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, 2001

[  ]     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) 554-2715


         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 registrant's classes of common stock as of April
  30, 2001: Common Stock, $5 par value, held by Ameren Corporation (parent
  company of Registrant) - 102,123,834


<PAGE>



                             Union Electric Company

                                      Index

                                                                       Page No.

Part I               Financial Information (Unaudited)

                     Management's Discussion and Analysis                   2

                     Quantitative and Qualitative Disclosures
                     About Market Risk                                      6

                     Balance Sheet
                     - March 31, 2001 and December 31, 2000                 9

                     Statement of Income
                     - Three months and 12 months ended
                        March 31, 2001 and 2000                            10

                     Statement of Cash Flows
                     - Three months ended March 31, 2001 and 2000          11

                     Statement of Common Stockholder's Equity
                     - March 31, 2001 and December 31, 2000                12

                     Notes to Financial Statements                         13


Part II              Other Information                                     18


<PAGE>



                    PART I. FINANCIAL INFORMATION (UNAUDITED)

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

OVERVIEW

Union Electric Company (AmerenUE or the Registrant) is a subsidiary of Ameren
Corporation (Ameren), a holding company registered under the Public Utility
Holding Company Act of 1935 (PUHCA). Both Ameren and its subsidiaries are
subject to the regulatory provisions of the PUHCA. The Registrant is a public
utility operating company engaged principally in the generation, transmission,
distribution and sale of electric energy and the purchase, distribution,
transportation and sale of natural gas in the states of Missouri and Illinois.
The Registrant serves 1.2 million electric and 125,000 gas customers in a 24,500
square-mile area of Missouri and Illinois, including Metropolitan St. Louis.

The following discussion and analysis should be read in conjunction with the
Notes to the Financial Statements beginning on page 13, and the Management's
Discussion and Analysis of Financial Condition and Results of Operations (MD&A),
the Audited Financial Statements, and the Notes to the Financial Statements
appearing in the Registrant's 2000 Form 10-K.


RESULTS OF OPERATIONS

Earnings
First quarter 2001 earnings of $36 million decreased $1 million compared to 2000
first quarter earnings. 2001 earnings include the impact of a one-time charge of
$5 million associated with the required adoption of a new accounting standard
related to derivative financial instruments (see Note 8 under Notes to Financial
Statements for further information). Earnings for the 12 months ended March 31,
2001, were $343 million, a $7 million increase from the preceding 12-month
period. Earnings fluctuated due to many conditions, primarily: sales growth,
weather variations, credits to electric customers, electric rate reductions, gas
rate increases, competitive market forces, fluctuating operating costs
(including Callaway Nuclear Plant refueling outages), expenses relating to the
withdrawal from the electric transmission related Midwest Independent System
Operator (Midwest ISO), adoption of a new accounting standard, changes in
interest expense, and changes in income and property taxes.

The significant items affecting revenues, costs and earnings during the
three-month and 12-month periods ended March 31, 2001 and 2000 are detailed on
the following pages.

<TABLE>
<CAPTION>

Electric Operations
Electric Operating Revenues                       Variations for periods ended March 31, 2001
                                                    from comparable prior-year periods
--------------------------------------------- ------------------- ---- -----------------------
(Millions of Dollars)                            Three Months              Twelve Months
--------------------------------------------- ------------------- ---- -----------------------
<S>                                              <C>                        <C>
Credit to customers                                $   (5)                    $   (42)
Effect of abnormal weather                             22                          39
Growth and other                                       (1)                         45
Interchange sales                                      62                         126
--------------------------------------------- ------------------- ---- -----------------------
                                                   $   78                     $   168
--------------------------------------------- ------------------- ---- -----------------------
</TABLE>


The $78 million increase in the first quarter electric revenues compared to the
year-ago quarter was primarily driven by a 25 percent increase in interchange
sales, due to strong marketing efforts and greater interchange opportunities.
Also, contributing to the revenue increase was a 5 percent increase in native
sales, which were primarily due to increases in weather-sensitive residential
and commercial sales of 9 percent and 7 percent, respectively, partially offset
by a 24 percent decrease in wholesale sales, while industrial sales were flat.
Electric revenues were also impacted by an increase in the estimated credit to
Missouri electric customers (see Note 5 under Notes to Financial Statements for
further information).

Electric revenues for the 12 months ended March 31, 2001 increased $168 million
compared to the prior 12-month period. The increase in revenues was primarily
driven by increased interchange sales due to increased interchange
opportunities. Interchange sales increased 39 percent, partially offset by a 43
percent decline in wholesale sales and

                                      -2-

<PAGE>

a 4 percent decline in industrial sales, while weather sensitive residential and
commercial sales increased by 8 percent and 10 percent, respectively, for the 12
months ended March 31, 2001. Partially offsetting this increase is the estimated
increase  in the credit to  Missouri  electric  customers  (see Note 5 under the
Notes to Financial Statements for further information).

<TABLE>
<CAPTION>

Fuel and Purchased Power                    Variations for periods ended March 31, 2001
                                                  from comparable prior-year periods
---------------------------------------------------------------------------------------------
(Millions of Dollars)                            Three Months              Twelve Months
---------------------------------------------------------------------------------------------
<S>                                                <C>                            <C>
Fuel:
     Generation                                      $   6                          $   36
     Price                                               4                             (15)
     Generation efficiencies and other                  (1)                             (4)
Purchased power variation                               38                              50
----------------------------------------------------------------------------------------------
                                                     $  47                          $   67
----------------------------------------------------------------------------------------------
</TABLE>



The increase in fuel and purchased power costs for the three month and 12 month
periods ended March 31, 2001, compared to the year ago comparable periods, was
primarily due to increased generation and purchased power resulting from higher
sales volumes.

Gas Operations
Gas revenues for the three month and 12 month periods ended March 31, 2001
increased $27 million and $67 million, respectively, compared to the prior-year
periods primarily due to increases in retail sales due to a return to more
normal weather conditions, as compared to the same year ago periods, and higher
gas costs reflected in the purchased gas adjustment clause (PGA).

Gas costs for the three and 12 months ended March 31, 2001 increased $23 million
and $49 million, respectively compared to the year-ago period, primarily due to
an increase in purchases, as well as higher gas prices.

Other Operating Expenses
Other operating expense variations reflected recurring factors such as growth,
inflation, labor and employee benefit costs.

Other operations expenses for the three months ended March 31, 2001 increased
$26 million, compared to the same year-ago period primarily due to increased
employee benefit costs. Other operations expenses increased $85 million for the
12 months ended March 31, 2001, compared to the same year-ago period primarily
due to increased professional services expenses in addition to the Midwest ISO
charge in the fourth quarter of 2000 (see discussion below under "Electric
Industry Restructuring" for further information).

Maintenance expenses for the three and 12 months ended March 31, 2001 increased
$6 million and $8 million, respectively, compared to the year-ago periods
primarily due to increased fossil power plant maintenance.

Depreciation and amortization expense for the 12 months ended March 31, 2001
increased $8 million compared to the prior year due to an increase in
depreciable property.

Taxes
Other tax expense increased $9 million for the 12 months ended March 31, 2001
due to increased property tax assessments in the state of Missouri and a refund
from previous periods recorded in the first quarter of 2000.

