaking (NOPR)

     On July 31, 2002,  the FERC issued a Standard  Market Design NOPR. The NOPR
proposes  a number of  changes  to the way the  current  wholesale  transmission
service and energy  markets are operated.  Specifically,  the NOPR calls for all
jurisdictional  transmission  facilities  to be placed  under the  control of an
independent   transmission   provider  (similar  to  an  RTO),  proposes  a  new
transmission  service tariff that provides a single form of transmission service
for all users of the  transmission  system  including  bundled  retail load, and
proposes  a new  energy  market  and  congestion  management  system  that  uses
locational marginal pricing as its basis.

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

Illinois Gas

     In November 2002, we filed a request with the ICC to increase  annual rates
for  natural  gas  service  by  approximately  $4  million.  The ICC  Staff  has
recommended  an annual  increase of  approximately  $2 million and other parties
have also proposed a lower  increase.  Hearings were  completed in June and July
2003.  The ICC has until  October 2003 to render a decision in this gas case and
any rate change is expected to be effective in November 2003.

                                       11

<PAGE>

Missouri Gas

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

NOTE 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  $24 million for the three  months ended June 30, 2003 (2002 - $23
million)  and $51  million  for the six months  ended June 30,  2003 (2002 - $50
million).  Intercompany  power sales  totaled  $25 million for the three  months
ended June 30,  2003 (2002 - $17  million)  and $57  million  for the six months
ended June 30, 2003 (2002 - $37 million).

     Interchange  revenues  from outside sales of available  generation  through
AmerenEnergy  were $41 million for the three  months ended June 30, 2003 (2002 -
$41 million) and $111 million for the six months ended June 30, 2003 (2002 - $95
million).  Purchased  power  derived from  AmerenEnergy  was $11 million for the
three  months  ended June 30, 2003 (2002 - $30  million) and $28 million for the
six months ended June 30, 2003 (2002 - $67 million).

     Costs of support  services  provided by Ameren  Services and  AmerenEnergy,
including wages, employee benefits and professional services are based on actual
costs  incurred.  Support  services  included  in  Operating  Expenses  -  Other
Operations and  Maintenance for the three months ended June 30, 2003 totaled $47
million  (2002 - $48  million) and $97 million for the six months ended June 30,
2003 (2002 - $96 million).

     As of June 30, 2003,  intercompany  receivables  included in  Miscellaneous
Accounts and Notes Receivable were  approximately $14 million (December 31, 2002
- $25 million). As of June 30, 2003,  intercompany payables included in Accounts
and Wages Payable totaled  approximately  $55 million  (December 31, 2002 - $103
million).

     We have the  ability  to borrow  from  Ameren  Corporation  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 June 30, 2003 was
our  commercial  paper  program.  Through the  utility  money pool we can access
committed credit facilities at Ameren Corporation and AmerenCIPS,  which totaled
$615 million at June 30, 2003.  These facilities are in addition to our own $157
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  Corporation,  AmerenCIPS or
Ameren  Services  have  surplus  funds and the  availability  of other  external
borrowing  sources.  The  availability  of funds is also  determined  by funding
requirement  limits  established  by 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 June 30, 2003,  the average
interest  rate for the  utility  money pool was 1.19% (2002 - 1.75%) and for the
six months ended June 30, 2003 was 1.25% (2002 - 1.77%).  At June 30,  2003,  we
had outstanding intercompany notes payables of $167 million, sourced by internal
funds through the utility money pool (December 31, 2002 - $15 million).  Subject
to the receipt of regulatory approval, which is being pursued,  AmerenCILCO will
also participate in the utility money pool arrangement.

                                       12

<PAGE>

     We jointly  dispatch  generation with  Generating  Company under an amended
joint dispatch agreement.  Under the amended agreement,  both of us are entitled
to serve our load  requirements  from our own least-cost  generation  first, and
then allow the other company  access to any  available  excess  generation.  The
agreement  has no  expiration,  but either  party may give a one year  notice of
termination beginning January 1, 2004.  Termination of this agreement could have
a material adverse impact on our business.

NOTE 4 - Derivative Financial Instruments

     As of June 30,  2003,  we recorded the fair value of  derivative  financial
instrument assets of $7 million in Other Assets and the fair value of derivative
financial  instrument  liabilities of $4 million in Other  Deferred  Credits and
Liabilities.

