UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                              WASHINGTON, DC 20549


                                    FORM 10-Q

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

    For Quarterly Period Ended March 31, 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 May
10, 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
           Balance Sheet at March 31, 2002 and December 31, 2001............   2
           Statement of Income for the three months ended
           March 31, 2002 and 2001..........................................   3
           Statement of Cash Flows for the three months ended
           March 31, 2002 and 2001..........................................   4
           Statement of Common Stockholder's Equity for the three months
           ended March 31, 2002 and 2001....................................   5
           Notes to Financial Statements....................................   6

  ITEM 2.  Management's Discussion and Analysis of Financial Condition
           and Results of Operations........................................  11

  ITEM 3.  Quantitative and Qualitative Disclosures About Market Risk.......  17

PART II    Other Information

  ITEM 1.  Legal Proceedings................................................  21

  ITEM 6.  Exhibits and Reports on Form 8-K.................................  21

SIGNATURE...................................................................  22


                                       1

<PAGE>
PART I.   FINANCIAL INFORMATION

ITEM 1.   Financial Statements
<TABLE>
<CAPTION>
                              UNION ELECTRIC COMPANY
                                   BALANCE SHEET
                      (In Millions, Except Per Share Amounts)

                                                              March 31,   December 31,
                                                                2002          2001
                                                            -----------   ------------
                                                            (Unaudited)
<S>                                                        <C>           <C>
ASSETS:
Property and plant, at original cost:
   Electric                                                   $  9,919    $  9,828
   Gas                                                             255         252
   Other                                                            37          37
                                                              --------    --------
                                                                10,211      10,117
   Less accumulated depreciation and amortization                4,862       4,802
                                                              --------    --------
                                                                 5,349       5,315
Construction work in progress:
   Nuclear fuel in process                                         102          97
   Other                                                           288         298
                                                              --------    --------
         Total property and plant, net                           5,739       5,710
                                                              --------    --------
Investments and other assets:
   Nuclear decommissioning trust fund                              188         187
   Other                                                            84          75
                                                              --------    --------
         Total investments and other assets                        272         262
                                                              --------    --------
Current assets:
   Cash and cash equivalents                                        12          15
   Accounts receivable - trade (less allowance for doubtful
         accounts of $8 and $7, respectively)                      222         234
   Other accounts and notes receivable                              30          73
   Intercompany notes receivable                                     -          84
   Materials and supplies, at average cost -
      Fossil fuel                                                   56          71
      Other                                                         86          85
   Other                                                            13          16
                                                              --------    --------
         Total current assets                                      419         578
                                                              --------    --------
Regulatory assets:
   Deferred income taxes                                           604         604
   Other                                                           131         134
                                                              --------    --------
         Total regulatory assets                                   735         738
                                                              --------    --------
Total Assets                                                  $  7,165    $  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                                             1,413       1,440
   Accumulated other comprehensive income                           (1)          1
                                                              --------    --------
      Total common stockholder's equity                          2,625       2,654
                                                              --------    --------
   Preferred stock not subject to mandatory redemption             155         155
   Long-term debt                                                1,605       1,599
                                                              --------    --------
         Total capitalization                                    4,385       4,408
                                                              --------    --------
Current liabilities:
   Current maturity of long-term debt                               89          92
   Short-term debt                                                   -         186
   Intercompany notes payable                                      192           -
   Accounts and wages payable                                      135         305
   Accumulated deferred income taxes                                34          35
   Taxes accrued                                                   158         104
   Other                                                           126         128
                                                              --------    --------
         Total current liabilities                                 734         850
                                                              --------    --------
Accumulated deferred income taxes                                1,322       1,326
Accumulated deferred investment tax credits                        127         129
Regulatory liabilities                                             137         137
Other deferred credits and liabilities                             460         438
                                                              --------    --------
Total Capital and Liabilities                                 $  7,165    $  7,288
                                                              ========    ========

</TABLE>
See Notes to Financial Statements.

                                      2
<PAGE>

                             UNION ELECTRIC COMPANY
                               STATEMENT OF INCOME
                                    UNAUDITED
                                  (In Millions)

                                                          Three Months Ended
                                                               March 31,
                                                       -------------------------
                                                            2002     2001
OPERATING REVENUES:                                         ----     ----

   Electric                                                $ 684    $ 597
   Gas                                                        50       69
                                                           -----    -----
      Total operating revenues                               734      666

OPERATING EXPENSES:
   Operations
      Fuel and purchased power                               294      219
      Gas                                                     32       46
      Other                                                  129      130
                                                           -----    -----
                                                             455      395
   Maintenance                                                55       58
   Depreciation and amortization                              72       69
   Income taxes                                               28       31
   Other taxes                                                52       50
                                                           -----    -----
      Total operating expenses                               662      603
                                                           -----    -----

