SECURITIES AND EXCHANGE COMMISSION
                              WASHINGTON, DC 20549



                                    FORM 8-K


                                 CURRENT REPORT




     Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934



                Date of Report (Date of earliest event reported):
                                February 14, 2002





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




           Missouri                        1-14756              43-1723446
   (State or other jurisdiction          (Commission         (I.R.S. Employer
        of incorporation)                File Number)        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

<PAGE>


ITEM 5.  OTHER EVENTS AND REGULATION FD DISCLOSURE

         On February  13,  2002,  Ameren  Corporation  (the  "Registrant")filed
the following with the  Securities and Exchange Commission as exhibits to this
Current Report on Form 8-K: (i) consolidated financial statements as of
December 31, 2001 and 2000, and for each of the three years in the period ended
December 31, 2001, and the report thereon of PricewaterhouseCoopers LLP,
independent accountants, and (ii) the related Management's Discussion and
Analysis of Financial Condition and Results of Operations.


ITEM 7.  EXHIBITS

         (c) Exhibits.

             23       Consent of Independent Accountants.

             99.1     The Registrant's consolidated financial statements as of
                      December 31, 2001 and 2000, and for each of the three
                      years in the period ended December 31, 2001, and the
                      report thereon of PricewaterhouseCoopers LLP, independent
                      accountants.

             99.2     The Registrant's Management's Discussion and Analysis of
                      Financial Condition and Results of Operations.



                                    SIGNATURE

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

                                          AMEREN CORPORATION
                                           (Registrant)


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


Date:  February 14, 2002











<PAGE>


                                  Exhibit Index

Exhibit No.                     Description

     23           - Consent of Independent Accountants.

     99.1         - The Registrant's consolidated financial statements as of
                    December 31, 2001 and 2000, and for each of the three years
                    in the period ended December 31, 2001, and the report
                    thereon of PricewaterhouseCoopers LLP, independent
                    accountants.

     99.2         - The Registrant's Management's Discussion and Analysis of
                    Financial Condition and Results of Operations.





















<PAGE>

                                                                      EXHIBIT 23
                       CONSENT OF INDEPENDENT ACCOUNTANTS


We  hereby  consent  to the  incorporation  by  reference  in  the  Registration
Statements on Form S-8 (Nos. 333-43737,  333-43743, 333-50793 and 333-72156) and
the Registration  Statement on Form S-3 (No. 333-39400) of Ameren Corporation of
our  report  dated  February  1, 2002  relating  to the  consolidated  financial
statements,  which  appears  in  the  Current  Report  on  Form  8-K  of  Ameren
Corporation dated February 14, 2002.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
St. Louis, Missouri
February 14, 2002
<PAGE>



                                                                    EXHIBIT 99.1
                        Report of Independent Accountants


To the Board of Directors and Shareholders
of Ameren Corporation

In our opinion,  the  accompanying  consolidated  balance sheets and the related
consolidated  statements  of income,  of cash flows and of common  stockholders'
equity  present  fairly,  in all material  respects,  the financial  position of
Ameren  Corporation and its subsidiaries at December 31, 2001, and 2000, and the
results of their  operations and their cash flows for each of the three years in
the period ended  December 31, 2001, in conformity  with  accounting  principles
generally accepted in the United States of America.  These financial  statements
are the  responsibility of the Company's  management;  our  responsibility is to
express  an  opinion  on these  financial  statements  based on our  audits.  We
conducted our audits of these  statements in accordance with auditing  standards
generally  accepted in the United States of America,  which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements,  assessing the accounting  principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.


/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
St. Louis, Missouri
February 1, 2002
<PAGE>
<TABLE>
<CAPTION>
                               AMEREN CORPORATION
                           CONSOLIDATED BALANCE SHEET
                  (Thousands of Dollars, Except Share Amounts)

                                                    December      December
                                                         31,          31,
ASSETS                                                   2001        2000
------                                                  ----         ----
<S>                                                 <C>        <C>
Property and plant, at original cost:
   Electric                                      $ 13,664,168    $ 12,684,366
   Gas                                                532,346         509,746
   Other                                              104,790          97,214
                                                 ------------    ------------
                                                   14,301,304      13,291,326
   Less accumulated depreciation and
     amortization                                   6,535,693       6,204,367
                                                 ------------    ------------
                                                    7,765,611       7,086,959
Construction work in progress:
   Nuclear fuel in process                             96,676         117,789
   Other                                              564,275         500,924
                                                 ------------    ------------
         Total property and plant, net              8,426,562       7,705,672
                                                 ------------    ------------
 Investments and other assets:
   Investments                                         39,432          40,235
   Nuclear decommissioning trust fund                 186,937         190,625
   Other                                              113,493          97,630
                                                 ------------    ------------
         Total investments and other assets           339,862         328,490
                                                 ------------    ------------
  Current assets:
   Cash and cash equivalents                           67,092         125,968
   Accounts receivable - trade (less allowance
       for doubtful  accounts of  $8,783 and
       $8,028, respectively)                          389,127         474,425
   Other accounts and notes receivable                 71,234          56,529
   Materials and supplies, at average cost:
      Fossil fuel                                     158,800         107,572
      Other                                           136,322         119,478
   Other                                               40,939          37,210
                                                 ------------    ------------
         Total current assets                         863,514         921,182
                                                 ------------    ------------
 Regulatory assets:
   Deferred income taxes                              604,092         600,100
   Other                                              166,545         158,986
                                                 ------------    ------------
         Total regulatory assets                      770,637         759,086
                                                 ------------    ------------
 Total Assets                                    $ 10,400,575    $  9,714,430
                                                 ============    ============

CAPITAL AND LIABILITIES
Capitalization:
   Common stock, $.01 par value, 400,000,000
     shares authorized -shares outstanding of
     138,045,639 and 137,215,462, respectively
     (Note 5)                                          $1,380          $1,372
   Other paid-in capital, principally premium
     on common stock                                1,614,206       1,581,339
   Retained earnings                                1,733,558       1,613,960
   Accumulated other comprehensive income               4,417           -
   Other                                               (4,801)          -
                                                 ------------    ------------
         Total common stockholders' equity          3,348,760       3,196,671
   Preferred stock of subsidiaries not subject
     to mandatory redemption  (Note 5)                235,197         235,197
   Long-term debt  (Note 7)                         2,835,378       2,745,068
                                                 ------------    ------------
         Total capitalization                       6,419,335       6,176,936
                                                 ------------    ------------
Minority interest in consolidated subsidiaries          3,534           3,940
Current liabilities:
   Current maturity of long-term debt (Note 7)        138,961          44,444
   Short-term debt                                    641,336         203,260
   Accounts and wages payable                         392,169         462,924
   Accumulated deferred income taxes                   57,787          49,829
   Taxes accrued                                      132,246         124,706
   Other                                              218,525         300,798
                                                 ------------    ------------
        Total current liabilities                   1,581,024       1,185,961
                                                 ------------    ------------
                                       2


<PAGE>

Commitments and contingencies (Notes 2, 11
  and 12)
Accumulated deferred income taxes                   1,562,916       1,540,536
Accumulated deferred investment tax credits           157,936         164,120
Regulatory liability                                  172,290         183,541
Other deferred credits and liabilities                503,540         459,396
                                                 ------------    ------------
Total Capital and Liabilities                    $ 10,400,575    $  9,714,430
                                                 ============    ============
See Notes to Consolidated Financial Statements.
</TABLE>

                                       3
<PAGE>
<TABLE>
<CAPTION>
                               AMEREN CORPORATION
                        CONSOLIDATED STATEMENT OF INCOME
           (Thousands of Dollars, Except Share and Per Share Amounts)

                                                              December 31,      December 31,       December 31,
For the year ended                                                2001               2000               1999
                                                                  ----               ----               ----
<S>                                                          <C>               <C>              <C>
OPERATING REVENUES:
   Electric                                                   $   4,155,240    $   3,526,578    $   3,300,022
   Gas                                                              342,168          323,886          228,298
   Other                                                              8,459            6,366            7,743
                                                              -------------    -------------    -------------
      Total operating revenues                                    4,505,867        3,856,830        3,536,063

OPERATING EXPENSES:
   Operations:
      Fuel and purchased power                                    1,562,164        1,025,221          973,277
      Gas                                                           221,842          209,467          131,449
      Other                                                         708,096          664,544          629,482
                                                              -------------    -------------    -------------
                                                                  2,492,102        1,899,232        1,734,208
   Maintenance                                                      382,105          367,921          370,873
   Depreciation and amortization                                    405,804          383,110          362,971
   Income taxes                                                     300,052          301,192          258,870
   Other taxes                                                      260,817          265,065          246,592
                                                              -------------    -------------    -------------
      Total operating expenses                                    3,840,880        3,216,520        2,973,514

OPERATING INCOME                                                    664,987          640,310          562,549

OTHER INCOME AND (DEDUCTIONS):
   Allowance for equity funds used during construction               12,893            5,298            7,161
   Miscellaneous, net                                                   674           (4,400)         (10,813)
                                                              -------------    -------------    -------------
    Total other income and (deductions)                              13,567              898           (3,652)

INCOME BEFORE INTEREST CHARGES
  AND PREFERRED DIVIDENDS                                           678,554          641,208          558,897

INTEREST CHARGES AND PREFERRED DIVIDENDS:
   Interest                                                         198,648          179,706          168,275
   Allowance for borrowed funds used during construction             (7,925)          (8,292)          (7,123)
   Preferred dividends of subsidiaries                               12,445           12,700           12,650
                                                              -------------    -------------    -------------
      Net interest charges and preferred dividends                  203,168          184,114          173,802
                                                              -------------    -------------    -------------
INCOME BEFORE CUMULATIVE EFFECT OF
  CHANGE IN ACCOUNTING PRINCIPLE                                    475,386          457,094          385,095

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
  PRINCIPLE, NET OF INCOME TAXES                                     (6,841)            -               -
                                                              -------------    -------------    -------------

NET INCOME                                                    $     468,545    $     457,094    $     385,095
                                                              =============    =============    =============

EARNINGS PER COMMON SHARE  - BASIC
   Income before cumulative effect of change in accounting
principle                                                     $        3.46    $        3.33    $        2.81
   Cumulative effect of change in accounting principle, net
of  income taxes                                                       (.05)            -               -
                                                              -------------    -------------    -------------
   EARNINGS PER COMMON SHARE - BASIC
                                                              $        3.41    $        3.33    $        2.81
                                                              =============    =============    =============
EARNINGS PER COMMON SHARE - DILUTED
 Income before cumulative effect of
   change in accounting principle                             $        3.45    $        3.33    $        2.81
   Cumulative effect of change in accounting principle,
   net of income taxes                                                 (.05)            -               -
                                                              -------------    -------------    -------------
   EARNINGS PER COMMON SHARE - DILUTED                        $        3.40    $        3.33    $        2.81
                                                              =============    =============    =============
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (Note 1)             137,320,692      137,215,462      137,215,462
                                                              =============    =============    =============

See Notes to Consolidated Financial Statements.
</TABLE>
                                       4
<PAGE>
<TABLE>
<CAPTION>
                               AMEREN CORPORATION
                      CONSOLIDATED STATEMENT OF CASH FLOWS
                             (Thousands of Dollars)


                                                             December 31,     December 31,    December 31,
For the year ended                                             2001               2000            1999
                                                               ----               ----            ----
<S>                                                       <C>               <C>             <C>
Cash Flows From Operating:
   Net income                                                $   468,545    $   457,094       $ 385,095
   Adjustments to reconcile net income to net cash
     provided by operating activities:
       Cumulative effect of change in accounting principle         6,841           -              -
       Depreciation and amortization                             393,088         370,776        352,761
       Amortization of nuclear fuel                               29,370          37,101         36,068
       Allowance for funds used during construction              (20,818)       (13,590)        (14,284)
       Deferred income taxes, net                                 28,018          1,699         (22,578)
       Deferred investment tax credits, net                       (6,184)        (6,714)         (7,998)
       Changes in assets and liabilities:
           Receivables, net                                       70,593       (139,845)         34,484
           Materials and supplies                                (68,072)        26,174          (7,432)
           Accounts and wages payable                            (70,755)       121,650          56,456
           Taxes accrued                                           7,540        (30,690)         41,290
           Other, net                                           (100,124)        31,927          63,713
                                                             -----------     -----------    -----------
Net cash provided by operating activities                        738,042        855,582         917,575

Cash Flows From Investing:
   Construction expenditures                                  (1,102,586)      (928,727)       (570,807)
   Allowance for funds used during construction                   20,818         13,590          14,284
   Nuclear fuel expenditures                                     (24,359)       (21,527)        (21,901)
   Other                                                             803         26,241          20,218
                                                                -----------  -----------    -----------
Net cash used in investing activities                         (1,105,324)      (910,423)       (558,206)

Cash Flows From Financing:
   Dividends on common stock                                    (348,819)      (348,527)       (348,527)
   Redemptions -
      Nuclear fuel lease                                         (64,122)       (11,356)        (15,138)
      Long-term debt                                             (63,544)      (420,994)       (174,444)
   Issuances -
      Common stock                                                33,397           -              -
      Nuclear fuel lease                                          13,418          9,109          64,972
      Short-term debt                                            438,076         55,095          79,637
      Long-term debt                                             300,000        702,600         152,150
                                                             -----------     -----------    -----------
Net cash provided by (used in) financing activities              308,406        (14,073)       (241,350)

Net change in cash and cash equivalents                          (58,876)       (68,914)        118,019
Cash and cash equivalents at beginning of year                   125,968        194,882          76,863
                                                             -----------     -----------    -----------
Cash and cash equivalents at end of year                     $    67,092    $   125,968     $   194,882
=======================================================================================================
Cash paid during the periods:
-------------------------------------------------------------------------------------------------------
   Interest (net of amount capitalized)                      $   187,121    $   168,650    $   162,705
   Income taxes                                                  266,352        311,848        247,428
-------------------------------------------------------------------------------------------------------

See Notes to Consolidated Financial Statements.
</TABLE>

                                       5
<PAGE>
<TABLE>
<CAPTION>
                               AMEREN CORPORATION
              CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY
                             (Thousands of Dollars)


                                                           December 31,    December 31,    December 31,
For the year ended                                             2001            2000           1999
                                                               ----            ----           ----
<S>                                                       <C>          <C>             <C>
Common stock
   Beginning balance                                       $     1,372    $     1,372    $     1,372
   Shares issued                                                     8          -               -
                                                           -----------    -----------    -----------
                                                                 1,380          1,372          1,372

Other paid-in capital
   Beginning balance                                         1,581,339      1,582,501      1,582,548
   Shares issued                                                33,389          -               -
   Employee stock awards                                          (522)        (1,162)           (47)
                                                           -----------    -----------    -----------
                                                             1,614,206      1,581,339      1,582,501

Retained earnings
   Beginning balance                                         1,613,960      1,505,827      1,472,200
   Net income                                                  468,545        457,094        385,095
   Dividends                                                  (348,947)      (348,961)      (351,468)
                                                           -----------    -----------    -----------
                                                             1,733,558      1,613,960      1,505,827

Accumulated other comprehensive income
   Beginning balance                                              -             -             -
   Change in current period                                      4,417          -             -
                                                           -----------    -----------    -----------
                                                                 4,417          -             -

Other
   Beginning balance                                              -             -             -
   Unamortized restricted stock compensation                    (5,704)         -             -
   Compensation amortized and mark-to-market adjustments           903          -             -
                                                           -----------    -----------    -----------
                                                                (4,801)         -             -
                                                           -----------    -----------    -----------
Total common stockholders' equity                          $ 3,348,760    $ 3,196,671    $ 3,089,700
                                                           ===========    ===========    ===========

Comprehensive income, net of taxes
   Net income                                              $   468,545        457,094        385,095
   Cumulative effect of accounting change                      (11,258)         -            -
   Unrealized net gain on derivative hedging instruments        15,675          -            -
                                                           -----------    -----------    -----------
                                                           $   472,962   $    457,094    $   385,095
                                                           ===========    ===========    ===========

See Notes to Consolidated Financial Statements.
</TABLE>
                                       6
<PAGE>

AMEREN CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001

NOTE 1 - Summary of Significant Accounting Policies

Basis of Presentation
Ameren Corporation (Ameren or the Company) is a holding company registered under
the Public Utility Holding Company Act of 1935 (PUHCA).  In December 1997, Union
Electric Company  (AmerenUE) and CIPSCO  Incorporated  (CIPSCO) combined to form
Ameren, with AmerenUE and CIPSCO's subsidiaries, Central Illinois Public Service
Company (AmerenCIPS) and CIPSCO Investment Company (CIC),  becoming subsidiaries
of Ameren  (the  Merger).  The  outstanding  preferred  shares of  AmerenUE  and
AmerenCIPS were not affected by the Merger.

The  accompanying  consolidated  financial  statements  include the  accounts of
Ameren and its subsidiaries  (collectively,  the Company).  All subsidiaries for
which the Company owns directly or indirectly  more than 50% of the voting stock
are included as consolidated subsidiaries. Ameren's primary operating companies,
AmerenUE,  AmerenCIPS, and AmerenEnergy Generating Company (Generating Company),
a wholly-owned subsidiary of AmerenEnergy Resources Company (Resources 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. The
Company's other principal  subsidiaries  include:  CIC, an investing subsidiary;
AmerenEnergy,   Inc.,  an  energy  trading  and  marketing  subsidiary;   Ameren
Development Company, a nonregulated products and services subsidiary;  Resources
Company, a holding company for the Company's nonregulated generating operations;
and Ameren Services Company, a shared support services  subsidiary.  The Company
also has a 60% 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. All
significant intercompany balances and transactions have been eliminated from the
consolidated financial statements.

References to the Company are to Ameren on a  consolidated  basis.  However,  in
certain  circumstances,  the subsidiaries are separately referred to in order to
distinguish among their different business activities.

Regulation
Ameren is subject to regulation by the Securities and Exchange Commission (SEC).
Certain of Ameren's  subsidiaries  are also  regulated  by the  Missouri  Public
Service  Commission  (MoPSC),   Illinois  Commerce  Commission  (ICC),   Nuclear
Regulatory Commission (NRC) and the Federal Energy Regulatory Commission (FERC).
The  accounting  policies  of the  Company  conform to U.S.  generally  accepted
accounting  principles  (GAAP).  See Note 2 -  Regulatory  Matters  for  further
information.

Property and Plant
The cost of  additions  to, and  betterments  of, units of property and plant is
capitalized.  Cost includes labor, material,  applicable taxes and overheads. An
allowance  for funds used during  construction  is also added for the  Company's
regulated  assets,  and interest during  construction is added for  nonregulated
assets.  Maintenance  expenditures and the renewal of items not considered units
of  property  are  charged to income,  as  incurred.  When units of  depreciable
property are retired,  the original cost and removal cost,  less salvage  value,
are charged to accumulated depreciation.

Depreciation
Depreciation  is provided  over the  estimated  lives of the various  classes of
depreciable  property by applying composite rates on a straight-line  basis. The
provision for depreciation in 2001,  2000, and 1999 was  approximately 3% of the
average depreciable cost.

Fuel and Gas Costs
In the Company's retail electric utility jurisdictions, the cost of fuel for
electric  generation is reflected in base rates with no provision for changes in
such cost to be  reflected  in billings to  customers  through  fuel  adjustment
clauses. In the Company's retail gas utility jurisdictions, changes in gas costs
are  generally  reflected in billings to gas  customers  through  purchased  gas
adjustment clauses.