Other Income and Deductions
Other income and deductions for the three and 12 month periods ended March 31,
2001 increased $5 million and $7 million, respectively, due primarily to the
mark to market adjustment made in the first quarter of 2001 relating to the
adoption of Statement of Financial Accounting Standards No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (see Note 8 under Notes to
Financial Statements for further information).

Balance Sheet
The $25 million decrease in accounts receivable-trade at March 31, 2001,
compared to the year-end, was due primarily to lower revenues in February and
March 2001 compared to November and December 2000. The $18 million decrease in
intercompany notes receivable reflects changes in funds invested in a regulated
money pool (see Note 6 under Notes to Financial Statements for further
information).

                                      -3-

<PAGE>


LIQUIDITY AND CAPITAL RESOURCES

Cash provided by operating activities totaled $128 million for the three months
ended March 31, 2001, compared to $141 million during the same 2000 period.

Cash flows used in investing activities totaled $75 million and $80 million for
the three months ended March 31, 2001 and 2000, respectively. Construction
expenditures for the three months ended March 31, 2001, for constructing new or
improving existing facilities were $89 million. In addition, the Registrant
expended $8 million for the acquisition of nuclear fuel.

Cash flows used in financing activities totaled $48 million for the three months
ended March 31, 2001, compared to $171 million during the same 2000 period. The
Registrant's principal financing activities for the period included redemption
of long-term debt and the payment of dividends.

The Registrant plans to continue utilizing short-term debt to support normal
operations and other temporary requirements. The Registrant is authorized by the
Securities and Exchange Commission (SEC) under the PUHCA to have up to $1
billion of short-term unsecured debt instruments outstanding at any one time.
Short-term borrowings consist of bank loans (maturities generally on an
overnight basis) and commercial paper (maturities generally within 1 to 45
days). At March 31, 2001, the Registrant had committed bank lines of credit
aggregating $150 million (all of which was unused and available at such date)
which make available interim financing at various rates of interest based on
LIBOR, the bank certificate of deposit rate or other options. The lines of
credit are renewable annually at various dates throughout the year. At March 31,
2001, the Registrant had no outstanding short-term borrowings.

The Registrant also has a bank credit agreement due 2002 which permits the
borrowing of up to $300 million on a long-term basis, all of which was unused,
and $239 was available at March 31, 2001. In addition, the Registrant has the
ability to borrow up to approximately $488 million from Ameren or from two of
Ameren's other subsidiaries, Central Illinois Public Service Company
(AmerenCIPS) and Ameren Services Company (Ameren Services), through a regulated
money pool agreement. The total amount available to the Registrant 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 AmerenCIPS or Ameren
Services have surplus funds and the availability of other external borrowing
sources. The regulated money pool was established to coordinate and provide for
certain short-term cash and working capital requirements of the Registrant,
AmerenCIPS and Ameren Services and is administered by Ameren Services. Interest
is calculated at varying rates of interest depending on the composition of
internal and external funds in the regulated money pool. For the quarter ended
March 31, 2001, the average interest rate for the regulated money pool was
5.50%. As of March 31, 2001, the Registrant had loaned $238 million to the
regulated money pool and at least $239 million was available through the
regulated money pool subject to reduction for borrowings by AmerenCIPS or Ameren
Services.

Additionally, the Registrant has a lease agreement that provides for the
financing of nuclear fuel. At March 31, 2001, the maximum amount that could be
financed under the agreement was $120 million. Cash used in financing activities
for the three months ended March 31, 2001, included redemptions under the lease
for nuclear fuel of $35 million, offset by $2 million of issuances. At March 31,
2001, $81 million was financed under the lease.

During the course of Ameren's resource planning, several alternatives are being
considered to satisfy regulatory load requirements for 2001 and beyond for the
Registrant, AmerenCIPS and AmerenEnergy Resources Company (the Ameren subsidiary
which holds its nonregulated generation operations). The Registrant has
purchased 450 megawatts of capacity and energy for the summer of 2001 from
AmerenEnergy Resources Company, and is considering the purchase of an additional
100 megawatts. Alternatives being considered for the summer of 2002 and beyond
include the purchase of capacity and energy, among other things. At this time,
management is unable to predict which course of action it will pursue to satisfy
these requirements and their ultimate impact on the Registrant's financial
position, results of operations or liquidity.

The Registrant, in the ordinary course of business, explores opportunities to
reduce its cost in order to remain competitive in the marketplace. Areas where
the Registrant focuses its review include, but are not limited to, labor

                                      -4-

<PAGE>

costs and fuel supply  costs.  In the labor area,  over the past two years,  the
Registrant has reached  agreements with all of the Registrant's major collective
bargaining  units which will  permit it to manage its labor costs and  practices
effectively  in  the  future.  The  Registrant  also  explores  alternatives  to
effectively  manage  the  size  of its  workforce.  These  alternatives  include
utilizing hiring freezes, outsourcing and offering employee separation packages.
In the fuel supply area, the  Registrant  explores  alternatives  to effectively
manage its overall fuel costs.  These  alternatives  include  diversifying  fuel
sources  for  use  at  the  Registrant's   fossil  power  plants,   as  well  as
restructuring or terminating existing contracts with suppliers.

Certain of these cost reduction alternatives could result in additional
investments being made at the Registrant's power plants in order to utilize
different types of coal, or could require nonrecurring payments of employee
separation benefits or nonrecurring payments to restructure or terminate an
existing fuel contract with a supplier. Management is unable to predict which
(if any), and to what extent, these alternatives to reduce its overall cost
structure will be executed nor can it determine the impact of these actions on
its future financial position, results of operations or liquidity.


RATE MATTERS

In July 1995, the Missouri Public Service Commission (MoPSC) approved an
agreement establishing contractual obligations involving the Registrant's
Missouri retail electric rates. Included was a three-year experimental
alternative regulation plan (the Original Plan) that ran from July 1, 1995,
through June 30, 1998. A new three-year experimental alternative regulation plan
(the New Plan) was authorized by the MoPSC in February 1997. The New Plan runs
from July 1, 1998 through June 30, 2001. On February 1, 2001, the Registrant,
MoPSC staff, and other parties submitted filings to the MoPSC addressing the
merits of extending the current experimental alternative regulation plan. In its
filing, the Registrant supported an extension of this plan with certain
modifications, including retail electric rate reductions and additional customer
credits. The MoPSC staff filing noted several concerns with the current plan and
suggested that under traditional cost of service ratemaking, an annualized
electric rate decrease of at least $100 million could be warranted. On March 8,
2001, the MoPSC issued an Order authorizing the MoPSC staff to file an earnings
complaint to seek a rate reduction on July 1, 2001 if it determines that one is
warranted. In addition, the Order stated that the New Plan will not be continued
beyond June 30, 2001. The Registrant has been engaged in discussions with the
MoPSC staff and other parties in an effort to address issues associated with the
expiration of the New Plan, including the development of a new alternative
regulation plan. At this time, the Registrant cannot predict the outcome of
these discussions or the timing or amount of any future electric rate
reductions.

See Note 5 under Notes to Financial Statements for further discussion of the
experimental alternative regulation plan.


