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 September 30, 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 1-14756.

                               AMEREN CORPORATION
             (Exact name of registrant as specified in its charter)

                     Missouri                                  43-1723446
         (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 registrant's classes of common stock as of
  November 13, 2001: Common Stock, $ .01 par value - 137,622,840




                               Ameren Corporation

                                      Index
                                                                       Page No.


Part I    Financial Information

          Item 1.  Consolidated Financial Statements (Unaudited)

             Consolidated Balance Sheet
               - September 30, 2001 and December 31, 2000                 11

             Consolidated Statement of Income
               - Three months, nine months and 12 months ended
                  September 30, 2001 and 2000                             12

             Consolidated Statement of Cash Flows
               - Nine months ended September 30, 2001 and 2000            13

             Consolidated Statement of Common Stockholders'
                 Equity - Nine months ended September 30, 2001 and
                 12 months ended December 31, 2000                        14

             Notes to Consolidated Financial Statements                   15

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

          Item 3.  Quantitative and Qualitative Disclosures
          About Market Risk                                                8


Part II   Other Information

          Item 1.  Legal Proceedings                                      20

          Item 5.  Other Information                                      20

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





                         PART I - FINANCIAL INFORMATION

ITEM 1.  CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED).

The unaudited consolidated financial statements of Ameren Corporation (Ameren or
the Registrant) appear on pages 11 through 18 of this report.

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
         OF OPERATIONS.

OVERVIEW

Ameren  Corporation  (Ameren or the Registrant) is a holding company  registered
under the Public Utility Holding Company Act of 1935 (PUHCA).  Ameren's  primary
operating  companies are Union Electric  Company  (AmerenUE),  Central  Illinois
Public  Service  Company   (AmerenCIPS),   both  subsidiaries  of  Ameren,   and
AmerenEnergy  Generating Company (Generating Company), the nonregulated electric
generating  subsidiary of AmerenEnergy  Resources Company  (Resources  Company),
which is a subsidiary of Ameren. Ameren also has a 60 percent ownership interest
in Electric Energy,  Inc. (EEI),  which is consolidated for financial  reporting
purposes. Ameren's other subsidiaries include AmerenEnergy, Inc. (AmerenEnergy),
Ameren  Development  Company,  Resources  Company,  Ameren Services  Company and
CIPSCO  Investment  Company.  AmerenEnergy,  an  energy  trading  and  marketing
subsidiary,  primarily  serves  as a power  marketing  agent  for  AmerenUE  and
Generating  Company and provides a range of energy and risk management  services
to targeted customers.  Ameren Development Company is a nonregulated  subsidiary
encompassing  Ameren's  nonregulated  products and services.  Resources  Company
holds the  Registrant's  nonregulated  generating  operations.  Ameren  Services
Company provides shared support services to Ameren and all of its subsidiaries.

The following  discussion and analysis  should be read in  conjunction  with the
Notes  to  Consolidated  Financial  Statements  beginning  on page  15,  and the
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations (MD&A), the Audited  Consolidated  Financial Statements and the Notes
to Consolidated  Financial  Statements appearing in the Registrant's 2000 Annual
Report to Stockholders  (which are incorporated by reference in the Registrant's
2000 Form 10-K).

References to the Registrant are to Ameren on a consolidated basis;  however, in
certain  circumstances,  the subsidiaries are separately referred to in order to
distinguish between their different business activities.

RESULTS OF OPERATIONS

Earnings
Third quarter 2001 earnings of $267 million,  or $1.94 per share,  increased $11
million,  or 7 cents  per  share,  as  compared  to the third  quarter  of 2000.
Earnings for the nine months ended September 30, 2001, totaled $420 million,  or
$3.06 per share,  compared to the year-ago earnings of $431 million or $3.14 per
share.  Earnings for the 12 months ended  September 30, 2001, were $446 million,
or $3.25 per  share,  compared  to $426  million,  or $3.10 per  share,  for the
preceding 12-month period.

Earnings and earnings per share  fluctuated due to many  conditions,  primarily:
sales growth, weather variations,  credits to electric customers,  electric rate
reductions,  gas rate changes,  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),  charges for coal contract  terminations,  adoption of a
new accounting standard,  changes in interest expense, and changes in income and
property taxes.

The  Registrant  continues to estimate  that ongoing  earnings per share for the
year ending  December 31, 2001,  will range  between  $3.30 and $3.45 per share.
This estimate  continues to  incorporate a future form of incentive  regulation,
which includes retail electric rate reductions and additional  customer credits.
This  estimate  is  subject  to,  among  other  things,  the  regulatory  issues
associated  with the  Registrant's  Missouri  retail  electric  operations  (see
discussion  below under "Rate  Matters"  and Note 2 under Notes to  Consolidated
Financial  Statements for further  information).  The resolution of those issues
could differ  materially  from the  assumptions  used in the  Registrant's  2001
estimate.

The  significant  items  affecting  revenues,  costs  and  earnings  during  the
three-month,  nine-month and 12-month  periods ended September 30, 2001 and 2000
are detailed on the following pages.

                                       2



                                                                                        
Electric Operations
Electric Operating Revenues                                  Variations for periods ended September 30, 2001
                                                                  from comparable prior-year periods
----------------------------------------------------------------------------------------------------------------
(Millions of Dollars)                            Three Months          Nine Months           Twelve Months
                                                 ------------          -----------           -------------
----------------------------------------------------------------------------------------------------------------
Credit to customers                              $   20                $  45                 $  23
Effect of abnormal weather                           15                   62
                                                                                                98
Growth and other                                     34                   91                   117
Interchange sales                                   184                  332                   384
EEI sales                                           (22)                 (53)                  (67)
----------------------------------------------------------------------------------------------------------------
                                                 $  231                $ 477                 $ 555
----------------------------------------------------------------------------------------------------------------

The $231 million  increase in third quarter  electric  revenues  compared to the
year-ago  quarter  was  primarily  driven by a 30 percent  increase in the total
kilowatthour sales. Weather-sensitive residential and commercial sales increased
2 percent and 6 percent, respectively, due to warmer summer weather and moderate
growth,  compared to the prior year.  Industrial sales rose 2 percent  primarily
due to a new  industrial  contract  effective  August  2000.  During the period,
interchange sales increased significantly;  however, lower electric margins were
realized on these sales due to lower energy prices and less low-cost  generation
available for sale,  resulting  primarily from increased demand from native-load
customers. Revenues were also favorably impacted by a reduction in the estimated
credits to Missouri  electric  customers (see Note 2 under Notes to Consolidated
Financial Statements for further information).

Electric  revenues  for the first nine  months of 2001  increased  $477  million
compared to the  prior-year  period,  primarily due to a 13 percent  increase in
total  kilowatthour  sales.  Weather-sensitive  residential and commercial sales
increased  5 percent  and 8  percent,  respectively.  Industrial  sales  rose 11
percent primarily due to a new industrial  contract effective August 2000, while
wholesale  sales rose 13 percent.  Interchange  sales also  increased 52 percent
during the period,  however, lower electric margins were realized on these sales
due to lower energy  prices and less  low-cost  generation  available  for sale.
These increases were offset in part by a decline in sales at EEI, which resulted
from a decrease in sales under a contract with its major customer. Revenues were
also  favorably  impacted by a reduction  in the  estimated  credits to Missouri
electric customers (see Note 2 under Notes to Consolidated  Financial Statements
for further information).