                                       7
<PAGE>

Nuclear Fuel
The cost of nuclear fuel is  amortized  to fuel expense on a  unit-of-production
basis.   Spent  fuel  disposal  cost  is  charged  to  expense,   based  on  net
kilowatthours generated and sold.

Cash and Cash Equivalents
Cash  and  cash  equivalents  include  cash on hand  and  temporary  investments
purchased with an original maturity of three months or less.

Income Taxes
The  Company  and its  subsidiaries  file a  consolidated  federal  tax  return.
Deferred tax assets and liabilities  are recognized for the tax  consequences of
transactions that have been treated  differently for financial reporting and tax
return purposes, measured using statutory tax rates.

Investment tax credits utilized in prior years were deferred and are being
amortized over the useful lives of the related properties.

Allowance for Funds Used During Construction
Allowance  for  funds  used  during  construction  (AFC) is a  utility  industry
accounting  practice  whereby the cost of borrowed  funds and the cost of equity
funds (preferred and common  stockholders'  equity)  applicable to the Company's
regulated  construction  program are capitalized as a cost of construction.  AFC
does not  represent a current  source of cash funds.  This  accounting  practice
offsets the effect on earnings of the cost of  financing  current  construction,
and treats such financing costs in the same manner as  construction  charges for
labor and materials.

Under  accepted  ratemaking  practice,  cash  recovery  of AFC, as well as other
construction  costs,  occurs when  completed  projects are placed in service and
reflected in customer  rates.  The AFC ranges of rates used were 4% - 10% during
2001, 6% - 10% during 2000, and 5% - 10% during 1999.

Unamortized Debt Discount, Premium and Expense
Discount,  premium and expense associated with long-term debt are amortized over
the lives of the related issues.

Revenue
The  Company  accrues an  estimate  of  electric  and gas  revenues  for service
rendered, but unbilled, at the end of each accounting period.

Energy Contracts
Statement of Financial  Accounting  Standards  (SFAS) No. 133,  "Accounting  for
Derivative  Instruments and Hedging  Activities," became effective on January 1,
2001.  SFAS 133  establishes  accounting and reporting  standards for derivative
instruments,   including  certain  derivative   instruments  embedded  in  other
contracts,   and  for  hedging  activities  and  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, a cash flow hedge, or a foreign  currency hedge will determine
when the gains or losses on the  derivatives  are to be reported in earnings and
when they are to be  reported as a component  of other  comprehensive  income in
stockholders'  equity.  See Note 3 - Risk  Management and  Derivative  Financial
Instruments for further information.

The  Emerging  Issues Task Force of the  Financial  Accounting  Standards  Board
(EITF)  Issue  98-10,   "Accounting  for  Energy  Trading  and  Risk  Management
Activities" became effective on January 1, 1999. EITF 98-10 provides guidance on
the  accounting  for energy  contracts  entered into for the purchase or sale of
electricity,  natural  gas,  capacity  and  transportation.  The EITF  reached a
consensus in EITF 98-10 that sales and purchase  activities being performed need
to be classified as either  trading or  non-trading.  Furthermore,  transactions
that are determined to be trading  activities would be recognized on the balance
sheet  measured at fair value,  with  changes in fair market  value  included in
earnings.

AmerenEnergy, Inc. enters into contracts, some of which are derivatives, for the
sale and  purchase  of  energy on behalf of  AmerenUE  and  Generating  Company.
Derivatives  are  accounted  for  under  SFAS  133 or EITF  98-10  based  on the
Company's intent when entering into the contract.  Virtually all  non-derivative
contracts are accounted for using the accrual or settlement method.

                                       8
<PAGE>

Software
Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use" became effective on January 1, 1999. SOP
98-1  provides  guidance  on  accounting  for the  costs  of  computer  software
developed or obtained for internal  use.  Under SOP 98-1,  certain  costs may be
capitalized and amortized over some future period.

Evaluation of Assets for Impairment
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," prescribes  general standards for the recognition and
measurement of impairment  losses.  The Company  determines if long-lived assets
are impaired by comparing their undiscounted expected future cash flows to their
carrying amount.  An impairment loss is recognized if the undiscounted  expected
future cash flows are less than the carrying amount of the asset.  SFAS 121 also
requires that regulatory assets which are no longer probable of recovery through
future  revenues be charged to  earnings  (see Note 2 -  Regulatory  Matters for
further information). As of December 31, 2001, no impairment was identified.

In August 2001, the Financial  Accounting Standards Board (FASB) issued SFAS No.
144,  "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS 144
addresses the financial  accounting and reporting for the impairment or disposal
of  long-lived  assets and  supersedes  SFAS 121.  SFAS 144 retains the guidance
related to calculating and recording impairment losses, but adds guidance on the
accounting  for  discontinued   operations,   previously   accounted  for  under
Accounting  Principles Board Opinion No. 30. SFAS 144 was adopted by the Company
on  January  1,  2002,  and did not  have a  material  effect  on the  Company's
financial position, results of operations or liquidity.

Asset Retirement Obligations
In July  2001,  the FASB  issued  SFAS 143,  "Accounting  for  Asset  Retirement
Obligations."   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.  At this time,  the
Company is assessing the impact of SFAS 143 on its financial  position,  results
of operations  and liquidity  upon  adoption.  However,  SFAS 143 is expected to
result in significant increases to the Company's reported assets and liabilities
as a  result  of  its  ongoing  collection  through  rates  of  and  obligations
associated with Callaway Nuclear Plant decommissioning costs. See Note 12 -
Callaway Nuclear Plant for further information.

Stock Compensation Plans
The Company applies  Accounting  Principles Board Opinion (APB) 25,  "Accounting
for Stock  Issued to  Employees"  in  accounting  for its  plans.  See Note 10 -
Stock-Based Compensation for further information.

Earnings Per Share
The Company's  calculation of diluted earnings per share resulted in dilution of
$.01 for 2001.  There was no difference  between the basic and diluted  earnings
per share amounts in 2000 and 1999. The reconciling item in each of the years is
comprised of assumed  stock option  conversions,  which  increased the number of
shares  outstanding  in the diluted  earnings per share  calculation  by 331,813
shares, 183,201 shares, and 38,786 shares in 2001, 2000 and 1999, respectively.

Use of Estimates
The  preparation  of  financial  statements  in  conformity  with GAAP  requires
management  to make  certain  estimates  and  assumptions.  Such  estimates  and
assumptions  affect reported amounts of assets and liabilities and disclosure of
contingent  assets and  liabilities at the date of the financial  statements and
the reported amounts of revenues and expenses during the reported period. Actual
results could differ from those estimates.

New Accounting Pronouncements
In July 2001, the FASB issued SFAS No. 141,  "Business  Combinations,"  and SFAS
No. 142,  "Goodwill and Other  Intangible  Assets."  SFAS 141 requires  business
combinations to be accounted for under the purchase method of accounting,  which
requires  one  party  in the  transaction  to be  identified  as  the  acquiring
enterprise  and for that party to allocate the purchase  price to the assets and

                                       9
<PAGE>

liabilities of the acquired  enterprise based on fair market value. 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 became effective
for the  Company  on  January  1,  2002.  SFAS  141 and  SFAS 142 did not have a
material effect on the Company's  financial  position,  results of operations or
liquidity upon adoption.

Reclassifications
Certain reclassifications have been made to prior years' financial statements to
conform with 2001 reporting.

NOTE 2 - Regulatory Matters

Missouri Electric
In  July  1995,  the  MoPSC  approved  an  agreement  establishing   contractual
obligations  involving AmerenUE'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%  regulatory return on equity (ROE) be shared equally
between customers and stockholders,  and earnings above a 14% ROE be credited to
customers. The formula for computing the credit used twelve-month results ending
June 30, rather than calendar year earnings.

The MoPSC staff proposed  adjustments to AmerenUE's estimated customer credit of
$43 million for the final year of the Original  Plan ended June 30, 1998,  which
were the subject of regulatory proceedings before the MoPSC in 1999. In December
1999,  the MoPSC issued a Report and Order  (Order)  concerning  these  proposed
adjustments.  Based  on the  provisions  of that  Order,  AmerenUE  revised  its
estimated  final year credit of the Original  Plan to $31 million in the quarter
ended December 31, 1999. Subsequently, AmerenUE filed a request for rehearing of
the Order  with the MoPSC,  asking  that it  reconsider  its  decision  to adopt
certain of the MoPSC  staff's  adjustments.  The request was denied by the MoPSC
and in  February  2000,  AmerenUE  filed a Petition  for Writ of Review with the
Circuit Court of Cole County,  Missouri,  requesting that the Order be reversed.
The appeal is pending and the ultimate outcome cannot be predicted; however, the
final decision is not expected to materially impact the financial condition,
results of operations or liquidity of the Company. A partial stay of the Order
was granted by the Court pending the appeal.

A new three-year  experimental  alternative  regulation  plan (the New Plan) was
included in the joint  agreement  authorized  by the MoPSC in its February  1997
order  approving the Merger.  Like the Original  Plan,  the New Plan required an
earnings over a 12.61% ROE up to a 14% ROE be shared equally  between  customers
and  stockholders.  The New Plan also  returned to customers 90% of all earnings
above a 14% ROE up to a 16% ROE. Earnings above a 16% ROE were credited entirely
to  customers.  The New Plan ran from July 1, 1998 through June 30, 2001. In May
2001,  the MoPSC approved a stipulation  and agreement of the parties  regarding
the credit for the plan year ended June 30, 2000 of $28 million, which was paid.
At December 31, 2001,  the Company  recorded an estimated  credit that  AmerenUE
expects to pay its Missouri electric  customers of $40 million for the plan year
ended June 30,  2001.  During the year ended  December  31,  2001,  the  Company
reduced the estimated  credit  previously  recorded for the plan year ended June
30, 2001 by $10 million,  compared to estimated  credits of $65 million recorded
in the year ago  period  for plan  years  ended  June 30,  2001 and 2000.  These
credits were reflected as a reduction in electric revenues.  The final amount of
the 2001 credit will depend on several factors, including approval by the MoPSC.

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  AmerenUE that
proposed to reduce its annual  electric  revenues  ranging  from $213 million to
$250 million.  Factors contributing to the MoPSC staff's recommendation included
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  ranged from 9.04% to 10.04%. The MoPSC is not bound by the MoPSC
staff's  recommendation.  In  January  2002,  the  MoPSC  issued  an order  that
established  the test year to be used to determine rates as July 1, 2000 through
June 30, 2001,  with updates to that test year permitted  through  September 30,
2001.  The MoPSC staff had utilized a test year of July 1, 1999 through June 30,
2000 in its  original  complaint.  In  addition,  the MoPSC  order  stated  that
AmerenUE  would be  permitted to propose an  incentive  regulation  plan in this
proceeding.

                                       10
<PAGE>

The MoPSC order also included a revised procedural schedule to allow all parties
additional time to review data and file  testimony,  due to the utilization of a
more current test year. Under the new schedule, the MoPSC staff will file direct
testimony  on March 1, 2002,  with  AmerenUE  and the  Office of Public  Counsel
filing  rebuttal  testimony on May 10, 2002.  Evidentiary  hearings on the MoPSC
staff's  recommendation are scheduled to be conducted before the MoPSC beginning
in July 2002.  In the event  that the MoPSC  ultimately  determines  that a rate
decrease is warranted in this case,  that rate reduction would be retroactive to
April 1,  2002,  regardless  of when the  MoPSC  issues  its  decision.  A final
decision  on this  matter  may not  occur  until  the  fourth  quarter  of 2002.
Depending on the outcome of the MoPSC's decision,  further appeals in the courts
may be warranted.

In the interim, the Company expects to continue  negotiations with all pertinent
parties with the intent to continue with an incentive  regulation plan,  similar
in form to the New  Plan.  The  Company  cannot  predict  the  outcome  of these
negotiations and their impact on the Company's  financial  position,  results of
operations or liquidity; however, the impact could be material.

Gas
In October  2000,  the MoPSC  approved a $4 million  annual  rate  increase  for
natural gas  service in  AmerenUE's  Missouri  jurisdiction.  The rate  increase
became  effective  November 1, 2000.  In February  1999,  the ICC  approved a $9
million  total annual rate  increase for natural gas service in  AmerenUE's  and
AmerenCIPS'  Illinois  jurisdictions.  The increase became effective in February
1999.

Midwest ISO and Alliance RTO
In 1998,  AmerenUE and AmerenCIPS  joined a group of companies  that  originally
supported  the formation of the Midwest  Independent  System  Operator  (Midwest
ISO).  An ISO  operates,  but does not own,  electric  transmission  systems and
maintains  system  reliability and security,  while  facilitating  wholesale and
retail competition through the elimination of "pancaked" transmission rates. The
Midwest  ISO is  regulated  by the FERC.  The FERC  conditionally  approved  the
formation of the Midwest ISO in September 1998.

In December 1999,  the FERC issued Order 2000 relating to Regional  Transmission
Organizations  (RTOs) that would meet certain  characteristics  such as size and
independence.  RTOs,  including  ISOs,  are entities that ensure  comparable and
non-discriminatory  access to regional electric transmission systems. Order 2000
calls on all transmission owners to join RTOs.

In the fourth quarter of 2000,  the Company  announced its intention to withdraw
from the Midwest ISO and to join the 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  Company's  estimated  obligation  under the  Midwest  ISO
agreement for costs incurred by the Midwest ISO, plus  estimated exit costs.  In
2001, the Company announced that it had signed an agreement to join the Alliance
RTO.  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.  This  settlement  agreement  was approved by the
FERC.  The Company's  withdrawal  from the Midwest ISO remains  subject to MoPSC
approval. In July 2001, the FERC conditionally approved the formation, including
the rate structure, of the Alliance RTO. However, on December 20, 2001, the FERC
issued an order that  reversed its  position  and rejected the  formation of the
Alliance  RTO.  Instead,  the FERC  granted  RTO status to the  Midwest  ISO and
ordered  the  Alliance  RTO  Companies  and the  Midwest  ISO to discuss how the
Alliance RTO business  model could be  accommodated  within the Midwest ISO. The
Alliance  RTO  members  have until  February  19,  2002 to respond to the FERC's
December 2001 order.  At this time, the Company is evaluating its  alternatives,
including the possible appeal of the FERC's  December 2001 order,  and is unable
to determine  the impact that the FERC's  latest  ruling will have on its future
financial condition, results of operations or liquidity.

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

                                       11
<PAGE>

Under the Illinois Law, retail direct access,  which allows  customers to choose
their  electric  generation  suppliers,  will be phased in over  several  years.
Access for  commercial  and  industrial  customers  occurred  over a period from
October 1999 to December 2000, and access for  residential  customers will occur
after May 1, 2002.

As a  requirement  of the Illinois Law, in March 1999,  AmerenUE and  AmerenCIPS
filed  delivery  service  tariffs with the ICC.  These  tariffs would be used by
electric customers who choose to purchase their power from alternate  suppliers.
In August 1999, the ICC issued an order approving the delivery  service tariffs,
with an allowed rate of return on equity of 10.45%.  In December 2000,  AmerenUE
and AmerenCIPS filed revised Illinois delivery service tariffs with the ICC. The
purpose  of the  filing  was to update  financial  information  that was used to
establish the initial rates and to propose new rates.  Additionally,  the filing
establishes  tariffs for residential  customers who may choose to purchase their
power from alternate  suppliers beginning in May 2002. In December 2001, the ICC
issued an Order approving the delivery service tariffs,  with an allowed rate of
return on equity of 11.35%.

Under the Illinois  Law, the Company is subject to a  residential  electric rate
decrease of up to 5% in 2002, to the extent its rates exceed the Midwest utility
average at that time. In 2001, the Company's  Illinois electric rates were below
the Midwest utility average.

The Illinois Law also  contains a provision  requiring  that  one-half of excess
earnings  from the  Illinois  jurisdiction  for the years 1998  through  2004 be
refunded to Ameren's  Illinois  customers.  Excess  earnings  are defined as the
portion of the two-year average annual rate of return on common equity in excess
of 1.5% of the two-year average of an Index, as defined in the Illinois Law. The
Index is defined as the sum of the average for the twelve months ended September
30 of the  average  monthly  yields of the 30-year  U.S.  Treasury  bonds,  plus
prescribed  percentages ranging from 4% to 7%. Filings must be made with the ICC
on, or before,  March 31 of each year 2000  through  2005.  The  Company did not
record any estimated refunds to Illinois customers in 2001.

In  conjunction  with another  provision  of the  Illinois  Law, on May 1, 2000,
following the receipt of all required  state and federal  regulatory  approvals,
AmerenCIPS  transferred  its  electric  generating  assets and  liabilities,  at
historical net book value, to Generating  Company,  in exchange for a promissory
note from  Generating  Company in the  principal  amount of  approximately  $552
million and Generating Company common stock (the Transfer).  The promissory note
bears  interest  at 7% and has a term of five years  payable  based on a 10-year
amortization.   The  transferred  assets  represent  a  generating  capacity  of
approximately 2,900 megawatts.  Approximately 45% of AmerenCIPS'  employees were
transferred to Generating Company as part of the transaction.

In conjunction with the Transfer, an electric power supply agreement was entered
into between  Generating Company and its newly created  nonregulated  affiliate,
AmerenEnergy   Marketing  Company  (Marketing  Company),   also  a  wholly-owned
subsidiary of Resources  Company.  Under this  agreement,  Marketing  Company is
entitled to purchase all of the Generating  Company's energy and capacity.  This
agreement may not be terminated  until at least  December 31, 2004. In addition,
Marketing   Company  entered  into  an  electric  power  supply  agreement  with
AmerenCIPS to supply it sufficient  energy and capacity to meet its  obligations
as a public  utility.  This  agreement  expires  December 31,  2004.  Power will
continue to be jointly dispatched between AmerenUE and Generating Company.

The creation of the new subsidiaries and the transfer of AmerenCIPS'  generating
assets and liabilities had no effect on the consolidated financial statements of
Ameren as of the date of the Transfer.

In August 1999, the Company filed a transmission system rate case with the FERC.
This filing was primarily  designed to implement rates, terms and conditions for
transmission  service for  wholesale  customers  and those  retail  customers in
Illinois  who choose  other  suppliers  as allowed  under the  Illinois  Law. In
January  2000,  the Company and other  parties to the rate case  entered  into a
settlement  agreement resolving all issues pending before the FERC. In May 2000,
the FERC  approved the  settlement  and allowed the  settlement  rates to become
effective as of the first quarter of 2000.

                                       12
<PAGE>

The provisions of the Illinois Law could also result in lower revenues,  reduced
profit margins and increased  costs of capital and operations  expense.  At this
time,  the Company is unable to determine  the impact of the Illinois Law on the
Company's future financial condition, results of operations or liquidity.

Missouri Electric Restructuring
In Missouri,  where  approximately 70% of the Company's retail electric revenues
are derived,  restructuring  bills have been  introduced but no legislation  has
been passed.  Furthermore, no restructuring legislation is expected to be passed
by the Missouri state legislature in 2002. The potential  negative  consequences
of  electric  industry  restructuring  could  be  significant  and  include  the
impairment and write-down of certain assets, including  generation-related plant
and net regulatory assets, lower revenues,  reduced profit margins and increased
costs of capital and operations expense. At December 31, 2001, the Company's net
investment  in  generation  facilities  related  to  its  Missouri  jurisdiction
approximated  $2.8 billion and was included in electric plant  in-service on the
Company's  balance  sheet.  In addition,  at December 31,  2001,  the  Company's
Missouri net  generation-related  regulatory  assets  approximated $449 million.