OPERATING INCOME                                              72       63

OTHER INCOME AND (DEDUCTIONS):
   Allowance for equity funds used during construction         1        1
   Miscellaneous, net                                          3        7
                                                           -----    -----
      Total other income and (deductions)                      4        8

INCOME BEFORE INTEREST CHARGES                                76       71


INTEREST CHARGES:
   Interest                                                   27       30
   Allowance for borrowed funds used during construction      (2)      (2)
                                                           -----    -----
      Net interest charges                                    25       28
                                                           -----    -----

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN
      ACCOUNTING PRINCIPLE                                    51       43

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

NET INCOME                                                    51       38

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

NET INCOME AFTER PREFERRED STOCK DIVIDENDS                 $  49    $  36
                                                           =====    =====

See Notes to Financial Statements.




                                       3


<PAGE>

                           UNION ELECTRIC COMPANY
                           STATEMENT OF CASH FLOWS
                                  UNAUDITED
                                (In Millions)

                                                              Three Months Ended
                                                                   March 31,
                                                           ---------------------
                                                                2002     2001
                                                                ----     ----
Cash Flows From Operating:
   Net income                                                  $  51    $  38
   Adjustments to reconcile net income to net cash
       provided by operating activities:
         Cumulative effect of change in accounting principle       -        5
         Depreciation and amortization                            69       65
         Amortization of nuclear fuel                              7        9
         Allowance for funds used during construction             (3)      (3)
         Deferred income taxes, net                               (4)      (6)
         Deferred investment tax credits, net                     (2)      (2)
           Changes in assets and liabilities:
               Receivables, net                                   55        9
               Materials and supplies                             14        9
               Accounts and wages payable                       (170)     (69)
               Taxes accrued                                      54       56
               Other, net                                         14       18
                                                               -----    -----
Net cash provided by operating activities                         85      129

Cash Flows From Investing:
   Construction expenditures                                    (101)     (89)
   Allowance for funds used during construction                    3        3
   Nuclear fuel expenditures                                      (5)      (8)
   Intercompany notes receivable                                  84       18
                                                               -----    -----
Net cash used in investing activities                            (19)     (76)

Cash Flows From Financing:
   Dividends on common stock                                     (76)     (54)
   Dividends on preferred stock                                   (2)      (2)
   Redemptions:
      Nuclear fuel lease                                           -      (35)
      Short-term debt                                           (186)       -
   Issuances:
      Nuclear fuel lease                                           3        2
      Long-term debt                                               -       41
      Intercompany notes payable                                 192        -
                                                               -----    -----
Net cash used in financing activities                            (69)     (48)
                                                               -----    -----

Net change in cash and cash equivalents                           (3)       5
Cash and cash equivalents at beginning of year                    15       20
                                                               -----    -----
Cash and cash equivalents at end of period                     $  12    $  25
                                                               =====    =====

Cash paid during the periods:
   Interest (net of amount capitalized)                        $  19    $  21
   Income taxes, net                                           $   4    $   -

See Notes to Financial Statements.



                                       4

<PAGE>
<TABLE>
<CAPTION>

                     UNION ELECTRIC COMPANY
            STATEMENT OF COMMON STOCKHOLDER'S EQUITY
                           UNAUDITED
                         (In Millions)


                                                                          Three Months Ended
                                                                               March 31,
                                                                        ---------------------
                                                                           2002          2001
                                                                           ----          ----
<S>                                                                <C>              <C>
Common stock                                                              $ 511         $ 511


Other paid-in capital                                                       702           702

Retained earnings
   Beginning balance                                                      1,440         1,358
   Net income                                                                51            38
   Common stock dividends                                                   (76)          (54)
   Preferred stock dividends                                                 (2)           (2)
                                                                    ------------    ----------
                                                                          1,413         1,340

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


Total common stockholder's equity                                       $ 2,625       $ 2,551
                                                                    ============   ==========


Comprehensive income, net of taxes
   Net income                                                              $ 51          $ 38
   Unrealized net gain/(loss) on derivative hedging instruments              (2)            6
   Cumulative effect of accounting change                                     -            (8)
                                                                    ------------    ----------
                                                                           $ 49          $ 36
                                                                    ============    ==========
</TABLE>
See Notes to Financial Statements.


                                       5


<PAGE>

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

     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  as a result of  obligations  associated  with  Callaway
Nuclear  Plant  decommissioning  costs  which are being fully  recovered  in our
rates.

     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.  SFAS  144 did not  have any  effect  on our  financial
position, results of operations or liquidity upon adoption.