Electric  revenues for the 12 months ended  September  30, 2001  increased  $555
million  compared to the prior  12-month  period.  The  increase in revenues was
primarily  driven  by  a  13  percent  increase  in  total  kilowatthour  sales.
Interchange sales increased 32 percent, while native sales increased 14 percent.
These increases were partially offset by a decline in sales at EEI.


                                                                                       
Fuel and Purchased Power                               Variations for periods ended September 30, 2001
                                                                from comparable prior-year periods
-----------------------------------------------------------------------------------------------------------------
(Millions of Dollars)                            Three Months          Nine Months           Twelve Months
                                                 ------------          -----------           -------------
-----------------------------------------------------------------------------------------------------------------
Fuel:
     Generation                                  $    4                $  (4)                $  24
     Price                                           15                   29                    20
     Generation efficiencies and other               (4)                  (7)                  (10)
     Coal contract termination payments               -                    -                   (52)
Purchased power                                     213                  416                   463
EEI                                                 (19)                 (41)                  (52)
-----------------------------------------------------------------------------------------------------------------
                                                 $  209                $ 393                 $ 393
-----------------------------------------------------------------------------------------------------------------

Fuel and  purchased  power costs for the three months ended  September  30, 2001
increased $209 million,  as compared to the prior-year  period  primarily due to
increased  purchased power,  resulting from higher sales volume, and higher fuel
costs.

Fuel and  purchased  power costs for the nine months  ended  September  30, 2001
increased  $393 million as compared to the  prior-year  period  primarily due to
increased purchased power resulting from higher sales volume, higher fuel costs,
and replacement  power resulting from the refueling  outage of the  Registrant's
Callaway Nuclear Plant, which occurred during the second quarter 2001.

Fuel and  purchased  power  costs for the 12 months  ended  September  30,  2001
increased  $393 million as compared to the  prior-year  period  primarily due to
increased  generation and purchased  power,  resulting from higher sales volume,
higher blended fuel costs, and the refueling outage of the Registrant's Callaway
Nuclear Plant, which occurred in second quarter 2001.

                                       3


Gas Operations
Gas  revenues  for the  nine and  12-month  periods  ended  September  30,  2001
increased $74 million and $138 million,  respectively,  compared to the year-ago
periods  primarily  from  increased  sales and  higher  costs  reflected  in the
Registrant's purchased gas adjustment clauses.

Gas costs for the nine and 12-months  ended  September  30, 2001,  increased $65
million and $126 million, respectively, primarily due to higher sales and higher
gas prices.

Other Operating Expenses
Other operating expense variations  reflected  recurring factors such as growth,
inflation, labor and employee benefit increases, and plant maintenance outages.

Other operating  expenses increased $7 million and $48 million for the three and
nine month periods ended  September 30, 2001 compared to the prior-year  periods
primarily due to higher employee  benefit costs in 2001,  resulting from changes
in actuarial  assumptions and investment  performance of employee benefit plans'
assets, and increased professional services.  Other operating expenses increased
$164 million for the 12-month  period ended  September  30, 2001 compared to the
same year-ago  period  primarily due to the withdrawal from the Midwest ISO (see
discussion   below  under   "Electric   Industry   Restructuring"   for  further
information),  in addition to higher  employee  benefit  costs,  resulting  from
changes in actuarial  assumptions  and  investment  performance  of the employee
benefit plans' assets, and increased professional services.

Maintenance  expenses  for the  nine  month  period  ended  September  30,  2001
increased $29 million  compared to the prior period due to a refueling outage at
the Callaway Nuclear Plant during second quarter 2001. The spring 2001 refueling
was  completed  in 45 days.  There  was not a  refueling  in  2000.  Maintenance
expenses  for the 12 months  ended  September  30,  2001  increased  $14 million
primarily  resulting from an increase in the spring 2001 Callaway  Nuclear Plant
refueling  expense  compared to fall 1999,  partially  offset by a reduction  in
fossil power plant maintenance.

Depreciation  and amortization  expenses for the three month,  nine month and 12
month periods ended September 30, 2001 increased $7 million, $20 million and $36
million,   respectively,   compared  to  the  prior  periods  due  to  increased
depreciable  property,  primarily  resulting  from the  addition  of  combustion
turbine generating facilities (see discussion below under "Liquidity and Capital
Resources" for further information).

Taxes
Income taxes  increased  $12 million and $14 million for the three and 12 months
ended September 30, 2001, respectively, primarily due to higher pretax income.

Other tax expense  increased  $7 million for the 12 months ended  September  30,
2001  compared to the prior year  primarily  due to a change in the property tax
assessment in the state of Illinois.

Other Income and Deductions
The  variation  in other income and  deductions,  net for the three month period
ended September 30, 2001 compared to the prior-year  period was primarily due to
contributions  in  aid of  construction  as  well  as  gains  on  the  sales  of
unregulated property.

The variation in other income and deductions,  net for the nine and twelve month
periods  ended  September  30,  2001  compared  to the  prior-year  periods  was
primarily  due to gains on the sales of  unregulated  property  and prior period
write-offs of certain nonregulated investments.

Balance  Sheet
The 8  percent,  or $40  million,  increase  in  trade  accounts  receivable  at
September  30,  2001,  compared to the  year-end,  was due  primarily  to higher
revenues in August and September 2001 compared to November and December 2000.

Changes in accounts and wages payable and taxes accrued resulted from the timing
of various payments to taxing authorities and suppliers.

Decrease in other current  liabilities  of $44 million  during 2001 is primarily
due to the reduction in the estimated credit that the Registrant  expects to pay
its  Missouri  electric  customers  (see  Note 2  under  Notes  to  Consolidated
Financial Statements for further information).

                                       4


LIQUIDITY AND CAPITAL RESOURCES

Cash provided by operating  activities  totaled $735 million for the nine months
ended September 30, 2001, compared to $762 million during the same 2000 period.

Cash flows used in  investing  activities  totaled $813 million and $633 million
for  the  nine  months  ended   September  30,  2001  and  2000,   respectively.
Construction  expenditures  for the nine months ended  September  30, 2001,  for
constructing  new or improving  existing  facilities  were $812  million,  which
included  expenditures  associated  with  the  purchase  of  combustion  turbine
generating facilities.  The Registrant added 670 megawatts of combustion turbine
generation  capacity  during  the nine  months  ended  September  30,  2001.  In
addition,  the  Registrant  expended $15 million for the  acquisition of nuclear
fuel.

As of  September  30,  2001,  the  Registrant  plans to add  combustion  turbine
generating  units  as  follows:  820  megawatts  in  2001 at  Resources  Company
(including  those already in service as of September  30); 710 megawatts in 2002
(470  megawatts at Resources  Company and 240  megawatts at  AmerenUE);  and 325
megawatts each in 2004 and 2005.  The  Registrant is reviewing  four  combustion
turbine generating units which had been planned for commercial operation in 2004
and 2005 to  determine  if they can be used by AmerenUE  rather  than  Resources
Company. The Registrant  continually reviews its generation portfolio,  and as a
result,  could modify its plan for generation  asset  additions or  assignments,
which  could  include  the  timing of when  certain  assets  will be added to or
removed  from  its  portfolio,  whether  the  generation  will be  added  to the
regulated or  nonregulated  portfolio,  as well as the type of generation  asset
technology that will be employed, among other things.