Regulatory Assets and Liabilities
In accordance  with SFAS No. 71 "Accounting  for the Effects of Certain Types of
Regulation,"  the Company has deferred  certain costs pursuant to actions of its
regulators,  and is currently recovering such costs in electric rates charged to
customers.

At December 31, the Company had recorded the following regulatory assets and
regulatory liability:
--------------------------------------------------------------------------------
In Millions                                              2001         2000
--------------------------------------------------------------------------------
Regulatory Assets:
  Income taxes (a)                                        $604        $600
  Callaway costs (b)                                        84          88
  Unamortized loss on reacquired debt(c)                    28          31
  Recoverable costs - contaminated facilities (d)           26           6
  Merger costs (e)                                          12          17
  Other                                                     17          17
--------------------------------------------------------------------------------
Regulatory Assets                                         $771        $759
--------------------------------------------------------------------------------
Regulatory Liability:
  Income taxes                                            $172        $184
--------------------------------------------------------------------------------
Regulatory Liability                                      $172        $184
--------------------------------------------------------------------------------
(a)  See Note 8 - Income Taxes.
(b)  Represents  Callaway  Nuclear Plant  operations and  maintenance  expenses,
     property  taxes and carrying costs  incurred  between the plant  in-service
     date and the date the plant was  reflected in rates.  These costs are being
     amortized over the remaining life of the plant (through 2024).
(c)  Represents  losses  related  to  refunded  debt.  These  amounts  are being
     amortized  over the lives of the related  new debt issues or the  remaining
     lives of the old debt issues if no new debt was issued.
(d)  Represents  the   recoverable   portion  of  accrued   environmental   site
     liabilities.
(e)  Represents  the  portion  of  merger-related  expenses  applicable  to  the
     Missouri retail  jurisdiction.  These costs are being  amortized  within 10
     years, based on a MoPSC order.

The Company  continually  assesses the  recoverability of its regulatory assets.
Under  current  accounting  standards,  regulatory  assets  are  written  off to
earnings  when it is no longer  probable  that such  amounts  will be  recovered
through future revenues.  However,  as noted in the above  paragraphs,  electric
industry  restructuring  legislation may impact the recoverability of regulatory
assets in the future.

NOTE 3 - Risk Management and Derivative Financial Instruments

The Company handles market risks in accordance with established policies,  which
may include entering into various derivative transactions.  In the normal course
of  business,  the  Company  also faces risks that are either  non-financial  or
non-quantifiable.  The Company'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.

                                     13
<PAGE>

Market Risk
The Company engages in price risk management  activities  related to electricity
and fuel. In addition to physically  buying and selling these  commodities,  the
Company uses  derivative  financial  instruments  to manage  market risks and to
reduce exposure  resulting from fluctuations in interest rates and the prices of
electricity  and  fuel.  Hedging  instruments  used  include  futures,   forward
contracts,  options and swaps. The primary use of these instruments is to manage
and hedge  contractual  commitments and to reduce exposure  related to commodity
market prices and interest rate volatility.

Credit Risk
Credit risk represents the loss that would be recognized if counterparties  fail
to perform as contracted.  New York Mercantile  Exchange  (NYMEX) traded futures
contracts  are  supported by the  financial  and credit  quality of the clearing
members of the NYMEX and have nominal  credit risk.  On all other  transactions,
the  Company  is exposed to credit  risk in the event of  nonperformance  by the
counterparties in the transaction.

The  Company's  physical and  financial  instruments  are subject to credit risk
consisting of trade  accounts  receivables  and executory  contracts with market
risk exposures.  The risk associated with trade  receivables is mitigated by the
large  number of customers in a broad range of industry  groups  comprising  the
Company's  customer  base.  No  customer  represents  greater  than  10%  of the
Company's accounts receivable. The Company's revenues are primarily derived from
sales of electricity and natural gas to customers in Missouri and Illinois.  The
Company analyzes each counterparty's  financial condition prior to entering into
forwards,  swaps,  futures or option  contracts.  The Company  also  establishes
credit limits for these counterparties and monitors the appropriateness of these
limits on an  ongoing  basis  through a credit  risk  management  program  which
involves  daily  exposure  reporting to senior  management,  master  trading and
netting agreements,  and credit support management (e.g.,  letters of credit and
parental guarantees).

Derivative Financial Instruments
In January 2001, the Company  adopted SFAS No. 133,  "Accounting  for Derivative
Instruments and Hedging Activities." The impact of that adoption resulted in the
Company  recording a cumulative  effect  charge of $7 million after taxes to the
income statement, and a cumulative effect adjustment of $11 million after income
taxes  to  Accumulated   Other   Comprehensive   Income  (OCI),   which  reduced
stockholders' equity. In June 2001, the Derivatives  Implementation Group (DIG),
a committee of the 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 be accounted for as normal purchases and sales if certain
criteria are met. This guidance was effective  beginning  July 1, 2001,  and did
not have a material  impact on the  Company's  financial  condition,  results of
operations or liquidity. However, in October and again in December 2001, the DIG
revised this guidance, with the revisions generally effective April 1, 2002. The
Company  does not expect the  impact of the DIG's  revisions  to have a material
effect on the Company's financial condition, results of operations, or liquidity
upon adoption.

SFAS 133 requires all derivatives to be recognized on the balance sheet at their
fair value. On the date that the Company 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   Company   reevaluates   its
classification of individual derivative transactions daily.

Changes in the fair value of  derivatives  are  recorded  each period in current
earnings or OCI,  depending on whether a derivative  is  designated as part of a
hedge transaction and, if it is, the type of hedge  transaction.  For fair-value
hedge transactions,  changes in the fair value of the derivative  instrument are
offset in the income  statement by changes in the hedged item's fair value.  For
cash-flow  hedge  transactions,  changes  in the fair  value  of the  derivative
instrument  are  reported  in  OCI.  The  gains  and  losses  on the  derivative
instrument  that are  reported  in OCI will be  reclassified  as earnings in the
periods in which  earnings are impacted by the  variability of the cash flows of
the  hedged  item.  The  ineffective  portion  of all  hedges is  recognized  in
current-period earnings.
                                       14

<PAGE>

The Company utilizes derivatives principally to manage the risk of changes in
market prices for natural gas, fuel,  electricity  and emission  credits.  Price
fluctuations  in  natural  gas,  fuel and  electricity  cause (1) an  unrealized
appreciation or  depreciation  of the Company's firm  commitments to purchase or
sell when purchase or sales 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 Company 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 Company.

As of December 31, 2001,  the Company has recorded the fair value of  derivative
financial instrument assets of $17 million in Other Assets and the fair value of
derivative  financial  instrument  liabilities  of $18 million in Other Deferred
Credits and Liabilities.

Cash Flow Hedges
The Company  routinely  enters into  forward  purchase and sales  contracts  for
electricity  based  on  forecasted  levels  of  economic   generation  and  load
requirements.  The relative balance between load and economic  generation varies
throughout the year. The contracts  typically cover a period of twelve months or
less.  The  purpose  of these  contracts  is to  hedge  against  possible  price
fluctuations in the spot market for the period covered under the contracts.  The
Company formally  documents all  relationships  between hedging  instruments and
hedged  items,  as  well as its  risk  management  objective  and  strategy  for
undertaking various hedge transactions.

As of  December  31,  2001,  a gain of $7  million  ($4.3  million,  after  tax)
associated with interest rate swaps for debt to be issued was in OCI and will be
amortized  over the life of the debt  ultimately  issued  or will be  recognized
immediately to the income  statement if a  determination  is made that debt will
not be issued.

For the year ended December 31, 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 OCI due to
transactions going to delivery, was approximately $15 million.

As of  December  31,  2001,  the  entire  net  gain  on  derivative  instruments
accumulated  in OCI is expected  to be  recognized  in earnings  during the next
twelve months upon delivery of the commodity being hedged.

Other Derivatives
The Company enters into option transactions to manage the Company's positions in
sulfur  dioxide (SO2)  allowances,  coal,  heating oil, and  electricity.  These
transactions  are  treated as  non-hedge  transactions  under SFAS 133.  The net
change in the market  value of S02 options is  recorded  as  electric  revenues,
while the net change in the market value of coal,  heating oil, and  electricity
options is recorded as fuel and purchased power in the income statement.

The Company has entered into fixed-price  forward  contracts for the purchase of
fuel.  While these contracts meet the definition of a derivative under SFAS 133,
the Company  records  these  transactions  as normal  purchases and normal sales
because the contracts are expected to result in physical delivery.  In September
2001,  the DIG issued  guidance  regarding  the  accounting  treatment  for fuel

                                       15
<PAGE>

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  that extends the quantity to be purchased at a fixed price are
not eligible to qualify for the normal  purchases and sales exception under SFAS
133.  This guidance is effective as of April 1, 2002.  The Company  continues to
evaluate the impact of this guidance on its future financial condition,  results
of operations or liquidity; however, the impact is not expected to be material.

NOTE 4 - Nuclear Fuel Lease

The Company has a lease  agreement  that provides for the financing of a portion
of its nuclear  fuel.  At December  31, 2001,  the maximum  amount that could be
financed  under the  agreement  was $120  million.  Pursuant to the terms of the
lease, the Company has assigned to the lessor certain  contracts for purchase of
nuclear fuel. The lessor  obtains,  through the issuance of commercial  paper or
from direct loans under a committed  revolving  credit agreement from commercial
banks, the necessary funds to purchase the fuel and make interest  payments when
due.

The Company is obligated to reimburse  the lessor for  expenditures  for nuclear
fuel,  interest and related costs under the lease.  Obligations under this lease
become due as any leased  nuclear  fuel is  consumed at the  Company's  Callaway
Nuclear  Plant.  No  leased  nuclear  fuel was  consumed  in 2001.  The  Company
reimbursed  the  lessor  $13  million in 2000 and $16  million  during  1999 for
amounts consumed under the lease.


The Company has capitalized the cost,  including  certain interest costs, of the
leased  nuclear  fuel and has  recorded  the  related  lease  obligation.  Total
interest  charges  under the lease were $4 million in 2001,  $8 million in 2000,
and $5 million in 1999.  Interest  charges for these years were based on average
interest rates of approximately  5% for 2001 and 7% for 2000 and 1999.  Interest
charges of $4 million in 2001,  $6 million in 2000,  and $4 million in 1999 were
capitalized.

NOTE 5 - Shareholder Rights Plan and Preferred Stock of Subsidiaries

In October 1998,  the  Company's  Board of Directors  approved a share  purchase
rights plan designed to assure  shareholders  of fair and equal treatment in the
event of a proposed takeover. The rights will be exercisable only if a person or
group acquires 15% or more of Ameren's common stock or announces a tender offer,
the  consummation of which would result in ownership by a person or group of 15%
or more of the common stock.  Each right will entitle the holder to purchase one
one-hundredth of a newly issued preferred stock at an exercise price of $180. If
a person or group  acquires 15% or more of Ameren's  outstanding  common  stock,
each right will  entitle  its holder  (other than such person or members of such
group) to purchase,  at the right's  then-current  exercise  price,  a number of
Ameren's  common shares having a market value of twice such price.  In addition,
if Ameren is  acquired  in a merger or other  business  combination  transaction
after a person or group has  acquired 15% or more of the  Company's  outstanding
common  stock,  each right will entitle its holder to  purchase,  at the right's
then-current  exercise price, a number of the acquiring  company's common shares
having a market value of twice such price.  The  acquiring  person or group will
not be entitled to exercise these rights.  The SEC approved the plan under PUHCA
in December 1998. The rights were issued as a dividend  payable January 8, 1999,
to shareholders  of record on that date;  these rights expire in 2008. One right
will  accompany  each new  share of Ameren  common  stock  issued  prior to such
expiration date.

At December 31, 2001 and 2000, AmerenUE and AmerenCIPS had 25 million shares and
4.6 million shares respectively, of authorized preferred stock.

                                       16
<PAGE>

<TABLE>
<CAPTION>
Outstanding preferred stock is entitled to cumulative dividends and is
redeemable at the prices shown in the following table:
------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------

Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption:
------------------------------------------------------------------------------------------------
Dollars in Millions at December 31,
<S>                                                  <C>                    <C>         <C>
                                                         Redemption Price      2001        2000
                                                           (per share)
Without par value and stated value of $100 per
share--
$7.64 Series     - 330,000 shares                      $103.82 - note (a)      $33         $33
$5.50 Series A   -  14,000 shares                       110.00                   1           1
$4.75 Series     -  20,000 shares                       102.176                  2           2
$4.56 Series     - 200,000 shares                       102.47                  20          20
$4.50 Series     - 213,595 shares                       110.00 - note (b)       21          21
$4.30 Series     -  40,000 shares                       105.00                   4           4
$4.00 Series     - 150,000 shares                       105.625                 15          15
$3.70 Series     -  40,000 shares                       104.75                   4           4
$3.50 Series     - 130,000 shares                       110.00                  13          13

With par value of $100 per share--
4.00% Series     - 150,000 shares                       101.00                  15          15
4.25% Series     -  50,000 shares                       102.00                   5           5
4.90% Series     -  75,000 shares                       102.00                   8           8
4.92% Series     -  50,000 shares                       103.50                   5           5
5.16% Series     -  50,000 shares                       102.00                   5           5
1993 Auction     - 300,000 shares                       100.00 - note (c)       30          30
6.625% Series    - 125,000 shares                       100.00                  12          12

Without par value and stated value of $25 per share--
$1.735 Series  - 1,657,500 shares                        25.00                  42          42
-----------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCK OF SUBSIDIARIES NOT SUBJECT TO MANDATORY
REDEMPTION                                                                    $235        $235
-----------------------------------------------------------------------------------------------
(a)  Beginning February 15, 2003, eventually declining to $100 per share.
(b)  In the event of voluntary liquidation, $105.50.
(c)  Dividend  rates,  and the  periods  during  which  such rates  apply,  vary
     depending on the Company's  selection of certain  defined  dividend  period
     lengths. The average dividend rate during 2001 was 3.63%.
</TABLE>

NOTE 6 - Short-Term Borrowings

Short-term  borrowings of the Company consist of bank loans and commercial paper
(maturities  generally  within 1-45 days).  At December 31, 2001 and 2000,  $641
million  and  $203  million,   respectively,   of  short-term   borrowings  were
outstanding.  The  weighted  average  interest  rates on  short-term  borrowings
outstanding at December 31, 2001 and 2000, were 1.9% and 6.7%, respectively.

At  December  31,  2001,  the  Company  had  committed  bank  lines  of  credit,
aggregating  $156 million,  all of which were unused and available at such date.
These lines 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 Company also has bank credit agreements  totaling $700 million,  expiring at
various dates between 2002 and 2003, that support the Company's commercial paper
programs.  At December 31, 2001, all of the bank credit  agreements were unused;
however, due to commercial paper borrowings and other commitments,  $126 million
of such borrowing capacity was available.

                                       17

<PAGE>

The  Company  has money  pool  agreements  with and among  its  subsidiaries  to
coordinate  and  provide  for  certain   short-term  cash  and  working  capital
requirements.   Separate  money  pools  are  maintained  between  regulated  and
nonregulated  businesses.  Interest is  calculated  at varying rates of interest
depending on the  composition of internal and external funds in the money pools.
This debt and the related interest represent  intercompany  balances,  which are
eliminated at the Ameren Corporation consolidated level.

<TABLE>
<CAPTION>
NOTE 7 - Long-Term Debt
--------------------------------------------------------------------------------
Long-term debt outstanding at December 31,                    2001      2000
--------------------------------------------------------------------------------
In Millions
--------------------------------------------------------------------------------
First Mortgage Bonds - note (a)
--------------------------------------------------------------------------------
<S>                                                          <C>      <C>
  8.33%  Series due 2002                                       $75       $75
  6 3/8% Series Z due 2003                                      40        40
  7.65%  Series due 2003                                       100       100
  6 7/8% Series due 2004                                       188       188
  7 3/8% Series due 2004                                        85        85
  7 1/2% Series X due 2007                                      50        50
  6 3/4% Series due 2008                                       148       148
  6.625% Series due 2011                                       150         -
  7.61% 1997 Series due 2017                                    40        40
  8 3/4% Series due 2021                                       125       125
  8 1/4% Series due 2022                                       104       104
  8%       Series due 2022                                      85        85
  7.15%  Series due 2023                                        75        75
  7%       Series due 2024                                     100       100
  6.125% Series due 2028                                        60        60
  5.45%  Series due 2028 - note (b)                             44        44
  Other  5.375%-7.05% due 2002 through 2008                     93       123
--------------------------------------------------------------------------------
                                                             1,562     1,442
--------------------------------------------------------------------------------
Environmental Improvement/Pollution Control Revenue Bonds
--------------------------------------------------------------------------------
  1991 Series due 2020 - note (c)                               43        43
  1992 Series due 2022 - note (c)                               47        47
  1993 Series A 6 3/8% due 2028                                 35        35
  1993 Series C-1 5.95% due 2026 (h)                            35        35
  1998 Series A due 2033 - note (c)                             60        60
  1998 Series B due 2033 - note (c)                             50        50
  1998 Series C due 2033 - note (c)                             50        50
  2000 Series A 5.5% due 2014 (h)                               51        51
  2000 Series A due 2035 - note (c)                             64        64
  2000 Series B due 2035 - note (c)                             63        63
  2000 Series C due 2035 - note (c)                             60        60
  Other  5%-5.90% due 2026 through 2028                         60        60
--------------------------------------------------------------------------------
                                                               618       618
--------------------------------------------------------------------------------
Subordinated Deferrable Interest Debentures
--------------------------------------------------------------------------------
  7.69% Series A due 2036 - note (d)                            66        66
--------------------------------------------------------------------------------
Unsecured Loans
--------------------------------------------------------------------------------
  Commercial Paper                                              -         19
  1991 Senior Medium Term Notes 8.60% due through 2005          27        33
  1994 Senior Medium Term Notes 6.61% due through 2005          31        39
  2000 Senior Notes 7.61% due 2004                              40        40
  2000 Senior Notes Series C 7 3/4% due 2005 - note (e)        225       225
  2000 Senior Notes Series D 8.35% due 2010 - note (f)         200       200
  2001 Floating Rate Notes due 2003 - note (g)                 150        -
--------------------------------------------------------------------------------
                                                               673       556
--------------------------------------------------------------------------------
Nuclear Fuel Lease                                              63       114
--------------------------------------------------------------------------------
Unamortized Discount and Premium on Debt                        (8)       (7)
--------------------------------------------------------------------------------
Maturities Due Within One Year                                (139)      (44)
--------------------------------------------------------------------------------
Total Long-Term Debt                                        $2,835    $2,745
--------------------------------------------------------------------------------

                                       18
<PAGE>

(a)  At December 31,  2001,  a majority of the property and plant was  mortgaged
     under, and subject to liens of, the respective indentures pursuant to which
     the bonds were issued.
(b)  Environmental Improvement Series
(c)  Interest  rates,  and the  periods  during  which  such rates  apply,  vary
     depending on the  Company's  selection of certain  defined rate modes.  The
     average interest rates for the year 2001 are as follows: 1991 Series 3.15%
                  1992 Series               3.11%
                  1998 Series A             3.07%
                  1998 Series B             3.07%
                  1998 Series C             3.04%
                  2000 Series A             2.99%
                  2000 Series B             2.97%
                  2000 Series C             3.03%
(d)  During  the  terms  of the  debentures,  the  Company  may,  under  certain
     circumstances,  defer the  payment of interest  for up to five  years.
(e)  Interest is payable semiannually in arrears on May 1 and November 1 of each
     year,  commencing  May 1, 2001.  Principal  will be payable on  November 1,
     2005.
(f)  Interest is payable semiannually in arrears on May 1 and November 1 of each
     year,  commencing  May 1, 2001.  Principal  will be payable on  November 1,
     2010.
(g)  Interest is payable  quarterly  commencing  March 12,  2002.  Principal  is
     payable on December 12, 2003.  The per annum interest rate on the notes for
     each  interest  period  will be a floating  rate equal to three month LIBOR
     plus a spread of 0.95%.
(h)  Variable rate tax-exempt  pollution  control  indebtedness was converted to
     long-term fixed rates.
</TABLE>
Maturities of long-term debt through 2006 are as follows:
----------------------------------------------------------
(In Millions)                             Principal Amount
----------------------------------------------------------
                                2002            $139
                                2003             340
                                2004             344
                                2005             259
                                2006              20
----------------------------------------------------------
In January 2002,  Ameren  Corporation  issued 5.70% Notes totaling $100 million.
Interest  is  payable  semi-annually  on  February  1 and August 1 of each year,
beginning August 1, 2002, and on the date of maturity,  February 1, 2007. Ameren
Corporation  received  net  proceeds  of $99.1  million  after a discount to the
public and deduction of  underwriters'  commissions.  With the proceeds,  Ameren
Corporation reduced its short-term borrowings.