Cash Flow Hedges

     The pretax net gain or loss on power forward derivative instruments,  which
represented the impact of discontinued cash flow hedges, the ineffective portion
of cash flow hedges, as well as the reversal of amounts  previously  recorded in
OCI due to transactions going to delivery or settlement, was a $0.2 million gain
for the three  months  (2002 - $1 million  loss) and a $0.5 million loss for the
six months  ended June 30, 2003.  For the six months  ended June 30,  2002,  the
second  quarter  loss on power  forward  derivative  instruments  offset  the $1
million gain from the first quarter.

     As of June 30,  2003,  we had  hedged a portion  of the  electricity  price
exposure for periods  generally  less than one year.  The  mark-to-market  value
accumulated  in OCI for the  effective  portion of hedges of  electricity  price
exposure was a net gain of  approximately  $0.7 million  ($0.4  million,  net of
taxes).

     As of June 30,  2003,  a loss of  approximately  $1  million  (less than $1
million,  net of taxes)  associated  with natural gas swaps was included in OCI.
The swaps are a partial hedge of our natural gas  requirements  through  October
2006.

     We also hold two call options for coal with two suppliers. These options to
purchase  coal  expire  October  2003 and July  2005.  As of June  30,  2003,  a
mark-to-market  gain of  approximately  $5 million  ($3  million,  net of taxes)
associated  with these  options  was  included  in OCI.  The final  value of the
options  will be  recognized  as a reduction in fuel costs as the hedged coal is
burned.

Other Derivatives

     We enter into option transactions to manage our positions in sulfur dioxide
allowances,  coal and electricity.  Certain of these transactions are treated as
non-hedge  transactions  under SFAS 133.  The net 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 $0.4 million ($0.2  million,  net of taxes) for the three months ended
June 30, 2003 and $0.4 million ($0.2  million,  net of taxes) for the six months
ended June 30, 2003. For the three and six months ended June 30, 2002, the above
related  amounts  were a $2  million  gain ($1  million,  net of taxes) and a $3
million gain ($2 million, net of taxes).


NOTE 5 - Property and Plant, Net

     Property and plant, net at June 30, 2003 and December 31, 2002 consisted of
the following:

================================================================================
                                                     June 30,       December 31,
                                                       2003             2002
--------------------------------------------------------------------------------
Property and plant, at original cost:
  Electric                                           $10,575          $10,294
  Gas                                                    272              268
  Other                                                   37               36
--------------------------------------------------------------------------------
                                                      10,884           10,598
    Less accumulated depreciation and amortization     5,134            4,968
--------------------------------------------------------------------------------
                                                       5,750            5,630


                                       13
<PAGE>

Construction work in progress:
  Nuclear fuel in process                                 71               81
  Other                                                  273              280
--------------------------------------------------------------------------------
Property and plant, net                              $ 6,094          $ 5,991
================================================================================

NOTE 6 - Debt Financings

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

     In March 2003, 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 matured
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 debt.

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

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

     Once  declared  effective by the SEC, we may sell all, or a portion of, the
securities  registered  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.

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

     In July 2003, Ameren Corporation entered into two new credit agreements for
$470 million in revolving  credit  facilities  to be used for general  corporate
purposes,  including support of our commercial paper program through the utility
money pool. The $470 million in new facilities  includes a $235 million  364-day
revolving  credit  facility  and a  $235  million  three-year  revolving  credit
facility.  These new credit facilities  replaced Ameren  Corporation's  existing
$270 million 364-day revolving credit facility,  which matured in July 2003, and
a $200  million  facility,  which would have matured in December  2003.  The new
credit  facilities  contain  provisions  which  require  Ameren to meet  minimum
Employee  Retirement  Income Security Act (ERISA) funding  requirements  for its
pension plan. The prior credit facilities  included more

                                       14

<PAGE>

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

     At June 30, 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.

     Amortization  of debt  issuance  costs and any premium or discounts for the
three and six months  ended June 30, 2003 of $1 million  (2002 - $1 million) and
$2 million (2002 - $2 million),  respectively, were included in interest expense
in the income statement.

