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, 2002

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

     For The Transition Period From                            to

                         Commission file number 1-2967.

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

                  Missouri                                   43-0559760
     (State or other jurisdiction of                      (I.R.S. Employer
     incorporation or organization)                      Identification No.)


                 1901 Chouteau Avenue, St. Louis, Missouri 63103
              (Address of principal executive offices and Zip Code)


                         Registrant's telephone number,
                       including area code: (314) 621-3222


     Indicate  by check mark  whether the  registrant  (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days.


                            Yes      X     .       No            .
                                ------------          ------------



Shares  outstanding  of each of the  registrant's  classes of common stock as of
August 9, 2002:
 Common Stock, $5 par value, held by Ameren  Corporation  (parent company of
 registrant) - 102,123,834

<PAGE>

                             UNION ELECTRIC COMPANY

                                      INDEX


                                                                         Page
                                                                         ----

PART I.    Financial Information

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

  ITEM 2.  Management's Discussion and Analysis of Financial Condition
            and Results of Operations...................................  13

  ITEM 3.  Quantitative and Qualitative Disclosures About Market Risk...  21

PART II.            Other Information

  ITEM 1.  Legal Proceedings............................................  24

  ITEM 4.  Submission of Matters to a Vote of Security Holders..........  24

  ITEM 5.  Other Information............................................  24

  ITEM 6.  Exhibits and Reports on Form 8-K.............................  25

SIGNATURE...............................................................  26





                                       1
<PAGE>
<TABLE>
<CAPTION>
PART I.   FINANCIAL INFORMATION

ITEM 1.  Financial Statements

                             UNION ELECTRIC COMPANY
                                  BALANCE SHEET
               (Unaudited, in millions, except per share amounts)
<S>                                                          <C>           <C>
                                                               June 30,     December 31,
                                                                 2002          2001
                                                              ----------   -------------
ASSETS:
Property and plant, at original cost:
   Electric                                                    $ 10,165       $ 9,828
   Gas                                                              259           252
   Other                                                             37            37
                                                              ----------    ------------
                                                                 10,461        10,117
   Less accumulated depreciation and amortization                 4,913         4,802
                                                              ----------    ------------
                                                                  5,548         5,315
Construction work in progress:
   Nuclear fuel in process                                          114            97
   Other                                                            161           298
                                                              ----------    ------------
         Total property and plant, net                            5,823         5,710
                                                              ----------    ------------
Investments and other assets:
   Nuclear decommissioning trust fund                               175           187
   Other                                                             96            75
                                                              ----------    ------------
         Total investments and other assets                         271           262
                                                              ----------    ------------
Current assets:
   Cash and cash equivalents                                          8            15
   Accounts receivable - trade (less allowance for doubtful
         accounts of $9 and $7, respectively)                       180           144
   Unbilled revenue                                                 166            90
   Other accounts and notes receivable                               24            73
   Intercompany notes receivable                                      -            84
   Materials and supplies, at average cost -
      Fossil fuel                                                    62            71
      Other                                                          86            85
   Other                                                             12            16
                                                              ----------    ------------
         Total current assets                                       538           578
                                                              ----------    ------------
Regulatory assets:
   Deferred income taxes                                            579           604
   Other                                                            128           134
                                                              ----------    ------------
         Total regulatory assets                                    707           738
                                                              ----------    ------------
Total Assets                                                    $ 7,339       $ 7,288
                                                              ==========    ============

CAPITAL AND LIABILITIES:
Capitalization:
   Common stock, $5 par value, 150.0 shares authorized -
     102.1 shares outstanding                                  $    511       $   511
   Other paid-in capital, principally premium on common stock       702           702
   Retained earnings                                              1,442         1,440
   Accumulated other comprehensive income                             1             1
                                                              ----------     ------------
      Total common stockholder's equity                           2,656         2,654
                                                              ----------     ------------
   Preferred stock not subject to mandatory redemption              155           155
   Long-term debt                                                 1,599         1,599
                                                              ----------     ------------
         Total capitalization                                     4,410         4,408
                                                              ----------     ------------
Current liabilities:
   Current maturities of long-term debt                              98            92
   Short-term debt                                                    -           186
   Intercompany notes payable                                       260             -
   Accounts and wages payable                                       186           305
   Accumulated deferred income taxes                                 35            35
   Taxes accrued                                                    186           104
   Other                                                            140           128
                                                              ----------     ------------
         Total current liabilities                                  905           850
                                                              ----------     ------------
Accumulated deferred income taxes                                 1,291         1,326
Accumulated deferred investment tax credits                         126           129
Regulatory liabilities                                              138           137
Other deferred credits and liabilities                              469           438
                                                              ----------     ------------
Total Capital and Liabilities                                   $ 7,339       $ 7,288
                                                              ==========     ============

See Notes to Financial Statements.

</TABLE>
                                       2

<PAGE>
<TABLE>
<CAPTION>
                             UNION ELECTRIC COMPANY
                               STATEMENT OF INCOME
                            (Unaudited, in millions)


                                                               Three Months Ended            Six Months Ended
                                                                    June 30,                     June 30,
                                                            ----------------------        --------------------
<S>                                                        <C>            <C>             <C>           <C>
                                                               2002          2001             2002          2001
                                                               ----          ----             ----          ----
OPERATING REVENUES:
   Electric                                                   $ 732         $ 765           $ 1,416       $ 1,362
   Gas                                                           18            18                68            87
                                                             -------       -------         ---------     ---------
      Total operating revenues                                  750           783             1,484         1,449
                                                             -------       -------         ---------     ---------

OPERATING EXPENSES:
   Operations
      Fuel and purchased power                                  210           261               504           480
      Gas                                                        10            11                42            57
      Other                                                     139           133               268           263
                                                             -------       -------         ---------     ---------
                                                                359           405               814           800
   Maintenance                                                   68           101               123           159
   Depreciation and amortization                                 69            70               141           139
   Income taxes                                                  53            48                81            79
   Other taxes                                                   55            53               107           103
                                                             -------       -------         ---------     ---------
      Total operating expenses                                  604           677             1,266         1,280
                                                             -------       -------         ---------     ---------

OPERATING INCOME                                                146           106               218           169

OTHER INCOME AND (DEDUCTIONS):
   Allowance for equity funds used during construction            1             3                 2             4
   Miscellaneous, net -
     Miscellaneous income                                        17             4                23            17
     Miscellaneous expense                                       29)           (3)              (31)           (7)
     Income taxes                                                (1)            1                (2)           (1)
                                                             -------       -------         ---------     ---------
      Total other income and (deductions)                       (12)            5                (8)           13
                                                             -------       -------         ---------     ---------

INTEREST CHARGES:
   Interest                                                      27            31                54            61
   Allowance for borrowed funds used during construction          -            (2)               (2)           (4)
                                                             -------       -------         ---------     ---------
      Net interest charges                                       27            29                52            57
                                                             -------       -------         ---------     ---------

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
      ACCOUNTING PRINCIPLE                                      107            82               158           125

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

NET INCOME                                                      107            82               158           120

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

NET INCOME AFTER PREFERRED STOCK DIVIDENDS                    $ 105          $ 80             $ 154         $ 116
                                                             =======       =======         =========     =========

See Notes to Financial Statements.