The Company anticipates  securing additional financing in 2002. In January 2002,
Ameren Corporation filed a shelf registration statement with the SEC on Form S-3
which,  upon its  effective  date,  will allow the offering from time to time of
various forms of debt and equity  securities,  up to an aggregate offering price
of $1 billion.  The  proceeds  from any sale of such  securities  may be used to
finance  the  Company's   subsidiaries'  ongoing  construction  and  maintenance
programs,  to  redeem,  repurchase,  repay or retire  outstanding  indebtedness,
including  indebtedness  of the  Company's  subsidiaries,  to finance  strategic
investments in or future  acquisitions of other entities or other assets and for
other  general  corporate  purposes.  At this  time,  the  Company  is unable to
determine  the amount of the  additional  financing,  as well as the  additional
financing's impact on the Company's financial position, results of operations or
liquidity.

NOTE 8 - Income Taxes
<TABLE>
<CAPTION>
Total income tax expense for 2001 resulted in an effective tax rate of 39% on
earnings before income taxes (39% in 2000 and 1999).

Principal reasons such rates differ from the statutory federal rate:
--------------------------------------------------------------------------------
                                                 2001       2000      1999
--------------------------------------------------------------------------------
<S>                                            <C>        <C>       <C>
Statutory federal income tax rate:                 35%       35%       35%
Increases (Decreases) from:
  Depreciation differences                          2         2         1
  State tax                                         3         3         4
  Other                                            (1)       (1)       (1)
--------------------------------------------------------------------------------
Effective income tax rate                          39%       39%       39%
--------------------------------------------------------------------------------

                                       19
<PAGE>

Income tax expense components:
--------------------------------------------------------------------------------
In Millions                                      2001      2000      1999
--------------------------------------------------------------------------------
Taxes currently payable (principally
  Federal):
Included in operating expenses                  $ 280     $ 307     $ 287
Included in other income--
     Miscellaneous, net                             6        (2)       (3)
--------------------------------------------------------------------------------
                                                  286       305       284
Deferred taxes (principally federal):
Included in operating expenses--
     Depreciation differences                       9        (5)        3
     Other                                         19         7       (23)
Included in other income--
     Other                                         -          -        (2)
--------------------------------------------------------------------------------
                                                   28         2       (22)
Deferred investment tax credits,
  Amortization:
Included in operating expenses                     (8)       (8)       (8)
--------------------------------------------------------------------------------
Total income tax expense                        $ 306     $ 299     $ 254
--------------------------------------------------------------------------------
</TABLE>

In accordance with SFAS 109,  "Accounting for Income Taxes," a regulatory asset,
representing the probable recovery from customers of future income taxes,  which
is expected to occur when temporary differences reverse, was recorded along with
a  corresponding   deferred  tax  liability.   Also,  a  regulatory   liability,
recognizing  the lower  expected  revenue  resulting  from reduced  income taxes
associated  with amortizing  accumulated  deferred  investment tax credits,  was
recorded.  Investment  tax credits have been  deferred  and will  continue to be
credited to income over the lives of the related property.

The Company adjusts its deferred tax liabilities for changes enacted in tax laws
or rates.  Recognizing  that regulators will probably reduce future revenues for
deferred tax  liabilities  initially  recorded at rates in excess of the current
statutory  rate,  reductions in the deferred tax liability  were credited to the
regulatory liability.

Temporary differences gave rise to the following deferred tax assets and
deferred tax liabilities at December 31:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
In Millions                                                     2001     2000
--------------------------------------------------------------------------------
<S>                                                         <C>        <C>
Accumulated Deferred Income Taxes:
  Depreciation                                                $1,040    $1,043
  Regulatory assets, net                                         434       417
  Capitalized taxes and expenses                                 184       181
  Deferred benefit costs                                         (68)      (73)
  Other                                                           31        22
--------------------------------------------------------------------------------
Total net accumulated deferred income tax liabilities         $1,621    $1,590
--------------------------------------------------------------------------------
</TABLE>
NOTE 9 - Retirement Benefits

The Company has defined  benefit  retirement  plans covering  substantially  all
employees  of  AmerenUE,  AmerenCIPS,  and Ameren  Services  Company and certain
employees of Resources Company and its  subsidiaries.  Benefits are based on the
employees' years of service and compensation.  The Company's plans are funded in
compliance with income tax regulations and federal funding requirements.

Pension costs for 2001 and 2000 were $4 million and $3 million, respectively, of
which 16% and 21%, respectively, were charged to construction accounts.

                                       20
<PAGE>

<TABLE>
<CAPTION>
Funded Status of Ameren's Pension Plans:
--------------------------------------------------------------------------------
 In Millions                                                    2001     2000
--------------------------------------------------------------------------------
<S>                                                           <C>     <C>
Change in benefit obligation
 Net benefit obligation at beginning of year                  $ 1,362   $1,257
  Service cost                                                     32       30
  Interest cost                                                   100       98
  Plan amendments                                                  -        28
  Actuarial loss                                                   14       38
  Benefits paid                                                   (90)     (89)
--------------------------------------------------------------------------------
Net benefit obligation at end of year                           1,418    1,362
--------------------------------------------------------------------------------
Change in plan assets *
Fair value of plan assets at beginning of year                  1,359    1,427
  Actual return on plan assets                                     45      (20)
  Employer contributions                                            1        1
  Benefits paid                                                   (90)     (89)
--------------------------------------------------------------------------------
Fair value of plan assets at end of year                        1,225    1,359
--------------------------------------------------------------------------------

Funded status - deficiency/(excess)                               193        3
Unrecognized net actuarial gain/(loss)                            (33)     160
Unrecognized prior service cost                                   (77)     (82)
Unrecognized net transition asset                                   5        6
--------------------------------------------------------------------------------
Accrued pension cost at December 31                           $    88   $   87
--------------------------------------------------------------------------------
* Plan assets consist principally of common stocks and fixed income securities.
  Components of Ameren's Net Periodic Pension Benefit Cost:
</TABLE>
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
In Millions                             2001    2000     1999
--------------------------------------------------------------------------------
<S>                                  <C>      <C>      <C>
Service cost                           $  32    $  30    $  33
Interest cost                            100       98       91
Expected return on plan assets          (115)    (110)    (104)
Amortization of:
    Transition asset                      (1)      (1)      (1)
    Prior service cost                     9        7        7
    Actuarial gain                       (21)      (2)     (21)
--------------------------------------------------------------------------------
Net periodic benefit cost              $   4    $    3   $    24
--------------------------------------------------------------------------------
</TABLE>
Weighted-average Assumptions for Actuarial Present Value of Projected Benefit
Obligations:
--------------------------------------------------------------------------------
                                        2001    2000
--------------------------------------------------------------------------------
Discount rate at measurement date       7.25%   7.50%
Expected return on plan assets          8.50%   8.50%
Increase in future compensation         4.25%   4.50%
--------------------------------------------------------------------------------
On January 1, 2000, the AmerenUE and the AmerenCIPS postretirement benefit plans
combined to form the Ameren  Plans.  The Ameren  Plans cover  substantially  all
employees  of  AmerenUE,  AmerenCIPS,  and Ameren  Services  Company and certain
employees of Resources Company and its subsidiaries. The AmerenUE and AmerenCIPS
postretirement plans' information for 1999 is presented separately. Following is
the postretirement plan information related to Ameren's plans as of December 31.

Ameren's funding policy is to annually fund the Voluntary  Employee  Beneficiary
Association trusts (VEBA) with the lesser of the net periodic cost or the amount
deductible  for federal income tax purposes.  Postretirement  benefit costs were
$63  million  and  $58  million  for  2001  and  2000,  respectively,  of  which
approximately 18% and 17%,  respectively were charged to construction  accounts.
Ameren's transition  obligation at December 31, 2001 is being amortized over the
next 12 years.

The MoPSC and the ICC allow the  recovery  of  postretirement  benefit  costs in
rates to the extent that such costs are funded.

                                       21
<PAGE>

<TABLE>
<CAPTION>
Funded Status of Ameren's Postretirement Benefit Plans:
--------------------------------------------------------------------------------
 In Millions                                                   2001        2000
--------------------------------------------------------------------------------
<S>                                               <C>               <C>
Change in benefit obligation
Net benefit obligation at beginning of year                 $ 589         $ 492
  Service cost                                                 23            20
  Interest cost                                                47            43
  Plan amendments                                              -            (26)
  Actuarial loss                                               80            94
  Benefits paid                                               (38)          (34)
--------------------------------------------------------------------------------
Net benefit obligation at end of year                         701           589
--------------------------------------------------------------------------------

Change in plan assets *
Fair value of plan assets at beginning of year                290           269
  Actual return on plan assets                                (17)           (4)
  Employer contributions                                       65            59
  Benefits paid                                               (38)          (34)
--------------------------------------------------------------------------------
Fair value of plan assets at end of year                      300           290
--------------------------------------------------------------------------------

Funded status - deficiency                                    401           299
Unrecognized net actuarial gain                              (134)          (14)
Unrecognized prior service cost                                 2             2
Unrecognized net transition obligation                       (180)         (196)
--------------------------------------------------------------------------------
Postretirement benefit liability at December 31             $  89         $  91
--------------------------------------------------------------------------------
* Plan assets consist principally of common stocks, bonds and money market
instruments.
</TABLE>
<TABLE>
<CAPTION>
Components of Ameren's Net Periodic Postretirement Benefit Cost:
--------------------------------------------------------------------------------
In Millions                                                 2001      2000
--------------------------------------------------------------------------------
<S>                                                        <C>     <C>
Service cost                                                $ 23     $ 19
Interest cost                                                 47       43
Expected return on plan assets                               (25)     (18)
Amortization of:
    Transition obligation                                     16       16
    Actuarial (gain)/loss                                      2       (2)
--------------------------------------------------------------------------------
Net periodic benefit cost                                   $ 63     $ 58
--------------------------------------------------------------------------------

Assumptions for the Obligation Measurements:
--------------------------------------------------------------------------------
                                                            2001     2000
--------------------------------------------------------------------------------
Discount rate at measurement date                           7.25%    7.50%
Expected return on plan assets                              8.50%    8.50%
Medical cost trend rate                                     5.25%    5.00%
--------------------------------------------------------------------------------
</TABLE>
A 1% increase in the medical  cost trend rate is  estimated  to increase the net
periodic   cost   and  the   accumulated   postretirement   benefit   obligation
approximately  $7 million and $55  million,  respectively.  A 1% decrease in the
medical cost trend rate is  estimated to decrease the net periodic  cost and the
accumulated  postretirement benefit obligation  approximately $7 million and $51
million, respectively.

AmerenUE's  plans  cover  substantially  all  employees  of  AmerenUE as well as
certain employees of Ameren Services Company.  Postretirement benefit costs were
$46 million for 1999,  of which  approximately  18% was charged to  construction
accounts.

                                       22
<PAGE>

Components of AmerenUE's Net Periodic Postretirement Benefit Cost:
--------------------------------------------------------------------------------
In Millions                                      1999
--------------------------------------------------------------------------------
Service cost                                     $15
Interest cost                                     25
Expected return on plan assets                    (6)
Amortization of transition obligation             12
--------------------------------------------------------------------------------
Net periodic benefit cost                        $46
--------------------------------------------------------------------------------

AmerenCIPS'  plans cover  substantially  all  employees of AmerenCIPS as well as
certain employees of Ameren Services Company.  Postretirement benefit costs were
$3 million for 1999,  of which  approximately  10% was  charged to  construction
accounts.

Components of AmerenCIPS' Net Periodic Postretirement Benefit Cost:
--------------------------------------------------------------------------------
In Millions                                      1999
--------------------------------------------------------------------------------
Service cost                                      $3
Interest cost                                      9
Expected return on plan assets                    (9)
Amortization of:
    Transition obligation                          6
    Actuarial gain                                (6)
--------------------------------------------------------------------------------
Net periodic benefit cost                         $3
--------------------------------------------------------------------------------

NOTE 10 - Stock-Based Compensation

The Company has a long-term  incentive  plan (the Plan) for eligible  employees,
which provides for the grant of options,  performance awards,  restricted stock,
dividend  equivalents and stock appreciation  rights. The Company applies APB 25
in  accounting  for its  stock-based  compensation.  The Company has adopted the
disclosure-only  method of fair  value  data  under  SFAS 123,  "Accounting  for
Stock-Based Compensation."

Under the Plan, 141,788 restricted shares of the Company's stock were granted at
$39.60 in 2001. Upon the achievement of certain Company  performance levels, the
restricted stock award vests over a period of seven years, beginning at the date
of grant, and include  provisions  requiring  certain stock ownership levels. An
accelerated  vesting  provision is also included in the Plan,  which reduces the
vesting  period from seven years to three years.  The Company  records  unearned
compensation (as a component of stockholders'  equity) equal to the market value
of the  restricted  stock  on  the  date  of  grant  and  charges  the  unearned
compensation to expense over the vesting  period.  In accordance with APB 25 and
under SFAS 123, the Company's  compensation expense relating to restricted stock
awards totaled $903,000 in 2001.

Also  under the terms of the Plan,  options  may be  granted at a price not less
than the fair market  value of the common  shares at the date of grant.  Granted
options vest over a period of five years,  beginning  at the date of grant,  and
provide for acceleration of exercisability of the options upon the occurrence of
certain  events,  including  retirement.  Outstanding  options expire on various
dates  through  2010.  Under the Plan,  subject to adjustment as provided in the
Plan,  four million shares have been  authorized to be issued or delivered under
the Company's Plan. In accordance with APB 25, no compensation  expense has been
recognized for the Company's  stock options.  If the fair value method set forth
under SFAS 123 had been used to account for  options,  the effects on net income
and earnings would have been immaterial.

                                       23
<PAGE>

The following table summarizes stock option activity during 2001, 2000 and 1999:
<TABLE>
<CAPTION>
---------------------------------------------------------------------------------------------------------------------
                                                   2001                     2000                        1999
---------------------------------------------------------------------------------------------------------------------
                                                     Weighted                  Weighted                   Weighted
                                                      Average                   Average                    Average
                                                     Exercise                  Exercise                   Exercise
                                         Shares        Price        Shares       Price         Shares       Price
---------------------------------------------------------------------------------------------------------------------
<S>                                    <C>         <C>          <C>          <C>            <C>           <C>
Outstanding at beginning of year         2,430,532     $35.38      1,834,108     $38.22       1,095,180     $39.41
---------------------------------------------------------------------------------------------------------------------
Granted                                       -           -          957,100      31.00         768,100      36.63
Exercised                                  106,416      38.31        295,693      38.41          11,162      37.20
Cancelled or expired                        83,009      35.77         64,983      37.38          18,010      42.45
---------------------------------------------------------------------------------------------------------------------
Outstanding at end of year               2,241,107     $35.23      2,430,532     $35.38       1,834,108     $38.22
---------------------------------------------------------------------------------------------------------------------
Exercisable at end of year                 572,092     $38.74        312,736     $39.58         391,456     $39.06
---------------------------------------------------------------------------------------------------------------------
</TABLE>
Additional information about stock options outstanding at December 31, 2001:
--------------------------------------------------------------------------------
  Exercise      Outstanding       Weighted      Exercisable
    Price          Shares       Average Life      Shares
                                  (Years)
--------------------------------------------------------------------------------
$31.00               908,500        8.1          8,000
 35.50                   800        3.6            800
 35.875               35,880        3.3         35,880
 36.625              633,050        7.0        148,550
 38.50               102,985        5.1         71,170
 39.25               464,616        6.2        215,066
 39.8125               5,300        6.5          2,650
 43.00                89,976        3.8         89,976
--------------------------------------------------------------------------------

The fair values of stock options were estimated using a binomial option-pricing
model with the following assumptions:

--------------------------------------------------------------------------------
 Grant Date      Risk-free        Option Term        Expected        Expected
               Interest Rate                        Volatility    Dividend Yield
--------------------------------------------------------------------------------
  2/11/00        6.81%           10 years            17.39%           6.61%

  2/12/99        5.44%           10 years            18.80%           6.51%

  6/16/98        5.63%           10 years            17.68%           6.55%

  4/28/98        6.01%           10 years            17.63%           6.55%

  2/10/97        5.70%           10 years            13.17%           6.53%

  2/7/96         5.87%           10 years            13.67%           6.32%
--------------------------------------------------------------------------------

NOTE 11 - Commitments and Contingencies

The  Company  is  engaged  in a capital  program  under  which  expenditures  of
apprxomately  $3.5  billion,   including  AFC  and  capitalized  interest,   are
anticipated   over  the  next  five  years.   This  estimate   includes  capital
expenditures for the purchase of new combustion  turbine  generating  facilities
and for the replacement of four steam  generators at its Callaway Nuclear Plant.
In addition,  this estimate  includes  capital  expenditures  for  transmission,
distribution and other generation related activities,  as well as for compliance
with new NOx control regulations,  as discussed later in this Note.  Commitments
have been made with regard to certain of these capital expenditures.