During the course of the Registrant's  resource planning,  several  alternatives
are being  considered to satisfy  anticipated  regulatory load  requirements for
2001 and beyond for AmerenUE,  AmerenCIPS and Resources Company.  The Registrant
purchased 50 megawatts of capacity and energy  during the third quarter of 2001,
and is  considering  proposals  for purchases of up to 500 megawatts of capacity
and energy for the summer of 2002 and beyond,  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.

Cash flows  provided by  financing  activities  totaled $64 million for the nine
months ended September 30, 2001. The Registrant's principal financing activities
for the period included issuance of short-term and long-term debt, offset by the
redemption  of debt and the  payment  of  dividends.  On August  24,  2001,  the
Registrant's  Board of  Directors  declared a quarterly  dividend  for the third
quarter of 2001 of 63.5 cents per common share that was paid to  shareholders on
September  28,  2001.  Common  stock  dividends  paid  for the 12  months  ended
September 30, 2001,  resulted in a payout rate of 78 percent of the Registrant's
earnings to common stockholders.

In April 2001,  AmerenCIPS  filed with the  Securities  and Exchange  Commission
(SEC) a shelf  registration  statement on Form S-3 authorizing the offering from
time to time of senior notes in one or more series with an offering price not to
exceed $250 million.  The SEC declared the registration  statement  effective in
May 2001. In June 2001,  AmerenCIPS issued $150 million of the senior notes with
an interest  rate of 6.625  percent due June 2011.  The proceeds of these senior
notes were used to repay  short-term debt and first mortgage bonds which matured
in June 2001.

On November 1, 2000,  Generating Company issued transfer restricted Senior Notes
in a private  placement,  Series A due 2005  (Series A Notes) and Senior  Notes,
Series B due 2010 (Series B Notes) (collectively,  the Senior Notes). Generating
Company filed a registration  statement in the first quarter of 2001 to register
the Senior  Notes under the  Securities  Act of 1933,  as amended,  to permit an
exchange  offer of the Senior  Notes.  The  registration  statement was declared
effective in April 2001. On June 12, 2001, all holders  completed their exchange
of the Senior  Notes for new  Series C and D Notes  which are  identical  in all
material respects to the Series A Notes and Series B Notes, respectively, except
that the new  series  of  notes do not  contain  transfer  restrictions  and are
registered.

The Registrant  anticipates securing $400 to $600 million of long-term financing
in late 2001 or early 2002 which will primarily be used to repay short-term debt
incurred in  conjunction  with  construction  of combustion  turbine  generating
facilities.

The Registrant  plans to continue  utilizing  short-term  debt to support normal
operations and other temporary requirements. The Registrant and its subsidiaries
are authorized by the SEC under PUHCA to have up to an aggregate $2.8 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 September
30, 2001, the Registrant  had committed  bank lines of credit  aggregating  $161

                                       5


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. The Registrant has bank
credit agreements, expiring at various dates between 2001 and 2003, that support
commercial  paper  programs  totaling  $763  million,  $463  million of which is
available for the Registrant's own use and for the use of its subsidiaries.  The
remaining  $300 million is available for the use of the  Registrant's  regulated
subsidiaries. At September 30, 2001, $263 million was available under these bank
credit agreements.  The Registrant had $459 million of short-term  borrowings at
September 30, 2001.

AmerenUE also has a lease  agreement  that provides for the financing of nuclear
fuel. At September 30, 2001, the maximum amount that could be financed under the
agreement  was $120  million.  Cash used in  financing  activities  for the nine
months  ended  September  30,  2001,  included  redemptions  under the lease for
nuclear fuel of $64 million,  partially  offset by $3 million of  issuances.  At
September 30, 2001, $53 million was financed under the lease.

The Registrant,  in the ordinary course of business,  explores  opportunities to
reduce its costs in order to remain competitive in the marketplace.  Areas where
the Registrant  focuses its review include,  but are not limited to, labor costs
and fuel  supply  costs.  In the  labor  area,  over the  past  two  years,  the
Registrant has reached  agreements with all of its major  collective  bargaining
units which will permit the  Registrant  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  (e.g.  utilizing  low
sulfur  versus  high  sulfur  coal),  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,  as well as determine the impact of these actions on
the Registrant's future financial position, results of operations or liquidity.

RATE MATTERS

On June 30, 2001, the Registrant's experimental alternative regulation plan (the
Plan) for its  Missouri  electric  customers  expired (see Note 2 under Notes to
Consolidated  Financial Statements for further information about the Plan). With
the Plan's  expiration,  on July 2, 2001, the Missouri Public Service Commission
(MoPSC)  staff  filed with the MoPSC an excess  earnings  complaint  against the
Registrant that proposes to reduce the  Registrant's  annual  electric  revenues
ranging from $213 million to $250  million.  Factors  contributing  to the MoPSC
staff's  recommendation  include  return on equity (ROE),  revenues and customer
growth,  depreciation  rates  and  other  cost  of  service  expenses.  The  ROE
incorporated into the MoPSC staff's  recommendation  ranges from 9.04 percent to
10.04  percent.  The MoPSC has not yet  determined  a schedule  for  evidentiary
hearings  on the  MoPSC  staff's  recommendation.  The MoPSC is not bound by the
MoPSC staff's recommendation.  Depending on the outcome of the MoPSC's decision,
further appeals in the courts may be warranted.

In the interim,  the  Registrant  is preparing to  vigorously  contest the MoPSC
staff's  recommendation and expects to continue  negotiations with all pertinent
parties with the intent to continue with an incentive  regulation plan,  similar
in form to the  Plan.  The  Registrant  can not  predict  the  outcome  of these
negotiations and their impact on the Registrant's financial position, results of
operations or liquidity; however, the impact could be material.

See  Note 2  under  Notes  to  Consolidated  Financial  Statements  for  further
discussion of Rate Matters.

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.

                                       6


Illinois
In December 1997, the Governor of Illinois signed the Electric  Service Customer
Choice and Rate  Relief Law of 1997 (the Law)  providing  for  electric  utility
restructuring  in Illinois.  This  legislation  introduces  competition into the
supply of electric energy in Illinois.

One of the major provisions of the Law is 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,  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 13 percent of the Registrant's total sales. As
of September 30, 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
During  the  legislative   session  that  ended  in  May  2001,  the  Registrant
participated 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 have allowed the State's largest nonresidential
customers  to choose  their  electric  supplier,  among other  things.  Electric
industry legislation was not passed during the legislative session.