</TABLE>




                                       3


<PAGE>
<TABLE>
<CAPTION>

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

                                                                                 Six Months Ended
                                                                                     June 30,
                                                                             -------------------------
<S>                                                                           <C>            <C>
                                                                                2002           2001
                                                                                ----           ----

Cash Flows From Operating:
   Net income                                                                  $ 158          $ 120
   Adjustments to reconcile net income to net cash
       provided by operating activities:
         Cumulative effect of change in accounting principle                       -              5
         Depreciation and amortization                                           141            139
         Amortization of nuclear fuel                                             16             12
         Amortization of debt issuance costs and premium/discounts                 2              2
         Allowance for funds used during construction                             (4)            (8)
         Deferred income taxes, net                                               (9)            15
         Deferred investment tax credits, net                                     (3)            (1)
         Other                                                                     -             (4)
         Changes in assets and liabilities:
               Receivables, net                                                  (63)           (48)
               Materials and supplies                                              8            (17)
               Accounts and wages payable                                       (119)           (29)
               Taxes accrued                                                      82             81
               Assets, other                                                      (9)            (8)
               Liabilities, other                                                 43            (34)
                                                                             ---------       ---------
Net cash provided by operating activities                                        243            225
                                                                             ---------       ---------

Cash Flows From Investing:
   Construction expenditures                                                    (246)          (253)
   Allowance for funds used during construction                                    4              8
   Nuclear fuel expenditures                                                     (16)           (12)
   Intercompany notes receivable                                                  84             78
                                                                             ---------       ---------
Net cash used in investing activities                                           (174)          (179)
                                                                             ---------       ---------

Cash Flows From Financing:
   Dividends on common stock                                                    (152)          (141)
   Dividends on preferred stock                                                   (4)            (4)
   Redemptions:
      Nuclear fuel lease                                                           -            (64)
      Short-term debt                                                           (186)             -
   Issuances:
      Nuclear fuel lease                                                           6              2
      Long-term debt                                                               -            146
      Intercompany notes payable                                                 260              -
                                                                             ---------       ---------
Net cash used in financing activities                                            (76)           (61)
                                                                             ---------       ---------

Net change in cash and cash equivalents                                           (7)           (15)
Cash and cash equivalents at beginning of year                                    15             20
                                                                             ---------       ---------
Cash and cash equivalents at end of period                                     $   8          $   5
                                                                             =========       =========

Cash paid during the periods:
   Interest                                                                     $ 48            $ 53
   Income taxes, net                                                              63              31

See Notes to Financial Statements.

</TABLE>

                                       4

<PAGE>
<TABLE>
<CAPTION>

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


                                                                                 Three Months Ended            Six Months Ended
                                                                                       June 30,                      June 30,
                                                                            ----------------------------     -----------------------
<S>                                                                         <C>             <C>             <C>           <C>
                                                                                  2002           2001          2002           2001
                                                                                  ----           ----          ----           ----

Common stock                                                                     $ 511            $ 511        $ 511         $ 511


Other paid-in capital                                                              702              702          702           702

Retained earnings
   Beginning balance                                                             1,413            1,340        1,440         1,358
   Net income                                                                      107               82          158           120
   Common stock dividends                                                          (76)             (87)        (152)         (141)
   Preferred stock dividends                                                        (2)              (2)          (4)           (4)
                                                                            -----------      -----------     ----------    ---------
                                                                                 1,442            1,333        1,442         1,333
                                                                            -----------      -----------     ----------    ---------

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


Total common stockholder's equity                                              $ 2,656          $ 2,542       $2,656         2,542
                                                                            ===========      ===========     ==========    =========


Comprehensive income, net of taxes
   Net income                                                                    $ 107             $ 82       $  158         $ 120
   Unrealized net gain/(loss) on derivative hedging instruments
        (net of income taxes of $1, $(2), $1 and $(1), respectively)                 1               (3)           2            (2)
   Reclassification adjustments for gains/(losses) included in net income
        (net of income taxes of $ -, $1, $(1) and $4, respectively)                  1                1           (2)            6
   Cumulative effect of accounting change, net of income taxes of $(5)               -                -            -            (8)
                                                                            -----------      -----------     ----------    ---------
           Total comprehensive income, net of taxes                              $ 109             $ 80       $  158         $ 116
                                                                            ===========      ===========     ==========    =========

See Notes to Financial Statements.

</TABLE>


                                       5

<PAGE>



UNION ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
June 30, 2002

NOTE 1 - Summary of Significant Accounting Policies

Basis of Presentation

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

     When we  refer  to  AmerenUE,  our,  we or us,  we are  referring  to Union
Electric  Company.  All  dollar  amounts  are  in  millions,   unless  otherwise
indicated.

Accounting Changes

     In January 2001,  we adopted  Statement of Financial  Accounting  Standards
(SFAS) No. 133, "Accounting for Derivative  Instruments and Hedging Activities."
The impact of that adoption resulted in a cumulative effect charge of $5 million
after taxes to the income  statement,  and a cumulative  effect adjustment of $8
million,  after taxes, to Accumulated Other  Comprehensive  Income (OCI),  which
reduced common stockholder's equity.

     On January 1, 2002, we adopted SFAS No. 141,  "Business  Combinations," and
SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS 141 requires business
combinations to be accounted for under the purchase method of accounting,  which
requires  one  party  in the  transaction  to be  identified  as  the  acquiring
enterprise  and for that party to allocate the purchase  price to the assets and
liabilities  of the acquired  enterprise  based on fair market  value.  SFAS 142
requires  goodwill  and  indefinite-lived  intangible  assets  recorded  in  the
financial statements to be tested for impairment at least annually,  rather than
amortized over a fixed period,  with  impairment  losses  recorded in the income
statement.  SFAS  141 and SFAS 142 did not  have  any  effect  on our  financial
position,  results  of  operations  or  liquidity  upon  adoption.  See Note 6 -
"CILCORP Acquisition."

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

     On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived  Assets." SFAS 144 addresses the financial  accounting
and reporting for the impairment or disposal of long-lived assets and supersedes
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of." SFAS 144 retains the guidance  related to calculating
and  recording  impairment  losses,  but adds  guidance  on the  accounting  for
discontinued  operations,  previously accounted for under Accounting  Principles
Board Opinion No. 30. We evaluate  long-lived  assets for impairment when events
or changes in circumstances  indicate that the carrying value of such assets may
not be  recoverable.  The  determination  of whether  impairment has occurred is
based on an estimate of undiscounted  cash flows  attributable to the assets, as
compared with the carrying value of the assets. If impairment has occurred,  the
amount of the  impairment  recognized is determined by estimating the fair value
of the  assets and  recording  a  provision  for loss if the  carrying  value is
greater than the fair value.  SFAS 144 did not have any effect on our  financial
position, results of operations or liquidity upon adoption.

     Historically,  our  accounting  practice was to present all settled  energy
purchase or sale contracts  within our power risk management  program on a gross
basis in Operating  Revenues - Electric and in Operating Expenses - Operations -
Fuel and Purchased Power in our income statement.  This means that revenues were
recorded  for  the  notional   amount  of  the  power  sale   contracts  with  a
corresponding  charge  to  income  for the  cost of the  energy  that  has  been
generated  or for the notional  amount of a purchased  power  contract.  In June
2002,  the  Emerging  Issues Task Force (or EITF)  reached a consensus  in Issue
02-03,  "Accounting

                                       6

<PAGE>


for Contracts  Involved in Energy Trading and Risk Management  Activities," that
certain energy contracts should be shown on a net basis in the income statement.
The consensus on this issue is applicable  to financial  statements  for periods
ending after July 15, 2002,  with a requirement to conform prior periods to this
presentation.  As a result of the EITF's  accounting  guidance and other factors
that exist within our industry,  beginning with the period ending  September 30,
2002, we will change our accounting  practice to present,  on a net basis in our
income  statement,  all contracts within our power risk management  program that
have been net settled.  All prior periods included in our prospective  financial
statements will be  reclassified to reflect this change in accounting  practice.
We are still in the  process  of  evaluating  the  impact of this  change to our
income  statement,  but our revenues and  operating  expenses will be reduced in
future  periods  with  no  impact  on our  earnings.  See  Note 4 -  "Derivative
Financial Instruments" for more information.

Interchange Revenues

     Interchange  revenues  included in Operating  Revenues - Electric were $140
million for the three months ended June 30, 2002 (2001 - $161  million) and $369
million for the six months ended June 30, 2002 (2001 - $324 million).

Purchased Power

     Purchased  power  included in  Operating  Expenses,  Operations  - Fuel and
Purchased  Power was $131 million for the three months ended June 30, 2002 (2001
- $184  million) and $346 million for the six months ended June 30, 2002 (2001 -
$310 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 applicable to Illinois  electric  customer bills are imposed on the
consumer and are recorded as tax collections  payable.  Excise taxes recorded in
Operating Revenues and Other Taxes for the three months ended June 30, 2002 were
$28 million (2001 - $25 million) and $49 million for the six-month  period ended
June 30, 2002 (2001 - $46 million).