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


NOTE 7 - Miscellaneous, Net

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

<TABLE>
<CAPTION>

============================================================================================================
                                                                      Three Months            Six Months
------------------------------------------------------------------------------------------------------------

                                                               <C>          <C>         <C>       <C>
                                                                    2003        2002        2003      2002
Miscellaneous income:
   Interest and dividend income                                     $  -        $  2        $  -      $  2
   Equity in earnings of subsidiary                                    4          10           5        11
   Gain on disposition of property and other assets                    -           5           -         8
   Other                                                               4           -           4         2
-------------------------------------------------------------------------------------------------------------
Total miscellaneous income                                          $  8        $ 17        $  9      $ 23
-------------------------------------------------------------------------------------------------------------

Miscellaneous expense:
   Plant acquisition amortization                                   $  -        $  -        $   -     $ (1)
   Loss on disposition of property and other assets                    -          (1)           -        -
   Donations - rate case settlement                                    -         (26)           -      (26)
   Other                                                              (2)         (2)          (3)      (4)
-------------------------------------------------------------------------------------------------------------
Total miscellaneous expense                                         $ (2)       $(29)       $  (3)    $(31)
-------------------------------------------------------------------------------------------------------------
</TABLE>


                                       15

<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  Acquisitions  for further
     information.
o    AmerenEnergy  Resources Company (Resources Company),  which consists of non
     rate-regulated  operations.  Subsidiaries include  AmerenEnergy  Generating
     Company (Generating  Company),  which operates non rate-regulated  electric
     generation  in  Missouri  and  Illinois,   AmerenEnergy  Marketing  Company
     (Marketing  Company),  which markets power for periods  primarily  over one
     year,  AmerenEnergy  Fuels and Services  Company,  which  procures fuel and
     manages the related risks for 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 and renamed it
     AmerenEnergy Medina Valley Cogen (No. 4), LLC. See Acquisitions for further
     information.
o    AmerenEnergy,  Inc.  (AmerenEnergy),  which serves as a power marketing and
     risk management agent for 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    The financial statements and related notes included in our Quarterly Report
     on Form 10-Q for the period ended March 31, 2003.
o    Management's  Discussion and Analysis of Financial Condition and Results of
     Operations  that  appears in our Annual  Report on Form 10-K for the period
     ended December 31, 2002, as amended by Form 10-K/A.
o    The  audited  financial  statements  and  related  notes that appear in our
     Annual  Report on Form 10-K for the period  ended  December  31,  2002,  as
     amended by Form 10-K/A.

     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  AmerenEnergy  Fuels and Services  Company.  All
tabular dollar amounts are in millions, unless otherwise indicated.

     Our results of  operations  and  financial  position  are  affected by many
factors.  Weather,  economic  conditions  and the  actions of key  customers  or
competitors can  significantly  impact the demand for our services.  Our results
are also affected by seasonal  fluctuations  caused by winter heating and summer
cooling demand.  With 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,

                                       16

<PAGE>

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

Acquisitions

     On  January  31,  2003,  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  indirect  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 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 three and six months ended
June 30, 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 our service
territory.  CILCO  also  has a non  rate-regulated  electric  and gas  marketing
business  principally  focused in the Chicago,  Illinois  region.  Finally,  the
purchase included approximately 1,200 megawatts of largely coal-fired generating
capacity, most of which is expected to become non rate-regulated in 2003.

     The total acquisition cost was approximately  $1.4 billion and included the
assumption of CILCORP and Medina  Valley debt and preferred  stock at closing of
$895 million and  consideration  of $489 million in cash,  net of cash acquired.
The cash  component  of the  purchase  price  came from  Ameren's  issuances  in
September  2002 of 8.05 million  common shares and its issuance in early 2003 of
an additional 6.325 million common shares,  which together  generated  aggregate
net proceeds of $575 million.


RESULTS OF OPERATIONS

Earnings Summary

     Our net income of $107 million in the second quarter of 2003 was comparable
to the second quarter of 2002. Second quarter earnings were negatively  impacted
by milder weather. The impact of the mild weather,  however, was offset by lower
operations  and  maintenance  expenses,  favorable  interchange  margins  due to
improved  power  prices in the  energy  markets  and solid  low-cost  generation
available for sale. In addition,  we expensed costs of economic  development and
energy  assistance  programs that were required by a Missouri electric rate case
settlement in the second quarter of 2002.