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 $25
million ($15 million after taxes,  or 11 cents per share),  which related to the
Registrant's  estimated  obligation  under the Midwest ISO  agreement  for costs
incurred by the Midwest ISO,  plus  estimated  exit costs.  During first quarter
2001, the Federal Energy Regulatory Commission (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.  Also in
first quarter 2001,  in a proceeding  before the FERC,  the Alliance RTO and the
Midwest ISO reached an agreement  that would enable  Ameren to withdraw from the
Midwest ISO and to join the  Alliance  RTO.  During the second  quarter of 2001,
this settlement agreement was approved by the FERC. The Registrant's  withdrawal
from the Midwest ISO remains  subject to MoPSC approval.  Additional  regulatory
approvals of the SEC, FERC,  MoPSC and the Illinois  Commerce  Commission may be
required in  connection  with various  transactions  involving  the Alliance RTO
relating  to its  organization,  capitalization  and the  possible  transfer  of
transmission  assets.  Such  approvals,  if  required,  will  be  sought  at the
appropriate  times. The Alliance RTO is expected to be operational within 90-120
days  after the  FERC's  approval.  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 operations or liquidity.

ACCOUNTING MATTERS

In January 2001, the Registrant  implemented  Statement of Financial  Accounting
Standards  (SFAS) No. 133,  "Accounting  for Derivative  Instruments and Hedging
Activities." The impact of that adoption resulted in the Registrant  recording a
cumulative effect charge of $7 million after taxes to the income statement,  and
a cumulative adjustment of $11 million after income taxes to other comprehensive
income (OCI),  which reduced  stockholders'  equity.  (See Note 3 under Notes to
Consolidated  Financial  Statements for further  information.) In June 2001, the
Derivatives  Implementation Group (DIG), a committee of the Financial Accounting
Standards Board (FASB)  responsible for providing guidance on the implementation
of SFAS 133, reached a conclusion regarding the appropriate accounting treatment
of  certain  types of energy  contracts  under SFAS 133.  Specifically,  the DIG
concluded that power purchase or sales  agreements  (both forward  contracts and
option  contracts)  may  meet  an  exception  for  normal  purchases  and  sales
accounting  treatment if certain  criteria are met.  This guidance was effective
beginning  July 1, 2001 and did not have a material  impact on the  Registrant's
financial condition,  results of operations or liquidity upon adoption. However,
in October 2001,  the DIG revised this  guidance,  with the revisions  effective
January 1, 2002. At this time,  the  Registrant is evaluating  the impact of the
DIG's  revisions to determine the effect on the  Registrant's  future  financial
condition, results of operations, or liquidity upon application.

In September  2001, the DIG issued guidance  regarding the accounting  treatment
for fuel  contracts  that  combine a forward  contract  and a  purchased  option
contract.  The DIG concluded that contracts  containing both a forward  contract
and a  purchased  option  contract  are not  eligible  to qualify for the normal
purchases  and sales  exception  under SFAS 133.  This  guidance is effective in
second quarter 2002. The Registrant is evaluating the impact of this guidance on
its future financial condition, results of operations or liquidity; however, the
impact could be material.

                                       7


In July 2001, the FASB issued SFAS No. 141, "Business  Combinations,"  SFAS 142,
"Goodwill  and Other  Intangible  Assets," and SFAS 143,  "Accounting  for Asset
Retirement Obligations." 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
record the assets and  liabilities  of the  acquired  enterprise  at fair market
value rather than historical cost. It prohibits use of the  pooling-of-interests
method of accounting  for business  combinations.  SFAS 141 is effective for all
business combinations  initiated after June 30, 2001, or transactions  completed
using the  purchase  method  after June 30,  2001.  SFAS 142  requires  goodwill
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 142 is  effective  for all fiscal years
beginning  after  December  15,  2001.  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 fiscal years  beginning  after June 15, 2002.  SFAS 141 and
SFAS  142 are  not  expected  to  have a  material  effect  on the  Registrant's
financial  position,  results of operations or liquidity upon adoption.  At this
time,  the  Registrant  is  assessing  the  impact of SFAS 143 on its  financial
position, results of operations or liquidity upon adoption.

ITEM 3.  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 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.  The Registrant  handles market risks in accordance with established
policies,  which may include entering into various derivative  transactions.  In
the normal course of business,  the Registrant  also faces 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.

The  Registrant'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
associated with its issuance of both long-term and short-term variable-rate debt
and fixed-rate  debt,  commercial  paper and  auction-rate  preferred stock. 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  $11 million
and net income would decrease by approximately $7 million.  This amount has been
determined using the assumptions that the Registrant's outstanding variable-rate
debt,  commercial  paper and  auction-rate  preferred stock, as of September 30,
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
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
that has its value  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.

The  Registrant has a subsidiary,  AmerenEnergy  Fuels and Services  Company,  a
wholly owned subsidiary of Resources Company, which is responsible for providing
fuel procurement and gas supply services on behalf of the Registrant's operating
subsidiaries, and for managing fuel and natural gas price risks. Fixed price

                                       8

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. All of the required coal
for the Registrant's  coal plants has been acquired at fixed prices for 2001. In
addition,  at least 80 percent of the coal requirements through 2005 are covered
by long-term  contracts.  The Registrant has recently experienced some delays in
its coal deliveries due to certain  transportation and operating  constraints in
the system. The Registrant is working closely with the transportation  companies
and monitoring its operating  practices in order to maintain  adequate levels of
coal inventory for future  operating  purposes.  With regard to the Registrant's
nonregulated  electric  generation  operations,  the  Registrant  is  exposed to
changes in market prices for natural gas to the extent it must purchase  natural
gas to run its  combustion  turbine  generators.  The  Registrant's  natural gas
procurement  strategy is designed to ensure  reliable and immediate  delivery of
natural gas to its intermediate  and peaking units by optimizing  transportation
and storage  options and minimizing  cost and price risk by structuring  various
supply agreements to maintain access to multiple gas pools and supply basins and
reducing the impact of price volatility.

With regard to the  Registrant's  exposure to commodity price risk for purchased
power  and  excess   electricity   sales,   the  Registrant  has  a  subsidiary,
AmerenEnergy,  which has as its primary  responsibility  managing  market  risks
associated  with changing  market prices for  electricity  purchased and sold on
behalf of AmerenUE and Generating Company.

Although the  Registrant  cannot  completely  eliminate the effects of gas price
volatility, its strategy is designed to minimize the effect of 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 September  30, 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 electric rates.

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 2000 Annual
Report to Stockholders  (portions of which are  incorporated by reference in the
Registrant's 2000 Form 10-K) 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 the  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;  the impact of the adoption of new  accounting  standards;  interest
rates;  weather  conditions;  fuel availability;  generation plant construction,
installation and performance; the impact of current environmental regulations on
utilities and generating companies and the expectation that more stringent

                                       9


requirements  will be  introduced  over time,  which  could  potentially  have a
negative  financial  effect;  monetary  and fiscal  policies;  future  wages and
employee benefits costs;  competition from other generating facilities including
new facilities  that may be developed in the future;  cost and  availability  of
transmission  capacity for the energy generated by the  Registrant's  generating
facilities or required to satisfy energy sales made by the Registrant; and legal
and administrative proceedings.
                                       10



                               AMEREN CORPORATION
                           CONSOLIDATED BALANCE SHEET
                                    UNAUDITED
                      (Thousands of Dollars, Except Shares)
                                                                           