ELECTRIC INDUSTRY RESTRUCTURING

Certain states are considering proposals or have adopted legislation that will
promote competition at the retail level. During 2000 and in early 2001,
deregulation laws established in the state of California, coupled with high
energy prices, increasing demands for power by users in that state, transmission
constraints, and limited generation resources, among other things, negatively
impacted several major electric utilities in that state. Federal and state
regulators and legislators have proposed and implemented, in part, different
courses of action to attempt to address these issues. The Registrant does not
maintain utility operations in the state of California, nor does it provide
energy directly to utilities in that state. At this time, the Registrant is
uncertain what impact, if any, changes in deregulation laws will have on future
federal and state deregulation laws (including the state of Missouri), which
could directly impact the Registrant's 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 introduces competition into
the supply of electric energy in Illinois.

The Illinois Law, among other things, requires the phasing-in through 2002 of
retail direct access, which allows customers to choose their electric generation
supplier. The phase-in of retail direct access began on October 1, 1999,

                                      -5-

<PAGE>

with large  commercial  and  industrial  customers  principally  comprising  the
initial group.  The remaining  commercial  and industrial  customers in Illinois
were offered choice on December 31, 2000. Commercial and industrial customers in
Illinois represent approximately 7% of the Registrant's total sales. As of March
31,  2001,  the impact of retail  direct  access on the  Registrant's  financial
condition,  results of  operations or liquidity  was  immaterial.  Retail direct
access will be offered to residential customers on May 1, 2002.

Missouri
The Registrant is participating in discussions with the Missouri legislature
regarding legislation that would not restructure the electric industry in
Missouri, but would allow utilities to transfer generation assets to an
affiliated generating company. In addition, the legislation would allow the
State's largest nonresidential customers to choose their electric supplier,
among other things. At this time, the Registrant does not believe that any
electric industry legislation will be passed during the legislative session
scheduled to end in May 2001.

Midwest ISO and Alliance RTO
In the fourth quarter of 2000, the Registrant announced its intention to
withdraw from the Midwest ISO and to join the Alliance Regional Transmission
Organization (Alliance RTO), and recorded a pretax charge to earnings of $17
million ($10 million after taxes), which related to the Registrant's estimated
obligation under the Midwest ISO agreement for costs incurred by the Midwest
ISO, plus estimated exit costs. In January 2001, the FERC conditionally approved
the formation, including the rate structure, of the Alliance RTO, and the
Registrant announced that it had signed an agreement to join the Alliance RTO.
In February 2001, in a proceeding before the Federal Energy Regulatory
Commission (FERC), the Alliance RTO and the Midwest ISO reached an agreement
that would enable the Registrant to withdraw from the Midwest ISO and to join
the Alliance RTO. In April 2001, this settlement agreement was certified by the
Administrative Law Judge of the FERC and submitted to the FERC Commissioners for
approval. The settlement agreement was approved by the FERC in May 2001. The
Registrant's withdrawal from the Midwest ISO remains subject to MoPSC approval.
In addition, the Registrant's transfer of control and operation of its
transmission assets to the Alliance RTO is subject to MoPSC and Illinois
Commerce Commission approval and its membership in the Alliance RTO is subject
to SEC approval under the PUHCA. At this time, the Registrant is unable to
determine the impact that its withdrawal from the Midwest ISO and its
participation in the Alliance RTO will have on its future financial condition,
results of operation or liquidity.


QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market risk represents the risk of changes in value of a physical asset or a
financial instrument, derivative or non-derivative, caused by fluctuations in
market variables (e.g. interest rates, equity prices, commodity prices, etc.).
The following discussion of Ameren's, including the Registrant's, risk
management activities includes "forward-looking" statements that involve risks
and uncertainties. Actual results could differ materially from those projected
in the "forward-looking" statements. Ameren handles market risks in accordance
with established policies, which may include entering into various derivative
transactions. In the normal course of business, Ameren and the Registrant also
face risks that are either non-financial or non-quantifiable. Such risks
principally include business, legal, operational, and credit 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
The Registrant is exposed to market risk through changes in interest rates
through its issuance of both long-term and short-term variable-rate debt and
fixed-rate debt, and commercial paper. The Registrant manages its interest rate
exposure by controlling the amount of these instruments it holds within its
total capitalization portfolio and by monitoring the effects of market changes
in interest rates.

If interest rates increase one percentage point in 2002, as compared to 2001,
the Registrant's interest expense would increase by approximately $5 million,
and net income would decrease by approximately $3 million. This amount has been
determined using the assumptions that the Registrant's outstanding variable-rate
debt and commercial paper, as of March 31, 2001, continued to be outstanding
throughout 2002, and that the average interest rates for these instruments
increased one percentage point over 2001. The estimate 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

                                      -6-

<PAGE>

significant  change in interest rates,  management  would likely take actions to
further  mitigate  its  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  the  Registrant's
financial structure.

Commodity Price Risk
The Registrant is exposed to changes in market prices for natural gas, fuel and
electricity. Several techniques are utilized to mitigate the Registrant's risk,
including utilizing derivative financial instruments. A derivative is a contract
whose value is dependent on, or derived from, the value of some underlying
asset. The derivative financial instruments that the Registrant uses (primarily
forward contracts, futures contracts and option contracts) are dictated by risk
management policies.

With regard to its natural gas utility business, the Registrant's exposure to
changing market prices is in large part mitigated by the fact that the
Registrant has purchased gas adjustment clauses (PGAs) in place in both its
Missouri and Illinois jurisdictions. The PGA allows the Registrant to pass on to
its customers its prudently incurred costs of natural gas.

Ameren has a subsidiary, AmerenEnergy Fuels and Services Company, a wholly owned
subsidiary of AmerenEnergy Resources Company, which is responsible for providing
fuel procurement and gas supply services on behalf of Ameren's operating
subsidiaries, and for managing fuel and natural gas price risks. Fixed price
forward contracts, as well as futures and options, are all instruments, which
may be used to manage these risks. The majority of the Registrant's fuel supply
contracts are physical forward contracts. Since the Registrant does not have a
provision similar to the PGA for its electric operations, the Registrant has
entered into several long-term contracts with various suppliers to purchase coal
and nuclear fuel to manage its exposure to fuel prices.

With regard to the Registrant's exposure to commodity price risk for purchased
power and excess electricity sales, Ameren has a subsidiary, AmerenEnergy, Inc.,
(AmerenEnergy), whose primary responsibility includes managing market risks
associated with changing market prices for electricity purchased and sold on
behalf of the Registrant.

Although the Registrant cannot completely eliminate the effects of elevated
prices and price volatility, its strategy is designed to minimize the effect of
these market conditions on the results of operations. The Registrant's gas
procurement strategy includes procuring natural gas under a portfolio of
agreements with price structures, including fixed price, indexed price and
embedded price hedges such as caps and collars. The Registrant's strategy also
utilizes physical assets through storage, operator and balancing agreements to
minimize price volatility. The Registrant's electric marketing strategy is to
extract additional value from its generation facilities by selling energy in
excess of needs for term sales and purchasing energy when the market price is
less than the cost of generation. The Registrant's primary use of derivatives
has been limited to transactions that are expected to reduce price risk exposure
for the Registrant.