     Our net income  increased  $17  million to $175  million for the six months
ended June 30,  2003  compared to the  year-ago  earnings  of $158  million.  In
addition to the items  discussed  above,  net income for the first six months of
2003 benefited from higher interchange margins and colder winter weather than in
2002,  which  resulted in increased  native load electric  demand and higher gas
margins in the first quarter of 2003.

                                       17

<PAGE>

Electric Operations

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

================================================================================
                                                   Three Months       Six Months
--------------------------------------------------------------------------------
Electric Revenues:
   Interchange revenues                              $   3              $  27
   Effect of weather (estimate)                        (49)               (28)
   Rate reductions                                      (5)               (16)
   Growth and other (estimate)                          13                  -
--------------------------------------------------------------------------------
   Total variation in electric operating revenues      (38)               (17)
--------------------------------------------------------------------------------
Fuel and Purchased Power:
   Fuel:
     Generation                                      $  (5)            $  (21)
     Price                                              (3)                (3)
     Generation efficiencies and other                   1                  -
   Purchased power                                      17                 37
--------------------------------------------------------------------------------
   Total variation in fuel and purchased power          10                 13
--------------------------------------------------------------------------------
Change in electric margin                            $ (28)            $   (4)
================================================================================

     Electric  margin  decreased $28 million for the three months and $4 million
for the six months  ended June 30, 2003  compared  to the same  periods in 2002.
Decreases in electric  margin in the second quarter and first six months of 2003
were  primarily   attributable  to  unfavorable   weather  conditions  and  rate
reductions  resulting  from the 2002  Missouri  electric  rate case  settlement,
partially  offset by increased  interchange  margins.  The  unfavorable  weather
conditions were primarily due to mild early summer weather in the second quarter
of 2003 versus warmer than normal  conditions in the same period in 2002. In our
service  territory,   weather-sensitive   residential  and  commercial  electric
kilowatthour sales declined 17% and 10%, respectively,  in the second quarter of
2003 (year-to-date - 1% and 2%,  respectively)  compared to 2002. Cooling degree
days were  approximately 30% and 40% less in the second quarter of 2003 compared
to normal and the prior year period, respectively.

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

     Interchange  margins  increased  approximately  $11  million  in the second
quarter  and  approximately  $40  million in the first six months of 2003 due to
improved  power  prices in the  energy  markets  and solid  low-cost  generation
availability.   Average  power  prices  increased  to   approximately   $36  per
megawatthour  in the  first  six  months  of  2003  from  approximately  $24 per
megawatthour in the first six months of 2002. Fuel and purchased power decreased
$10  million in the second  quarter  and $13  million in the first six months of
2003 due to greater availability of low-cost generation.

     The growth and other line item includes our sale of emission  credits.  The
sale of emission credits  increased in the second quarter of 2003 by $4 million,
but  decreased  in the first six months of 2003 by $9  million,  compared to the
same  periods in 2002.  In  addition,  industrial  electric  kilowatthour  sales
increased  approximately  14% in the  second  quarter  of  2003  in our  service
territory.

     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 and six months  ended June 30, 2002
were $78 million  and $228  million,  respectively,  which  reduced  interchange
revenues  and  purchased  power  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.

                                       18

<PAGE>

Gas Operations

     Our gas margin decreased $1 million in the second quarter of 2003, compared
to the second quarter of 2002, as a result of more mild weather.  Our gas margin
increased  $7  million  in the first six  months of 2003,  compared  to the same
period in the prior year,  primarily due to increased  customer demand resulting
from colder winter weather in the first quarter of 2003.

Other Operating Expenses

Other Operations and Maintenance

     Other  operations  and  maintenance  expenses  decreased $19 million in the
second quarter and $17 million in the first six months of 2003,  compared to the
prior year periods,  primarily due to lower labor costs related to our voluntary
employee  retirement program instituted at the end of 2002 and lower maintenance
costs at our power plants primarily due to the number and timing of outages. The
decreases in expense were  partially  offset by higher  employee  benefit costs,
primarily related to higher healthcare and pension costs.

     Costs of support  services  provided by Ameren  Services and  AmerenEnergy,
including wages, employee benefits and professional services are based on actual
costs  incurred.  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  increased $2 million in the second
quarter  of 2003,  compared  to the  year-ago  period,  as a result  of  capital
additions  in 2002.  For the six  months  ended  June  30,  2003,  increases  in
depreciation  and  amortization  expenses as a result of capital  additions were
offset by a $5 million reduction in depreciation expense in the first quarter of
2003 resulting from a $20 million annual depreciation  reduction of depreciation
rates. This reduction was based on the updated analysis of asset values, service
lives  and  accumulated  depreciation  levels  that  were  required  by our 2002
Missouri electric rate case settlement.