The Company has committed to purchase  combustion  turbine generator  equipment,
which  will add nearly  1,400  megawatts  to its net  peaking  capacity  and are
expected  to cost  approximately  $630  million.  The  Company  plans to add 710
megawatts (approximately 470 megawatts at Resources Company and 240 megawatts at
AmerenUE) of combustion  turbine  generating  capacity during 2002.  Total costs
expected  to  be  incurred  for  these  combustion   turbine   generating  units
approximate  $340 million.  Due to expected  increased  demand,  and the need to

                                       24
<PAGE>

maintain  appropriate  reserve  margins,  the  Company  believes  it  will  need
additional  regulated  generating  capacity  in the  future.  In 2002,  AmerenUE
expects to purchase up to 500  megawatts of capacity for the summer.  Additional
future resource options under  consideration by the Company include the transfer
of  AmerenUE's  Illinois-based  electric and gas business to  AmerenCIPS.  Other
alternatives  include  the  addition  of 650  megawatts  of  combustion  turbine
generating  units.  These units are  estimated to cost $280 million and would be
added subsequent to 2004. As of December 31, 2001, the Company had noncancelable
reservation  commitments  of $22 million  related to the  potential  purchase of
these  units.  The Company  continually  reviews  its  genertion  portfolio  and
expected electrical neeeds, and as result,  could modify its plan for generation
asset  purchases,  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, the type of generation asset technology
that will be employed, or whether capacity may be purchased, among other things.
Changes to the  Company's  plans for future  generating  needs  could  result in
losses being incurred by the Company, which could be material.

The Company has commitments for the purchase of coal under long-term  contracts.
Coal contract commitments, including transportation costs, for 2002 through 2006
are  estimated  to  total  $2.0  billion.   Total  coal   purchases,   including
transportation  costs, for 2001, 2000 and 1999 were $562 million,  $507 million,
and $603 million,  respectively.  The Company also has existing  contracts  with
pipeline and natural gas  suppliers to provide,  transport and store natural gas
for distribution and electric generation.  Gas-related contract cost commitments
for 2002  through  2006 are  estimated to total $253  million.  Total  delivered
natural gas costs were $222 million for 2001,  $209  million for 2000,  and $131
million for 1999. The Company's  nuclear fuel commitments for 2002 through 2006,
including  uranium  concentrates,  conversion,  enrichment and fabrication,  are
expected to total $76  million,  and are expected to be  substantially  financed
under the nuclear  fuel lease.  Nuclear fuel  expenditures  were $24 million for
2001,  and $22  million  in each of the years 2000 and 1999.  Additionally,  the
Company has  long-term  contracts  with other  utilities  to  purchase  electric
capacity.  These  commitments  for 2002 through 2006 are estimated to total $301
million.  During  2001,  2000 and 1999,  electric  capacity  purchases  were $31
million, $40 million, and $44 million, respectively.

In  1999,  AmerenCIPS  and two of its  coal  suppliers  executed  agreements  to
terminate  their existing coal supply  contracts,  effective  December 31, 1999.
Under  these  agreements,  AmerenCIPS  has  made  termination  payments  to  the
suppliers totaling  approximately $52 million.  These termination  payments were
recorded as an unusual charge in the fourth  quarter of 1999,  equivalent to $31
million, after income taxes, or 23 cents per share.

The Company's insurance coverage for Callaway Nuclear Plant at December 31,
2001, was as follows:

Type and Source of Coverage
--------------------------------------------------------------------------------
(In Millions)                                  Maximum              Maximum
                                             Coverages           Assessments
                                                                 For Single
                                                                  Incidents
--------------------------------------------------------------------------------
Public Liability:
     American Nuclear Insurers                   $ 200              $  -
     Pool Participation                          9,338                88  (a)
--------------------------------------------------------------------------------
                                                $9,538  (b)         $ 88
--------------------------------------------------------------------------------
Nuclear Worker Liability:
     American Nuclear Insurers                   $ 200  (c)         $  3
--------------------------------------------------------------------------------
Property Damage:
     Nuclear Electric Insurance Ltd.            $2,750  (d)         $ 23
--------------------------------------------------------------------------------
Replacement Power:
     Nuclear Electric Insurance Ltd.             $ 490  (e)         $  5
--------------------------------------------------------------------------------
(a)  Retrospective premium under the Price-Anderson  liability provisions of the
     Atomic  Energy  Act of 1954,  as  amended  (Price-  Anderson).  Subject  to
     retrospective  assessment with respect to loss from an incident at any U.S.
     reactor, payable at $10 million per year. Price-Anderson expires in 2002.
(b)  Limit of liability for each incident under Price-Anderson.
(c)  Industry limit for potential  liability from workers  claiming  exposure to
     the hazard of nuclear radiation.
(d)  Includes premature decommissioning costs.
(e)  Weekly  indemnity of $3.5 million,  for 52 weeks which  commences after the
     first 12 weeks of an  outage,  plus  $2.8  million  per week for 110  weeks
     thereafter.
--------------------------------------------------------------------------------

                                       25
<PAGE>

Price-Anderson  limits the liability  for claims from an incident  involving any
licensed  U.S.  nuclear  facility.  The limit is based on the number of licensed
reactors and is adjusted at least every five years based on the  Consumer  Price
Index.  Utilities  owning a  nuclear  reactor  cover  this  exposure  through  a
combination  of private  insurance  and mandatory  participation  in a financial
protection pool, as established by Price-Anderson.

If losses from a nuclear  incident at Callaway  exceed the limits of, or are not
subject  to,  insurance,  or if  coverage is not  available,  the  Company  will
self-insure the risk. Although the Company has no reason to anticipate a serious
nuclear   incident,   if  one  did  occur,   it  could  have  a  material,   but
indeterminable,  adverse effect on the Company's financial position,  results of
operations or liquidity.

The State of Illinois has developed a NOx control regulation for utility boilers
in the State  consistent with a United States  Environmental  Protection  Agency
(EPA) program aimed at reducing ozone levels in the Eastern United States.  As a
result  of  these  state  requirements,  Generating  Company  anticipates  a 75%
reduction  from current  levels of NOx emissions from its power plant boilers in
Illinois by the year 2004.  Generating Company estimates spending  approximately
$210  million for capital  expenditures  to comply  with these  rules,  of which
approximately  $50 million  was spent in 2001.  On February  13,  2002,  the EPA
proposed  similar rules for Missouri which require an approximate  64% reduction
from current  levels of NOx emissions.  AmerenUE  estimates  approximately  $140
million  will be required to be spent to comply with these rules for NOx control
on the AmerenUE  generating  system by 2005. The Company is still evaluating the
impact of the EPA's  regulations  as applied to its Missouri  operations and may
challenge  certain  aspects of those rules.  In summary,  the Company  currently
estimates that its capital expenditures to comply with the final NOx regulations
could  range from $300  million to $350  million.  This  estimate  includes  the
assumption  that the  regulations  will  require the  installation  of Selective
Catalytic  Reduction (SCR) technology on some of the Company's units, as well as
additional controls.

Under both Illinois and Missouri  regulatory  programs,  Generating  Company and
AmerenUE  have  applied for Early  Reduction  NOx credits  which would allow the
companies  to manage  compliance  strategies  by either  purchasing  NOx control
equipment or utilizing credits.  Generating Company and AmerenUE may be eligible
for  such  credits  due to the  current  low NOx  emission  rates of some of the
Companies' boilers under current state regulations.

In July 1997,  the EPA issued  regulations  revising  the  National  Ambient Air
Quality  Standards  for  ozone  and  particulate   matter.  The  standards  were
challenged by industry and some states,  and arguments were eventually  heard by
the U. S. Supreme  Court.  On February 27,  2001,  the Supreme  Court upheld the
standards  in large part,  but remanded a number of  significant  implementation
issues back to the EPA for  resolution.  The EPA is  currently  working on a new
rulemaking  to address  the issues  raised by the  Supreme  Court.  New  ambient
standards may require significant additional reductions in SO2 and NOx emissions
from the Company's  power plants by 2008. At this time, the Company is unable to
predict the ultimate impact of these revised air quality standards on its future
financial condition, results of operations or liquidity.

In December 1999, the EPA issued a decision to regulate mercury  emissions from
coal-fired power plants by 2008. The EPA is scheduled to propose  regulations by
2004.  These  regulations  have the potential to add significant  capital and/or
operating costs to the Ameren  generating  systems after 2005. On July 20, 2001,
the EPA issued proposed Best Available Retrofit  Technology (BART) guidelines to
address  visibility  impairment  (so called  "Regional  Haze") across the United
States from sources of air pollution,  including  coal-fired  power plants.  The
guidelines are to be used by States to mandate  pollution  control  measures for
SO2 and NOx emissions.  These rules could also add significant pollution control
costs to the Ameren generating systems between 2008 and 2012.

In addition,  the United  States  Congress has been  working on  legislation  to
consolidate the numerous air pollution  regulations facing the utility industry.
This "multi-pollutant"  legislation is expected to be deliberated in Congress in
2002.  While the cost to comply  with such  legislation,  if  enacted,  could be
significant,  it is  anticipated  that the costs would be less than the combined
impact of the new National Ambient Air Quality  Standards,  mercury and Regional
Haze   regulations,   discussed  above.   Pollution  control  costs  under  such
legislation  are  expected to be incurred in phases from 2007 through  2015.  At
this time,  the  Company is unable to predict the  ultimate  impact of the above
expected  regulations and this  legislation on its future  financial  condition,
results of operations, or liquidity; however, the impact could be material.

                                       26
<PAGE>

The Company is involved in a number of remediation actions to clean up hazardous
waste sites as required by federal and state law.  Such  statutes  require  that
responsible  parties fund remediation  actions regardless of fault,  legality of
original disposal, or ownership of a disposal site. AmerenUE and AmerenCIPS have
been identified by the federal or state governments as a potentially responsible
party (PRP) at several contaminated sites.

The Company  owns or is otherwise  responsible  for 14 former  manufactured  gas
plant (MGP) sites in Illinois.  The ICC permits the recovery of remediation  and
litigation  costs  associated  with certain former MGP sites located in Illinois
from the Company's  Illinois  electric and natural gas utility customers through
environmental adjustment clause rate riders. To be recoverable,  such costs must
be  prudently  and properly  incurred  and are subject to annual  reconciliation
review by the ICC. Through  December 31, 2001, the total costs deferred,  net of
recoveries  from  insurers  and  through  environmental  adjustment  clause rate
riders, was $26 million.

In addition,  the Company owns or is otherwise  responsible  for 10 MGP sites in
Missouri and 1 in Iowa. Unlike Illinois,  the Company does not have in effect in
Missouri a rate rider mechanism which permits  remediation costs associated with
MGP sites to be recovered from utility customers,  and the Company has no retail
utility operations in Iowa.

In June 2000, the EPA notified AmerenUE and numerous other companies that former
landfills  and lagoons in Sauget,  Illinois,  may contain  soil and  groundwater
contamination.  These  sites are known as Sauget  Area 1 and Sauget Area 2. From
approximately  1926 until 1976,  AmerenUE  operated a power generating  facility
adjacent to Sauget Area 2 and currently owns and operates electric  transmission
and distribution facilities in or near Sauget Area 1.

In September 2000, the United States  Department of Justice was granted leave by
the United States District Court - Southern District of Illinois to add numerous
additional  parties,  including  AmerenUE,  to a preexisting lawsuit between the
government and others. The government seeks recovery of response costs under the
Comprehensive   Environmental   Response  Compensation  Liability  Act  of  1980
(commonly  known as  CERCLA  or  Superfund),  incurred  in  connection  with the
remediation of Sauget Area 1. The Company  believes that the final resolution of
this  lawsuit  and the  remediation  of Sauget  Area 1 will not have a  material
adverse effect on its financial position, results of operations or liquidity.

With  respect to Sauget Area 2,  AmerenUE has joined with other PRPs to evaluate
the extent of potential  contamination.  At this time,  the Company is unable to
predict the ultimate impact of the Sauget Area 2 site on its financial position,
results of operations or liquidity.

On September 13, 2001, the EPA proposed in the Federal Register that Sauget Area
1 and  Sauget  Area 2 be listed  on the  National  Priorities  List  (NPL).  The
inclusion of a site on the NPL allows the EPA to access  Superfund  trust monies
to fund site remediations.

In addition,  the Company's  operations,  or that of its predecessor  companies,
involve the use,  disposal  and, in  appropriate  circumstances,  the cleanup of
substances regulated under environmental  protection laws. The Company is unable
to  determine  the impact  these  actions  may have on the  Company's  financial
position, results of operations or liquidity.

Certain   employees  of  the  Company  are  represented  by  the   International
Brotherhood  of  Electrical  Workers and the  International  Union of  Operating
Engineers.   These  employees  comprise   approximately  66%  of  the  Company's
workforce. Contracts with collective bargaining units representing approximately
30% of  these  employees  will  expire  in 2002.  In  addition,  contracts  with
collective  bargaining units  representing  approximately 70% of these employees
will expire in 2003.

Regulatory  changes enacted and being considered at the federal and state levels
continue to change the structure of the utility industry and utility regulation,
as well as encourage increased competition.  At this time, the Company is unable
to  predict  the  impact of these  changes  on the  Company's  future  financial
condition,  results of operations or liquidity.  See Note 2 - Regulatory Matters
for further information.

The Company is involved in other  legal and  administrative  proceedings  before
various  courts and  agencies  with  respect to matters  arising in the ordinary
course of  business,  some of which  involve  substantial  amounts.  The Company
believes  that  the  final  disposition  of  these  proceedings  will not have a
material  adverse  effect on its  financial  position,  results of operations or
liquidity.

                                       27
<PAGE>

NOTE 12 - Callaway Nuclear Plant

Under the Nuclear  Waste Policy Act of 1982,  the  Department of Energy (DOE) is
responsible  for the permanent  storage and disposal of spent nuclear fuel.  The
DOE  currently  charges  one mill per  nuclear-generated  kilowatthour  sold for
future  disposal of spent fuel.  Electric  utility  rates  charged to  customers
provide  for  recovery  of such  costs.  The  DOE is not  expected  to have  its
permanent  storage  facility for spent fuel  available  until at least 2015. The
Company has sufficient storage capacity at the Callaway Nuclear Plant site until
2020 and has the capability for additional storage capacity through the licensed
life of the plant.  The delayed  availability of the DOE's disposal  facility is
not expected to adversely affect the continued operation of the Callaway Nuclear
Plant.

Electric  utility  rates  charged to customers  provide for recovery of Callaway
Nuclear  Plant  decommissioning  costs over the life of the  plant,  based on an
assumed 40-year life, ending with expiration of the plant's operating license in
2024.  The  Callaway  site is  assumed  to be  decommissioned  using  the  DECON
(immediate    dismantlement)    method.    Decommissioning    costs,   including
decontamination,  dismantling  and site  restoration,  are  estimated to be $585
million in current year dollars and are  expected to escalate  approximately  4%
per year through the end of  decommissioning  activity in 2033.  Decommissioning
costs are charged to  depreciation  expense  over  Callaway's  service  life and
amounted to  approximately  $7 million in each of the years 2001, 2000 and 1999.
Every three  years,  the MoPSC and ICC require the Company to file  updated cost
studies for decommissioning Callaway, and electric rates may be adjusted at such
times to reflect changed estimates. The latest studies were filed in 1999. Costs
collected  from customers are deposited in an external trust fund to provide for
Callaway's decommissioning.  Fund earnings are expected to average approximately
9% annually through the date of decommissioning.  If the assumed return on trust
assets is not earned, the Company believes it is probable that any such earnings
deficiency  will be recovered in rates.  Trust fund  earnings,  net of expenses,
appear  on  the   consolidated   balance  sheet  as  increases  in  the  nuclear
decommissioning  trust  fund  and  in  the  accumulated  provision  for  nuclear
decommissioning.

The staff of the SEC has questioned certain accounting practices of the electric
utility industry, regarding the recognition,  measurement, and classification of
decommissioning   costs  for  nuclear  generating   stations  in  the  financial
statements  of electric  utilities.  In response  to these  questions,  the FASB
issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (see Note 1 -
Summary of Significant Accounting Policies).

NOTE 13 - Fair Value of Financial Instruments

The following  methods and  assumptions  were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate that
value:

Cash and Temporary Investments/Short-Term Borrowings
The carrying amounts  approximate fair value because of the short-term  maturity
of these instruments.

Marketable Securities
The fair  value is based on  quoted  market  prices  obtained  from  dealers  or
investment managers.

Nuclear Decommissioning Trust Fund
The fair value is estimated based on quoted market prices for securities.

Preferred Stock of Subsidiaries
The fair value is estimated  based on the quoted  market  prices for the same or
similar issues.

Long-Term Debt
The fair  value is  estimated  based on the  quoted  market  prices  for same or
similar  issues or on the  current  rates  offered  to the  Company  for debt of
comparable maturities.

Derivative Financial Instruments
Market prices used to determine fair value are based on management's  estimates,
which  take  into   consideration   factors   like  closing   exchange   prices,
over-the-counter prices, and time value of money and volatility factors.

                                       28
<PAGE>

Carrying amounts and estimated fair values of the Company's financial
instruments at December 31:
<TABLE>
<CAPTION>
                                                  2001              2000
--------------------------------------------------------------------------------
In Millions                                 Carrying    Fair   Carrying   Fair
                                             Amount    Value    Amount    Value
--------------------------------------------------------------------------------
<S>                                       <C>       <C>      <C>      <C>
Long-term debt (including current portion)   $2,974   $3,052   $2,789   $2,841
Preferred stock                                 235      207      235      186
--------------------------------------------------------------------------------
</TABLE>

The Company has investments in debt and equity securities that are held in trust
funds for the  purpose of funding the nuclear  decommissioning  of its  Callaway
Nuclear Plant (see Note 12 - Callaway Nuclear Plant). The Company has classified
these  investments  in debt and equity  securities as available for sale and has
recorded  all such  investments  at their fair market value at December 31, 2001
and 2000. In 2001, 2000 and 1999, the proceeds from the sale of investments were
$230 million,  $61 million,  and $83 million,  respectively.  Using the specific
identification method to determine cost, the gross realized gains on those sales
were approximately $4 million for 2001, $1 million for 2000, and $11 million for
1999.  Net  realized  and  unrealized  gains and  losses  are  reflected  in the
accumulated  provision for nuclear  decommissioning on the consolidated  balance
sheet,  which is  consistent  with the method used by the Company to account for
the decommissioning costs recovered in rates.

Costs and fair values of investments in debt and equity securities in the
nuclear decommissioning trust fund at December 31 were as follows:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
2001 (In Millions)                       Gross Unrealized
Security Type              Cost         Gain         (Loss)    Fair Value
--------------------------------------------------------------------------------
<S>                      <C>          <C>        <C>         <C>
Debt Securities            $57           $2          $ -        $59
Equity Securities           78           44            -        122
Cash Equivalents             6            -            -          6
--------------------------------------------------------------------------------
                          $141          $46          $ -       $187
--------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>

--------------------------------------------------------------------------------
2000 (In Millions)                       Gross Unrealized
Security Type               Cost        Gain         (Loss)    Fair Value
--------------------------------------------------------------------------------
<S>                      <C>          <C>        <C>         <C>
Debt Securities           $71            $3          $ -        $74
Equity Securities          52            61            -        113
Cash Equivalents            4             -            -          4
--------------------------------------------------------------------------------
                         $127           $64          $ -       $191
--------------------------------------------------------------------------------
</TABLE>
The contractual maturities of investments in debt securities at December 31,
2001 were as follows:
--------------------------------------------------------------------------------
(In Millions)                           Cost       Fair Value
--------------------------------------------------------------------------------
Less than 5 years                       $20          $21
5 years to 10 years                      22           23
Due after 10 years                       15           15
--------------------------------------------------------------------------------
                                        $57          $59
--------------------------------------------------------------------------------

                                       29
<PAGE>

NOTE 14 - Segment Information

Ameren's  principal  business  segment is  comprised  of the  utility  operating
companies  that  provide  electric  and gas service in portions of Missouri  and
Illinois. The other reportable segment includes the nonutility subsidiaries,  as
well as the Company's 60% interest in Electric Energy, Inc.