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.  At  March  31,  2002,  we had an  accrual  representing  the
estimated  credit

                                       6

<PAGE>


that we expect to pay our  Missouri  electric  customers  of $40 million for the
plan year ended June 30, 2001. In 2002, the Missouri  Public Service  Commission
(MoPSC)  Staff and the  Missouri  Office of Public  Counsel  (OPC)  Staff  filed
testimony with the MoPSC on this matter. Combined, the MoPSC Staff and OPC Staff
recommend  that the credit to  customers  for the plan year ended June 30, 2001,
should  approximate $80  million.  The  MoPSC  is  not  bound  by  their
recommendations. To date, a procedural schedule and hearing dates on this matter
have not been  established  by the MoPSC.  At this time,  we continue to believe
that our accrual is adequate in all material respects.

     Following  expiration of the  experimental  alternative  regulation plan on
June 30, 2001, the MoPSC Staff filed an excess  earnings  complaint  against us.
Based upon a January 2002 MoPSC order, on March 1, 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 is based on a return
to traditional cost of service ratemaking, a return on equity ranging from 8.91%
to 9.91%,  a  reduction  in our  depreciation  rates,  and other cost of service
adjustments. The MoPSC is not bound by the Staff's recommendation.

     On May 10,  2002,  we filed  rebuttal  testimony  in  response to the MoPSC
Staff's recommendation. In our testimony, we stated that a return to traditional
cost of service  ratemaking  would result in an increase in our annual  Missouri
electric  revenues by  approximately  $150  million.  Our position is based on a
12.5%  return on  equity,  higher  depreciation  rates  and  other  adjustments.
However,  a key  component  of our  testimony is our  recommendation  that a new
alternative  rate regulation plan (Alt Reg Plan) be adopted by the MoPSC. In our
filing,  we included a new Alt Reg Plan proposal.  Key provisions of the Alt Reg
Plan include the following:

     o  A three-year  plan from July 1, 2002 through June 30, 2005 which would
        require us to share earnings over certain  regulatory return on equity
        (ROE)  thresholds  for the 12 months  ending July 1 through June 30;
     o  The proposed earnings sharing grid would require us to provide sharing
        credits of $17  million  if our  regulatory  ROE is between  10.5% and
        12.5%.  Additional credits of 55% of our earnings between a regulatory
        ROE of 12.5%  and 15% would be  provided,  90% of  earnings  between a
        regulatory  ROE of 15% and 16%, and 100% of any earnings  above 16%.
     o  An immediate  one-time credit to customers bills of $15 million;
     o  An annualized $15 million permanent rate reduction, retroactive to
        April 1, 2002;
     o  An immediate funding of $5 million to a low-income customer assistance
        program and $5 million to an economic development program;
     o  A commitment of $1.5 billion to $1.75 billion in energy infrastructure
        investment from January 1, 2002 through June 30, 2005.

     Hearings for this case are  scheduled  to commence in mid-July  2002 and be
completed in early  August  2002. A final  decision on this matter may not occur
until  the  fourth  quarter  of  2002.  In the  interim,  we  plan  to  continue
negotiations  with all  pertinent  parties  with the intent to continue  with an
incentive regulation plan. We cannot predict the outcome of the MoPSC's decision
in this matter or its impact on our financial statements,  results of operations
or liquidity. However, the impact could be material.

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

     In May 2001,  the MoPSC filed a pleading with the  Securities  and Exchange
Commission (SEC) relating to our agreement to purchase 450 megawatts of capacity
and energy from  Marketing  Company  during 2001 (the 2001  Marketing  Company -
AmerenUE   agreement).   The  pleading   requested  an  investigation  into  the
contractual  relationship  between  us,  Marketing  Company  and our  affiliate,
AmerenEnergy Generating Company (Generating Company), in the context of the 2001
Marketing Company - AmerenUE agreement and requested that the SEC find that such
relationship  violates  a  provision  of  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

                                       7

<PAGE>


contract directly with Generating  Company and submit such contract to the MoPSC
for review.  The SEC has not  responded to this matter to date.  On May 9, 2002,
the MoPSC filed a similar pleading with the SEC relating to AmerenUE's agreement
to purchase 200 megawatts of capacity and energy from  Marketing  Company during
2002.  At this  time,  management  is unable to  predict  the  outcome  of these
pleadings or the ultimate impact on our future  financial  position,  results of
operations or liquidity.

Illinois

     In December  1997,  the Governor of Illinois  signed the  Electric  Service
Customer  Choice and Rate Relief Law of 1997 (the  Illinois  Law)  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 already  offered  this choice.  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 to have a material  adverse  effect on our
business either.