NOTE 2 - Rate and Regulatory Matters

Missouri Electric

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

     On July 16, 2002,  AmerenUE,  the MoPSC Staff, and all of the other parties
to the proceeding  submitted to the MoPSC a stipulation and agreement  resolving
this case.  On July 24, 2002,  the MoPSC held a hearing on the  stipulation  and
agreement.  On July 25, 2002, the MoPSC approved the  stipulation and agreement,
and on August 4,  2002,  it became  effective.  The  stipulation  and  agreement
includes the following principal features:

     o    the phase-in of $110 million of electric rate reductions through April
          2004, $50 million of which is  retroactively  effective as of April 1,
          2002, $30 million of which will become effective on April 1, 2003, and
          $30 million of which will become effective on April 1, 2004,
     o    a  rate  moratorium  providing  for no  requests  for  changes  in our
          electric rates as established by the stipulation and agreement  before
          January  1, 2006 and no  resulting  changes in rates  before  June 30,
          2006, subject to certain statutory and other exceptions,

                                       7

<PAGE>

     o    a commitment to contribute, as early as September 2002, $14 million to
          programs  for  low  income  energy   assistance  and   weatherization,
          promotion of energy efficiency and economic development in our service
          territory,  with  additional  payments of $3 million made  annually on
          June 30, 2003 through June 30, 2006,
     o    a commitment to make $2.25 billion to $2.75 billion in critical energy
          infrastructure investments from January 1, 2002 through June 30, 2006,
          including, among other things, the addition of more than 700 megawatts
          of new generation  capacity and the replacement of steam generators at
          our nuclear power plant. The 700 megawatts of new generation  includes
          240 megawatts  already added this year and may include the transfer at
          book  value  to  us  of  generation   assets  from  our  non-regulated
          affiliates.  The amount of energy  infrastructure  investments through
          June 2006  described in the  stipulation  and  agreement is consistent
          with   our   previously-disclosed   estimate   of   the   construction
          expenditures we expect to make over the same time period,
     o    an  annual  reduction  in  our  depreciation  rates  by  $20  million,
          retroactive  to April 1, 2002,  based on an updated  analysis of asset
          values, service lives and accumulated depreciation levels, and
     o    a one-time  credit of $40  million to be paid to our  Missouri  retail
          electric customers as early as August 2002 for settlement of the final
          sharing period under the alternative regulation plan that expired June
          30,  2001.  At June 30,  2002,  we had  accrued $40 million in Current
          Liabilities - Other.

     In total,  the  stipulation  and  agreement is estimated to reduce 2002 net
earnings by $32 million.  Net earnings are expected to be reduced in 2002 due to
the rate  reduction  ($26 million,  net of taxes,  including $8 million,  net of
taxes, in the quarter ended June 30,  2002),  the expensing in the quarter ended
June 30, 2002 of the entire  obligation  to fund certain  programs ($15 million,
net of taxes),  offset,  in part, by the reduction in  depreciation  expense ($9
million,  net of taxes, including $3 million, net of taxes, in the quarter ended
June 30,  2002).  Net earnings  were reduced by $20 million in the quarter ended
June 30, 2002 due to the  stipulation  and agreement.  We expect  earnings to be
reduced by $9 million in the third  quarter of 2002 and $3 million in the fourth
quarter of 2002.

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

     In May 2001,  the MoPSC filed a complaint  with the Securities and Exchange
Commission  (SEC) relating to the 2001 Marketing  Company - AmerenUE  agreement.
The  complaint  requested an  investigation  into the  contractual  relationship
between  AmerenUE,   Marketing  Company  and  AmerenEnergy   Generating  Company
(Generating Company),  also our affiliate,  in the context of the 2001 Marketing
Company  -  AmerenUE  agreement  and  requests  that  the  SEC  find  that  such
relationship  violates a provision of the Public Utility  Holding Company Act of
1935 (or PUHCA), which requires state utility commission approval of power sales
contracts  between  an  electric  utility  company  and an  affiliated  electric
wholesale  generator,  like  Generating  Company.  We believe  that the  MoPSC's
approval  of the power  sales  agreement  under  PUHCA is not  required  because
Generating  Company  is not a party to the  agreement.  As a  remedy,  the MoPSC
proposes that the SEC require us to contract  directly with  Generating  Company
and submit  such  contract to the MoPSC for  review.  On May 9, 2002,  the MoPSC
filed a similar  complaint with the SEC relating to the 2002 Marketing Company -
AmerenUE agreement.  The SEC is investigating these matters.  Also, with respect
to the 2002 Marketing Company - AmerenUE agreement, on May 31, 2002, the Federal
Energy Regulatory  Commission (FERC) accepted the agreement,  subject to refund,
and   scheduled   the  matter  for  a  January   2003   hearing  to  assess  the
appropriateness  of the rates  charged.  At this time,  management  is unable to
predict the outcome of these  proceedings  or the ultimate  impact on our future
financial position, results of operations or liquidity.

Illinois

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

                                       8

<PAGE>

     The Illinois Law contained a provision  freezing  retail  bundled  electric
rates through  January 1, 2005. In 2002,  legislation was passed and signed into
law that extended the rate freeze period  through  January 1, 2007. The offering
of choice to our  industrial  and  commercial  customers  has not had a material
adverse  effect on our  business  and we do not expect the offering of choice to
our  residential  customers,  or the  extension  of the rate  freeze,  to have a
material adverse effect on our business.

Federal - Regional Transmission Organizations

     In December  1999,  the FERC issued Order 2000,  requiring  all  utilities,
subject to FERC  jurisdiction,  to state their intentions for joining a regional
transmission  organization  (RTO). RTOs are independent  organizations that will
functionally  control the  transmission  assets of utilities in order to improve
the  wholesale  power market.  Since January 2001,  we, along with several other
utilities, were seeking approval from the FERC to participate in an RTO known as
the Alliance  RTO. We had  previously  been a member of the Midwest  Independent
System  Operator  (MISO) and recorded a pretax charge to earnings in 2000 of $17
million ($10  million  after taxes) for an exit fee and other costs when we left
that  organization.  We felt the  for-profit  Alliance  RTO  business  model was
superior to the  not-for-profit  MISO business model and provided us with a more
equitable return on our transmission assets.

     In late 2001,  the FERC issued an order that  rejected the formation of the
Alliance RTO and ordered the Alliance RTO  companies and the MISO to discuss how
the Alliance RTO business model could be accommodated  within the MISO. On April
25,  2002,  after the Alliance  RTO and MISO failed to reach an  agreement,  and
after a series of filings by the two  parties  with the FERC,  the FERC issued a
declaratory  order  setting forth the division of  responsibilities  between the
MISO and National Grid (the managing member of the  transmission  company formed
by the  Alliance  companies)  and  approved  the  rate  design  and the  revenue
distribution  methodology proposed by the Alliance companies.  However, the FERC
denied a request by the Alliance  companies  and the  National  Grid to purchase
certain  services  from the MISO at  incremental  cost  rather  than MISO's full
tariff  rates.  The FERC also  ordered  the MISO to return  the exit fee paid by
AmerenUE to leave the MISO,  provided AmerenUE returns to the MISO and agrees to
pay its proportional  share of the startup and ongoing  operational  expenses of
the MISO.  Moreover,  the FERC required the Alliance companies to select the RTO
in which they will participate within thirty days of the order.

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

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


NOTE 3 - Related Party Transactions

     AmerenUE has transactions in the normal course of business with its parent,
Ameren Corporation (Ameren), and its other subsidiaries.  These transactions are
primarily  comprised of power  purchases  and

                                       9

<PAGE>

sales,  as well as other  services  received  or  rendered.  Intercompany  power
purchases  from joint  dispatch  and other  agreements  were  approximately  $23
million for the three  months  ended June 30, 2002 (2001 - $21  million) and $50
million  for  the  six  months  ended  June  30,  2002  (2001  -  $44  million).
Intercompany power sales totaled $17 million for the three months ended June 30,
2002 (2001 - $12 million) and $37 million for the six months ended June 30, 2002
(2001 - $40 million).

     Support  services  provided by our affiliates,  Ameren Services Company and
AmerenEnergy, Inc., including wages, employee benefits and professional services
are based on actual  costs  incurred.  For the three months ended June 30, 2002,
Other Operating  Expenses  provided by Ameren Services and AmerenEnergy  totaled
$48 million  (2001 - $43 million)  and $96 million  (2001 - $90 million) for the
six months ended June 30, 2002.