Equity Price Risk
The Registrant maintains trust funds, as required by the Nuclear Regulatory
Commission and Missouri and Illinois state laws, to fund certain costs of
nuclear decommissioning. As of March 31, 2001, these funds were invested
primarily in domestic equity securities, fixed-rate, fixed-income securities,
and cash and cash equivalents. By maintaining a portfolio that includes
long-term equity investments, the Registrant is seeking to maximize the returns
to be utilized to fund nuclear decommissioning costs. However, the equity
securities included in the Registrant's portfolio are exposed to price
fluctuations in equity markets, and the fixed-rate, fixed-income securities are
exposed to changes in interest rates. The Registrant actively monitors its
portfolio by benchmarking the performance of its investments against certain
indices and by maintaining, and periodically reviewing, established target
allocation percentages of the assets of its trusts to various investment
options. The Registrant's exposure to equity price market risk is, in large
part, mitigated, due to the fact that the Registrant is currently allowed to
recover its decommissioning costs in its rates.

                                      -7-

<PAGE>


SAFE HARBOR STATEMENT

Statements made in this Form 10-Q 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, the Registrant is 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  fiscal  year  ended  December  31,  2000,  and in  subsequent
securities  filings,  could cause results to differ  materially  from management
expectations as suggested by such "forward-looking"  statements:  the effects of
regulatory actions,  including changes in regulatory policy; changes in laws and
other governmental  actions; the impact on the Registrant of current regulations
related  to the  phasing-in  of the  opportunity  for some  customers  to choose
alternative energy suppliers in Illinois;  the effects of increased  competition
in the future,  due to, among other things,  deregulation  of certain aspects of
the Registrant's  business at both the state and federal levels;  the effects of
withdrawal  from the Midwest ISO and  membership in Alliance RTO;  future market
prices for fuel and purchased power, electricity, and natural gas, including the
use of financial  instruments;  average  rates for  electricity  in the Midwest;
business and economic conditions; interest rates; weather conditions; the impact
of the  adoption of new  accounting  standards;  fuel  prices and  availability;
generation  plant  construction,  installation  and  performance;  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;  monetary  and  fiscal
policies; future wages and employee benefits costs; and legal and administrative
proceedings.

                                      -8-


<PAGE>

<TABLE>
<CAPTION>


                             UNION ELECTRIC COMPANY
                                  BALANCE SHEET
                                    UNAUDITED
                      (Thousands of Dollars, Except Shares)



                                                                                  March 31,         December 31,
ASSETS                                                                                2001                 2000
------                                                                        ------------------    -----------------
<S>                                                                            <C>                   <C>
Property and plant, at original cost:
   Electric                                                                      $  9,487,985          $  9,449,275
   Gas                                                                                238,817               236,139
   Other                                                                               37,062                37,140
                                                                              -----------------      ----------------
                                                                                    9,763,864             9,722,554
   Less accumulated depreciation and amortization                                   4,630,401             4,571,292
                                                                              -----------------      ----------------
                                                                                    5,133,463             5,151,262
Construction work in progress:
   Nuclear fuel in process                                                            125,554               117,789
   Other                                                                              145,948               111,527
                                                                              ----------------       ----------------
         Total property and plant, net                                              5,404,965             5,380,578
                                                                              ----------------       ----------------
Investments and other assets:
   Nuclear decommissioning trust fund                                                 179,690               190,625
   Other                                                                               84,501                65,811
                                                                              ----------------       ----------------
         Total investments and other assets                                           264,191               256,436
                                                                              ----------------       ----------------
Current assets:
   Cash and cash equivalents                                                           25,287                19,960
   Accounts receivable - trade (less allowance for doubtful
         accounts of $5,830 and $6,251 respectively)                                  252,689               277,947
   Other accounts and notes receivable                                                 44,428                28,216
   Intercompany notes receivable                                                      238,020               255,570
   Materials and supplies, at average cost -
      Fossil fuel                                                                      42,680                52,155
      Other                                                                            82,536                82,161
   Other                                                                               15,740                16,757
                                                                              ----------------      ----------------
         Total current assets                                                         701,380               732,766
                                                                              ----------------      ----------------
Regulatory assets:
   Deferred income taxes                                                              600,238               599,973
   Other                                                                              143,113               146,373
                                                                              ----------------      ----------------
         Total regulatory assets                                                      743,351               746,346
                                                                              ----------------      ----------------
Total Assets                                                                     $  7,113,887          $  7,116,126
                                                                              ================      ================

CAPITAL AND LIABILITIES
Capitalization:
   Common stock, $5 par value, 150,000,000 shares authorized -
     102,123,834 shares outstanding                                              $    510,619          $    510,619
   Other paid-in capital, principally premium on
     common stock                                                                     701,896               701,896
   Retained earnings                                                                1,340,202             1,358,137
   Accumulated other comprehensive income                                              (2,085)                  -
                                                                              ----------------      ----------------
         Total common stockholder's equity                                          2,550,632             2,570,652
   Preferred stock not subject to mandatory redemption                                155,197               155,197
   Long-term debt                                                                   1,769,072             1,760,439
                                                                              ----------------      ----------------
         Total capitalization                                                       4,474,901             4,486,288
                                                                              ----------------      ----------------
Current liabilities:
   Accounts and wages payable                                                         224,388               293,511
   Accumulated deferred income taxes                                                   21,465                30,325
   Taxes accrued                                                                      142,030                86,125
   Other                                                                              213,243               196,127
                                                                              ----------------      ----------------
         Total current liabilities                                                    601,126               606,088
                                                                              ----------------      ----------------
Accumulated deferred income taxes                                                   1,318,397             1,315,109
Accumulated deferred investment tax credits                                           131,322               132,922
Regulatory liability                                                                  147,478               148,643
Other deferred credits and liabilities                                                440,663               427,076
                                                                              ----------------      ----------------
Total Capital and Liabilities                                                    $  7,113,887          $  7,116,126
                                                                              ===============       ================

See Notes to Financial Statements.

</TABLE>

                                      -9-

<PAGE>

<TABLE>
<CAPTION>


                             UNION ELECTRIC COMPANY
                               STATEMENT OF INCOME
                                    UNAUDITED
                             (Thousands of Dollars)



                                                          Three Months Ended                   Twelve Months Ended
                                                               March 31,                              March 31,
                                                      -------------------------           -----------------------------
                                                          2001          2000                  2001            2000
                                                          ----          ----                  ----            ----
<S>                                                   <C>             <C>                  <C>             <C>
 OPERATING REVENUES:
    Electric                                            $596,865        $519,113             $2,667,748      $2,499,690
    Gas                                                   69,236          42,077                156,400          89,138
    Other                                                    107             -                      107             151
                                                        -----------  -------------        ---------------   -------------
       Total operating revenues                          666,208         561,190              2,824,255       2,588,979