     In addition,  the Illinois  Law contains a provision  freezing  residential
electric rates through  January 1, 2005.  Legislation has been introduced in the
Illinois House of  Representatives  and Senate that would extend the rate freeze
to December 31, 2006. At this time, we cannot predict  whether that  legislation
will ultimately be passed.

Federal - Midwest ISO and Alliance RTO

     In December 1999, the Federal Energy  Regulatory  Commission  (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 have been 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. At this time, we
continue to evaluate our  alternatives and are in the process of determining the
impact  that the FERC's  April  2002  ruling  will have on our future  financial
condition, results of operations or liquidity.

NOTE 3 - Related Party Transactions

     AmerenUE  has  transactions  in the normal  course of business  with Ameren
Corporation,  our parent company,  and its subsidiaries.  These transactions are
primarily  comprised  of power  purchases  and sales and  services  received  or
rendered.  Intercompany power purchases from joint dispatch and other agreements
were  approximately  $27 million  for the three  months  ended  March 31,  2002,
compared to $23 million for the three months ended March 31, 2001.  Intercompany
power  sales  totaled $20 million  for the three  months  ended March 31,  2002,
compared to $28 million for the three months ended March 31, 2001.  Intercompany
receivables  included in Other Accounts and Notes Receivable were  approximately
$14 million as of March 31, 2002 (December 31, 2001 - $38 million). Intercompany
payables  included in  Accounts  and Wages  Payable  totaled  approximately  $47
million as of March 31, 2002 (December 31, 2001 - $70 million).

                                       8

<PAGE>

     Support   services   provided  by  our  affiliates,   Ameren  Services  and
AmerenEnergy,  including wages,  employee  benefits,  professional  services and
other  expenses are based on actual costs  incurred.  For the three months ended
March 31,  2002,  Other  Operating  Expenses  provided  by Ameren  Services  and
AmerenEnergy totaled $48 million, compared to $47 million for the same period in
2001.

     We have the ability to borrow up to approximately  $425 million from Ameren
or our affiliate,  AmerenCIPS,  through a regulated  money pool  agreement.  The
total amount  available to us at any given time from the regulated money pool is
reduced  by the amount of  borrowings  by  AmerenCIPS  or Ameren  Services,  but
increased to the extent Ameren, AmerenCIPS or Ameren Services have surplus funds
or the availability of other external  borrowing sources.  AmerenUE,  AmerenCIPS
and Ameren  Services rely on the regulated  money pool to coordinate and provide
for certain  short-term cash and working capital  requirements.  Ameren Services
administers the regulated money pool. 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 March 31, 2002,  the average
interest rate for the regulated money pool was 1.79% (2001 - 5.50%). As of March
31, 2002, we had outstanding  intercompany  payables of $192 million through the
regulated  money pool.  At December 31, 2001,  we had  outstanding  intercompany
receivables of $84 million  through the regulated money pool. At March 31, 2002,
at least $357 million was available through the regulated money pool.

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.

     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 and
modify our  exposure to market,  credit and  operational  risk by entering  into
various offsetting transactions. In general, we believe these transactions serve
to reduce price risk for AmerenUE.

     As of March 31, 2002,  we recorded the fair value of  derivative  financial
instrument  assets  of $20  million  in  Other  Assets  and the  fair  value  of
derivative  financial  instrument  liabilities  of $24 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.

     For the three  months  ended  March 31,  2002,  the pretax net gain,  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.

     As of March 31,  2002,  the  entire  net loss on power  forward  derivative
instruments of approximately $6 million,  or approximately $4 million after tax,
accumulated  in OCI is expected  to be  recognized  in earnings  during the next
twelve months upon delivery of the commodity being hedged.

                                       9

<PAGE>

     We also  hold a call  option  for coal  with a  supplier.  This  option  to
purchase  coal expires  October 15, 2003.  The entire gain of  approximately  $5
million,  or approximately $3 million after tax,  accumulated in OCI is expected
to be recognized in earnings prior to that date.

Other Derivatives

     We enter into option transactions to manage our positions in sulfur dioxide
(SO2) allowances, coal, and electricity.  Most of these transactions are treated
as  non-hedge  transactions  under  SFAS 133.  Therefore,  the net change in the
market value of these options is recorded as Miscellaneous, net in the statement
of income and was immaterial at March 31, 2002.

NOTE 5 - Subsequent Event

     On  April  28,  2002,  Ameren  entered  into  an  agreement  with  The  AES
Corporation to purchase all or 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  currently  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  200,000 and 205,000  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
nonregulated by closing.

     Upon completion of the acquisition,  expected within 12 months,  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 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.