The accounting  policies of the segments are the same as those described in Note
1  -  Summary  of  Significant   Accounting  Policies.   Segment  data  includes
intersegment  revenues,  as well as a charge  allocating costs of administrative
support services to each of the operating companies. These costs are accumulated
in a separate subsidiary,  Ameren Services Company,  which provides a variety of
support  services  to Ameren and its  subsidiaries.  The Company  evaluates  the
performance of its segments and allocates  resources to them, based on revenues,
operating income and net income.

The table below presents information about the reported revenues, net income,
and total assets of Ameren for the years ended December 31:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
                           Utility                      Reconciling
(In Millions)             Operations       Other          Items         Total
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
2001
--------------------------------------------------------------------------------
<S>                        <C>            <C>          <C>            <C>
Revenues                     $5,063         $248         $(805)*        $4,506
Net income                      467            2            -              469
Total assets                 11,171          240        (1,010)         10,401
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
2000
--------------------------------------------------------------------------------
Revenues                     $4,120         $294         $(557)*        $3,857
Net income                      457           -             -              457
Total assets                 10,777          287        (1,350)          9,714
--------------------------------------------------------------------------------

-----------------------------------------------------------------------------
1999
--------------------------------------------------------------------------------
Revenues                     $3,467         $243         $(174)*        $3,536
Net income                      384            1            -              385
Total assets                  8,825          435           (82)          9,178
--------------------------------------------------------------------------------
* Elimination of intercompany revenues.

Specified items included in segment profit/loss for the years ended December 31:
--------------------------------------------------------------------------------
                                   Utility               Reconciling
(In Millions)                     Operations    Other       Items       Total
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
2001
--------------------------------------------------------------------------------
Interest expense                     $231       $11       $(43)*        $199
Depreciation and amortization
    expense                           382        12         12           406
Income tax expense                    289         7          4           300
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
2000
--------------------------------------------------------------------------------
Interest expense                     $205       $12       $(37)*        $180
Depreciation and amortization
    expense                           360        13         10           383
Income tax expense                    297         4         -            301
-------------------------------------------------------------------------------

--------------------------------------------------------------------------------
1999
--------------------------------------------------------------------------------
Interest expense                     $163        $9       $(4)*        $168
Depreciation and amortization
    expense                           349        12         2           363
Income tax expense                    261        (2)        -           259
--------------------------------------------------------------------------------
*Elimination of intercompany interest charges

                                       30
<PAGE>

Specified item related to segment assets as of December 31:
--------------------------------------------------------------------------------
                                   Utility               Reconciling
(In Millions)                     Operations    Other       Items       Total
--------------------------------------------------------------------------------
2001
--------------------------------------------------------------------------------
 Expenditures for additions
   to long-lived assets            $1,059       $10       $34         $1,103
--------------------------------------------------------------------------------
2000
--------------------------------------------------------------------------------
  Expenditures for additions
   to long-lived assets              $872       $45       $12           $929
--------------------------------------------------------------------------------
1999
--------------------------------------------------------------------------------
  Expenditures for addition
   to long-lived asset               $342      $179       $50           $571
---------------------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>

SELECTED QUARTERLY INFORMATION  (Unaudited)
--------------------------------------------------------------------------------
(Thousands of Dollars, Except Per Share Amounts)
--------------------------------------------------------------------------------
                           Operating     Operating     Net       Earnings Per
                            Revenues        Income    Income     Common Share
Quarter Ended:                                        (Loss)
-------------------------------------------------------------------------------
<S>                      <C>          <C>          <C>          <C>
March 31, 2001       (a)   $1,024,528   $  116,086   $   58,492   $    .43
March 31, 2000       (a)      825,376      108,578       61,393        .45

June 30, 2001        (b)    1,057,016      145,203       94,630        .69
June 30, 2000        (b)      940,708      159,206      113,585        .83

September 30, 2001          1,431,613      310,422      266,576       1.94
September 30, 2000   (c)    1,195,723      305,685      256,137       1.87

December 31, 2001             992,710       93,276       48,847        .35
December 31, 2000    (d)      895,023       66,841       25,979        .19
</TABLE>

(a)  The first  quarter of 2001 and 2000 included  credits to Missouri  electric
     customers that reduced net income  approximately $9 million, or 6 cents per
     share and $6 million, or 4 cents per share, respectively. The first quarter
     of  2001  also  included  an  unusual  charge  for  the  adoption  of a new
     accounting  standard  related to  derivatives  that  reduced  net income $7
     million, or 5 cents per share.
(b)  The second  quarter of 2001  included a reduction  to  previously  recorded
     credits  to  Missouri   electric   customers   that  increased  net  income
     approximately  $15 million,  or 10 cents per share.  The second  quarter of
     2000  included  credits to Missouri  electric  customers  that  reduced net
     income approximately $3 million, or 2 cents per share.
(c)  The third quarter of 2000 included credits to Missouri  electric  customers
     that reduced net income  approximately  $11 million,  or 8 cents per share.
(d)  The fourth quarter of 2000 included credits to Missouri electric  customers
     that reduced net income  approximately $17 million,  or 12 cents per share.
     The fourth  quarter of 2000 also included an unusual  charge related to the
     withdrawal from the Midwest ISO that reduced net income $15 million,  or 11
     cents  per  share.  (See  Note  2  -  Regulatory  Matters  under  Notes  to
     Consolidated Financial Statements for further information).

Other  changes on  quarterly  earnings are due to the effect of weather on sales
and other factors that are characteristic of public utility operations.

                                       31

<PAGE>
                                                                    EXHIBIT 99.2

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

OVERVIEW

Ameren Corporation (Ameren or the Company) is a holding company registered under
the Public Utility Holding Company Act of 1935 (PUHCA).  In December 1997, Union
Electric Company  (AmerenUE) and CIPSCO  Incorporated  (CIPSCO) combined to form
Ameren, with AmerenUE and CIPSCO's subsidiaries, Central Illinois Public Service
Company (AmerenCIPS) and CIPSCO Investment Company (CIC),  becoming subsidiaries
of Ameren (the  Merger).  As a result of the Merger,  Ameren has a 60% ownership
interest in Electric  Energy,  Inc. (EEI),  which is consolidated  for financial
reporting   purposes.   Since  the  Merger,   Ameren  has  formed   several  new
subsidiaries,  including AmerenEnergy,  Inc. (AmerenEnergy),  Ameren Development
Company, AmerenEnergy Resources Company (Resources Company), and Ameren Services
Company.  AmerenEnergy,  an energy trading and marketing  subsidiary,  primarily
serves as a power  marketing  agent for  AmerenUE  and  AmerenEnergy  Generating
Company (Generating Company), the nonregulated electric generating subsidiary of
Resources Company,  and provides a range of energy and risk management  services
to targeted customers.  Ameren Development Company is a nonregulated  subsidiary
encompassing  various  nonregulated  energy  products  and  services.  Resources
Company holds  Ameren's  nonregulated  generating  operations.  Ameren  Services
Company provides shared support services to Ameren and all of its  subsidiaries.

References  to the Company  are to Ameren on a  consolidated  basis.  In certain
circumstances,   the  subsidiaries  are  separately  referred  to  in  order  to
distinguish among their different business activities.

RESULTS OF OPERATIONS

Earnings
Earnings  for 2001,  2000 and 1999,  were $469  million  ($3.41 per share before
dilution),  $457 million  ($3.33 per share) and $385 million  ($2.81 per share),
respectively.  Earnings  and earnings per share  increased  over the  three-year
period primarily due to: the rate of 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.

In 2001, the Company recorded an after-tax,  unusual charge of $7 million,  or 5
cents per share,  representing  the  impact of the  required  adoption  of a new
accounting  standard related to derivative  financial  instruments (see Note 3 -
Risk Management and Derivative Financial Instruments under Notes to Consolidated
Financial Statements for further  information).  In 2000, the Company recorded a
$25 million  unusual charge to earnings in connection  with its withdrawal  from
the Midwest ISO. The charge reduced  earnings $15 million,  net of income taxes,
or  11  cents  per  share  (see  discussion   below  under  "Electric   Industry
Restructuring"  and Note 2 -  Regulatory  Matters  under  Notes to  Consolidated
Financial Statements for further  information).  In 1999, the Company recorded a
$52 million  nonrecurring  charge to earnings in  connection  with coal contract
terminations  with two coal suppliers.  The charge reduced earnings $31 million,
net of income taxes, or 23 cents per share (see discussion below under "Electric
Operations"  and  Note  11  -  Commitments  and  Contingencies  under  Notes  to
Consolidated Financial Statements for further information).

The  Company  estimates  that  ongoing  earnings  per share for the year  ending
December 31, 2002,  will range between $3.15 and $3.45 per share.  This estimate
incorporates  significant  assumptions,  including  resolution of the regulatory
issues  associated with the Company's  Missouri retail electric  operations (see
discussion  below under "Rate  Matters"  and Note 2 - Regulatory  Matters  under
Notes to  Consolidated  Financial  Statements  for  further  information).  This
estimate assumes a future form of incentive regulation relative to the Company's
Missouri electric  operations,  which could include electric rate reductions and
additional  customer  credits.  This  estimate is also  subject to,  among other
things,  changing energy markets,  and economic and weather  conditions.  Actual
results could differ  materially from the assumptions used in the Company's 2002
earnings per share estimate.
<PAGE>

<TABLE>
<CAPTION>
Electric Operations
Electric Revenues                         Variations from Prior Year
--------------------------------------------------------------------------------
In Millions                                2001     2000     1999
--------------------------------------------------------------------------------
<S>                                      <C>      <C>      <C>
Rate variations                            $  -      $ -      $(17)
Credit to customers                           75      (27)       5
Effect of abnormal weather                    10       (4)     (53)
Growth and other                             117      136       78
Interchange sales                            480      135      159
EEI sales                                    (53)     (13)      24
--------------------------------------------------------------------------------
                                           $ 629    $ 227    $ 196
--------------------------------------------------------------------------------
</TABLE>

Electric  revenues for 2001 increased  $629 million,  compared to the prior year
period,  primarily  driven  by a  19%  increase  in  total  kilowatthour  sales.
Interchange sales increased 85%;  however,  lower electric margins were realized
on these sales due to lower energy prices in the wholesale markets.  Residential
sales  were  comparable  to the  prior  year  while  commercial  sales  rose 1%.
Industrial  sales rose 11%  primarily due to a new electric  service  industrial
contract  effective  August 2000.  Revenues  were also  favorably  impacted by a
reduction in the estimated credits to Missouri electric  customers (see Note 2 -
Regulatory Matters under Notes to Consolidated  Financial Statements for further
information). These increases were partially offset by reduced EEI sales.

Electric  revenues for 2000 increased  $227 million,  compared to the prior year
period,  primarily  due to an 8%  increase  in total  kilowatthour  sales.  This
increase was primarily driven by a 35% increase in interchange  sales reflecting
the marketing efforts of AmerenEnergy.  In addition,  residential and commercial
sales rose 6% and 8%, respectively, while industrial and wholesale sales rose 3%
and 41%, respectively. These increases were offset in part by an increase in the
credits to Missouri  electric  customers (see Note 2 - Regulatory  Matters under
Notes to Consolidated Financial Statements for further information).

Electric revenues for 1999 increased $196 million,  compared to 1998,  primarily
due to a 9% increase in total  kilowatthour  sales.  This increase was primarily
driven by a 53% increase in interchange  sales, due to strong marketing  efforts
at  AmerenEnergy  and a 12%  increase  in EEI sales.  Also  contributing  to the
revenue  increase was a decrease in the credit to Missouri  electric  customers,
partially  offset by the credit to  Illinois  electric  customers  (see Note 2 -
Regulatory Matters under Notes to Consolidated  Financial Statements for further
information).   Partially   offsetting   these   increases,    weather-sensitive
residential  and  commercial  sales  decreased  2% and 1%,  respectively,  while
industrial  sales  remained  flat. In addition,  revenues were lower due to rate
decreases in both Missouri and Illinois  (see Note 2 - Regulatory  Matters under
Notes to Consolidated Financial Statements for further information).
<TABLE>
<CAPTION>
Fuel and Purchased Power                          Variations from Prior Year
--------------------------------------------------------------------------------
In Millions                                           2001     2000     1999
--------------------------------------------------------------------------------
<S>                                                <C>      <C>      <C>
Fuel:
     Generation                                      $ (19)   $  49    $  10
     Price                                              28      (33)     (15)
     Generation efficiencies and other                  (6)     (13)      (8)
     Coal contract termination payments                  -      (52)      52
Purchased power                                        579       92      117
EEI                                                    (45)       9       37
--------------------------------------------------------------------------------
                                                     $ 537    $  52    $ 193
--------------------------------------------------------------------------------
</TABLE>
The $537 million  increase in fuel and purchased power costs for 2001,  compared
to 2000, was primarily due to increased  purchased power,  resulting from higher
interchange sales and the spring 2001 refueling outage at the Company's Callaway
Nuclear Plant, in addition to higher blended fuel costs.

The $52 million increase in fuel and purchased power costs for 2000, compared to
1999, was primarily due to increased  generation and purchased power,  resulting
from higher  sales  volume,  partially  offset by lower fuel  costs,  due to the
termination of certain coal contracts in the fourth quarter of 1999.

                                       2
<PAGE>

The $193 million  increase in fuel and purchased power costs for 1999,  compared
to  1998,  was  primarily  due to  increased  generation  and  purchased  power,
resulting from higher sales volume,  increased fuel and purchased power costs at
EEI and coal contract termination payments discussed below,  partially offset by
lower fuel costs.

In the fourth quarter of 1999, AmerenCIPS and two of its coal suppliers executed
agreements to terminate their existing coal supply contracts  effective December
31, 1999. Under these  agreements,  AmerenCIPS made termination  payments to the
suppliers totaling  approximately $52 million.  These termination  payments were
recorded  as an  unusual  charge in the fourth  quarter  of 1999.  See Note 11 -
Commitments and Contingencies under Notes to Consolidated  Financial  Statements
for further information.

Gas Operations

Gas revenues in 2001 increased $18 million,  compared to 2000,  primarily due to
higher gas costs  recovered  through  the  Company's  purchased  gas  adjustment
clauses,  partially  offset by lower total sales of 9% resulting  from unusually
warm winter  weather.  Gas revenues in 2000  increased $96 million,  compared to
1999, primarily due to increases in retail sales, due to unusually cold weather,
and an annualized $4 million Missouri gas rate increase,  which became effective
in November 2000. Gas revenues in 1999 increased $12 million,  compared to 1998,
primarily  due to an  annualized $9 million  Illinois gas rate  increase,  which
became  effective in February 1999 (see Note 2 - Regulatory  Matters under Notes
to Consolidated  Financial  Statements for further  information)  and higher gas
costs recovered through the Company's purchased gas adjustment clauses.

Gas costs in 2001  increased  $12 million,  compared to 2000,  primarily  due to
higher gas  prices,  partially  offset by lower total  sales.  Gas costs in 2000
increased  $78  million,  compared to 1999,  primarily  due to higher  sales and
higher gas prices.  Gas costs in 1999  increased $13 million,  compared to 1998,
primarily due to higher gas prices, partially offset by lower total sales.

Other Operating Expenses
Other  operating  expense  variations in 1999 through 2001  reflected  recurring
factors,  such  as  growth,  inflation,   labor  and  benefit  variations,   the
capitalization  of  certain  costs  as a result  of a  Missouri  Public  Service
Commission  (MoPSC) Order and charges for estimated costs relating to withdrawal
from the Midwest ISO as discussed below.

Other  operating  expenses  increased  $44  million in 2001,  compared  to 2000,
primarily  due  to  higher  employee  benefit  costs  in  2001,  resulting  from
increasing  healthcare  costs,  changes in actuarial  assumptions and investment
performance  of  employee  benefit  plans'  assets  and  increased  professional
services.  Other operating  expenses,  excluding the Midwest ISO-related unusual
charge,  increased  $10 million in 2000,  compared to 1999.  This  increase  was
primarily  due to increases in injuries  and damages  expense,  and higher labor
expenses, offset in part by lower employee benefit costs in 2000, resulting from
changes in actuarial assumptions. Other operating expenses decreased $18 million
in 1999,  compared to 1998.  This  decrease was primarily due to the 1998 charge
for a targeted  employee  separation plan and related reduced  workforce and the
capitalization  of certain costs  (including  computer  software costs) that had
previously been expensed for the Company's  Missouri  electric  operations.  The
capitalization  was a result of the MoPSC Order  received in December  1999 (see
Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for
further  information).  These  decreases were partially  offset by 1999 expenses
associated with electric industry deregulation in Illinois.

In November 2000, the Company announced that it was withdrawing from the Midwest
ISO to  become a  member  of the  Alliance  Regional  Transmission  Organization
(Alliance  RTO). In the fourth  quarter of 2000,  the Company  recorded a pretax
unusual charge to earnings of $25 million ($15 million after income taxes, or 11
cents per share) as a result of the  Company's  decision  to  withdraw  from the
Midwest ISO.  This charge  related to Ameren's  estimated  obligation  under the
Midwest ISO agreement for costs incurred by the Midwest ISO, plus estimated exit
costs. See discussion below under "Electric Industry Restructuring" and Note 2 -
Regulatory Matters under Notes to Consolidated  Financial Statements for further
information.

Maintenance  expenses increased $14 million in 2001, compared to 2000, primarily
due to a refueling outage at the Callaway Nuclear Plant in 2001. The spring 2001
refueling was completed in 45 days.  There was not a refueling in 2000. The next
refueling is scheduled for the fall of 2002.  Maintenance  expenses decreased $3

                                       3
<PAGE>

million in 2000,  compared to 1999. This decrease was primarily the result of no
Callaway Nuclear Plant refueling  outage in 2000,  partially offset by increased
scheduled fossil power plant maintenance and tree-trimming activity. Maintenance
expenses  increased  $59 million in 1999,  compared to 1998.  This  increase was
primarily  due to increased  fossil power plant  maintenance  and  tree-trimming
activity.

Depreciation and amortization  expense  increased $23 million and $20 million in
2001 and 2000,  respectively,  compared to prior year periods,  due to increased
depreciable  property,  primarily  resulting  from the  addition  of  combustion
turbine generating facilities (see discussion below under "Liquidity and Capital
Resources"  and  "Electric  Industry  Restructuring"  for further  information).
Depreciation and amortization expense in 1999 was comparable to 1998.

Taxes
Income tax expense for 2001 was comparable to 2000. Income tax expense increased
$42 million in 2000,  compared to 1999, due to higher pretax income.  Income tax
expense  decreased  $9 million in 1999,  compared to 1998,  due to lower  pretax
income.

Other tax expense decreased $4 million in 2001, compared to 2000,  primarily due
to a  decrease  in  gross  receipts  taxes  related  to the  Company's  Illinois
jurisdiction. Other tax expense increased $18 million in 2000, compared to 1999,
primarily  due to a  change  in the  property  tax  assessment  in the  state of
Illinois.  Other tax expense  decreased  $26 million in 1999,  compared to 1998,
primarily  due to a decrease in gross  receipts  taxes  related to the Company's
Illinois jurisdiction.