 OPERATING EXPENSES:
    Operations
       Fuel and purchased power                          219,301         172,438                775,375         708,397
       Gas                                                45,576          22,599                104,500          55,268
       Other                                             130,451         104,725                526,025         441,257
                                                       ---------       ---------          ---------------   -------------
                                                         395,328         299,762              1,405,900       1,204,922
    Maintenance                                           58,505          52,260                256,275         248,772
    Depreciation and amortization                         68,822          67,066                272,132         264,427
    Income taxes                                          31,012          28,612                229,200         228,048
    Other taxes                                           49,864          47,715                211,609         202,654
                                                       ----------      ----------           ------------    -------------
       Total operating expenses                          603,531         495,415              2,375,116       2,148,823

 OPERATING INCOME                                         62,677          65,775                449,139         440,156

 OTHER INCOME AND (DEDUCTIONS):
    Allowance for equity funds used during
       construction                                        1,605           1,229                  5,674           5,730
    Miscellaneous, net                                     7,037           2,879                 20,604          13,199
                                                       -----------     -----------          --------------  -------------
       Total other income and (deductions)                 8,642           4,108                 26,278          18,929

 INCOME BEFORE INTEREST CHARGES                           71,319          69,883                475,417         459,085

 INTEREST CHARGES :
    Interest                                              30,555          32,466                 127,371        121,521
    Allowance for borrowed funds used during
    construction                                          (2,285)         (1,819)                 (8,778)        (7,181)
                                                       ------------      ---------            -------------  ------------
       Net interest charges                                28,270          30,647                 118,593       114,340
                                                       ------------      ---------            -------------  ------------

 INCOME BEFORE CUMULATIVE EFFECT OF CHANGE
            IN ACCOUNTING PRINCIPLE                        43,049          39,236                 356,824       344,745

 CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
            PRINCIPLE, NET OF INCOME TAXES                 (4,848)            -                    (4,848)           -
                                                        -----------      ---------            -------------  ------------
 NET INCOME                                                38,201          39,236                 351,976       344,745

 PREFERRED STOCK DIVIDENDS                                  2,204           2,204                   8,817         8,817
                                                        ---------        ---------            -------------   -----------

NET INCOME AFTER PREFERRED
            STOCK DIVIDENDS                               $35,997         $37,032                $343,159      $335,928
                                                        ==========       =========            =============   ===========

 See Notes to Financial Statements.
</TABLE>

                                      -10-

<PAGE>

<TABLE>
<CAPTION>


                             UNION ELECTRIC COMPANY
                             STATEMENT OF CASH FLOWS
                                    UNAUDITED
                             (Thousands of Dollars)




                                                                                     Three Months Ended
                                                                                           March 31,
                                                                                      --------------------
                                                                                 2001                2000
                                                                                 ----                ----
<S>                                                                           <C>                  <C>
Cash Flows From Operating:
   Net income                                                                   $38,201              $39,236
   Adjustments to reconcile net income to net cash
      provided by operating activities:
        Cumulative effect of change in accounting principle                       4,848                  -
        Depreciation and amortization                                            65,835               64,077
        Amortization of nuclear fuel                                              8,575                9,075
        Allowance for funds used during construction                             (3,889)              (3,048)
        Deferred income taxes, net                                               (5,802)              (3,284)
        Deferred investment tax credits, net                                     (1,600)              (1,520)
        Changes in assets and liabilities:
           Receivables, net                                                       9,046               44,697
           Materials and supplies                                                 9,100               18,769
           Accounts and wages payable                                            69,123)            (104,429)
           Taxes accrued                                                         55,905               52,032
           Other, net                                                            17,168               25,030
                                                                               ---------           ----------
Net cash provided by operating activities                                       128,264              140,635

Cash Flows From Investing:
   Construction expenditures                                                    (89,286)            (100,124)
   Allowance for funds used during construction                                   3,889                3,048
   Nuclear fuel expenditures                                                     (7,505)              (6,228)
   Intercompany notes receivable                                                 17,550               23,240
                                                                               ---------           ----------
Net cash used in investing activities                                           (75,352)             (80,064)

Cash Flows From Financing:
   Dividends on common stock                                                    (53,932)             (69,076)
   Dividends on preferred stock                                                  (2,204)              (2,204)
   Environmental bond redemption fund                                                -              (186,500)
      Redemptions -
         Nuclear fuel lease                                                     (34,976)              (1,818)
         Long-term debt                                                              -               (99,722)
      Issuances -
         Nuclear fuel lease                                                       1,727                1,356
         Long-term debt                                                          41,800              186,500
                                                                               ---------           ----------
Net cash used in financing activities                                           (47,585)            (171,464)
                                                                               ---------           ----------

Net change in cash and cash equivalents                                           5,327             (110,893)
Cash and cash equivalents at beginning of year                                   19,960              117,308
                                                                               ---------           ----------

Cash and cash equivalents at end of period                                      $25,287             $  6,415
                                                                               =========           ===========

Cash paid during the periods:
   Interest (net of amount capitalized)                                         $21,292              $22,890
   Income taxes, net                                                         $      415              $  (179)

See Notes to Financial Statements.

</TABLE>

                                      -11-

<PAGE>

<TABLE>
<CAPTION>

                             UNION ELECTRIC COMPANY
                    STATEMENT OF COMMON STOCKHOLDER'S EQUITY
                                    UNAUDITED
                             (Thousands of Dollars)



                                                                              Three Months Ended               Year Ended
                                                                                March 31, 2001              December 31, 2000
                                                                              ---------------------       -------------------
<S>                                                                         <C>                           <C>
Common stock                                                                  $   510,619                   $    510,619

Other paid-in capital                                                             701,896                        701,896


Retained earnings
   Beginning balance                                                            1,358,137                      1,221,167
   Net income                                                                      38,201                        353,011
   Common stock dividends                                                         (53,932)                      (207,224)
   Preferred stock dividends                                                       (2,204)                        (8,817)
                                                                              ---------------------       -------------------
                                                                                1,340,202                      1,358,137


Accumulated other comprehensive income
   Beginning balance                                                                  -                              -
   Change in current period                                                        (2,085)                           -
                                                                              ---------------------       -------------------
                                                                                   (2,085)                           -

                                                                              ---------------------       -------------------
Total common stockholder's equity                                             $ 2,550,632                   $  2,570,652
                                                                              =====================       ===================


Comprehensive income, net of tax
   Net income                                                                 $    38,201                   $    353,011
   Cumulative effect of accounting change, net of taxes                            (7,881)                           -
   Unrealized net gain on derivative hedging instruments                            5,796                            -
                                                                              ---------------------       -------------------
                                                                              $    36,116                   $    353,011
                                                                              =====================       ===================


See Notes to Financial Statements.

</TABLE>

                                      -12-

<PAGE>


UNION ELECTRIC COMPANY
NOTES TO FINANCIAL STATEMENTS (UNAUDITED)
March 31, 2001

Note 1 - Union Electric Company (AmerenUE or the Registrant) is a subsidiary of
Ameren Corporation (Ameren), a holding company registered under the Public
Utility Holding Company Act of 1935 (PUHCA). Ameren is the parent company of the
following operating subsidiaries: the Registrant, Central Illinois Public
Service Company (AmerenCIPS), and AmerenEnergy Generating Company, a wholly
owned subsidiary of AmerenEnergy Resources Company. Both Ameren and its
subsidiaries are subject to the regulatory provisions of the PUHCA. The
Registrant is a public utility engaged principally in the generation,
transmission, distribution and sale of electric energy and the purchase,
distribution, transportation and sale of natural gas in the states of Missouri
and Illinois. Contracts among the Registrant and other Ameren
subsidiaries--dealing with jointly-owned generating facilities, interconnecting
transmission lines, and the exchange of electric power--are regulated by the
Federal Energy Regulatory Commission (FERC) or the Securities and Exchange
Commission (SEC). Administrative support services are provided to the Registrant
by a separate Ameren subsidiary, Ameren Services Company (Ameren Services). The
Registrant serves 1.2 million electric and 125,000 gas customers in a 24,500
square-mile area of Missouri and Illinois, including Metropolitan St. Louis.