                                                                   September 30,   December 31,
ASSETS                                                                 2001             2000
------                                                             -------------   -------------
Property and plant, at original cost:
   Electric                                                        $ 13,316,855    $ 12,684,366
   Gas                                                                  527,071         509,746
   Other                                                                104,495          97,214
                                                                   -------------   ------------
                                                                     13,948,421      13,291,326
   Less accumulated depreciation and amortization                     6,454,929       6,204,367
                                                                   -------------   ------------
                                                                      7,493,492       7,086,959
Construction work in progress:
   Nuclear fuel in process                                               87,171         117,789
   Other                                                                644,734         500,924
                                                                   -------------   ------------
         Total property and plant, net                                8,225,397       7,705,672
                                                                   -------------   ------------
Investments and other assets:
   Investments                                                           40,187          40,235
   Nuclear decommissioning trust fund                                   174,478         190,625
   Other                                                                 99,367          97,630
                                                                   -------------  ------------
         Total investments and other assets                             314,032         328,490
                                                                   -------------  ------------
Current assets:
   Cash and cash equivalents                                            112,112         125,968
   Accounts receivable - trade (less allowance for doubtful
         accounts of $8,786 and $8,028, respectively)                   514,105         474,425
   Other accounts and notes receivable                                   45,081          56,529
   Materials and supplies, at average cost -
      Fossil fuel                                                       155,955         107,572
      Other                                                             120,676         119,478
   Other current assets                                                  35,152          37,210
                                                                   -------------  -------------
         Total current assets                                           983,081         921,182
                                                                   -------------  -------------
Regulatory assets:
   Deferred income taxes                                                602,414         600,100
   Other                                                                153,012         158,986
                                                                   -------------  ------------
         Total regulatory assets                                        755,426         759,086
                                                                   -------------   ------------
Total Assets                                                       $ 10,277,936    $  9,714,430
                                                                   =============   ============
CAPITAL AND LIABILITIES
Capitalization:
   Common stock, $.01 par value, 400,000,000 shares authorized -
     137,539,177 shares outstanding                                $      1,375    $      1,372
   Other paid-in capital, principally premium on
     common stock                                                     1,593,098       1,581,339
   Retained earnings                                                  1,772,113       1,613,960
   Accumulated other comprehensive income                                (4,755)           -
   Other                                                                 (5,117)           -
                                                                   -------------   ------------
      Total common stockholders' equity                               3,356,714       3,196,671
   Preferred stock not subject to mandatory redemption                  235,197         235,197
   Long-term debt                                                     2,811,148       2,745,068
                                                                   -------------   ------------
         Total capitalization                                         6,403,059       6,176,936
                                                                   =============   ============
Minority interest in consolidated subsidiaries                            3,534           3,940
Current liabilities:
   Current maturity of long-term debt                                    47,444          44,444
   Short-term debt                                                      459,091         203,260
   Accounts and wages payable                                           287,060         462,924
   Accumulated deferred income taxes                                     46,139          49,829
   Taxes accrued                                                        390,464         124,706
   Other                                                                256,331         300,798
                                                                   -------------   ------------
         Total current liabilities                                    1,486,529       1,185,961
                                                                   -------------   ------------
Accumulated deferred income taxes                                     1,562,689       1,540,536
Accumulated deferred investment tax credits                             160,101         164,120
Regulatory liability                                                    175,573         183,541
Other deferred credits and liabilities                                  486,451         459,396
                                                                   -------------   ------------
Total Capital and Liabilities                                      $ 10,277,936    $  9,714,430
                                                                   =============   ============


See Notes to Consolidated Financial Statements.

                                                      11



                                                AMEREN CORPORATION
                                         CONSOLIDATED STATEMENT OF INCOME
                                                     UNAUDITED
                            (Thousands of Dollars, Except Shares and Per Share Amounts)


                                                      Three Months Ended         Nine Months Ended          Twelve Months Ended
                                                         September 30,            September 30,                September 30,
                                                      --------------------      --------------------        --------------------

                                                     2001          2000         2001           2000         2001           2000
                                                     ----          ----         ----           ----         ----           ----
                                                                                                   

OPERATING REVENUES:
   Electric                                     $ 1,389,991    $1,158,509    $3,251,374    $2,774,763    $4,003,189    $3,447,780
   Gas                                               40,517        36,275       255,343       181,447       397,782       248,145
   Other                                              1,105           939         6,440         5,597         7,209         6,484
                                                -----------    ----------    ----------    ----------    ----------    ----------
      Total operating revenues                    1,431,613     1,195,723     3,513,157     2,961,807     4,408,180     3,702,409

OPERATING EXPENSES:
   Operations
      Fuel and purchased power                      493,814       285,157     1,163,265       770,259     1,418,227     1,025,043
      Gas                                            19,967        23,632       171,429       106,549       274,347       148,158
      Other                                         173,273       166,008       517,880       469,654       712,770       615,475
                                                -----------    ----------    ----------    ----------    ----------    ----------
                                                    687,054       474,797     1,852,574     1,346,462     2,405,344     1,788,676
   Maintenance                                       78,216        79,155       296,233       267,653       396,501       386,411
   Depreciation and amortization                    104,226        96,845       303,400       283,808       402,702       373,784
   Income taxes                                     176,065       163,706       286,125       287,196       300,121       286,070
   Other taxes                                       75,630        75,535       203,114       203,219       264,960       258,376
                                                -----------    ----------    ----------    ----------    ----------    ----------
      Total operating expenses                    1,121,191       890,038     2,941,446     2,388,338     3,769,628     3,093,317

OPERATING INCOME                                    310,422       305,685       571,711       573,469       638,552       609,092

OTHER INCOME AND (DEDUCTIONS):
   Allowance for equity funds used
      during construction                             4,137         1,250         7,959         4,079         9,178         5,211
   Miscellaneous, net                                 3,615        (5,481)         (867)      (13,481)        8,214       (17,576)
                                                -----------    ----------    ----------   -----------    ----------    ----------
     Total other income and (deductions)              7,752        (4,231)        7,092        (9,402)       17,392       (12,365)
                                                -----------    ----------    ----------   -----------   ----------    -----------

INCOME BEFORE INTEREST CHARGES
   AND PREFERRED DIVIDENDS                          318,174       301,454       578,803       564,067       655,944       596,727

INTEREST CHARGES AND PREFERRED
   DIVIDENDS:
   Interest                                          50,498        44,223       148,836       129,411       199,131       166,242
   Allowance for borrowed funds used
      during construction                            (2,006)       (2,136)       (5,963)       (5,928)       (8,327)       (7,692)
   Preferred dividends of subsidiaries                3,106         3,230         9,391         9,469        12,622        12,664
                                                 ----------    ----------    ----------   -----------    ----------    ----------
      Net interest charges and                       51,598        45,317       152,264       132,952       203,426       171,214
      preferred dividends                       -----------    ----------    ----------   -----------   -----------   ----------

INCOME BEFORE CUMULATIVE EFFECT OF
      CHANGE  IN ACCOUNTING PRINCIPLE               266,576       256,137       426,539       431,115       452,518       425,513

CUMULATIVE EFFECT OF CHANGE IN
      ACCOUNTING PRINCIPLE, NET OF
      INCOME TAXES                                       --            --        (6,841)           --        (6,841)           --
                                                -----------    ----------    ----------   -----------   -----------   ----------
NET INCOME                                         $266,576      $256,137      $419,698      $431,115      $445,677      $425,513
                                                ===========    ==========    ==========   ===========   ==========    ==========

EARNINGS PER COMMON SHARE - BASIC AND DILUTED
(Based on average shares outstanding):
    Income before cumulative effect of change         $1.94         $1.87         $3.11         $3.14         $3.30         $3.10
      in accounting principle
    Cumulative effect of change in accounting
      principle, net of income taxes                     --            --         (0.05)           --         (0.05)           --
    Net income                                  -----------    ------------  -----------  ------------   ------------     ---------
                                                      $1.94         $1.87         $3.06         $3.14         $3.25         $3.10
                                                ===========    ============  ===========  ============   ============     =========
AVERAGE COMMON SHARES OUTSTANDING               137,222,499   137,215,462   137,217,834   137,215,462   137,217,236    137,215,462
                                                ===========   ============= ============  ============   ============     =========



See Notes to Consolidated Financial Statements.