Income Taxes

     Income tax expense  increased $7 million in the second  quarter of 2003, as
compared to the second quarter of 2002,  primarily due to a higher effective tax
rate.  Income tax expense increased $16 million in the first six months of 2003,
as compared to the same period in 2002, primarily due to higher pretax income.

Other Taxes

     Other taxes  expense  decreased  $1 million in the second  quarter or 2003,
compared  to the second  quarter of 2002,  primarily  due to a decrease in gross
receipts  taxes  related to lower  native  sales as a result of milder  weather.
Other tax expense for the six months ended 2003 was comparable to the prior year
period.

Other Income and Deductions

     Other income and deductions  (excluding income taxes) increased $17 million
in the second  quarter of 2003 and $12  million in the first six months of 2003,
compared to the same  periods in the prior year,  primarily  due to expensing in
2002 of economic  development  and energy  assistance  programs  required in the
Missouri  electric rate case  settlement  ($26 million),  partially  offset by a
decrease in earnings from our ownership  interest in EEI and decreased  gains on
derivative contracts.

Interest

     Interest  expense in the second quarter of 2003 was comparable to the prior
year  period.  Interest  expense  in the first six months of 2003  decreased  $1
million,  compared to the 2002 period,  primarily due to lower interest rates on
new issuances of first mortgage bonds as compared to those redeemed.

                                       19

<PAGE>


LIQUIDITY AND CAPITAL RESOURCES

Operating

     Our cash flows provided by operating  activities  were $238 million for the
first six months of 2003,  compared to $243 million for the same period in 2002.
Cash provided by operating activities decreased slightly in the first six months
of 2003 primarily as a result of increased  electric and gas operating  margins,
offset by increased working capital requirements.

     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 $225 million in the first six
months of 2003,  compared  to $174  million  for the same  period  in 2002.  The
increase over the prior year period was primarily related to the 2002 receipt of
$84 million we had invested in the utility money pool, partially offset by lower
construction  and nuclear fuel  expenditures in 2003. In the first six months of
2003,  construction  expenditures  were  $226  million  (2002  - $246  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 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 used in financing activities totaled $1 million in the first
six  months of 2003 and $76  million  for the  comparable  period  in 2002.  Our
principal  financing  activities  for the first six months of 2003  included the
redemptions of short-term and long-term  debt, as well as payments of dividends,
partially offset by issuances of long-term debt and intercompany notes payable.

     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 and  intercompany  borrowings
through Ameren's utility money pool (maturities  generally within 1 to 45 days).
At June 30, 2003,  Ameren  Corporation and its subsidiaries had committed credit
facilities,  expiring at various  dates  through  2005,  totaling  $772 million,
excluding  AmerenCILCO  facilities of $59 million, EEI facilities of $41 million
and our nuclear fuel lease facilities of $120 million. This amount includes $157
million of our committed credit  facilities and $615 million of committed credit
facilities  at Ameren  Corporation  and  AmerenCIPS.  We access  these  combined
facilities  through  Ameren's  utility money pool  arrangement.  AmerenCIPS  and
Ameren Services may also borrow under this  arrangement.  Subject to the receipt
of  regulatory  approval,   which  is  being  pursued,   AmerenCILCO  will  also
participate  in the  utility  money pool  arrangement.  These  committed  credit
facilities  are used to support our commercial  paper program,  under which $177
million was  outstanding  at June 30, 2003.  At June 30, 2003,  $595 million was
unused and available under these committed credit facilities.