Other Income and Deductions
Miscellaneous, net decreased $5 million in 2001, compared to 2000, primarily due
to decreased charitable contributions.  Miscellaneous,  net decreased $6 million
in  2000,  compared  to 1999,  due to the  prior  period  write-off  of  certain
nonregulated investments, partially offset by increased charitable contributions
in 2000. Miscellaneous,  net increased $8 million in 1999, compared to 1998, due
to the write-off of certain  nonregulated  investments  in 1999 and gains on the
sale of property realized in 1998 but not in 1999.

Interest
Interest  expense  increased  $19  million  and $11  million  in 2001 and  2000,
respectively,  compared to prior year periods,  primarily due to increased  debt
levels related to the construction and purchase of combustion turbine generating
facilities  (see  discussion  below under  "Liquidity  and Capital  Resources"),
partially offset by lower interest rates. Interest expense decreased $13 million
in 1999,  compared to 1998,  primarily due to a lower amount of debt outstanding
throughout the year.

LIQUIDITY AND CAPITAL RESOURCES

Cash provided by operating activities totaled $738 million for 2001, compared to
$856  million for 2000,  and $918  million for 1999.  Cash flow from  operations
decreased over the three-year  period  principally  due to the timing of credits
provided to the  Company's  Missouri  electric  customers and changes in working
capital requirements, partially offset by increased earnings.

Cash flows used in investing  activities totaled $1.1 billion,  $910 million and
$558  million,   for  the  years  ended  December  31,  2001,   2000  and  1999,
respectively.  Expenditures in 2001 for constructing  new or improving  existing
facilities,  net of  allowance  for funds used  during  construction,  were $1.1
billion,  $915 million for 2000,  and $557  million for 1999.  Included in these
amounts  were  approximately  $424  million for the  purchase of new  combustion
turbine  generating  facilities  in 2001 and $350  million in 2000.  The Company
added 820 megawatts and 692 megawatts of combustion turbine generating  capacity
during 2001 and 2000,  respectively.  In addition, the Company spent $24 million
in 2001 and $22 million in both 2000 and 1999, to acquire nuclear fuel.

Capital  expenditures  are expected to approximate $800 million in 2002. For the
five-year period 2002 through 2006,  construction  expenditures are estimated to
approximate $3.5 billion. This estimate includes capital expenditures related to
the purchase of new  combustion  turbine  generating  facilities  (see Note 11 -
Commitments and Contingencies under Notes to Consolidated  Financial  Statements
for further  information),  and the replacement of four steam  generators at
its  Callaway  Nuclear  Plant.  In  addition,  this  estimate  includes  capital
expenditures  for  transmission,   distribution  and  other   generation-related
activities,  as well as for  compliance  with new NOx  control  regulations,  as

                                       4
<PAGE>

discussed  below.  The Company  plans to add 710  megawatts  (approximately  470
megawatts at  Resources  Company and 240  megawatts  at AmerenUE) of  combustion
turbine generating capacity during 2002. Total costs expected to be incurred for
these  combustion  turbine  generating units  approximate  $340 million.  Due to
expected increased demand, and the need to maintain appropriate reserve margins,
the Company believes it will need additional  regulated  generating  capacity in
the  future.  In 2002,  AmerenUE  expects to  purchase  up to 500  megawatts  of
capacity for the summer.  Additional future resource options under consideration
by the Company  include the transfer of AmerenUE's  Illinois-based  electric and
gas  business to  AmerenCIPS.  Other  alternatives  include the  addition of 650
megawatts of combustion  turbine  generating units. These units are estimated to
cost $280  million and would be added  subsequent  to 2004.  As of December  31,
2001,  the  Company had  noncancelable  reservation  commitments  of $22 million
related to the  potential  purchase  of these  units.  The  Company  continually
reviews its generation portfolio and expected electrical needs, and as a result,
could modify its plan for generation  asset  purchases,  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,
the type of  generation  asset  technology  that will be  employed,  or  whether
capacity may be purchased,  among other things.  Changes to the Company's  plans
for  future  generating  needs  could  result in losses  being  incurred  by the
Company, which could be material.

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

Environmental

The State of Illinois has developed a NOx control regulation for utility boilers
in the State  consistent with a United States  Environmental  Protection  Agency
(EPA) program aimed at reducing ozone levels in the Eastern United States.  As a
result  of  these  state  requirements,  Generating  Company  anticipates  a 75%
reduction  from current  levels of NOx emissions from its power plant boilers in
Illinois by the year 2004.  Generating Company estimates spending  approximately
$210  million for capital  expenditures  to comply  with these  rules,  of which
approximately  $50 million  was spent in 2001.  On February  13,  2002,  the EPA
proposed  similar rules for Missouri which require an approximate  64% reduction
from current  levels of NOx emissions.  AmerenUE  estimates  approximately  $140
million  will be required to be spent to comply with these rules for NOx control
on the AmerenUE  generating  system by 2005. The Company is still evaluating the
impact of the EPA's  regulations  as applied to its Missouri  operations and may
challenge  certain  aspects of those rules.  In summary,  the Company  currently
estimates that its capital expenditures to comply with the final NOx regulations
could  range from $300  million to $350  million.  This  estimate  includes  the
assumption  that the  regulations  will  require the  installation  of Selective
Catalytic  Reduction (SCR) technology on some of the Company's units, as well as
additional controls.

Under both Illinois and Missouri  regulatory  programs,  Generating  Company and
AmerenUE  have  applied for Early  Reduction  NOx credits  which would allow the
companies  to manage  compliance  strategies  by either  purchasing  NOx control
equipment or utilizing credits.  Generating Company and AmerenUE may be eligible
for  such  credits  due to the  current  low NOx  emission  rates of some of the
Companies' boilers under current regulations.

In July 1997,  the EPA issued  regulations  revising  the  National  Ambient Air
Quality  Standards  for  ozone  and  particulate   matter.  The  standards  were
challenged by industry and some states,  and arguments were eventually  heard by
the U. S. Supreme  Court.  On February 27,  2001,  the Supreme  Court upheld the
standards  in large part,  but remanded a number of  significant  implementation
issues back to the EPA for  resolution.  The EPA is  currently  working on a new
rulemaking  to address  the issues  raised by the  Supreme  Court.  New  ambient
standards may require significant  additional reductions in sulfur dioxide (SO2)
and NOx  emissions  from the Company's  power plants by 2008. At this time,  the
Company is unable to predict the  ultimate  impact of these  revised air quality
standards on its future financial condition, results of operations or liquidity.

                                       5
<PAGE>

In December 1999, the EPA issued a decision to regulate  mercury  emissions from
coal-fired power plants by 2008. The EPA is scheduled to propose  regulations by
2004.  These  regulations  have the potential to add significant  capital and/or
operating  costs to the Ameren  generating  system after 2005. On July 20, 2001,
the EPA issued proposed Best Available Retrofit  Technology (BART) guidelines to
address  visibility  impairment  (so called  "Regional  Haze") across the United
States from sources of air pollution,  including  coal-fired  power plants.  The
guidelines are to be used by States to mandate  pollution  control  measures for
SO2 and NOx emissions.  These rules could also add significant pollution control
costs to the Ameren generating systems between 2008 and 2012.

In addition,  the United  States  Congress has been  working on  legislation  to
consolidate the numerous air pollution  regulations facing the utility industry.
This "multi-pollutant"  legislation is expected to be deliberated in Congress in
2002.  While the cost to comply  with such  legislation,  if  enacted,  could be
significant,  it is  anticipated  that the costs would be less than the combined
impact of the new National Ambient Air Quality  Standards,  mercury and Regional
Haze   regulations,   discussed  above.   Pollution  control  costs  under  such
legislation  are  expected to be incurred in phases from 2007 through  2015.  At
this time,  the  Company is unable to predict the  ultimate  impact of the above
expected  regulations and this  legislation on its future  financial  condition,
results of operations, or liquidity; however, the impact could be material.

See  Note  11 -  Commitments  and  Contingencies  under  Notes  to  Consolidated
Financial Statements for further discussion of environmental matters and Note 12
- Callaway Nuclear Plant under Notes to Consolidated  Financial Statements for a
discussion of Callaway Nuclear Plant decommissioning costs.

Financing Activities
Cash flows provided by financing activities were $308 million for 2001, compared
to cash flows used in  financing  activities  of $14  million  for 2000 and $241
million for 1999.  The  Company's  principal  financing  activities  during 2001
included  the  issuance of $300  million of  long-term  debt and $438 million of
short-term  debt,  offset by the redemption of $64 million of long-term debt and
the payment of dividends on common  stock.  The  Company's  principal  financing
activities  during 2000 and 1999 included the issuances of $703 million and $152
million of long-term  debt, the  redemptions of $421 million and $174 million of
long-term debt and the payment of dividends on common stock, respectively.

In December 2001, Ameren  Corporation issued Floating Rate Notes (FRNs) totaling
$150  million.  Interest  accrues  on the  FRNs  at  three  month  LIBOR  (reset
quarterly)  plus  0.95%  and is  payable  quarterly  commencing  in March  2002.
Principal  of the FRNs is payable in  December  2003.  With the  proceeds of the
FRNs,  Ameren  Corporation  reduced  its  short-term  borrowings.  See  Note 7 -
Long-Term  Debt under Notes to  Consolidated  Financial  Statements  for further
discussion.

In  September  2001,  the Company  began  issuing new shares of common  stock to
satisfy  requirements under the Ameren dividend  reinvestment and stock purchase
plan (DRPlus) and in December  2001, it began issuing new shares of common stock
in connection with its 401(k) plans. Previously,  these requirements were met by
purchasing outstanding shares. Under these plans, the Company issued 830,177 new
shares of common stock in 2001.

In January 2002,  Ameren  Corporation  issued 5.70% Notes totaling $100 million.
Interest  is  payable  semi-annually  on  February  1 and August 1 of each year,
beginning August 1, 2002, and on the date of maturity, February 1, 2007. The net
proceeds were used to reduce short-term borrowings.

In December 2001, the interest rate mode on AmerenCIPS' three series of variable
rate  tax-exempt  pollution  control  indebtedness  totaling  $104  million  was
converted to long-term fixed rates. Terms of the indebtedness  ranged from 5% to
5.95% with maturities through 2026.

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% due June 2011. Until the release date as described in
the registration statement, the senior notes will be secured by a related series
of  AmerenCIPS'  first mortgage  bonds.  The proceeds of these senior notes were
used to repay short-term debt and first mortgage bonds maturing in June 2001.

                                       6
<PAGE>

In November 2000,  Generating Company issued $225 million principal amount 7.75%
Senior  Notes,  Series A due 2005  (Series A Notes) and $200  million  principal
amount 8.35% Senior Notes, Series B due 2010 (Series B Notes) (collectively, the
Senior Notes).  Generating Company filed an S-4 registration  statement with the
SEC in 2001 to register the Senior Notes under the  Securities  Act of 1933,  as
amended,  to permit an exchange offer of the Senior Notes.  In 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.  With  the  proceeds  of the  Senior  Notes,
Generating  Company  reduced its short-term  borrowings  incurred in conjunction
with the construction of completed  combustion  turbine  generating  facilities,
paid for the construction of certain combustion turbine  facilities,  and funded
working capital and other capital expenditure needs. See Note 7 - Long-Term Debt
under Notes to Consolidated Financial Statements for further discussion.

In 2002,  Generating  Company  expects to issue  additional  debt to permanently
finance generating capacity additions. This additional debt issuance could be up
to $250 million and is expected to be issued in early 2002.

The Company anticipates  securing additional financing in 2002. In January 2002,
Ameren Corporation filed a shelf registration statement with the SEC on Form S-3
which,  upon its  effectiveness,  will allow the  offering  from time to time of
various forms of debt and equity  securities,  up to an aggregate offering price
of $1 billion.  The  proceeds  from any sale of such  securities  may be used to
finance  the  Company's   subsidiaries'  ongoing  construction  and  maintenance
programs,  to  redeem,  repurchase,  repay or retire  outstanding  indebtedness,
including  indebtedness  of the  Company's  subsidiaries,  to finance  strategic
investments in or future  acquisitions of other entities or other assets and for
other  general  corporate  purposes.  At this  time,  the  Company  is unable to
determine  the amount of the  additional  financing,  as well as the  additional
financing's impact on the Company's financial position, results of operations or
liquidity.

The  Company  plans to  continue  utilizing  short-term  debt to support  normal
operations and other temporary  requirements.  The Company 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 commercial  paper  (maturities  generally  within 1 to 45
days) and bank loans. At December 31, 2001, the Company had committed bank lines
of credit  aggregating  $156 million,  all of which were unused and available at
such date.  These lines 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 Company has bank credit  agreements,  expiring at various dates between 2002
and 2003, that support  commercial paper programs totaling $700 million of which
$400 million is for the Company's  own use and for the use of its  subsidiaries.
The  remaining  $300  million  is  for  the  use  of  the  Company's   regulated
subsidiaries.  At December  31,  2001,  all of the bank credit  agreements  were
unused; however, due to commercial paper borrowings and other commitments,  $126
million of such borrowing  capacity was available.  The Company had $641 million
of  short-term  borrowings  outstanding  at  December  31,  2001.  See  Note 6 -
Short-Term  Borrowings  under Notes to  Consolidated  Financial  Statements  for
further information.

AmerenUE also has a lease  agreement  that provides for the financing of nuclear
fuel. At December 31, 2001,  the maximum amount that could be financed under the
agreement was $120 million. Cash used in financing for 2001 included $64 million
of  redemptions  under the lease for  nuclear  fuel,  offset by $13  million  of
issuances.  At December 31, 2001, $63 million was financed under the lease.  See
Note 4 - Nuclear Fuel Lease under Notes to Consolidated Financial Statements for
further information.

The following table summarizes the Company's committed credit availability as of
December 31, 2001:
<TABLE>
<CAPTION>
                                    Amount of commitment expiration per period
--------------------------------------------------------------------------------------------
In Millions                                      Total      Less than 1    1 - 3     4 - 5
                                                 amounts       year        years     years
                                                 committed
--------------------------------------------------------------------------------------------
<S>                                            <C>           <C>         <C>      <C>
Lines of credit and credit agreements (a)        $856          $656        $200     $ -
--------------------------------------------------------------------------------------------
(a)  See Note 6 - Short-Term  Borrowings  under Notes to Consolidated  Financial
     Statements for further discussion.
</TABLE>

                                       7
<PAGE>

The following table summarizes the Company's contractual obligations as of
December 31, 2001:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------
In Millions                                       Less than  1 - 3    4 - 5
                                                    1 year   years    years
--------------------------------------------------------------------------------
<S>                                               <C>      <C>      <C>
Long-term debt and capital lease obligations (a)    $  139   $  684   $  279
Operating leases                                        13       27       19
Other long-term obligations (b)                        739    1,339      654
--------------------------------------------------------------------------------
Total cash contractual obligations                  $  891   $2,050   $  952
--------------------------------------------------------------------------------
(a)  See Note 7 - Long-Term  Debt and Note 4 - Nuclear Fuel Lease under Notes to
     Consolidated Financial Statements for further discussion.
(b)  Represents  purchase  contracts for coal,  gas,  nuclear fuel, and electric
     capacity.

During 2001,  as a result of the  uncertainty  created from the excess  earnings
complaint filed against AmerenUE (see discussion below under "Rate Matters"), as
well as other  factors,  Moody's,  Standard & Poor's and Fitch  rating  agencies
changed their outlooks for Ameren Corporation's long-term unsecured debt ratings
from  stable to  negative.  As of  December  31,  2001,  the  ratings  of Ameren
Corporation by these rating agencies were as follows:
</TABLE>
--------------------------------------------------------------------------------
                                     Moody's    Standard & Poor's     Fitch
--------------------------------------------------------------------------------
     Unsecured Debt                   A2               A               A+
     Commercial Paper                 P-1              A-1             F1

If the ratings of AmerenUE's  first mortgage bonds,  currently rated as Aa3, A+,
and AA, for  Moody's,  Standard & Poor's,  and Fitch,  respectively,  fall below
investment  grade,  lenders on AmerenUE's $300 million revolving credit facility
may elect not to make advances  and/or  declare  outstanding  borrowings due and
payable. In addition,  a decrease in the Company's ratings may reduce its access
to capital  and/or  increase  the costs of  borrowings  resulting  in a negative
impact on earnings.

DIVIDENDS

Common stock dividends paid in 2001,  2000, and 1999 resulted in payout rates of
74%, 76%, and 90%, respectively,  of the Company's net income. Dividends paid to
common stockholders in relation to net cash provided by operating activities for
the same periods were 47%, 41% and 38%.

The Board of Directors does not set specific  targets or payout  parameters when
declaring common stock dividends;  however,  the Board considers various issues,
including the Company's  historic  earnings and cash flow;  projected  earnings,
cash flow and potential cash flow  requirements;  dividend payout rates at other
utilities; return on investments with similar risk characteristics;  and overall
business  considerations.  On February 8, 2002,  the Ameren  Board of  Directors
declared a quarterly  common stock dividend of 63.5 cents per share,  to holders
of record on March 11, 2002, payable March 29, 2002.

RATE MATTERS

On June 30, 2001, AmerenUE's experimental alternative regulation plan (the Plan)
for its  Missouri  retail  electric  customers  expired (see Note 2 - Regulatory
Matters under Notes to Consolidated Financial Statements for further information
about the Plan). On July 2, 2001, the MoPSC staff filed with the MoPSC an excess
earnings  complaint against AmerenUE that proposed to reduce its annual electric
revenues ranging from $213 million to $250 million.  Factors contributing to the
MoPSC  staff's  recommendation  included  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 ranged from 9.04% to 10.04%.
The MoPSC is not bound by the MoPSC staff's recommendation. In January 2002, the
MoPSC  issued an order that  established  the test year to be used to  determine
rates as July 1, 2000  through  June 30,  2001,  with  updates to that test year
permitted  through  September 30, 2001. The MoPSC staff had utilized a test year
of July 1, 1999 through June 30, 2000 in its  original  complaint.  In addition,
the MoPSC order stated that AmerenUE  would be permitted to propose an incentive
regulation plan in this proceeding.

                                       8
<PAGE>

The MoPSC order also included a revised procedural schedule to allow all parties
additional time to review data and file  testimony,  due to the utilization of a
more current test year. Under the new schedule, the MoPSC staff will file direct
testimony  on March 1, 2002,  with  AmerenUE  and the  Office of Public  Counsel
filing  rebuttal  testimony on May 10, 2002.  Evidentiary  hearings on the MoPSC
staff's  recommendation are scheduled to be conducted before the MoPSC beginning
in July 2002.  In the event  that the MoPSC  ultimately  determines  that a rate
decrease is warranted in this case,  that rate reduction would be retroactive to
April 1,  2002,  regardless  of when the  MoPSC  issues  its  decision.  A final
decision  on this  matter  may not  occur  until  the  fourth  quarter  of 2002.
Depending on the outcome of the MoPSC's decision, further appeals in the courts
may be warranted.

In the interim, the Company expects to continue  negotiations with all pertinent
parties  with the intent to continue  with an  incentive  regulation  plan.  The
Company cannot predict the outcome of these negotiations and their impact on the
Company's financial position,  results of operations or liquidity;  however, the
impact could be material.

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

ELECTRIC INDUSTRY RESTRUCTURING

Federal
Steps taken and being  considered  at the federal and state  levels  continue to
change the  structure of the electric  industry and utility  regulation.  At the
federal level, the Energy Policy Act of 1992 reduced various restrictions on the
operation  and  ownership of  independent  power  producers and gave the Federal
Energy Regulatory Commission (FERC) the authority to order electric utilities to
provide transmission access to third parties.