The Registrant also has a 40 percent interest in Electric Energy, Inc. (EEI),
which is accounted for under the equity method of accounting. EEI owns and/or
operates electric generating and transmission facilities in Illinois that supply
electric power primarily to a uranium enrichment plant located in Paducah,
Kentucky.

Note 2 - Financial statement note disclosures, normally included in financial
statements prepared in conformity with generally accepted accounting principles,
have been omitted in this Form 10-Q pursuant to the Rules and Regulations of the
SEC. However, in the opinion of the Registrant, the disclosures contained in
this Form 10-Q are adequate to make the information presented not misleading.
See Notes to Financial Statements included in the 2000 Form 10-K for information
relevant to the financial statements contained in this Form 10-Q, including
information as to the significant accounting policies of the Registrant.

Note 3 - In the opinion of the Registrant, the interim financial statements
filed as part of this Form 10-Q reflect all adjustments, consisting only of
normal recurring adjustments, necessary for a fair statement of the results for
the periods presented.

Note 4 - Due to the effect of weather on sales and other factors which are
characteristic of public utility operations, financial results for the periods
ended March 31, 2001 and 2000, are not necessarily indicative of trends for any
three-month or 12-month period.

Note 5 - - In July 1995, the Missouri Public Service Commission (MoPSC) approved
an agreement establishing contractual obligations involving the Registrant's
Missouri retail electric rates. Included was a three-year experimental
alternative regulation plan (the Original Plan) that ran from July 1, 1995
through June 30, 1998, which provided that earnings in those years in excess of
a 12.61 percent regulatory return on equity (ROE) be shared equally between
customers and stockholders, and earnings above a 14 percent ROE be credited to
customers. The formula for computing the credit used twelve-month results ending
June 30, rather than calendar year earnings.

The MoPSC staff proposed adjustments to the Registrant's estimated customer
credit for the final year of the Original Plan ended June 30, 1998, which were
the subject of regulatory proceedings before the MoPSC in 1999. In December
1999, the MoPSC issued a Report and Order (Order) concerning these proposed
adjustments. Based on the provisions of that Order, the Registrant revised its
estimated final year credit to $31 million. Subsequently, the Registrant filed a
request for rehearing of the Order with the MoPSC, asking that it reconsider its
decision to adopt certain of the MoPSC staff's adjustments. The request was
denied by the MoPSC and in February 2000, the Registrant filed a Petition for
Writ of Review with the Circuit Court of Cole County, Missouri, requesting that
the Order be reversed. The appeal is pending and the ultimate outcome can not be
predicted; however, the final decision is not expected to

                                      -13-

<PAGE>

materially impact the financial condition, results of operations or liquidity of
the Registrant. A partial stay of the Order was granted by the Court pending the
appeal.

A new three-year experimental alternative regulation plan (the New Plan) was
included in the joint agreement authorized by the MoPSC in its February 1997
order approving the merger of the Registrant and CIPSCO Incorporated, which
formed Ameren (the Merger). Like the Original Plan, the New Plan requires that
earnings over a 12.61 percent ROE up to a 14 percent ROE be shared equally
between customers and stockholders. The New Plan also returns to customers 90
percent of all earnings above a 14 percent ROE up to a 16 percent ROE. Earnings
above a 16 percent ROE are credited entirely to customers. The New Plan runs
from July 1, 1998 through June 30, 2001. During the three months ended March 31,
2001, the Registrant recorded an estimated $15 million credit for the plan year
ending June 30, 2001 that the Registrant expects to pay its Missouri electric
customers. In total, the Registrant has recorded an estimated credit of $65
million as of March 31, 2001 for the plan year ending June 30, 2001, compared to
an estimated $30 million credit recorded over the same period last year. These
credits were reflected as a reduction in electric revenues. The final amount of
the credit will depend on several factors, including the Registrant's earnings
for 12 months ended June 30, 2001. In March 2001, the MoPSC approved a
stipulation and agreement of the parties regarding the credit for the plan year
ended June 30, 2000. As of March 31, 2001, the Registrant has reflected an
estimated $30 million credit it expects to pay its Missouri electric customers
for the plan year ended June 30, 2000.

The joint agreement approved by the MoPSC in its February 1997 order approving
the Merger also provided for a Missouri electric rate decrease, retroactive to
September 1, 1998, based on the weather-adjusted average annual credits to
customers under the Original Plan. The rate decrease was impacted by the Order
issued by the MoPSC in December 1999 relating to the estimated credit for the
third year of the Original Plan and a settlement reached between the Registrant,
the MoPSC staff and other parties relating to the calculation of the
weather-adjusted credits. Based on those results, the Registrant estimates that
its Missouri electric rate decrease will be $17 million on an annualized basis.
This estimate is subject to the final outcome of the above-referenced court
appeal of the Order.

On February 1, 2001, the Registrant, MoPSC staff, and other parties submitted
filings to the MoPSC addressing the merits of extending the current experimental
alternative regulation plan. In its filing, the Registrant supported an
extension of this plan with certain modifications, including retail electric
rate reductions and additional customer credits. The MoPSC staff filing noted
several concerns with the current plan and suggested that under traditional cost
of service ratemaking, an annualized electric rate decrease of at least $100
million could be warranted. On March 8, 2001, the MoPSC issued an Order
authorizing the MoPSC staff to file an earnings complaint to seek a rate
reduction on July 1, 2001, if it determines one is warranted. In addition, the
Order stated that the New Plan will not be continued beyond June 30, 2001. The
Registrant has been engaged in discussions with the MoPSC staff and other
parties in an effort to address issues associated with the expiration of the New
Plan, including the development of a new alternative regulation plan. At this
time, the Registrant cannot predict the outcome of these discussions or the
timing or amount of any future electric rate reductions.

Note 6 - The Registrant has transactions in the normal course of business with
other Ameren subsidiaries. These transactions are primarily comprised of power
purchases and sales and services received or rendered. Intercompany receivables
included in other accounts and notes receivable were approximately $87 million
and $20 million, respectively, as of March 31, 2001 and December 31, 2000.
Intercompany payables included in accounts and wages payable totaled
approximately $94 million and $27 million, respectively, as of March 31, 2001
and December 31, 2000.