     In July 2003, Ameren Corporation entered into two new credit agreements for
$470 million in revolving  credit  facilities  to be used for general  corporate
purposes,  including the support of our  commercial  paper  program  through the
utility money pool. The $470 million in new  facilities  includes a $235 million
364-day revolving credit facility and a $235 million three-year revolving credit
facility.  These new credit facilities  replaced Ameren  Corporation's  existing
$270 million 364-day revolving credit

                                       20

<PAGE>

facility,  which matured in July 2003, and a $200 million facility,  which would
have matured in December  2003.  The new credit  facilities  contain  provisions
which require Ameren to meet minimum  Employee  Retirement  Income  Security Act
(ERISA) funding  requirements for its pension plan. The prior credit  facilities
included more  restrictive  provisions  related to the funded status of Ameren's
pension plan, which are not present in the new facilities.  In addition, in July
2003, Ameren  Corporation  entered into an amendment of an existing $130 million
multi-year credit facility that similarly modified the ERISA-related  provisions
in this facility. As a result, all of Ameren Corporation's facilities require it
to meet minimum  ERISA  funding  requirements,  but do not  otherwise  limit the
underfunded  status of its pension plan. At July 31, 2003, all of such borrowing
capacity under these facilities was available to Ameren and its subsidiaries.

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

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

Financial Agreement Provisions and Covenants

     Our financial  agreements and those of Ameren include  customary default or
cross default provisions that could impact the continued  availability of credit
or result in the acceleration of repayment. The majority of the committed credit
facilities  of  Ameren  and  its  subsidiaries  each  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  financing
arrangements,  nor those of Ameren and its other  subsidiaries,  contain  credit
rating triggers, except for three funded bank term loans at AmerenCILCO totaling
$105 million at June 30, 2003.

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

Debt Issuances and Redemptions

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

     In April 2003,  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 debt.

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

                                       21

<PAGE>

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

Off-Balance Sheet Arrangements

     At June 30, 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.


OUTLOOK

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

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

     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 Ameren's overall cost;
o    A wage freeze in 2003 for all management employees;
o    Suspension  of  operations  at a  1940's-era  generating  plant  to  reduce
     operating costs; and
o    Reductions of 2003 expected capital expenditures.

     We are pursuing an annual gas rate increase of  approximately $4 million in
Illinois and $27 million in Missouri.  See Note 2 - Rate and Regulatory  Matters
to our Consolidated  Financial  Statements under Item 1 of Part I of this report
for  additional  information.  Ameren  is also  considering  additional  actions
including modifications to active employee benefits, further staffing reductions
and other initiatives.

     International Brotherhood of Electrical Workers and the International Union
of Operating  Engineers  labor  agreements  for six  bargaining  units  covering
approximately  65% of our entire  workforce  expired between April 1 and July 1,
2003. The principal issues being negotiated with regard to continuation of these
labor  agreements  are wages,  work rules and a proposal to change the  employee
medical  benefits  program to require  employees to pay for a greater portion of
their  benefit   coverage.   During  July  2003,  after  engaging  in  extensive
negotiations  with the collective  bargaining  units, we finalized new tentative
agreements  with five of the  bargaining  units with terms expiring in 2006. The
membership of three of the bargaining  units have ratified the  agreements  with
respect to wages and work rules and the  membership of the remaining  bargaining
units are expected to vote on their new  agreement in the third quarter of 2003.
Changes to the  employee  medical  benefits  program  have been agreed to with a
joint bargaining committee representing all unions;  however, the changes cannot
be implemented without  ratification by a majority of the collective  membership
of all bargaining units. We are unable to predict whether the agreements will be
ratified or what action,  if any, the collective  bargaining  units will take in
the  event  the   agreements   are  not   ratified  or  the  response  of  other
union-represented  employees  to any  action  by  its  employees.  We are  still
negotiating  as to  wages  and  work  rules  with  one  bargaining  unit,  which
represents  approximately 30% of

                                       22

<PAGE>

our  workforce.  We are unable to  determine  what,  if any,  impact these labor
matters could have on our future financial  condition,  results of operations or
liquidity.

     At  December  31,  2002,  Ameren  recorded  a minimum  accumulated  pension
liability  of  $102  million,  after  taxes,  which  resulted  in  a  charge  to
Accumulated  Other  Comprehensive   Income  (Loss)  (OCI)  and  a  reduction  in
stockholder's   equity.   Our  share  of  the  minimum  pension   liability  was
approximately  $62  million,  after taxes.  Based on changes in interest  rates,
Ameren expects it may need to change its actuarial  assumptions  for its pension
plan at December 31,  2003,  which could  result in a  requirement  to record an
additional minimum pension liability.