                                       10

<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
operating 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 operating 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
         nonregulated operations. Subsidiaries include AmerenEnergy Generating
         Company (Generating Company) that operates nonregulated 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.
     o   Ameren Services Company, which provides shared support services to
         Ameren and its subsidiaries, including AmerenUE. 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   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.
     o   The audited financial statements and related notes that appear 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, natural gas and
nuclear fuel 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 plant, and  transmission and distribution  systems,
and the level of operating and  administrative  costs and capital investment are
key  factors  that we seek to  control  in  order to  optimize  our  results  of
operations, cash flows and financial position.

RESULTS OF OPERATIONS

     Our net income increased by 34% to $51 million in the first quarter of 2002
from $38 million in the first  quarter of 2001. In the first quarter of 2001, we
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."  See  Accounting  Matters.  As  a  result,  income  before
cumulative effect of change in

                                       11

<PAGE>


accounting  principle in the first  quarter of 2002 was $51 million  compared to
$43 million in the first  quarter of 2001.  Income before  cumulative  effect of
change in accounting principle increased in the first quarter of 2002 versus the
prior  year  primarily  due to  internal  weather-normalized  growth  and the $9
million  after-tax benefit of the lack of estimated credits to Missouri electric
customers due to the  expiration  of our  incentive  rate plan on June 30, 2001.
Partially  offsetting these benefits was the effect of the extremely mild winter
weather in our service  territory.  According to National  Weather Service data,
there were  approximately 15% fewer heating degree days in our service territory
in the first quarter of 2002 as compared to 2001 and normal weather  conditions.
As  a  result,   weather-sensitive   residential  electric  kilowatt-hour  sales
decreased by 5%, commercial electric kilowatt-hour sales decreased by 3% and gas
sales  decreased  by 9% in the  first  quarter  of 2002  compared  to  2001.  In
addition,  industrial  electric  kilowatt-hour  sales  decreased  7%  due to the
continued soft economy.

     Despite the warmer winter weather,  total electric  revenues  increased 15%
for the first quarter of 2002, compared to the year-ago period, primarily due to
higher  interchange  sales.  However,  we realized  lower margins on these sales
compared to the prior year, due to lower wholesale electricity prices.

Recent Developments

     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  currently  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  200,000 and 205,000  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
nonregulated by closing.

     Upon completion of the acquisition,  expected within 12 months,  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 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.

     As a result  of the  continuing  uncertainty  associated  with our  pending
Missouri electric rate 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 our debt 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.  Currently,  Ameren's  corporate  credit  rating is A+ at Standard  and
Poor's and A2 at Moody's.  If the ratings of our first mortgage bonds fall below
investment  grade,  lenders under our $300 million revolving credit facility may
elect  not to  make  advances  and/or  declare  outstanding  borrowings  due and
payable.  In addition,  a decrease in Ameren's ratings may indirectly reduce our
access to  capital  and/or  increase  the  costs of  borrowings  resulting  in a
negative impact on earnings.



                                       12

<PAGE>


Electric Operations

     The following table represents the favorable (unfavorable) variation for
the three months ended March 31, 2002 from the comparable period in 2001:
--------------------------------------------------------------------------------
                                                                    Three Months
--------------------------------------------------------------------------------
Operating Revenues:
   Credit to customers.........................................        $  15
   Effect of abnormal weather (estimate).......................          (12)
   Growth and other (estimate).................................           18
   Interchange sales...........................................           66
--------------------------------------------------------------------------------
                                                                          87
Fuel and Purchased Power:
   Fuel:
     Generation................................................        $   8
     Price.....................................................            6
   Purchased power ............................................          (89)
--------------------------------------------------------------------------------
                                                                         (75)
--------------------------------------------------------------------------------
Change in electric margin                                              $  12
--------------------------------------------------------------------------------

     Electric  margins  increased  $12 million in the first three months of 2002
compared to the year-ago  quarter.  Revenues were favorably  impacted in 2002 by
the lack of  estimated  credits to  Missouri  electric  customers  (see Note 2 -
"Regulatory Matters" to the financial statements). We also experienced growth in
electric  revenues due to the expansion of our  weather-normalized  native load,
sales of SO2 allowances and an 80% increase in interchange sales. However, these
increased  interchange revenues were more than offset by the related increase in
purchased power, resulting in lower margins than 2001. The increases in revenues
were also partially  offset by decreases in  weather-sensitive  residential  and
commercial sales caused by the milder winter weather referenced above, and lower
industrial  sales  resulting  from the  continued  soft  economy in our  service
territory.