                                                    12



                                                 AMEREN CORPORATION
                                       CONSOLIDATED STATEMENT OF CASH FLOWS
                                                     UNAUDITED
                                              (Thousands of Dollars)

                                                              

                                                            Nine Months Ended
                                                              September 30,
                                                         -----------------------
                                                             2001         2000
                                                             ----         ----
Cash Flows From Operating:
   Net income                                            $ 419,698    $ 431,115
   Adjustments to reconcile net income to net cash
       provided by operating activities:
       Cumulative effect of change in accounting             6,841         --
          principle
       Depreciation and amortization                       293,911      274,557
       Amortization of nuclear fuel                         21,084       27,714
        Allowance for funds used during construction       (13,922)     (10,007)
        Deferred income taxes, net                          13,645       11,976
        Deferred investment tax credits, net                (4,019)      (4,501)
        Changes in assets and liabilities:
           Receivables, net                                (28,232)     (88,251)
           Materials and supplies                          (49,581)       3,898
           Accounts and wages payable                     (175,864)     (86,295)
           Taxes accrued                                   265,758      170,049
           Other, net                                      (14,324)      31,665
                                                          ---------    ---------
Net cash provided by operating activities                  734,995      761,920

Cash Flows From Investing:
   Construction expenditures                              (812,109)    (657,622)
   Allowance for funds used during construction             13,922       10,007
   Nuclear fuel expenditures                               (14,988)     (11,691)
   Other                                                        48       26,314
                                                          ---------     ---------
Net cash used in investing activities                     (813,127)    (632,992)

Cash Flows From Financing:
   Dividends on common stock                              (261,395)    (261,395)
   Redemptions:
      Nuclear fuel lease                                    (64,122)     (8,276)
      Long-term debt                                        (30,000)   (425,650)
   Issuances:
      Nuclear fuel lease                                      3,062       7,270
      Short-term debt                                       255,831     324,178
      Long-term debt                                        160,900     277,600
                                                           ---------   ---------
Net cash provided by (used in) financing activities          64,276     (86,273)
                                                           ---------   ---------

Net change in cash and cash equivalents                     (13,856)     42,655
Cash and cash equivalents at beginning of year              125,968     194,882
                                                           ---------   ---------
Cash and cash equivalents at end of period                $ 112,112   $ 237,537
                                                           =========   =========

Cash paid during the periods:
   Interest (net of amount capitalized)                   $ 122,852   $ 118,111
   Income taxes, net                                      $  78,364   $ 157,399

See Notes to Consolidated Financial Statements.


                                                13



                               AMEREN CORPORATION
              CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY
                                    UNAUDITED
                             (Thousands of Dollars)

                                        Nine Months Ended         Year Ended
                                       September 30, 2001      December 31, 2000
                                     ---------------------    ------------------

Common stock
   Beginning balance                         $     1,372    $     1,372
   Shares issued                                       3             --
                                             -----------    -----------

                                                   1,375          1,372

Other paid-in capital
   Beginning balance                           1,581,339      1,582,501
   Shares issued                                  12,217             --
   Employee stock awards                            (458)        (1,162)
                                             -----------    -----------

                                               1,593,098      1,581,339

Retained earnings
   Beginning balance                           1,613,960      1,505,827
   Net income                                    419,698        457,094
   Dividends                                    (261,545)      (348,961)
                                             -----------    -----------
                                               1,772,113      1,613,960

Accumulated other comprehensive income
   Beginning balance                                  --            --
   Change in current period                       (4,755)           --
                                             -----------   ------------
                                                  (4,755)           --

Other
   Beginning balance                                  --            --
   Unamortized restricted stock compensation      (5,704)           --
   Compensation amortized                            587            --
                                             -----------    -----------
                                                  (5,117)           --

                                             -----------    -----------
Total common stockholders' equity            $ 3,356,714    $ 3,196,671
                                             ===========    ===========


Comprehensive income, net of tax
   Net income                                $   419,698    $   457,094
   Cumulative effect of accounting change,       (11,258)            --
    net of taxes
   Unrealized net gain on derivative
     hedging instruments                           6,503             --
                                             -----------    -----------
                                             $   414,943    $   457,094
                                             ===========    ===========


See Notes to Consolidated Financial Statements.



                                                        14


AMEREN CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
September 30, 2001

Note 1 - Summary of Significant Accounting Policies

Basis of Presentation
Ameren  Corporation  (Ameren or the Registrant) is a holding company  registered
under the Public Utility Holding Company Act of 1935 (PUHCA).  Ameren's  primary
operating  companies are Union Electric  Company  (AmerenUE),  Central  Illinois
Public  Service  Company   (AmerenCIPS),   both  subsidiaries  of  Ameren,   and
AmerenEnergy  Generating Company (Generating Company), the nonregulated electric
generating  subsidiary of AmerenEnergy  Resources Company  (Resources  Company),
which is a subsidiary of Ameren. Ameren also has a 60 percent ownership interest
in Electric Energy, Inc. (EEI). EEI owns and/or operates electric generation and
transmission  facilities in Illinois that supply  electric power  primarily to a
uranium  enrichment  plant  located  in  Paducah,  Kentucky.  That  interest  is
consolidated  for financial  reporting  purposes.  Ameren's  other  subsidiaries
include AmerenEnergy,  Inc.  (AmerenEnergy),  Ameren Development Company, Ameren
Services  Company  and  CIPSCO  Investment  Company.   AmerenEnergy,  an  energy
marketing  subsidiary,  primarily serves as a power marketing agent for AmerenUE
and  Generating  Company  and  provides  a range of energy  and risk  management
services to targeted  customers.  Ameren  Development  Company is a nonregulated
subsidiary  encompassing Ameren's nonregulated products and services.  Resources
Company  holds  the  Registrant's  nonregulated  generating  operations.  Ameren
Services  Company  provides  shared  support  services  to Ameren and all of its
subsidiaries.