     We have the  ability  to  borrow  from  Ameren  and  AmerenCIPS  through  a
regulated money pool agreement.  Ameren Services administers the regulated money
pool and tracks  internal  and external  funds  separately.  Internal  funds are
surplus  funds  contributed  to the money pool from  participants.  The  primary
source of external funds for the regulated  money pool at June 30, 2002  was our
commercial paper program,  which was backed by bank credit  agreements  totaling
$430  million.  The total  amount  available  to us at any  given  time from the
regulated  money pool is reduced by the amount of borrowings by our  affiliates,
but increased to the extent Ameren,  AmerenCIPS or Ameren  Services have surplus
funds and the availability of other external borrowing sources. The availability
of funds is also determined by funding  requirement limits established by PUHCA.
AmerenUE,  AmerenCIPS  and Ameren  Services rely on the regulated  money pool to
coordinate  and  provide  for  certain   short-term  cash  and  working  capital
requirements.  Borrowers  receiving  a  loan  under  the  regulated  money  pool
agreement  must repay the principal  amount of such loan,  together with accrued
interest.  Interest is calculated at varying rates of interest  depending on the
composition of internal and external funds in the regulated  money pool. For the
three months ended June 30, 2002,  the average  interest  rate for the regulated
money pool was 1.75%  (2001 - 4.38%) and for the six months  ended June 30, 2002
was 1.77% (2001 - 4.94%).  As of June 30, 2002,  we had the ability to borrow up
to $425 million,  all of which was unused and  available,  through the regulated
money pool,  which was in addition to amounts  available  under our $430 million
commercial  paper  program.  At June 30, 2002, we had  outstanding  intercompany
payables of $260 million,  sourced by internal  funds through the money pool. At
December 31, 2001, we had  outstanding  intercompany  receivables of $84 million
through the money pool.

     In July 2002, Ameren entered into new credit agreements for $400 million in
revolving credit facilities to be used for general corporate purposes, including
support  of  commercial  paper  programs.  The $400  million  in new  facilities
includes a $270 million  364-day  revolving  credit  facility and a $130 million
3-year  revolving  credit  facility.  The  3-year  facility  has a  $50  million
sub-limit  for the  issuance of letters of credit.  These new credit  facilities
replaced our existing $300 million  revolving  credit facility that was in place
as of June 30,  2002 with a maturity of August 15,  2002.  There were no amounts
outstanding  under this facility at June 30, 2002. In July 2002, we also did not
renew a $25 million  committed  line of credit.  As a result of these changes in
facilities,  at July 31, 2002,  we had the ability to borrow up to $500 million,
all of which was unused and available,  from Ameren through our regulated  money
pool agreement.

     Intercompany  receivables  included in Other Accounts and Notes  Receivable
were  approximately  $15  million as of June 30, 2002  (December  31, 2001 - $38
million).  Intercompany  payables included in Accounts and Wages Payable totaled
approximately $50 million as of June 30, 2002 (December 31, 2001 - $70 million).


NOTE 4 - Derivative Financial Instruments

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

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

                                       10

<PAGE>

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

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

     As of June 30,  2002,  we recorded the fair value of  derivative  financial
instrument  assets  of $21  million  in  Other  Assets  and the  fair  value  of
derivative  financial  instrument  liabilities  of $19 million in Other Deferred
Credits and Liabilities.

Cash Flow Hedges

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

     For the three  months  ended  June 30,  2002,  the pretax net loss on power
forward  derivative  instruments,  which  represented the impact of discontinued
cash flow hedges,  the ineffective  portion of cash flow hedges,  as well as the
reversal  of amounts  previously  recorded in OCI due to  transactions  going to
delivery  or  settlement,  was  approximately  $1  million.  The loss from these
transactions for the three months in the prior year was immaterial.  For the six
months ended June 30, 2002, the second quarter loss on power forward  derivative
instruments  offset the gain of $1 million from the first quarter.  In the prior
year six-month period, we recognized a pretax net gain of $6 million.

     As of June 30, 2002, we had hedged a portion of the price exposure  related
to the relative  balance  between load and economic  generation for the upcoming
twelve-month  period.  The  mark-to-market  value  accumulated  in OCI  for  the
effective  portion  of hedges of  electricity  price  exposure  is a net loss of
approximately $4 million ($2 million, net of taxes).

     We also hold a call  option for coal  deliverable  in 2004 with a supplier.
This option to purchase coal expires in October  2003. As of June 30, 2002,  the
mark-to-market value accumulated in OCI is a gain of $5 million ($3 million, net
of taxes).  The final value of the option will be  recognized  as a reduction in
fuel costs as the hedged coal is burned.

Other Derivatives

     We enter into option transactions to manage our positions in sulfur dioxide
allowances,  coal, heating oil, and electricity.  Most of these transactions are
treated as non-hedge  transactions  under SFAS 133. The net change in the market
value of sulfur  dioxide  options is recorded as  Operating  Revenues - Electric
Revenues,  while the net change in the market  value of coal,  heating  oil, and
electricity  options is recorded as  Operating  Expense -  Operations - Fuel and
Purchased Power in the income statement.  The net change in the market values of
sulfur dioxide options, coal, heating oil, and electricity options was a gain of
$2 million for the three  months  ended June 30, 2002 and $3 million for the six
months  ended  June 30,  2002.

                                       11

<PAGE>

  The  change in market  values in the prior  year
resulted in losses of $2 million for the  three-month  period and $4 million for
the six-month period.


NOTE 5 - Miscellaneous, Net

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

<TABLE>
------------------------------------------------------ --------------------- ---------------------
                                                           Three Months           Six Months
------------------------------------------------------ --------------------- ---------------------
<S>                                                     <C>        <C>        <C>        <C>
                                                         2002       2001       2002       2001
                                                         ----       ----       ----       ----
Miscellaneous income:
   Interest and dividend income                          $  2       $  2       $  2       $  6
   Equity in earnings of subsidiary                        10          1         11          2
   Gain on disposition of property and other assets         5          -          8          8
   Other                                                    -          1          2          1
--------------------------------------------------------------------------------------------------
Total miscellaneous income                               $ 17       $  4       $ 23       $ 17
--------------------------------------------------------------------------------------------------

Miscellaneous expense:
   Plant acquisition amortization                        $  -       $  -       $ (1)      $ (1)
   Loss on disposition of property and other assets        (1)        (2)         -         (4)
   Donations - rate settlement                            (26)         -        (26)         -
   Other                                                   (2)        (1)        (4)        (2)
--------------------------------------------------------------------------------------------------
Total miscellaneous expense                              $(29)      $ (3)      $(31)      $ (7)
--------------------------------------------------------------------------------------------------
</TABLE>


NOTE 6 - CILCORP Acquisition

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

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

     Upon  completion  of the  acquisition,  expected by March 2003,  CILCO will
become  an  Ameren  subsidiary,  but will  remain a  separate  utility  company,
operating  as  AmerenCILCO.  The  transaction  is subject to the approval of the
Illinois Commerce  Commission,  the SEC, the FERC, the expiration of the waiting
period under the Hart-Scott-Rodino  Act, the Federal  Communications  Commission
and other customary closing conditions.

     For the period  ended  December  31,  2001,  CILCORP  had  revenues of $815
million,  operating  income of $126  million,  and net  income  from  continuing
operations of $28 million,  and as of December 31, 2001 had total assets of $1.8
billion.

                                       12

<PAGE>

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

OVERVIEW

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

     o    Central  Illinois Public Service  Company,  which operates a regulated
          electric and natural gas  transmission  and  distribution  business in
          Illinois as AmerenCIPS.
     o    AmerenEnergy Resources Company (Resources Company),  which consists of
          non-regulated operations. Subsidiaries include AmerenEnergy Generating
          Company  (Generating  Company)  that operates  non-regulated  electric
          generation in Missouri and Illinois,  AmerenEnergy  Marketing  Company
          (Marketing Company) which markets power for periods over one year, and
          AmerenEnergy  Fuels and  Services  Company,  which  procures  fuel and
          manages the related risks for Ameren affiliated companies.
     o    AmerenEnergy,  Inc.  which  serves  as  a  power  marketing  and  risk
          management agent for Ameren  affiliated  companies for transactions of
          primarily less than one year.
     o    Electric  Energy,  Inc.  (EEI),  which owns and/or  operates  electric
          generation  and  transmission  facilities  in Illinois.  We have a 40%
          ownership  interest in EEI and have  accounted for it under the equity
          method of accounting.  Our affiliate,  Resources Company,  also owns a
          20% interest.
     o    Ameren Services  Company,  which provides  shared support  services to
          Ameren and its subsidiaries,  including us. Charges are based upon the
          actual costs incurred by Ameren Services, as required by PUHCA.