     Interchange  revenues  for the  first  quarter  of 2002  included  sales to
related parties of $20 million,  compared to $28 million in the first quarter of
2001.  Fuel and  purchased  power costs for the first  quarter of 2002  included
purchases  of $27 million from related  parties  under joint  dispatch and other
agreements,  compared to $23 million for the first quarter of 2001. See Note 3 -
"Related Party Transactions" to the financial statements.

Gas Operations

     Our gas revenues  decreased  $19 million,  and our gas costs  decreased $14
million,  in first quarter of 2002 as compared to the year-ago quarter primarily
due to reduced sales of 9% caused by the milder winter weather and lower natural
gas prices.  As a result,  our gas margins  decreased by $5 million in the first
quarter of 2002 as compared to the same period a year ago.

Other Operating Expenses

     Other  operating  expenses in the first quarter of 2002 were  comparable to
the year-ago period.  Ameren Services and AmerenEnergy  provided  services to us
for the three months ended March 31, 2002 of  approximately  $48 million (2001 -
$47  million)  that were  included  in Other  Operating  Expenses.  See Note 3 -
"Related Party Transactions" to the financial statements.

     Maintenance  expenses  decreased  $3 million  in the first  quarter of 2002
compared to the year-ago  period,  primarily  due to decreased  coal power plant
maintenance,  partially  offset by higher  tree-trimming  expenses,  which  were
accelerated, in part, to take advantage of mild weather.

     Depreciation  and amortization  expenses  increased $3 million in the first
quarter of 2002 compared to the year-ago period, primarily due to an increase in
depreciable  property related to the investment in our coal electric  generating
plants.

                                       13

<PAGE>

Taxes

     Income tax  expense  decreased  $3  million  in the first  quarter of 2002,
compared to the year-ago  period,  primarily due to a lower  effective tax rate.

     Other tax  expense  increased  $2  million  in the first  quarter  of 2002,
compared to the year-ago period,  primarily due to higher Missouri  property tax
assessments  and higher gross receipts taxes  resulting from increased  electric
sales.

Other Income and Deductions

     Other income and  deductions  decreased $4 million in the first  quarter of
2002,  compared  to the  year-ago  period  primarily  due to lower  intercompany
interest earned on funds loaned to the regulated money pool resulting from lower
average  intercompany  notes  receivable  balances.  See Note 3 - "Related Party
Transactions" to financial statements.

Interest

     Interest expense decreased $3 million in the first quarter of 2002 compared
to the year-ago  period  primarily due to lower  interest  rates on our variable
rate  environmental  bonds  ($2  million),  as well as  lower  interest  expense
associated with a decreased balance under our nuclear fuel lease ($1 million).

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.  At  March  31,  2002,  we had an  accrual  representing  the
estimated  credit that we expect to pay our Missouri  electric  customers of $40
million for the plan year ended June 30,  2001.  In 2002,  the  Missouri  Public
Service Commission (MoPSC) Staff and the Missouri Office of Public Counsel (OPC)
Staff filed testimony with the MoPSC on this matter.  Combined,  the MoPSC Staff
and OPC Staff  recommend  that the credit to  customers  for the plan year ended
June 30, 2001, should  approximate $80 million.  The MoPSC is not bound by their
recommendations. To date, a procedural schedule and hearing dates on this matter
have not been  established  by the MoPSC.  At this time,  we continue to believe
that our accrual is adequate in all material respects.

     Following  expiration of the  experimental  alternative  regulation plan on
June 30, 2001, the MoPSC Staff filed an excess  earnings  complaint  against us.
Based upon a January 2002 MoPSC order, on March 1, 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 is based on a return
to traditional cost of service ratemaking, a return on equity ranging from 8.91%
to 9.91%,  a  reduction  in our  depreciation  rates,  and other cost of service
adjustments. The MoPSC is not bound by the Staff's recommendation.

     On May 10,  2002,  we filed  rebuttal  testimony  in  response to the MoPSC
Staff's recommendation. In our testimony, we stated that a return to traditional
cost of service  ratemaking  would result in an increase in our annual  Missouri
electric  revenues by  approximately  $150  million.  Our position is based on a
12.5%  return on  equity,  higher  depreciation  rates  and  other  adjustments.
However,  a key  component  of our  testimony is our  recommendation  that a new
alternative  rate regulation plan (Alt Reg Plan) be adopted by the MoPSC. In our
filing,  we included a new Alt Reg Plan proposal.  Key provisions of the Alt Reg
Plan include the following:

     o   A three-year plan from July 1, 2002 through June 30, 2005 which would
         require us to share earnings over certain regulatory return on equity
         (ROE) thresholds for the 12 months ending July 1 through June 30;
     o   The proposed earnings sharing grid would require us to provide sharing
         credits of $17 million if our regulatory ROE is between 10.5% and
         12.5%.  Additional credits of 55% of our earnings between a regulatory
         ROE of 12.5% and 15% would be provided, 90% of earnings between a
         regulatory ROE of 15% and 16%, and 100% of any earnings above 16%.
     o   An immediate one-time credit to customers bills of $15 million;
     o   An annualized $15 million permanent rate reduction, retroactive to
         April 1, 2002;

                                       14

<PAGE>

     o   An immediate funding of $5 million to a low-income customer assistance
         program and $5 million to an economic development program;
     o   A commitment of $1.5 billion to $1.75 billion in energy infrastructure
         investment from January 1, 2002 through June 30, 2005.