The  accompanying  financial  statements  include the accounts of Ameren and its
consolidated  subsidiaries  (collectively the Registrant).  All subsidiaries for
which the  Registrant  owns directly or  indirectly  more than 50 percent of the
voting  stock  are  included  as  consolidated  subsidiaries.  Ameren's  primary
operating  companies,  AmerenUE,  AmerenCIPS and Generating Company, are engaged
principally in the generation,  transmission,  distribution and sale of electric
energy and the purchase,  distribution,  transportation and sale of natural gas.
The  operating  companies  serve 1.5 million  electric  and 300,000  natural gas
customers in a 44,500-square-mile area of Missouri and Illinois. All significant
intercompany   balances  and   transactions   have  been   eliminated  from  the
consolidated financial statements.

Interim Financial Statements
Financial   statement  note  disclosures,   normally  included  in  consolidated
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 Securities and Exchange  Commission.  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  Consolidated
Financial  Statements  included in the 2000 Annual Report to Stockholders (which
are  incorporated  by  reference  in  the  Registrant's   2000  Form  10-K)  for
information relevant to the consolidated  financial statements contained in this
Form 10-Q,  including  information as to the significant  accounting policies of
the Registrant.

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.

Factors Affecting Business
Due to the effect of weather on sales and other factors which are characteristic
of public utility operations,  financial results for the periods ended September
30, 2001 and 2000, are not necessarily indicative of trends for any three-month,
nine-month or twelve-month period.

Note 2 - Regulatory Matters

Missouri
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 be shared equally between customers
and stockholders, and earnings above a 14 percent regulatory return on equity be
credited to customers.  The formula for  computing the credit used  twelve-month
results ending June 30, rather than calendar year earnings.

                                       15


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  AmerenUE  and CIPSCO  Incorporated  that formed
Ameren. Like the Original Plan, the New Plan required that earnings over a 12.61
percent  regulatory  return on equity up to a 14  percent  regulatory  return on
equity be shared equally between customers and  stockholders.  The New Plan also
returned to customers 90 percent of all earnings  above a 14 percent  regulatory
return on equity up to a 16 percent regulatory return on equity.  Earnings above
a 16 percent  regulatory  return on equity were credited  entirely to customers.
The New Plan ran from July 1, 1998 through June 30,  2001.  As of September  30,
2001, the Registrant  recorded an estimated  credit of $40 million,  or 17 cents
per share, for the plan year ended June 30, 2001 compared to $35 million,  or 15
cents  per  share,  in the prior  period.  These  credits  were  reflected  as a
reduction in electric  revenues in the periods accrued.  The final amount of the
credit will depend on several factors,  including the Registrant's  earnings for
12 months ended June 30, 2001.

With the New Plan's  expiration  on June 30,  2001,  on July 2, 2001,  the MoPSC
staff filed with the MoPSC an excess earnings  complaint  against the Registrant
that proposes to reduce the Registrant's  annual electric  revenues ranging from
$213  million  to  $250  million.  Factors  contributing  to the  MoPSC  staff's
recommendation  include  return on equity (ROE),  revenues and customer  growth,
depreciation rates and other cost of service expenses. The ROE incorporated into
the MoPSC staff's  recommendation ranges from 9.04 percent to 10.04 percent. The
MoPSC has not yet  determined  a schedule for  evdentiary  hearings on the MoPSC
staff's   recommendation.   The  MoPSC  is  not  bound  by  the  MoPSC   staff's
recommendation.  Depending  on the  outcome  of the  MoPSC's  decision,  further
appeals in the courts may be warranted.

In the interim,  the  Registrant  is preparing to  vigorously  contest the MoPSC
staff's  recommendation and expects to continue  negotiations with all pertinent
parties with the intent to continue with an incentive  regulation plan,  similar
to  the  New  Plan.  The  Registrant  can  not  predict  the  outcome  of  these
negotiations and their impact on the Registrant's financial position, results of
operations or liquidity; however, the impact could be material.

Midwest ISO and Alliance RTO
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 $25 million ($15 million  after taxes,  or 11 cents
per share),  which related to the  Registrant's  estimated  obligation under the
Midwest ISO agreement for costs incurred by the Midwest ISO, plus estimated exit
costs.  During first  quarter 2001,  the Federal  Energy  Regulatory  Commission
(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. Also in first quarter 2001, in a proceeding before the
FERC,  the  Alliance  RTO and the Midwest ISO  reached an  agreement  that would
enable  Ameren to withdraw  from the Midwest ISO and to join the  Alliance  RTO.
During the second quarter of 2001, this settlement agreement was approved by the
FERC. The Registrant's  withdrawal from the Midwest ISO remains subject to MoPSC
approval.  Additional  regulatory  approvals of the FERC, MoPSC,  Securities and
Exchange  Commission  and the Illinois  Commerce  Commission  may be required in
connection with various transactions  involving the Alliance RTO relating to its
organization,  capitalization and the possible transfer of transmission  assets.
Such  approvals,  if  required,  will be sought at the  appropriate  times.  The
Alliance RTO is expected to be  operational  within 90-120 days after the FERC's
approval.  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 operations or liquidity.

Note 3 - Derivative Financial Instruments

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 $7  million  after  income  taxes  to the  income
statement,  comprised of $2 million for ineffective  portion of cash flow hedges
and  $5  million  for  discontinued  hedges.  The  Registrant  also  recorded  a
cumulative effect adjustment of $11 million after income taxes, representing the
effective  portion  of  designated  cash  flow  hedges,  to OCI,  which  reduced

                                       16


stockholders'  equity.  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
"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
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.  Ameren  primarily  uses  derivatives  to  optimize  the value of its
physical and contractual  positions.  Ameren continually assesses its supply and
delivery  commitment  positions  against  forward  market prices and  internally
forecasts  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
RMSC to assure  compliance with Ameren  policies.  The RMSC 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.

                                       17


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 Ameren's risk management strategies and the effect
of these strategies on Ameren's consolidated financial statements.

Cash Flow Hedges
The Registrant  routinely  enters into forward  purchase and sales contracts for
electricity based on forecasted levels of excess economic generation. The amount
of excess economic generation varies throughout the year and is monitored by the
RMSC.  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.  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
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 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.

The  Registrant has entered into forward  starting  interest rate swaps to hedge
the  interest  rate  risk  associated  with  the cost of a  future  issuance  of
fixed-rate debt. Under a forward starting swap, the Registrant  agrees to pay or
receive an amount equal to the  difference  (calculated  on a net present  value
basis)  of the  respective  cash  flows  based  on the  notional  amount  of the
instrument and the difference  between the forward starting swap rate determined
at the date when the agreement is established and the spot swap rate at the date
when the agreement is settled,  typically when the Registrant  issues the hedged
debt  issuance.  The notional  amounts of the agreement are not  exchanged.  The
Registrant entered into these swap agreements with major financial  institutions
in order to minimize  counterparty  credit  risk.  At September  30,  2001,  the
Registrant had notional  amounts of interest rate swaps hedging the  anticipated
debt issuance of $150 million. These agreements,  by their current terms, settle
in December 2001.

Interest rate swaps are reflected at fair value in the Registrant's consolidated
balance sheet and the related gains and losses on these  agreements are deferred
in shareholders'  equity (as a component of other comprehensive  income).  These
deferred  gains and losses  are then  amortized  as an  adjustment  to  interest
expense over the same period in which the related interest costs on the new debt
issuance is recognized in income.