          You should read the following  discussion  and analysis in conjunction
          with:
     o    The financial  statements and related notes included in this Quarterly
          Report on Form 10-Q.
     o    The audited  financial  statements and related notes that are included
          in our Annual  Report on Form 10-K for the period  ended  December 31,
          2001.
     o    Management's  Discussion  and  Analysis  of  Financial  Condition  and
          Results of  Operations  that appears in our Annual Report on Form 10-K
          for the period ended December 31, 2001.

          When we refer to  AmerenUE,  our, we or us, we are  referring to Union
     Electric  Company.  All dollar  amounts are in millions,  unless  otherwise
     indicated.

          Our results of operations and financial  position are impacted by many
     factors,  including both controllable and uncontrollable factors.  Weather,
     economic  conditions,  and the actions of key customers or competitors  can
     significantly  impact the demand for our  services.  Our  results  are also
     impacted  by seasonal  fluctuations  caused by winter  heating,  and summer
     cooling,  demand.  With nearly all of our revenues subject to regulation by
     various  state and federal  agencies,  decisions by  regulators  can have a
     material  impact on the price we charge for our  services.  We  principally
     utilize coal,  nuclear fuel and natural gas in our  operations.  The prices
     for these commodities can fluctuate significantly due to the world economic
     and  political  environment,  weather,  production  levels  and many  other
     factors.  We do not have fuel recovery mechanisms in Missouri and Illinois,
     but do have gas cost recovery  mechanisms in each state.  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.



                                       13


<PAGE>


RESULTS OF OPERATIONS

Summary

     Our net income increased 30% to $107 million in the second quarter of 2002,
from $82  million in the second  quarter  of 2001.  Earnings  for the six months
ended June 30,  2002,  were $158  million,  an increase of $38 million  from the
first six months of 2001.  The  increase in both  periods was  primarily  due to
favorable weather  conditions  (second quarter - $11 million;  year to date - $6
million),  increased sales of emission credits,  including EEI (second quarter -
$9  million;  year to date - $17  million),  and the lack of a Callaway  nuclear
plant refueling  outage to date in 2002 (second  quarter - $16 million;  year to
date - $19 million).  These increases were partially offset by the impact of the
settlement of our Missouri electric rate case (second quarter and year to date -
$20 million) (see below) and a reduction of an accrual in 2001 (second quarter -
$15 million;  year to date - $6 million) for expected  customer  sharing credits
under the Missouri experimental alternative regulation plan that expired in June
2001 (see Note 2 - "Rate and Regulatory  Matters" to our financial  statements).
In January  2001, we also recorded a charge of $5 million due to the adoption of
Statement of Financial  Accounting  Standards  (SFAS) No. 133,  "Accounting  for
Derivative Instruments and Hedging Activities."


Recent Developments

Missouri Electric Rate Case

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

     On July 16, 2002,  AmerenUE,  the MoPSC Staff, and all of the other parties
to the proceeding  submitted to the MoPSC a stipulation and agreement  resolving
this case.  On July 24, 2002,  the MoPSC held a hearing on the  stipulation  and
agreement.  On July 25, 2002, the MoPSC approved the  stipulation and agreement,
and on August 4,  2002,  it became  effective.  The  stipulation  and  agreement
includes the following principal features:

     o    the phase-in of $110 million of electric rate reductions through April
          2004, $50 million of which is  retroactively  effective as of April 1,
          2002, $30 million of which will become effective on April 1, 2003, and
          $30 million of which will become effective on April 1, 2004,
     o    a  rate  moratorium  providing  for no  requests  for  changes  in our
          electric rates as established by the stipulation and agreement  before
          January  1, 2006 and no  resulting  changes in rates  before  June 30,
          2006, subject to certain statutory and other exceptions,
     o    a commitment to contribute, as early as September 2002, $14 million to
          programs  for  low  income  energy   assistance  and   weatherization,
          promotion of energy efficiency and economic development in our service
          territory,  with  additional  payments of $3 million made  annually on
          June 30, 2003 through June 30, 2006,
     o    a commitment to make $2.25 billion to $2.75 billion in critical energy
          infrastructure investments from January 1, 2002 through June 30, 2006,
          including, among other things, the addition of more than 700 megawatts
          of new generation  capacity and the replacement of steam generators at
          our nuclear power plant. The 700 megawatts of new generation  includes
          240 megawatts  already added this year and may include the transfer at
          book  value  to  us  of  generation   assets  from  our  non-regulated
          affiliates.  The amount of energy  infrastructure  investments through
          June 2006  described in the  stipulation  and  agreement is consistent
          with   our   previously-disclosed   estimate   of   the   construction
          expenditures we expect to make over the same time period,

                                       14

<PAGE>

     o    an  annual  reduction  in  our  depreciation  rates  by  $20  million,
          retroactive  to April 1, 2002,  based on an updated  analysis of asset
          values, service lives and accumulated depreciation levels, and
     o    a one-time  credit of $40  million to be paid to our  Missouri  retail
          electric customers as early as August 2002 for settlement of the final
          sharing period under the alternative regulation plan that expired June
          30,  2001.  At June 30,  2002,  we had  accrued $40 million in Current
          Liabilities - Other.

     In total,  the  stipulation  and  agreement is estimated to reduce 2002 net
earnings by $32 million.  Net earnings are expected to be reduced in 2002 due to
the rate  reduction  ($26 million,  net of taxes,  including $8 million,  net of
taxes, in the quarter  ended June 30, 2002),  the expensing in the quarter ended
June 30, 2002 of the entire  obligation  to fund certain  programs ($15 million,
net of taxes),  offset,  in part, by the reduction in  depreciation  expense ($9
million,  net of taxes, including $3 million, net of taxes, in the quarter ended
June 30,  2002).  Net earnings  were reduced by $20 million in the quarter ended
June 30, 2002 due to the  stipulation  and agreement.  We expect  earnings to be
reduced by $9 million in the third  quarter of 2002 and $3 million in the fourth
quarter of 2002.

CILCORP Acquisition

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

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

     Upon  completion  of the  acquisition,  expected by March 2003,  CILCO will
become  an  Ameren  subsidiary,  but will  remain a  separate  utility  company,
operating  as  AmerenCILCO.  The  transaction  is subject to the approval of the
Illinois Commerce Commission,  the Securities and Exchange Commission (SEC), the
Federal  Energy  Regulatory  Commission  (FERC),  the  expiration of the waiting
period under the Hart-Scott-Rodino  Act, the Federal  Communications  Commission
and other customary closing conditions.

     For the period  ended  December  31,  2001,  CILCORP  had  revenues of $815
million,  operating  income of $126  million,  and net  income  from  continuing
operations of $28 million,  and as of December 31, 2001 had total assets of $1.8
billion.

     In April 2002, as a result of our then pending Missouri  electric  earnings
complaint  case and the  CILCORP  transaction  and related  assumption  of debt,
credit  rating  agencies  placed  Ameren  Corporation's  debt  under  review for
possible  downgrade  or  negative  credit  watch.  Standard & Poor's  placed the
ratings of AmerenUE and AmerenCIPS  debt on negative credit watch and placed the
ratings of Generating Company's debt on positive credit watch. However, Standard
& Poor's  stated  they  expect the  corporate  credit  ratings of Ameren and its
subsidiaries  to be in the  "A"  rating  category  following  completion  of the
acquisition.  Moody's  Investor  Service  stated  they  envisioned  a one  notch
downgrade  of  Ameren's  issuer,  senior  unsecured  debt and  commercial  paper
ratings.  Ameren's  corporate  credit  rating is A+ at Standard & Poor's and its
issuer rating is A2 at Moody's,  while AmerenUE's  corporate credit rating is A+
at Standard & Poor's and its issuer rating is A1 at Moody's.  In July,  AmerenUE
settled its electric  earnings  complaint  case.  The rating  agencies  have not
changed the  assignment  of negative  watch,  review for  possible  downgrade or
negative outlook to any of the ratings nor have the ratings themselves  changed.
Any  adverse  change in the Ameren  companies'  ratings may reduce our access to
capital and/or  increase the costs of borrowings  resulting in a negative impact
on earnings.