     In the ordinary course of business,  we 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 on our proposed
sale of our Illinois service terriory and our proposed purchase of 550 megawatts
of  generating  capacity,  both  with  affiliates,   and  information  on  other
regulatory matters.


ACCOUNTING MATTERS

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


ITEM 3.  Quantitative and Qualitative Disclosures about Market Risk.

     Market risk  represents the risk of changes in value of a physical asset or
financial  instrument,  derivative or non-derivative,  caused by fluctuations in
market  variables  (e.g.  interest  rates,  etc.).  The following  discussion of
Ameren's,  including  those of AmerenUE,  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 June 30, 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.

                                       23

<PAGE>

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

     AmerenUE,  along with other  subsidiaries  of Ameren,  is 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 OCI 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. The minimum  pension
liability  did not  change at June 30,  2003.  In future  years,  the  liability
recorded, the costs reflected in net income or OCI, or cash contributions to the
plans could increase  materially  without a recovery in equity markets in excess
of our assumed return on plan assets.  If the fair value of the plan assets were
to grow and exceed the accumulated  benefit  obligations in the future, then the
recorded  liability would be reduced and a corresponding  amount of equity would
be restored in the Consolidated Balance Sheet.

     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

                                       24

<PAGE>

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

     The following  summarizes the favorable  (unfavorable)  changes in the fair
value of all  contracts  marked-to-market  during the three and six months ended
June 30, 2003:

<TABLE>
<CAPTION>
==================================================================================================
                                                                                 Three     Six
                                                                                 months   months
--------------------------------------------------------------------------------------------------
<S>                                                                            <C>       <C>
Fair value of contracts at beginning of period, net                              $  5      $  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                                                     (3)       (3)
--------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at end of period, net                        $  3      $  3
==================================================================================================
</TABLE>
<TABLE>
<CAPTION>

     Maturities of contracts as of June 30, 2003 were as follows:

======================================================================================================================
<S>                                               <C>           <C>            <C>          <C>          <C>
                                                    Maturity                                 Maturity
                                                    less than    Maturity 1-3   Maturity     in excess    Total fair
Sources of fair value                               1 year       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)                                           3              1           (1)            -            3
----------------------------------------------------------------------------------------------------------------------
Total                                                $  4          $   -         $ (1)         $  -         $  3
----------------------------------------------------------------------------------------------------------------------
</TABLE>

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


ITEM 4.  Controls and Procedures.

(a)  Evaluation of Disclosure Controls and Procedures

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

(b)  Changes in Internal Control Over Financial Reporting

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

FORWARD-LOOKING STATEMENTS

     Statements made in this report, which are not based on historical facts are
"forward-looking"  and, accordingly,  involve risks and uncertainties that could
cause actual results to differ  materially from those

                                       25

<PAGE>


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;
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;
o    legal and administrative proceedings; and
o    delays in or  difficulties  in connection  with  the receipt  of regulatory
     approvals  with respect to AmerenUE's  plan to  discontinue  operating as a
     public utility subject to ICC regulation and the transferring of AmerenUE's
     Illinois-based   electric  and  natural  gas  businesses   to AmerenCIPS or
     unexpected adverse conditions or terms of those approvals.

     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.

                                       26

<PAGE>


                           PART II. OTHER INFORMATION

ITEM 1.  Legal Proceedings.

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

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

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

     Reference  is  made  to  Note  2 to the  Notes  to  Consolidated  Financial
Statements in our Form 10-Q for the quarterly  period ended March 31, 2003 for a
discussion  of the  Missouri  Supreme  Court's  opinion  issued  in  April  2003
upholding  the  adoption  of  affiliate  rules by the  Missouri  Public  Service
Commission for Missouri's gas and electric utilities. We had originally appealed
the adoption of the  asymmetric  pricing  provisions  contained in the affiliate
rules.  In  May  2003,  the  Missouri   Supreme  Court  denied  our  Motion  for
Reconsideration  of its April 2003  opinion,  which  makes the  affiliate  rules
applicable to us. We do not expect these rules to have a material adverse impact
on our future financial position, cash flows or results of operations.