For the three  months  ended  September  30,  2001,  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
the transition adjustment due to transactions going to delivery, was $4 million.
For the nine months ended  September 30, 2001, the Registrant  recorded a pretax
net gain of $13 million in electric  revenues in the  statement of income.  This
gain  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 the transition adjustment due to transactions going to delivery. All
components of each  derivative's gain or loss were included in the assessment of
hedge effectiveness.

As of  September  30,  2001,  all $3  million  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 upon 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 SFAS 133; therefore,  the net change in the market value of SO2 options is
recorded as  electric  revenues  and the net change in the market  value of coal
options is recorded as fuel and purchased power in the statement of income.

                                       18


Other
As of  September  30,  2001,  the  Registrant  has  recorded  the fair  value of
derivative  financial  instrument  assets of $13  million  in Other  Assets  and
derivative financial instrument  liabilities of $26 million in Other Investments
and 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.  The Registrant is currently  reevaluating the accounting for
these  transactions  as a result of recent  guidance  issued by the  Derivatives
Implementation Group of the Financial Accounting Standards Board (see Accounting
Matters under  Management's  Discussion and Analysis of Financial  Condition and
Results of Operations for further discussion).

Note 4 - Segment Information

Segment  information for the three-month,  nine-month and 12-month periods ended
September 30, 2001 and 2000 is as follows:



                                                                    

------------------------------------------------------------------------------------------
                                          Regulated                  Reconciling
(in millions)                             Utilities    All Other       Items*       Total
------------------------------------------------------------------------------------------

Three months ended September 30, 2001:

Revenues                                    $1,629       $ 60        $(257)      $1,432
Net Income                                     267         --           --          267
-----------------------------------------------------------------------------------------

Three months ended September 30, 2000:

Revenues                                    $1,295       $ 88        $(187)      $1,196
Net Income                                     255          1           --          256
-----------------------------------------------------------------------------------------

Nine months ended September 30, 2001:

Revenues                                    $3,962       $193        $(642)      $3,513
Net Income                                     419          1           --          420
-----------------------------------------------------------------------------------------

Nine months ended September 30, 2000:
Revenues                                    $3,110       $229        $(377)      $2,962
Net Income                                     429          2           --          431
-----------------------------------------------------------------------------------------

12 months ended September 30, 2001:

Revenues                                    $4,972       $258        $(822)      $4,408
Net Income                                     447         (1)          --          446
-----------------------------------------------------------------------------------------

12 months ended September 30, 2000:

Revenues                                    $3,829       $289        $(416)      $3,702
Net Income                                     426         --           --          426
-----------------------------------------------------------------------------------------


* Elimination of intercompany revenues.

                                       19


                                            PART II - OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS.

     Reference is made to Note 12 - Commitments and  Contingencies to the "Notes
to Consolidated  Financial Statements" on Pages 41 - 43 of the Registrant's 2000
Annual  Report  to   Stockholders   pages   incorporated  by  reference  in  the
Registrant's Form 10-K for the year ended December 31, 2000, for a discussion of
the  involvement  of  the  Registrant's   subsidiary,   Union  Electric  Company
(AmerenUE), with a contaminated site in Sauget, Illinois. On September 13, 2001,
the United States Environmental Protection Agency (EPA) proposed that the Sauget
Area 1 and Sauget Area 2 sites be listed on the National  Priorities List (NPL).
If  successful,  the listing of these  sites on the NPL would  permit the EPA to
access  funds  designated  under  the   Comprehensive   Environmental   Response
Compensation  Liability Act of 1980  (commonly  known as CERCLA or Superfund) to
remediate the sites.

ITEM 5.  OTHER INFORMATION.

     The  following  material  organizational  changes  have been made to senior
management  by the Boards of  Directors  of the  Registrant  and  certain of its
subsidiary companies:

Ameren Corporation

     o    Gary L. Rainwater was elected  President and Chief Operating  Officer,
          effective  August 30,  2001,  reporting  to Charles  W.  Mueller,  who
          remains Chairman and Chief Executive  Officer.  o Warner L. Baxter was
          elected Senior Vice  President,  Finance,  effective  August 30, 2001,
          replacing Donald E. Brandt, who resigned.

     o    Jerre E. Birdsong was elected Vice President and Treasurer,  effective
          October 12, 2001.

     o    Baxter A.  Gillette  was  elected  Vice  President,  Risk  Management,
          effective October 12, 2001.

     o    Martin J. Lyons,  formerly a partner at  PricewaterhouseCoopers,  LLC,
          was  appointed  Controller,  effective  October 22,  2001.  Mr.  Lyons
          replaces Warner L. Baxter in this position.

Union Electric Company (Subsidiary)

     o    Gary L. Rainwater was elected  President and Chief Operating  Officer,
          effective August 30, 2001, reporting to Charles W. Mueller, who became
          Chairman, while retaining his title of Chief Executive Officer.

     o    Warner L. Baxter was elected Senior Vice President, Finance, effective
          August 30, 2001, replacing Donald E. Brandt.

     o    Jerre E. Birdsong was elected Vice President and Treasurer,  effective
          October 12, 2001.

     o    Martin J. Lyons was appointed Controller,  effective October 22, 2001,
          replacing Warner L. Baxter.

Central Illinois Public Service Company (Subsidiary)

     o    Warner L. Baxter was elected Senior Vice President, Finance, effective
          August 30, 2001.

                                       20



     o    Jerre E. Birdsong was elected Vice President and Treasurer,  effective
          October 12, 2001.

     o    Martin J. Lyons was appointed Controller,  effective October 22, 2001,
          replacing Warner L. Baxter.

AmerenEnergy Generating Company (Subsidiary)

     o    Daniel F. Cole was  elected  President,  effective  August  30,  2001,
          replacing Gary L. Rainwater.

     o    Warner L. Baxter was elected Senior Vice President, Finance, effective
          August 30, 2001.

     o    Jerre E. Birdsong was elected Vice President and Treasurer,  effective
          October 12, 2001.

     o    Martin J. Lyons was appointed Controller,  effective October 22, 2001,
          replacing Warner L. Baxter.

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

         (a)   Exhibits.  None.

         (b)   Reports on Form 8-K.  The  Registrant  filed a report on Form 8-K
               dated July 2, 2001  reporting  that the Missouri  Public  Service
               Commission  (MoPSC) staff filed with the MoPSC an excess earnings
               complaint  against the Registrant's  subsidiary,  AmerenUE,  that
               proposes to reduce  AmerenUE's  annual electric  revenues ranging
               from  $213  million  to $250  million.  Note:  Reports  of  Union
               Electric Company on Forms 8-K, 10-Q and 10-K are on file with the
               SEC under File Number 1-2967.

               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.

               Information regarding AmerenEnergy Generating Company on Form S-4
               is on file  with the SEC  under  File  Number  333-56594  and its
               reports on Forms 8-K,  10-Q and 10-K are being filed with the SEC
               under the same File Number.

                                   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.

                       AMEREN CORPORATION
                        (Registrant)


                       By:    /s/ Warner L. Baxter
                       --------------------------------------
                                  Warner L. Baxter
                            Senior Vice President, Finance
                             (Principal Financial Officer)


Date:   November 14, 2001


                                       21