                                       15

<PAGE>
<TABLE>
<CAPTION>
Electric Operations

     The following table  represents the favorable  (unfavorable)  variation for
the three and six-month periods ended June 30, 2002 from the comparable  periods
in 2001:

----------------------------------------------------------------------------------------------------
                                                          Three Months            Six Months
----------------------------------------------------------------------------------------------------
<S>                                                      <C>                   <C>
Operating Revenues:
   Effect of abnormal weather (estimate)............      $    22               $     10
   Growth and other (estimate)......................            4                     22
   Rate reductions                                            (13)                   (13)
   Credit to customers..............................          (25)                   (10)
   Interchange revenues.............................          (21)                    45
----------------------------------------------------------------------------------------------------
                                                              (33)                    54
Fuel and Purchased Power:
   Fuel:
     Generation.....................................       $  (14)              $     (6)
     Price..........................................           12                     18
   Purchased power .................................           53                    (36)
----------------------------------------------------------------------------------------------------
                                                               51                    (24)
----------------------------------------------------------------------------------------------------
Change in electric margin                                  $   18               $     30
----------------------------------------------------------------------------------------------------
</TABLE>
     Electric margin  increased $18 million for the three months and $30 million
for the six months  ended June 30,  2002,  compared  to the prior year  periods.
Favorable  weather  conditions  resulted  in an  increase  in  weather-sensitive
residential and commercial  kilowatt-hour sales of 9% for the three-month period
over the year-ago quarter. Revenues were reduced by $13 million in the three and
six months ended June 30, 2002 due to the  settlement  of the Missouri  electric
rate case. Revenues in 2001 were increased by $25 million in the second quarter,
and $10 million in the first six months,  due to a reduction  in the accrual for
expected  customer sharing credits under the Missouri  experimental  alternative
regulation plan that expired in June 2001.  During the first six months of 2002,
we also  experienced  growth in electric  revenues  due to the  expansion of our
weather-normalized native load and sales of sulfur dioxide allowances.  Although
interchange  sales decreased in the quarter,  the effect on margin was more than
offset by a resulting  decrease in  purchased  power.  Purchased  power was also
reduced  in the second  quarter  of 2002 due to the lack of a  Callaway  nuclear
plant  refueling.  Another  refueling  outage at Callaway is scheduled this Fall
which is estimated to reduce net earnings by $14 million  through an increase in
purchased power and maintenance  expenses.  For the six-month period, the impact
on margin of the favorable  second  quarter  weather was somewhat  offset by the
milder  weather  conditions  experienced  in the first  quarter.  Total electric
kilowatt-hour  sales  increased  for the six  months  of 2002,  compared  to the
year-ago  period,  primarily due to an increase in interchange  sales.  Fuel and
purchased power increased to accommodate the larger interchange sales volume. We
realized lower margins on  interchange  sales compared to the prior year, due to
lower wholesale electricity prices.

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

Gas Operations

     Our gas revenues and gas margins in second quarter of 2002 were  comparable
to the  year-ago  quarter.  Gas margins  decreased  $4 million for the first six
months of 2002 as compared to the year-ago period as gas revenues  decreased $19
million, primarily due to reduced sales of 6% caused by milder winter weather at
the beginning of the year. Reduced gas purchases  partially offset the effect of
the reduced sales.

Other Operating Expenses

     Other operations  related to operating expenses increased $6 million in the
second quarter of 2002 and $5 million in the first six months of 2002,  compared
to the year-ago periods,  primarily due to higher employee benefit costs related
to the investment  performance of pension plan assets and increasing  healthcare
costs.

                                       16

<PAGE>

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

     Maintenance  expenses  decreased $33 million in the second  quarter of 2002
and $36 million in the first six months of 2002, compared to the same prior year
periods,  primarily due to the lack of a Callaway nuclear plant refueling outage
to date in the current year, along with decreased  maintenance at our coal-fired
power plants.

     Depreciation and amortization expenses increased $2 in the first six months
of 2002,  compared  to the  year-ago  periods,  primarily  due to an increase in
depreciable  property related to investment in our coal power plants,  partially
offset by a reduction  of  depreciation  rates  based on an updated  analysis of
asset values, service lives and accumulated depreciation levels and agreed to in
the stipulation and agreement associated with the Missouri electric rate case.

     Income tax expense  increased $5 million in the second  quarter of 2002 and
$2  million  in the first six  months of 2002,  compared  to the same prior year
periods, primarily due to higher pre-tax income.

     Other tax expense increased $2 million in the second quarter of 2002 and $4
million  in the first six  months of 2002,  compared  to the  year-ago  periods,
primarily due to higher gross receipts taxes  resulting from increased  electric
sales.

Other Income and Deductions

     Other income and deductions  decreased $17 million in the second quarter of
2002 and $21  million  in the first six  months  of 2002,  compared  to the same
periods last year,  primarily due to the commitment to fund certain  programs as
part of the  settlement  of the Missouri  electric  rate case ($26  million) and
lower intercompany  interest earned in the first quarter of 2002 on funds loaned
to the regulated  money pool,  resulting from lower average  intercompany  notes
receivable  balances.  These  increases were partially  offset by an increase in
earnings  from our  ownership  interest  in EEI (second  quarter - $10  million;
year-to-date - $11 million) along with increased gains on asset  disposals.  See
Note 5 - "Miscellaneous, Net" to our financial statements.

Interest

     Interest expense  decreased $4 million in the second quarter of 2002 and $7
million  in the first six  months of 2002,  compared  to the  year-ago  periods,
primarily due to lower interest rates on our variable rate  environmental  bonds
and lower interest expense associated with a decreased balance under our nuclear
fuel lease, partially offset by increased short-term  intercompany interest as a
result of our borrowings  from the money pool in the current year.  Amortization
of debt issuance costs and premium/discounts for the three and six months ending
June 30,  2002 of $1  million  (2001 - $1  million)  and $2  million  (2001 - $2
million) were included in interest expense in the income statement.


LIQUIDITY AND CAPITAL RESOURCES

Operating

     Our cash flows  provided by operating  activities  increased $18 million to
$243 million in the first six months of 2002,  compared to the year-ago  period.
Cash flow from  operations  increased  primarily due to increased  earnings ($38
million),  a decrease in the prior  period's  liability  for  electric  customer
credits  ($45  million),  and  decreased  coal  inventories  and stored gas ($25
million).  Materials  and supplies were higher than normal at December 31, 2001,
due to the warm winter and  anticipation  of a potential coal supply  disruption
that  ultimately  did not occur.  The  primary  use of cash was a  reduction  of
accounts and wages payable ($90 million).

     Our tariff-based  gross margins continue to be our principal source of cash
from operating  activities.  Our diversified retail customer mix of residential,
commercial  and  industrial  classes  and a  commodity  mix of gas and  electric
service  provide  a  reasonably  predictable  source of cash  flows.  We plan to
utilize short-term debt to support normal operations and other temporary capital
requirements.  AmerenUE  is  authorized  by the SEC under PUHCA to have up to $1
billion of short-term unsecured debt instruments outstanding at

                                       17

<PAGE>

any one time.  Short-term  borrowings typically consist of commercial paper with
maturities generally within 1 to 45 days.

     As of June 30, 2002, we had several bank credit agreements expiring in 2002
that  supported our $430 million  commercial  paper  program,  all of which were
unused and available. We also had the ability to borrow up to approximately $425
million from Ameren or from AmerenCIPS, through a regulated money pool agreement
(see Note 3 - "Related Party Transactions" to our financial statements).

     In July 2002, Ameren entered into new credit agreements for $400 million in
revolving credit facilities to be used for general corporate purposes, including
support  of  commercial  paper  programs.  The $400  million  in new  facilities
includes a $270 million  364-day  revolving  credit  facility and a $130 million
3-year  revolving  credit  facility.  The  3-year  facility  has a  $50  million
sub-limit  for the  issuance of letters of credit.  These new credit  facilities
replaced our existing $300 million  revolving  credit facility that was in place
as of June 30,  2002 with a maturity of August 15,  2002.  There were no amounts
outstanding  under this facility at June 30, 2002. In July 2002, we also did not
renew a $25 million committed line of credit.  As a result of these changes,  at
July 31, 2002, we had the ability to borrow up to $500 million, all of which was
unused and available, from Ameren through our regulated money pool agreement.