Also, the Registrant has the ability to borrow up to approximately $488 million
from Ameren, AmerenCIPS or Ameren Services through a regulated money pool
agreement. The total amount available to the Registrant 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 AmerenCIPS or Ameren Services have
surplus funds and the availability of other external borrowing sources. The
regulated money pool was established to coordinate and provide for certain
short-term cash and working capital requirements of the Registrant, AmerenCIPS
and Ameren Services and is administered by Ameren Services. Interest is

                                      -14-

<PAGE>

calculated at varying rates of interest depending on the composition of internal
and external funds in the regulated money pool. For the quarter ended March 31,
2001, the average interest rate for the regulated money pool was 5.50%.
Intercompany interest income for the quarters ended March 31, 2001 and 2000 was
approximately $3 million and $2 million, respectively. For the 12-month periods
ended March 31, 2001 and 2000, intercompany interest income was approximately
$11million and $8 million, respectively. As of March 31, 2001, the Registrant
had outstanding intercompany receivables of $238 million and at least $239
million was available through the regulated money pool subject to reduction for
borrowings by AmerenCIPS or Ameren Services.

Note 7 - In the fourth quarter of 2000, the Registrant announced its intention
to withdraw from the Midwest Independent System Operator (Midwest ISO) and to
join the Alliance Regional Transmission Organization (Alliance RTO), and
recorded a pretax charge to earnings of $17 million ($10 million after taxes),
which related to the Registrant's estimated obligation under the Midwest ISO
agreement for costs incurred by the Midwest ISO, plus estimated exit costs. In
January 2001, the FERC conditionally approved the formation, including the rate
structure, of the Alliance RTO, and the Registrant announced that it had signed
an agreement to join the Alliance RTO. In February 2001, in a proceeding before
the FERC, the Alliance RTO and the Midwest ISO reached an agreement that would
enable the Registrant to withdraw from the Midwest ISO and to join the Alliance
RTO. In April 2001, this settlement agreement was certified by the
Administrative Law Judge of the FERC and submitted to the FERC Commissioners for
approval. The settlement agreement was approved by the FERC in May 2001. The
Registrant's withdrawal from the Midwest ISO remains subject to MoPSC approval.
In addition, the Registrant's transfer of control and operation of its
transmission assets to the Alliance RTO is subject to MoPSC and Illinois
Commerce Commission approval and its membership in the Alliance RTO is subject
to SEC approval under the PUHCA. At this time, the Registrant is unable to
determine the impact that its withdrawal from the Midwest ISO and its
participation in the Alliance RTO will have on its future financial condition,
results of operation or liquidity.

Note 8 -Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting
for Derivative Instruments and Hedging Activities" became effective on January
1, 2001. SFAS 133 established accounting and reporting standards for derivative
financial instruments, including certain derivative instruments embedded in
other contracts, and for hedging activities. SFAS 133 requires recognition of
all derivatives as either assets or liabilities on the balance sheet measured at
fair value. The intended use of derivatives and their designation as either a
fair value hedge or a cash flow hedge determines when the gains or losses on the
derivatives are to be reported in earnings and when they are reported as a
component of other comprehensive income (OCI) in stockholders' equity. In
accordance with the transition provisions of SFAS 133, the Registrant recorded a
cumulative effect charge of $5 million after income taxes to the income
statement, comprised of $1 million for ineffective portion of cash flow hedges
and $4 million for discontinued hedges. The Registrant also recorded a
cumulative effect adjustment of $8 million after income taxes, representing the
effective portion of designated cash flow hedges, to OCI, which reduced
stockholders' equity. The Registrant expects that within the next twelve months
it will reclassify to earnings all of the transition adjustment that was
recorded in accumulated other comprehensive income. Gains and losses on
derivatives that arose prior to the initial application of SFAS 133 and that
were previously deferred as adjustments of the carrying amount of hedged items
were not adjusted and were not included in the transition adjustments described
above.

All derivatives are recognized on the balance sheet at their fair value. On the
date that the Registrant enters into a derivative contract, it designates the
derivative as (1) a hedge of the fair value of a recognized asset or liability
or an unrecognized firm commitment (a "fair value" hedge); (2) a hedge of a
forecasted transaction or the variability of cash flows that are to be received
or paid in connection with a recognized asset or liability (a "cash flow"
hedge); or (3) an instrument that is held for trading or non-hedging purposes (a
"trading" or "non-hedging" instrument). The Registrant reevaluates its
classification of individual derivative transactions daily. The Registrant
designates or de-designates derivative transactions as hedges based on many
factors including changes in expectations of economic generation availability
and changes in projected sales commitments. Changes in the fair value of
derivatives are captured and reported based on the anticipated use of the
derivative. If a derivative is designated as a cash flow hedge, the effective
portion will not be reflected in the income statement. If the derivative is
subsequently designated

                                      -15-

<PAGE>

as a non-hedging instrument,  any further change in fair value will be reflected
in the  income  statement,  with any  previously  deferred  change in fair value
remaining in accumulated  OCI until the indicated  delivery  period.  If, on the
other hand, the derivative had been designated as a non-hedging  transaction and
subsequently  designated as a cash flow hedge,  the initial change in fair value
between the transaction date and the hedge  designation date will be recorded in
income, and the effective portion of any further change will be deferred in OCI.
Changes in the fair value of  derivatives  designated  as fair value  hedges and
changes in the fair value of the hedged asset or liability that are attributable
to the hedged  risk  (including  changes  that  reflect  losses or gains on firm
commitments) are recorded in current-period  earnings. Any hedge ineffectiveness
(which  represents  the  amount by which the  changes  in the fair  value of the
derivative  exceed the changes in the fair value of the hedged item) is recorded
in current-period earnings.  Changes in the fair value of derivative trading and
non-hedging instruments are reported in current-period earnings.

The Registrant utilizes derivatives principally to manage the risk of changes in
market prices for natural gas, fuel, electricity and emission credits. The
Registrant's risk management objective is to optimize the return from its
physical generating assets, while managing exposures to volatile energy
commodity prices and emission allowances within prudent risk management
policies, which are established by a Risk Management Steering Committee (RMSC)
comprised of senior-level Ameren officers. Price fluctuations in natural gas,
fuel and electricity cause (1) an unrealized appreciation or depreciation of the
Registrant's firm commitments to purchase when purchase prices under the firm
commitment are compared with current commodity prices; (2) market values of fuel
and natural gas inventories or purchased power to differ from the cost of those
commodities under the firm commitment; and (3) actual cash outlays for the
purchase of these commodities to differ from anticipated cash outlays. The
derivatives that the Registrant uses to hedge these risks are dictated by risk
management policies and include forward contracts, futures contracts, options
and swaps. The Registrant primarily uses derivatives to optimize the value of
its physical and contractual positions. The Registrant continually assesses its
supply and delivery commitment positions against forward market prices and
internally forecast forward prices and modifies its exposure to market, credit
and operational risk by entering into various offsetting transactions. In
general these transactions serve to reduce price risk for the Registrant.
Additionally, the Registrant is authorized to engage in certain transactions
that serve to increase the organization's exposure to price, credit and
operational risk for expected gains. All transactions are continuously monitored
and valued by the independent risk management group to assure compliance with
Ameren policies. The risk management group employs a variety of risk measurement
techniques and position limits including value at risk, credit value at risk,
stress testing, effectiveness testing along with qualitative measures to
establish transaction parameters and measure transaction compliance.