     Hearings for this case are  scheduled  to commence in mid-July  2002 and be
completed in early  August  2002. A final  decision on this matter may not occur
until  the  fourth  quarter  of  2002.  In the  interim,  we  plan  to  continue
negotiations  with all  pertinent  parties  with the intent to continue  with an
incentive regulation plan. We cannot predict the outcome of the MoPSC's decision
in this matter or its impact on our financial statements,  results of operations
or liquidity. However, the impact could be material.

LIQUIDITY AND CAPITAL RESOURCES

Operating

     Our cash flows  provided by operating  activities  decreased $44 million to
$85  million  in the first  quarter of 2002  compared  to the  year-ago  period,
primarily  due to changes  in  working  capital  requirements  resulting  from a
decrease in accounts and wages payable utilizing cash received from the decrease
in  receivables.  These decreases were partially offset by increased earnings.

     Our tariff-based  gross margins continue to be our principal source of cash
from operating  activities.  Our diversified retail customer mix of residential,
commercial  and  industrial  classes  and a  commodity  mix of gas and  electric
service  provide  a  reasonably  predictable  source of cash  flows.  We plan to
utilize short-term debt to support normal operations and other temporary capital
requirements.  AmerenUE  is  authorized  by the SEC under PUHCA to have up to $1
billion of short-term  unsecured debt  instruments  outstanding at any one time.
Short-term   borrowings   typically  consist  of  commercial  paper  (maturities
generally within 1 to 45 days).

     We have  several bank credit  agreements  expiring in 2002 that support our
commercial paper program totaling $430 million.  At March 31, 2002, all of these
bank credit  agreements  were unused and  available.  Ameren  expects to replace
these bank credit agreements prior to their maturity.

     We also have the ability to borrow up to  approximately  $425  million from
Ameren or from AmerenCIPS,  through a regulated money pool agreement.  The total
amount  available  to us at any given  time  from the  regulated  money  pool is
reduced  by the amount of  borrowings  by  AmerenCIPS  or Ameren  Services,  but
increased to the extent Ameren, AmerenCIPS or Ameren Services have surplus funds
or the availability of other external  borrowing sources.  AmerenUE,  AmerenCIPS
and Ameren  Services rely on the regulated  money pool to coordinate and provide
for certain  short-term cash and working capital  requirements.  Ameren Services
administers the regulated money pool. 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 March 31, 2002,  the average
interest rate for the regulated money pool was 1.79% (2001 - 5.50%). As of March
31, 2002, we had outstanding  intercompany payables of $192 million and at least
$357 million  available  through the regulated money pool. At December 31, 2001,
we had outstanding intercompany receivables of $84 million through the regulated
money pool.

     We also have a lease  agreement  that provides for the financing of nuclear
fuel.  At March 31, 2002,  the maximum  amount that could be financed  under the
agreement was $120 million, of which $67 million was utilized.

     Our short-term  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 March 31, 2002, we were in compliance
with these provisions.

Investing

     Our net cash used in  investing  activities  was $19  million  in the first
quarter of 2002  compared  to $76 million in the first  quarter of 2001.  In the
first quarter of 2002,  construction  expenditures were $101 million (2001 - $89
million),  primarily  related to various  upgrades at our coal power  plants and
further  construction  of  combustion  turbine  generating  units.  Our  capital
expenditures are expected to approximate

                                       15

<PAGE>

$500  million in 2002.  Also,  during the first  quarter of 2002,  AmerenUE  was
repaid $84 million (2001 - $18 million) from the regulated money pool.

Financing

     Our cash flows used in financing  activities  were $69 million in the first
quarter of 2002  compared to $48 million in the year-ago  period.  Our principal
financing  activities for the 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 upon its effectiveness  will allow 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 for  general  corporate  purposes,
including  the repayment of  short-term  debt  incurred to finance  construction
expenditures and other working capital needs. This registration has not yet been
declared effective by the SEC.

     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 the financial statements.