     Reference is made to Note 14 to the Notes to Financial  Statements  in Item
8.  "Financial  Statements  and  Supplementary  Data"  in  Part  II of our  2002
Consolidated  Annual  Report on Form 10-K,  to Note 7 under  Item 8.  "Financial
Statements and Supplementary  Data" in Part II of the 2002 Annual Report on Form
10-K of our  affiliates,  CILCORP  Inc.  and  Central  Illinois  Light  Company,
operating as AmerenCILCO,  and to Item 1. "Legal  Proceedings" in Part II of our
Form 10-Q for the quarterly  period ended March 31, 2003,  for a discussion of a
number of lawsuits that name our  affiliates,  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 our Form 10-Q for the  quarterly  period ended March 31, 2003,  eleven
additional  lawsuits  have  been  filed  against  the  Ameren  companies.  These
lawsuits,  like the previous  cases,  were mostly filed in the Circuit  Court of
Madison County in Illinois,  involve a large number of total defendants and seek
unspecified  damages  in excess of  $50,000  in each  case,  which,  if  proved,
typically would be shared among the named  defendants.  Also since the filing of
our Form  10-Q for the  quarterly  period  ended  March  31,  2003,  the  Ameren
companies  have  settled  one  case.  To date,  a total of 164  asbestos-related
lawsuits have been filed against the Ameren companies,  of which 84 are pending,
17 have been settled and 63 have been dismissed.  Of these 164 lawsuits, we have
been specifically named as a defendant in 112, of which 53 are pending,  11 have
been settled and 48 have been dismissed. We

                                       27

<PAGE>

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 4.  Submission of Matters To a Vote of Security Holders.

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


                                                                      Non-Voted
     Name                            For              Withheld         Brokers
     ----                            ---              --------        ---------

     Paul A. Agathen             102,612,791           7,806              0
     Warner L. Baxter            102,612,691           7,906              0
     Richard A. Liddy            102,612,406           8,191              0
     Richard A. Lumpkin          102,612,617           7,980              0
     Paul L. Miller, Jr.         102,612,791           7,806              0
     Charles W. Mueller          102,612,791           7,806              0
     Douglas R. Oberhelman       102,612,143           8,454              0
     Gary L. Rainwater           102,612,791           7,806              0
     Harvey Saligman             102,612,707           7,890              0
     Thomas R. Voss              102,612,791           7,806              0
     David A. Whiteley           102,612,791           7,806              0



ITEM 5.  Other Information.

     Reference  is made to Item 2.  "Properties"  in Part I of our  2002  Annual
Report on Form 10-K for a  discussion  of our  membership  in MAIN  (Mid-America
Interconnected  Network),  which  is one of the  regional  electric  reliability
councils  organized for  coordinating the planning and operation of the nation's
bulk power supply.  In response to the withdrawal  notices filed by Commonwealth
Edison and Illinois Power,  also members of MAIN, we, along with our affiliates,
AmerenCIPS and AmerenCILCO,  provided formal written notice to the MAIN Board of
Directors on June 23, 2003 of our intent to withdraw from MAIN effective January
1, 2005. We intend to join another Regional Reliability Organization (RRO) prior
to our  withdrawal  from  MAIN  becoming  effective.  Until  our  withdrawal  is
effective, we will continue to honor all of our obligations as a member of MAIN.
If we do not join  another RRO, we may withdraw our notice of intent to withdraw
from MAIN.

     Any stockholder  proposal  intended for inclusion in the proxy material for
our 2004 annual meeting of  stockholders  must be received by us by November 28,
2003.  In  addition,  under our  By-Laws,  stockholders  who  intend to submit a
proposal in person at an annual meeting, or who intend to nominate a director at
a meeting,  must provide  advance  written  notice  along with other  prescribed
information. In general, such notice must be received by our Secretary not later
than 60 nor  earlier  than 90 days  prior to the  anniversary  of the  preceding
year's annual  meeting.  For our 2004 annual  meeting of  stockholders,  written
notice of any  in-person  stockholder  proposal or director  nomination  must be
received not later than February 22, 2004 or earlier than January 23, 2004.  Our
2004 annual meeting of stockholders is scheduled to be held on April 27, 2004.


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

         (a) Exhibits filed herewith.

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

                                       28

<PAGE>

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

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

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

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

          ======================================================================
                                                  Items             Financial
                   Date of Report                Reported       Statements Filed
          ----------------------------------------------------------------------
                   April 9, 2003                   5, 7               None
                   May 23, 2003                    5, 7               None
                   May 30, 2003                     5                 None


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

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

               Reports of 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:  August 14, 2003

                                       30