By using derivative financial instruments, the Registrant is exposed to credit
risk and market risk. Credit risk is the risk that the counterparty might fail
to fulfill its performance obligations under contractual terms. Credit risk
management is based upon consideration and measurement of four factors: (1)
accounts receivable (2) mark to market (3) probability of default and (4) the
recovery rate of the defaulted position that is likely to be recovered. The
Registrant manages its credit (or repayment) risk in derivative instruments by
(1) using both portfolio limits, i.e. no more than prescribed dollar amounts
exposed to companies within various credit categories as well as limiting
exposures to individual companies, (2) monitoring the financial condition of its
counterparties and, (3) enhancing credit quality through contractual terms such
as netting, required collateral postings, letters of credit and parental
guaranties.

Market risk is the risk that the value of a financial instrument might be
adversely affected by a change in commodity prices. The Registrant manages this
risk by establishing and monitoring parameters that limit the types and degree
of market risk that may be undertaken as mentioned above.

The following is a summary of the Registrant's risk management strategies and
the effect of these strategies on the Registrant's financial statements.

Cash Flow Hedges
The Registrant routinely enters into forward sales contracts for electricity
based on forecasted levels of excess economic generation. The amount of excess
economic generation that may be sold forward varies throughout the year and is
monitored by the RMSC. The contracts typically cover a period of twelve

                                      -16-

<PAGE>

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.  The Registrant formally documents all relationships  between hedging
instruments  and hedged  items,  as well as its  risk-management  objective  and
strategy for  undertaking  various  hedge  transactions.  This process  includes
linking  all  derivatives  that are  designated  as cash flow hedges to specific
forecasted transactions.  The Registrant also formally assesses (both at hedge's
inception  and on an ongoing  basis)  whether the  derivatives  that are used in
hedging  transactions  have  historically  been highly  effective in  offsetting
changes in the cash flows of hedged  items and  whether  those  derivatives  are
expected to remain highly effective in future periods.

For the three months ended March 31, 2001, the net gain, which represented the
total ineffectiveness of all cash flow hedges as well as the reversal of amounts
previously recorded in the transition adjustment due to transactions going to
delivery, was immaterial. All components of each derivative's gain or loss were
included in the assessment of hedge effectiveness. Additionally, the Registrant
recorded a pretax net gain of $6 million as Miscellaneous, net in the statement
of income due to the change in value of discontinued cash flow hedges,
non-hedging transactions and the reversal of amounts previously recorded in the
transition adjustment due to transactions going to delivery.

As of March 31, 2001, all of the deferred net losses on derivative instruments
accumulated in other comprehensive income are expected to be reversed during the
next twelve months. The derivative losses will be reversed due to delivery of
the commodity being hedged.

Other Derivatives
The Registrant enters into option transactions to manage the Registrant's
positions in sulfur dioxide (SO2) allowances. In addition, the Registrant enters
into option transactions to manage the Registrant's coal purchasing prices and
to manage the cost of electricity by selling puts at prices below the marginal
cost of generation. These transactions are treated as non-hedge transactions
under FAS 133; therefore, the net change in the market value of SO2 options and
coal options are recorded as Miscellaneous, net in the statement of income.

Other
As of March 31, 2001, the Registrant has recorded the fair value of derivative
financial instrument assets of $10 million in Other Assets and derivative
financial instrument liabilities of $19 million in Other Deferred Credits and
Liabilities.

The Registrant has entered into fixed-price forward contracts for the purchase
of coal and natural gas. While these contracts meet the definition of a
derivative under SFAS 133, the Registrant records these transactions as normal
purchases and normal sales because the contracts are expected to result in
physical delivery.

                                      -17-

<PAGE>

                           PART II. OTHER INFORMATION


ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K
         --------------------------------

         (a)   Exhibits.

               Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges
               and Preferred Stock Dividend Requirements, 12 Months Ended March
               31, 2001.

         (b)   Reports on Form 8-K. The Registrant filed a report on Form 8-K
               dated January 11, 2001 reporting the recording of a nonrecurring
               charge in the fourth quarter of 2000 as a result of its decision
               to withdraw from the Midwest ISO.


                                   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/ Donald E. Brandt
                                    -------------------------------------
                                                 Donald E. Brandt
                                              Senior Vice President
                                          Finance and Corporate Services
                                           (Principal Financial Officer)


Date:  May 15, 2001

                                      -18-

<PAGE>


<TABLE>
<CAPTION>
                                                                                                    Exhibit 12


                                                            UNION ELECTRIC COMPANY
                    COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES AND PREFERRED STOCK DIVIDEND REQUIREMENTS

                                                                                                      12 Months
                                                                                                        Ended
                                       Year Ended December 31,                                         March 31,
                                      --------------------------------------------------------------------------

                                            1996         1997        1998        1999        2000        2001
                                            ----         ----        ----        ----        ----        ----

                                                        Thousands of Dollars Except Ratios

<S>                                      <C>         <C>         <C>         <C>         <C>         <C>
Net Income                                 $304,876    $301,655    $320,070    $349,252    $353,011    $351,976
Add- Extraordinary items net of tax               -      26,967           -           -           -           -
                                          ----------   ---------   ---------   ---------   ---------   ---------
Net income from continuing operations       304,876     328,622     320,070     349,252     353,011     351,976

                                          ----------   ---------   ---------   ---------   ---------   ---------
   Taxes based on income                    196,210     199,763     212,554     226,696     224,149     228,707
                                          ----------   ---------   ---------   ---------   ---------   ---------

Net income before income taxes              501,086     528,385     532,624     575,948     577,160     580,683
                                          ----------   ---------   ---------   ---------   ---------   ---------



Add- fixed charges:
   Interest on long term debt               120,547     125,705     124,766     117,899     121,763     119,854
   Other interest                             7,828       9,299       1,660      (1,342)      4,219       4,220
   Rentals                                    3,458       3,727       3,416       3,899       3,928       3,712
   Amortization of net debt premium, discount,
      expenses and losses                     4,269       3,672       3,522       3,421       3,300       3,296

                                          ----------   ---------   ---------   ---------   ---------   ---------
Total fixed charges                         136,102     142,403     133,364     123,877     133,210     131,082
                                          ----------   ---------   ---------   ---------   ---------   ---------

Earnings available for fixed charges        637,188     670,788     665,988     699,825     710,370     711,765
                                          ==========   =========   =========   =========   =========   =========

Ratio of earnings to fixed charges             4.68        4.71        4.99        5.64        5.33        5.42
                                          ==========   =========   =========   =========   =========   =========


Earnings required for preferred dividends:
   Preferred stock dividends                 13,249       8,817       8,817       8,817       8,817       8,817
   Adjustment to pre-tax basis                7,363       4,257       4,649       4,544       4,439       4,551
                                          ----------   ---------   ---------   ---------   ---------   ---------
                                             20,612      13,074      13,466      13,361      13,256      13,368

Fixed charges plus preferred stock dividend
    requirements                            156,714     155,477     146,830     137,238     146,466     144,450
                                          ==========   =========   =========   =========   =========   =========

Ratio of earnings to fixed charges plus
    preferred stock dividend requirements      4.06        4.31        4.53        5.09        4.85        4.92
                                          ==========   =========   =========   =========   =========   =========

</TABLE>