Federal - Midwest ISO and Alliance RTO

     See Note 2 - "Rate and Regulatory Matters" to the 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                        Judgments/Uncertainties Affecting Application
-----------------                        ---------------------------------------------

Regulatory Mechanisms & Cost Recovery

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

Nuclear Plant Decommissioning Costs

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

</TABLE>
                                       16

<PAGE>


Environmental Costs

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

Unbilled Revenue

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


Benefit Plan Accounting

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


Derivative Financial Instruments

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


Impact of Future Accounting Pronouncements

     See Note 1 - "Summary of Significant Accounting Policies" to the 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.

                                       17

<PAGE>


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 March  31,  2002,  if  interest  rates
increased by 1%, our annual interest  expense would increase by approximately $5
million and net income would  decrease by  approximately  $3 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

     Over 95% of the  required  2002 supply of coal for our coal 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 through 2006 are covered by
contracts.

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.

     The following summarizes changes in the fair value of all contracts marked
to market during the first quarter of 2002:
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
Fair value of contracts at January 1, 2002                             $  (2)
   Contracts at January 1, 2002 which were realized or otherwise
   settled during first quarter of 2002                                   --
   Changes in fair values attributable to changes in valuation
   techniques and assumptions                                             --
   Fair value of new contracts entered into during first quarter 2002     --
   Other changes in fair value                                            (2)
--------------------------------------------------------------------------------
Fair value of contracts outstanding at March 31, 2002                  $  (4)
--------------------------------------------------------------------------------




                                       18


<PAGE>
<TABLE>
<CAPTION>

Fair value of contracts as of March 31, 2002 were as follows:
<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)                              (2)           --           --             --            (2)
Prices based on models and other
   valuation methods (c)                    (3)            2           (1)            --            (2)
-----------------------------------------------------------------------------------------------------------
Total                                     $ (5)         $  2         $ (1)         $  --         $  (4)
-----------------------------------------------------------------------------------------------------------
(a)      Nearly 100% of contracts were with investment-grade rated counterparties.
(b)      Principally power forward hedges valued based on NYMEX prices for over-the-counter contracts.
(c)      Principally coal and SO2 options valued 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 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 our pending 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 and the Alliance RTO;
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  the effects of strategic initiatives, including acquisitions and
   divestitures;
o  operation of nuclear power facilities and decommissioning costs;
o  the impact of current environmental regulations on utilities and generating
   companies and the expectation that more stringent requirements will be
   introduced over time, which could potentially have a negative financial
   effect;
o  future wages and employee benefits costs;
o  competition from other generating facilities including new facilities that
   may be developed in the future;
o  delays in receipt of regulatory approvals for the acquisition of CILCORP or
   unexpected adverse conditions or terms of those approvals;
o  difficulties in integrating CILCO with Ameren's other businesses;
o  changes in the coal markets, environmental laws or regulations or other
   factors adversely impacting synergy assumptions in connection with the
   CILCORP acquisition;

                                       19

<PAGE>

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 energy sales made by
   AmerenUE; and
o  legal and administrative proceedings.






















                                       20

<PAGE>


                           PART II - OTHER INFORMATION


ITEM 1.  Legal Proceedings.

     Reference  is made to Item 3.  Legal  Proceedings  in Part I of our  Annual
Report on Form 10-K for the year ended  December 31, 2001 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.  With  respect to nine of those  lawsuits,  the Ameren
companies have reached  settlements with the plaintiffs for monetary amounts not
material to the Ameren  companies and in three cases,  the Ameren companies have
been voluntarily dismissed.

     Twenty-two additional  lawsuits claiming injury from asbestos exposure have
been filed against the Ameren  companies  since year-end 2001.  These  lawsuits,
like the  previous  cases,  were mostly  filed in the  Circuit  Court of Madison
County,  Illinois,  involve a large number of total defendants (over one hundred
in many  cases) and seek  unspecified  damages in excess of $50,000,  which,  if
proved, typically would be shared among the named defendants.  Currently, thirty
asbestos-related  lawsuits are pending against the Ameren companies.  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 6.  Exhibits and Reports on Form 8-K.

         (a)     Exhibits Incorporated by Reference.

                 10.1    - Power Sales Agreement between AmerenEnergy Marketing
                           Company and AmerenUE dated March 20, 2002 (March 31,
                           2002 AmerenEnergy Generating Company Form 10-Q,
                           Exhibit 10.1).

         (b)     Reports on Form 8-K. AmerenUE filed a report on Form 8-K
                 dated January 7, 2002 incorporating a press release issued by
                 Ameren Corporation relating to the earnings complaint case
                 filed by the Missouri Public Service Commission staff against
                 AmerenUE and announcing a revision to Ameren Corporation's
                 2001 earnings estimate.

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

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

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




                                       21

<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:   May 15, 2002



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