     We also have a lease  agreement  that provides for the financing of nuclear
fuel.  At June 30,  2002,  the maximum  amount that could be financed  under the
agreement was $120 million, of which $70 million was utilized.

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

Investing

     Our net cash used in investing activities was $174 million in the first six
months  of 2002  compared  to $179  million  in the  first  six  months of 2001.
Construction expenditures were incurred primarily for upgrades at our coal power
plants and further  construction of combustion  turbine  generating  units.  Our
capital expenditures are expected to approximate $500 million in 2002.

     As a part of the  settlement of the Missouri  electric  earnings  complaint
case (see Note 2 - "Rate and Regulatory  Matters" to our financial  statements),
we  committed  to  making  $2.25  billion  to $2.75  billion  in  infrastructure
investments  from  January 1, 2002  through  June 30,  2006.  These  investments
include,  among other  things,  the  addition of more than 700  megawatts of new
generation  capacity and the  replacement  of steam  generators  at our Callaway
nuclear power plant. The 700 megawatts of new generation  includes 240 megawatts
already  added this year and may  include  the  transfer  at book value to us of
generation  assets  from our other  non-regulated  subsidiaries.  The  amount of
energy infrastructure investments through June 2006 described in the stipulation
and  agreement  is  consistent  with our  previously-disclosed  estimate  of the
construction expenditures we expect to make over the same time period.

     Due to expected increased demand and the need to maintain appropriate power
reserve margins,  we believe we will need additional  generating capacity in the
future.  We have an equipment  supply agreement in place for the addition of two
combustion  turbine  generating  units with a total  installed  capacity  of 330
megawatts.  These units will replace the existing Venice steam plant  generating
units  which are  expected  to be  retired in 2003.  Noncancellable  reservation
commitment  fees paid of $22 million  will be applied to our total cost of these
megawatts pursuant to the agreement.

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

                                       18

<PAGE>


Financing

     Our cash flows used in financing  activities  were $76 million in the first
six months of 2002 compared to $61 million in the year-ago period. Our principal
financing   activities  for  the  current  period  included  the  redemption  of
short-term debt and the payment of dividends,  partially  offset by the issuance
of intercompany notes payable.

     In May 2002, we filed a shelf  registration  statement with the SEC on Form
S-3 that allows for the  offering,  from time to time,  of up to $750 million of
various  forms of long-term  debt and trust  preferred  securities  to refinance
existing debt and preferred  stock, as well as for general  corporate  purposes,
including  the repayment of  short-term  debt  incurred to finance  construction
expenditures and other working capital needs.

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


Electric Industry Restructuring

Illinois

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

Federal - Regional Transmission Organizations

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


ACCOUNTING MATTERS

Critical Accounting Policies

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

<TABLE>
<S>                                                <C>
Accounting Policy                                   Uncertainties Affecting Application
-----------------                                   -----------------------------------
Regulatory Mechanisms & Cost Recovery

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


                                       19

<PAGE>

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

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

Environmental Costs
<TABLE>
<S>                                               <C>
   We accrue for all known environmental           o   Extent of contamination
   contamination where remediation can be          o   Responsible party determination
   reasonably estimated, but some of our           o   Approved methods for cleanup
   operations have existed for over 100 years      o   Present and future legislation and governmental
   and previous contamination may be unknown to        regulations and standards
   us.                                             o   Results of ongoing research and development
                                                       regarding environmental impacts
</TABLE>
   Basis for Judgment
   We determine the proper amounts to accrue for  environmental  contamination
   based on  internal  and third  party  estimates  of  clean-up  costs in the
   context  of  current   remediation   regulation   standards  and  available
   technology.

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

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

Benefit Plan Accounting
<TABLE>
<S>                                               <C>
   Based on actuarial calculations, we accrue      o   Future rate of return on pension and other plan
   costs of providing future employee benefits         assets
   in accordance with SFAS 87, 106, and 112.       o   Interest rates used in valuing benefit
   See Note 10 to our financial statements for         obligations
   the year ended December 31, 2001.               o   Healthcare cost trend rates
</TABLE>

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


                                       20

<PAGE>

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

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

Impact of Future Accounting Pronouncements

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


ITEM 3.  Quantitative and Qualitative Disclosures about Market Risk

     Market risk  represents the risk of changes in value of a physical asset or
financial  instrument,  derivative or non-derivative,  caused by fluctuations in
market  variables  (e.g.  interest  rates,  etc.).  The following  discussion of
Ameren's,    including   AmerenUE's,   risk   management   activities   includes
"forward-looking"  statements  that  involve  risks  and  uncertainties.  Actual
results could differ  materially from those  projected in the  "forward-looking"
statements. Ameren manages market risks in accordance with established policies,
which may include entering into various derivative  transactions.  In the normal
course of  business,  Ameren  and our  company  also face  risks that are either
non-financial or  non-quantifiable.  Such risks  principally  include  business,
legal, and operational risk and are not represented in the following analysis.

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

Interest Rate Risk

     We are exposed to market risk through changes in interest rates  associated
with  our  issuance  of  both  long-term  and  short-term   variable-rate  debt,
fixed-rate  debt and commercial  paper.  We manage our interest rate exposure by
controlling   the  amount  of  these   instruments  we  hold  within  our  total
capitalization  portfolio  and by  monitoring  the effects of market  changes in
interest rates.

     Utilizing  our  debt  outstanding  at June  30,  2002,  if  interest  rates
increased by 1%, our annual interest  expense would increase by approximately $8
million and net income would  decrease by  approximately  $5 million.  The model
does not consider the effects of the reduced level of potential overall economic
activity that would exist in such an environment.  In the event of a significant
change in  interest  rates,  management  would  likely  take  actions to further
mitigate our exposure to this market risk.  However,  due to the  uncertainty of
the  specific  actions  that  would be taken and  their  possible  effects,  the
sensitivity analysis assumes no change in our financial structure.

Fuel Price Risk

     100% of the required 2002 supply of coal for our coal power plants has been
acquired at fixed prices.  As such, we have minimal coal price risk for 2002. In
addition,  approximately 70% of our coal requirements from 2003 through 2006 are
covered by contracts.

                                       21

<PAGE>

Fair Value of Contracts

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

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

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

     The following  summarizes changes in the fair value of all contracts marked
to market during the three and six months ended June 30, 2002:
<TABLE>
<CAPTION>
----------------------------------------------------------------------------------------------------------
                                                                                    Three        Six
                                                                                    months      months
----------------------------------------------------------------------------------------------------------
<S>                                                                                <C>         <C>
Fair value of contracts at beginning of period, net                                 $  (4)      $  (2)
   Contracts which were realized or otherwise settled during the period
                                                                                       (5)         (5)
   Changes in fair values attributable to changes in valuation techniques and
     assumptions                                                                        -           -
   Fair value of new contracts entered into during the period                           -           -
   Other changes in fair value                                                         11           9
----------------------------------------------------------------------------------------------------------
Fair value of contracts outstanding at June 30, 2002, net                           $   2       $   2
----------------------------------------------------------------------------------------------------------
</TABLE>

     Maturities of contracts as of June 30, 2002 were as follows:
<TABLE>
<S>                                   <C>           <C>           <C>          <C>            <C>
----------------------------------------------------------------------------------------------------------
                                        Maturity                                Maturity in
                                       less than      Maturity      Maturity    excess of 5    Total fair
Sources of fair value                    1 year      1-3 years     4-5 years       years       value (a)
----------------------------------------------------------------------------------------------------------
Prices actively quoted                     -             -             -             -              -
Prices provided by other external
   sources (b)                             -             -             -             -              -
Prices based on models and other
   valuation methods (c)                  (2)            5            (1)            -              2
----------------------------------------------------------------------------------------------------------
Total                                     (2)            5            (1)            -              2
----------------------------------------------------------------------------------------------------------
(a) Nearly 100% of contracts were with investment-grade rated counterparties.
(b) Principally power forward values based on NYMEX prices for over-the-counter contracts.
(c) Principally coal option and sulfur dioxide option values based on a Black-Scholes model that includes
    information from external sources and our estimates.

</TABLE>

SAFE HARBOR STATEMENT

     Statements made in this report which are not based on historical facts, are
"forward-looking"  and, accordingly,  involve risks and uncertainties that could
cause actual results to differ  materially from those  discussed.  Although such
"forward-looking"  statements  have  been  made in good  faith  and are based on
reasonable assumptions,  there is no assurance that the expected results will be
achieved.  These statements include (without limitation) statements as to future
expectations,  beliefs, plans, strategies,  objectives,  events,  conditions and
financial  performance.  In connection with the "Safe Harbor"  provisions of the
Private  Securities  Litigation  Reform  Act  of  1995,  we are  providing  this
cautionary  statement  to identify  important  factors  that could cause  actual
results to differ materially from those anticipated.  The following factors,  in
addition to those discussed elsewhere in this report and in the Annual Report on
Form 10-K for

                                       22

<PAGE>

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

o    the  effects  of the  stipulation  and  agreement  relating  to our  excess
     earnings complaint case and other regulatory actions,  including changes in
     regulatory policy;
o    changes in laws and other  governmental  actions,  including  monetary  and
     fiscal policies;
o    the impact on us of current  regulations  related  to the  opportunity  for
     customers to choose alternative energy suppliers in Illinois;
o    the  effects of  increased  competition  in the future due to,  among other
     things,  deregulation  of certain aspects of our business at both the state
     and federal levels;
o    the  effects of  participation  in a  FERC-approved  Regional  Transmission
     Organization  (RTO),  including  activities  associated  with  the  Midwest
     Independent System Operator;
o    availability  and  future  market  prices  for  fuel and  purchased  power,
     electricity, and natural gas, including the use of financial and derivative
     instruments and volatility of changes in market prices;
o    average rates for electricity in the Midwest;
o    business and economic conditions;
o    the impact of the adoption of new accounting standards;
o    interest rates and the availability of capital;
o    actions of rating agencies and the effects of such actions;
o    weather conditions;
o    generation plant construction, installation and performance;
o    operation of nuclear power facilities and decommissioning costs;
o    the impact of current environmental regulations on utilities and generating
     companies and the  expectation  that more  stringent  requirements  will be
     introduced over time,  which could  potentially  have a negative  financial
     effect;
o    future wages and employee benefits costs;
o    competition from other generating  facilities including new facilities that
     may be developed in the future;
o    disruptions of the capital markets or other events making AmerenUE's access
     to necessary capital more difficult or costly;
o    cost and availability of transmission  capacity for the energy generated by
     our generating facilities or required to satisfy our energy sales; and
o    legal and administrative proceedings.








                                       23

<PAGE>



PART II.  OTHER INFORMATION


ITEM 1.  Legal Proceedings

     Reference is made to Item 3. Legal  Proceedings  in Part I of our Form 10-K
for the year-ended December 31, 2001 and to Item 1. Legal Proceedings in Part II
of our Form 10-Q for the quarterly  period ended March 31, 2002 for a discussion
of a number of lawsuits that name our affiliate, Central Illinois Public Service
Company operating as AmerenCIPS,  our parent, Ameren Corporation,  and us (which
we refer to as the Ameren  companies),  along with numerous  other  parties,  as
defendants that have been filed by plaintiffs claiming varying degrees of injury
from  asbestos  exposure.  Since the  filing of our Form 10-Q for the  quarterly
period ended March 31, 2002,  thirty-four  additional  lawsuits  have been filed
against the Ameren  companies.  These lawsuits,  like the previous  cases,  were
mostly filed in the Circuit Court of Madison County,  Illinois,  involve a large
number of total  defendants and seek  unspecified  damages in excess of $50,000,
which,  if proved,  typically would be shared among the named  defendants.  Also
since our first quarter Form 10-Q filing,  a settlement  has been reached in one
lawsuit for a monetary  amount not material to the Ameren  companies  and in one
case, the Ameren companies have been voluntarily dismissed.

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


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

     At our annual meeting of stockholders held on April 23, 2002, the following
matter was  presented  to the  meeting for a vote and the results of such voting
are as follows:

Election of Directors.
<TABLE>
<S>                                       <C>                       <C>                       <C>
                                                                                               Non-Voted
Name                                       For                       Withheld                  Brokers
----                                       ---                       --------                  ---------
Paul A. Agathen...................         102,522,452               86,475                         0
Warner L. Baxter..................         102,522,452               86,475                         0
Charles W. Mueller................         102,522,335               86,592                         0
Gary L. Rainwater.................         102,522,452               86,475                         0
Thomas R. Voss....................         102,521,846               87,081                         0

</TABLE>

ITEM 5.  Other Information

     Any stockholder  proposal  intended for inclusion in the proxy material for
our 2003 annual meeting of  stockholders  must be received by us by November 30,
2002.

     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 first anniversary of the preceding
year's annual  meeting.  For our 2003 annual  meeting of  stockholders,  written
notice of any  in-person  stockholder  proposal or director  nomination  must be
received no later than February 22, 2003 or earlier than January 23, 2003.

                                       24

<PAGE>

     The Audit  Committee  of the Board of  Directors of Ameren has approved our
independent accountants, PriceWaterhouseCoopers,  to perform the following audit
and non-audit services:

     o    Audits required by the federal, state or local government rules
     o    Audits of employee pension and benefits plans
     o    Income tax accounting and consulting projects
     o    Comfort  letters and  consents  required  to complete  SEC filings and
          issue securities
     o    Consultation  on responses to  accounting  inquiries by  regulatory or
          other bodies
     o    Audit of AmerenEnergy earnings before interest and taxes statement
     o    Review of stock transfer agent and registrar internal controls
     o    Review of risk management internal controls
     o    Consultation on the accounting for corporate events and transactions
     o    Assistance with preparation of testimony for regulatory filings


ITEM 6.  Exhibits and Reports on Form 8-K

         (a)(i)  Exhibits.

                 99.1 -    Certificate of Chief Executive Officer required by
                           Section 906 of the Sarbanes-Oxley Act of 2002 (not
                           filed as a part of this Report on Form 10-Q).

                 99.2 -    Certificate of Chief Financial Officer required by
                           Section 906 of the Sarbanes-Oxley Act of 2002 (not
                           filed as a part of this Report on Form 10-Q).


         (a)(ii) Exhibits Incorporated by Reference.

                 10.1 -    Memorandum of Understanding dated May 24, 2002
                           between Ameren Services Company, as agent for
                           AmerenUE and AmerenCIPS, and the Midwest Independent
                           Transmission System Operator, Inc. (MISO) (June 30,
                           2002 Ameren Corporation Form 10-Q, Exhibit 10.1).

                 10.2 -    Participation Agreement dated as of July 3, 2002 by
                           and among MISO, Ameren Services Company as agent for
                           AmerenUE and AmerenCIPS, FirstEnergy Corporation on
                           behalf of American Transmission Systems,
                           Incorporated, Northern Indiana Public Service Company
                           and National Grid (June 30, 2002 Ameren Corporation
                           Form 10-Q, Exhibit 10.2).

                 99.3 -    Stipulation and Agreement dated July 15, 2002 in
                           Missouri Public Service Commission (MoPSC) Case No.
                           EC-2002-1 (earnings complaint case against AmerenUE)
                           (File Nos. 333-87506 and 333-87506-01, Exhibit 99.1).

         (b)     Reports on Form 8-K.  AmerenUE filed reports on Form 8-K as
                 follows: (i) dated May 28, 2002 relating to the decision of
                 AmerenCIPS and AmerenUE to rejoin the MISO; (ii) dated July 12,
                 2002 incorporating a press release stating that an agreement in
                 principle had been reached in the earnings complaint case filed
                 by the MoPSC staff against AmerenUE; (iii) dated July 16, 2002
                 incorporating a press release outlining the details of the
                 settlement reached in the MoPSC earnings complaint case; and
                 (iv) dated July 25, 2002 incorporating a press release stating
                 that the MoPSC had approved the settlement reached in the
                 earnings complaint case.

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

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

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







                                       25
<PAGE>

                                   SIGNATURES

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

                                             UNION ELECTRIC COMPANY
                                                  (Registrant)



                                         By    /s/ Martin J. Lyons
                                           ----------------------------
                                                   Martin J. Lyons
                                                      Controller
                                           (Principal Accounting Officer)

Date:  August 14, 2002




                                       26


<PAGE>


                                                                    Exhibit 99.1




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

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




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

Date:  August 14, 2002


<PAGE>


                                                                    Exhibit 99.2





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

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




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

Date:  August 14, 2002