Order 888 and Order 889, issued by the FERC, are intended to promote competition
in the wholesale electric market. The FERC requires  transmission-owning  public
utilities,  such as AmerenUE and AmerenCIPS,  to provide transmission access and
service to others in a manner similar and comparable to that which the utilities
have by virtue of ownership.  Order 888 requires that a single tariff be used by
the utility in providing  transmission service.  Order 888 also provides for the
recovery of stranded costs, under certain  conditions,  related to the wholesale
business.

Order 889 established the standards of conduct and information requirements that
transmission owners must adhere to in doing business under the open access rule.
Under Order 889, utilities must obtain transmission service for their own use in
the same manner their  customers will obtain  service,  thus  mitigating  market
power through control of transmission facilities.  In addition, under Order 889,
utilities must separate their merchant  function  (buying and selling  wholesale
power) from their transmission and reliability functions.

In 1998,  AmerenUE and AmerenCIPS  joined a group of companies  that  originally
supported the  formation of the Midwest ISO. An ISO operates,  but does not own,
electric  transmission  systems and maintains  system  reliability and security,
while facilitating  wholesale and retail competition  through the elimination of
"pancaked"  transmission  rates.  The Midwest ISO is regulated by the FERC.  The
FERC conditionally approved the formation of the Midwest ISO in September 1998.

In December 1999,  the FERC issued Order 2000 relating to Regional  Transmission
Organizations  (RTOs) that would meet certain  characteristics  such as size and
independence.  RTOs,  including  ISOs,  are entities that ensure  comparable and
non-discriminatory access to regional electric transmission systems. Order 2000
calls on all transmission owners to join RTOs.

In the fourth quarter of 2000,  the Company  announced its intention to withdraw
from the Midwest ISO and to join the 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  Company's  estimated  obligation  under the  Midwest  ISO
agreement for costs incurred by the Midwest ISO, plus  estimated exit costs.  In
2001, the Company announced that it had signed an agreement to join the Alliance
RTO.  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.  This  settlement  agreement  was approved by the
FERC.  The Company's  withdrawal  from the Midwest ISO remains  subject to MoPSC
approval. In July 2001, the FERC conditionally approved the formation, including
the rate structure, of the Alliance RTO. However, on December 20, 2001, the FERC
issued an order that  reversed its  position  and rejected the  formation of the
Alliance  RTO.  Instead,  the FERC  granted  RTO status to the  Midwest  ISO and
ordered  the  Alliance  RTO  Companies  and the  Midwest  ISO to discuss how the
Alliance RTO business  model could be  accommodated  within the Midwest ISO. The
Alliance  RTO  members  have until  February  19,  2002 to respond to the FERC's
December 2001 order.  At this time, the Company is evaluating its  alternatives,
including the possible appeal of the FERC's  December 2001 order,  and is unable
to determine  the impact that the FERC's  latest  ruling will have on its future
financial condition, results of operations or liquidity.

                                       9
<PAGE>

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

Major  provisions  of the  Illinois Law include 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 represented approximately 16% of the Company's total sales during 2001.
As of December  31, 2001,  the impact of Illinois  retail  direct  access on the
Company's   financial   condition,   results  of  operations  or  liquidity  was
immaterial.  Retail  direct  access  will be  offered  to  Illinois  residential
customers on May 1, 2002.

Under the Illinois  Law, the Company is subject to a  residential  electric rate
decrease of up to 5% in 2002, to the extent its rates exceed the Midwest utility
average at that time. In 2001, the Company's  Illinois electric rates were below
the Midwest utility average.

The Illinois Law also contains a provision  allowing for the potential  recovery
of a  portion  of  stranded  costs,  which  represent  costs  that  would not be
recoverable in a restructured environment, through a transition charge collected
from  customers  who choose an alternate  electric  supplier.  In addition,  the
Illinois  Law  contains a provision  requiring a portion of excess  earnings (as
defined  under the Illinois  Law) for the years 1998 through 2004 to be refunded
to  customers.  See Note 2 -  Regulatory  Matters  under  Notes to  Consolidated
Financial Statements for further information.

In  conjunction  with another  provision  of the  Illinois  Law, on May 1, 2000,
following the receipt of all required  state and federal  regulatory  approvals,
AmerenCIPS  transferred  its  electric  generating  assets and  liabilities,  at
historical net book value, to Generating  Company,  in exchange for a promissory
note from  Generating  Company in the  principal  amount of  approximately  $552
million and Generating Company common stock (the Transfer).  The promissory note
bears  interest  at 7% and has a term of five years  payable  based on a 10-year
amortization.   The  transferred  assets  represent  a  generating  capacity  of
approximately 2,900 megawatts.  Approximately 45% of AmerenCIPS'  employees were
transferred to Generating Company as part of the transaction.

In conjunction with the Transfer, an electric power supply agreement was entered
into between  Generating Company and its newly created  nonregulated  affiliate,
AmerenEnergy   Marketing  Company  (Marketing  Company),   also  a  wholly-owned
subsidiary of Resources  Company.  Under this  agreement,  Marketing  Company is
entitled to purchase  all of  Generating  Company's  energy and  capacity.  This
agreement may not be terminated  until at least  December 31, 2004. In addition,
Marketing   Company  entered  into  an  electric  power  supply  agreement  with
AmerenCIPS to supply it sufficient  energy and capacity to meet its  obligations
as a public  utility.  This  agreement  expires  December 31,  2004.  Power will
continue to be jointly dispatched between AmerenUE and Generating Company.

The creation of the new subsidiaries and the transfer of AmerenCIPS'  generating
assets and liabilities had no effect on the consolidated financial statements of
Ameren as of the date of the Transfer.

The provisions of the Illinois Law could also result in lower revenues,  reduced
profit margins and increased  costs of capital and operations  expense.  At this
time,  the Company is unable to determine  the impact of the Illinois Law on the
Company's future financial condition, results of operations or liquidity.

Missouri
In Missouri, where approximately 70% of the Company's retail electric revenues
are derived,  restructuring  bills have been  introduced but no legislation  has
been passed.  Furthermore, no restructuring legislation is expected to be passed
by the Missouri state legislature in 2002.

                                       10
<PAGE>

Summary
In  summary,  the  potential  negative  consequences  associated  with  electric
industry restructuring could be significant and could include the impairment and
writedown  of  certain  assets,  including   generation-related  plant  and  net
regulatory assets, lower revenues, reduced profit margins and increased costs of
capital and  operations  expenses.  Conversely,  a deregulated  marketplace  can
provide earnings enhancement  opportunities.  The Company will continue to focus
on cost control to ensure that it maintains a competitive cost structure.  Also,
in Illinois,  the Company's actions included the establishment of a nonregulated
generating   subsidiary,   the  expansion  of  its  generation   assets,   which
strengthened its trading and marketing operations in order to retain its current
customers  and obtain new  customers,  and the  enhancement  of its  information
systems. Management believes that these actions position the Company well in the
competitive Illinois marketplace.  In Missouri, the Company is actively involved
in  all  major   deliberations   taking  place  surrounding   electric  industry
restructuring  in an effort to ensure that  restructuring  legislation,  if any,
contains an orderly  transition and is equitable to the Company's  shareholders.
At this time,  the Company is unable to predict the ultimate  impact of electric
industry  restructuring on the Company's future financial condition,  results of
operations or liquidity.

CONTINGENCIES

See Note 2 - Regulatory  Matters,  Note 11 - Commitments and  Contingencies  and
Note  12  -  Callaway  Nuclear  Plant  under  Notes  to  Consolidated  Financial
Statements for material issues existing at December 31, 2001.

ACCOUNTING MATTERS

In January 2001, the Company adopted Statement of Financial Accounting Standards
(SFAS) No. 133, "Accounting for Derivative  Instruments and Hedging Activities."
The impact of that  adoption  resulted  in the Company  recording  a  cumulative
effect  charge  of $7  million  after  taxes  to  the  income  statement,  and a
cumulative  effect  adjustment of $11 million after income taxes to  Accumulated
Other Comprehensive Income (OCI), which reduced  stockholders' equity. (See Note
3 -  Risk  Management  and  Derivative  Financial  Instruments  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  Company's
financial condition,  results of operations or liquidity upon adoption. However,
in October and again in December 2001,  the DIG revised this guidance,  with the
revisions effective April 1, 2002. The Company does not expect the impact of the
DIG's revisions to have a material effect on the Company's financial  condition,
results of operations, or liquidity upon adoption.

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 as of
April 1, 2002. The Company  continues to evaluate the impact of this guidance on
its future financial  condition,  results of operations and liquidity;  however,
the impact is not expected to be material.

In July 2001, the FASB issued SFAS No. 141,  "Business  Combinations,"  and SFAS
No. 142,  "Goodwill and Other  Intangible  Assets."  SFAS 141 requires  business
combinations to be accounted for under the purchase method of accounting,  which
requires  one  party  in the  transaction  to be  identified  as  the  acquiring
enterprise  and for that party to allocate the purchase  price to the assets and
liabilities of the acquired  enterprise based on fair market value. 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 became effective
for the  Company  on  January  1,  2002.  SFAS  141 and  SFAS 142 did not have a
material effect on the Company's  financial  position,  results of operations or
liquidity upon adoption.

                                       11
<PAGE>

In addition,  in July 2001, the FASB issued SFAS No. 143,  "Accounting for Asset
Retirement  Obligations."  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.  At this time,  the
Company is assessing the impact of SFAS 143 on its financial  position,  results
of operations  and liquidity  upon  adoption.  However,  SFAS 143 is expected to
result in significant increases to the Company's reported assets and liabilities
as a  result  of  its  ongoing  collection  through  rates  of  and  obligations
associated with Callaway Nuclear Plant decommissioning costs.

In August 2001, the FASB issued SFAS No. 144,  "Accounting for the Impairment or
Disposal of Long-Lived Assets." SFAS 144 addresses the financial  accounting and
reporting for the  impairment or disposal of  long-lived  assets and  supersedes
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of." SFAS 144 retains the guidance  related to calculating
and  recording  impairment  losses,  but adds  guidance  on the  accounting  for
discontinued  operations,  previously accounted for under Accounting  Principles
Board  Opinion  No. 30.  SFAS 144 was adopted by the Company on January 1, 2002.
SFAS 144 did not have a material  effect on the  Company's  financial  position,
results of operations or liquidity upon adoption.

EFFECTS OF INFLATION AND CHANGING PRICES

The Company's  rates for retail  electric and gas utility  service are generally
regulated by the MoPSC and the Illinois Commerce  Commission  (ICC).  Non-retail
electric rates are regulated by the FERC.

The  current  replacement  cost of the  Company's  utility  plant  substantially
exceeds its recorded historical cost. Under existing regulatory  practice,  only
the historical cost of plant is recoverable  from customers.  As a result,  cash
flows  designed to provide  recovery of historical  costs  through  depreciation
might not be adequate to replace plants in future years. Regulatory practice has
been  modified  for the  Company's  generation  portion of its  business  in its
Illinois  jurisdiction  and may be  modified  in the  future  for the  Company's
Missouri   jurisdiction  (see  Note  2  -  Regulatory  Matters  under  Notes  to
Consolidated  Financial Statements for further  information).  In addition,  the
impact on common stockholders is mitigated to the extent depreciable property is
financed with debt that is repaid with dollars of less purchasing power.

In the Company's  retail electric  utility  jurisdictions,  the cost of fuel for
electric  generation is reflected in base rates with no provision for changes in
such cost to be  reflected  in billings to  customers  through  fuel  adjustment
clauses.  Changes in gas costs  relating  to retail  gas  utility  services  are
generally  reflected in billings to customers  through  purchased gas adjustment
clauses.  The Company is impacted by changes in market prices for natural gas to
the  extent  it  must  purchase  natural  gas  to  run  its  combustion  turbine
generators.  The Company has structured  various  supply  agreements to maintain
access to multiple  gas pools and supply  basins to  minimize  the impact to the
financial  statements (see  discussion  below under  "Commodity  Price Risk" for
further information).

Inflation continues to be a factor affecting operations, earnings, stockholders'
equity and financial performance.

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 Company'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 Company  handles  market risks in accordance  with  established
policies,  which may include entering into various derivative  transactions.  In
the normal  course of  business,  the  Company  also faces risks that are either
non-financial or  non-quantifiable.  Such risks  principally  include  business,
legal, and operational risk and are not represented in the following analysis.

The Company'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.

                                       12
<PAGE>

Interest Rate Risk
The  Company  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,   auction-rate   long-term  debt  and
auction-rate  preferred stock. The Company 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 1% in 2002,  as  compared  to 2001,  the  Company's
interest  expense  would  increase by  approximately  $13 million and net income
would  decrease by  approximately  $8 million.  This amount has been  determined
using  the  assumptions  that  the  Company's  outstanding  variable-rate  debt,
commercial paper, auction-rate long-term debt, and auction-rate preferred stock,
as of December 31, 2001,  continued to be outstanding  throughout 2002, and that
the average  interest  rates for these  instruments  increased 1% over 2001. The
model does not  consider the effects of the reduced  level of potential  overall
economic  activity  that would exist in such an  environment.  In the event of a
significant  change in interest rates,  management  would likely take actions to
further  mitigate  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 Company's financial
structure.

Credit Risk
Credit risk represents the loss that would be recognized if counterparties  fail
to perform as contracted.  New York Mercantile  Exchange  (NYMEX) traded futures
contracts  are  supported by the  financial  and credit  quality of the clearing
members of the NYMEX and have nominal  credit risk.  On all other  transactions,
the  Company  is exposed to credit  risk in the event of  nonperformance  by the
counterparties in the transaction.

The  Company's  physical and  financial  instruments  are subject to credit risk
consisting of trade  accounts  receivables  and executory  contracts with market
risk exposures.  The risk associated with trade  receivables is mitigated by the
large  number of customers in a broad range of industry  groups  comprising  the
Company's  customer  base.  No  customer  represents  greater  than  10%  of the
Company's accounts receivable. The Company's revenues are primarily derived from
sales of electricity and natural gas to customers in Missouri and Illinois.  The
Company analyzes each counterparty's  financial condition prior to entering into
forwards,  swaps,  futures or option  contracts.  The Company  also  establishes
credit limits for these counterparties and monitors the appropriateness of these
limits on an  ongoing  basis  through a credit  risk  management  program  which
involves  daily  exposure  reporting to senior  management,  master  trading and
netting agreements,  and credit support management (e.g.,  letters of credit and
parental guarantees).

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

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

                                       13

<PAGE>

The  Company's   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 Company's  operating
subsidiaries,  and for managing  fuel and natural gas price  risks.  Fixed price
forward contracts,  as well as futures and options,  are all instruments,  which
may be used to manage these risks.  The  majority of the  Company's  fuel supply
contracts  are  physical  forward  contracts.  Since the Company does not have a
provision  similar  to the PGA for its  electric  operations,  the  Company  has
entered into several long-term contracts with various suppliers to purchase coal
and  nuclear  fuel  to  manage  its  exposure  to  fuel  prices  (see  Note 11 -
Commitments and Contingencies under Notes to Consolidated  Financial  Statements
for further  information).  Over 95% of the required 2002 supply of coal for the
Company's  coal plants has been  acquired at fixed prices for 2002. In addition,
approximately  70%  of  the  coal  requirements  through  2006  are  covered  by
contracts.  With  regard  to  the  Company's  nonregulated  electric  generating
operations,  the Company 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 Company'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.

Although  the  Company  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 Company'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 Company's  strategy also utilizes physical assets through storage,
operator and balancing  agreements to minimize price  volatility.  The Company'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 Company's
primary use of derivatives has involved transactions that are expected to reduce
price risk exposure for the Company.

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

Equity Price Risk
The Company  maintains  trust  funds,  as  required  by the  Nuclear  Regulatory
Commission  and  Missouri  and Illinois  state laws,  to fund  certain  costs of
nuclear  decommissioning  (see Note 12 - Callaway  Nuclear  Plant under Notes to
Consolidated  Financial Statements for further information).  As of December 31,
2001,  these  funds were  invested  primarily  in  domestic  equity  securities,
fixed-rate,   fixed-income  securities,  and  cash  and  cash  equivalents.   By
maintaining a portfolio that includes long-term equity investments,  the Company
is  seeking  to  maximize   the   returns  to  be   utilized  to  fund   nuclear
decommissioning  costs. However, the equity securities included in the Company'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 Company  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 Company's  exposure to equity price market
risk is, in large part, mitigated, due to the fact that the Company is currently
allowed to recover its decommissioning costs in its rates.

                                       14
<PAGE>

Fair Value of Contracts
The Company  utilizes  derivatives  principally to manage the risk of changes in
market prices for natural gas, fuel,  electricity  and emission  credits.  Price
fluctuations  in  natural  gas,  fuel and  electricity  cause (1) an  unrealized
appreciation or  depreciation  of the Company's firm  commitments to purchase or
sell when purchase or sales 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 Company 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 Company.

The following summarizes changes in the fair value of all contracts marked to
market during 2001:
--------------------------------------------------------------------------------
In Millions
--------------------------------------------------------------------------------
Fair value of contracts at January 1, 2001                        $(30)
Contracts at January 1, 2001 which were realized or
otherwise settled during 2001                                       30
Changes in fair values attributable to changes in valuation
techniques and assumptions                                           -
Fair value of new contracts entered into during 2001                 4
Other changes in fair value                                         (5)
--------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31, 2001           $(1)
--------------------------------------------------------------------------------

Fair value of contracts as of December 31, 2001 were as follows:
<TABLE>
<CAPTION>
--------------------------------------------------------------------------------------------------------------------
In Millions                                       Maturity     Maturity 1-3     Maturity      Maturity    Total
                                                  less than    years            4-5 years    in excess    fair
Sources of fair value                             1 year                                     of 5 years   value (a)
--------------------------------------------------------------------------------------------------------------------
<S>                                             <C>           <C>            <C>            <C>         <C>
Prices actively quoted                           $-            $(2)            $ -            $ -          $(2)
Prices provided by other external sources (b)     5              -               -              -            5
Prices based on models and other
valuation methods (c)                             -             (2)             (1)            (1)          (4)
--------------------------------------------------------------------------------------------------------------------
     Total                                       $5            $(4)            $(1)           $(1)         $(1)
--------------------------------------------------------------------------------------------------------------------
(a)  Contracts  valued  at ($1  million)  were  with  noninvestment-grade  rated
     counterparties.
(b)  Principally   power  forward  hedges  valued  based  on  NYMEX  prices  for
     over-the-counter contracts.
(c)  Principally coal and SO2 options valued based on a Black-Scholes model that
     includes information from external sources and Company estimates.
</TABLE>

                                       15
<PAGE>

SAFE HARBOR STATEMENT

Statements  made in this annual  report to  stockholders  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
Company 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 subsequent securities filings,  could cause results to differ materially from
management expectations as suggested by such "forward-looking"  statements:  the
effects  of the  pending  AmerenUE  excess  earnings  complaint  case and  other
regulatory actions,  including changes in regulatory policy; changes in laws and
other  governmental  actions;  the impact on the Company 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  Company's  business  at both the state and federal  levels;  the effects of
participation in a FERC approved RTO, including  activities  associated with the
Midwest ISO and the Alliance  RTO;  future  market prices for fuel and purchased
power,  electricity,  and  natural  gas,  including  the  use of  financial  and
derivative instruments and volatility of changes in market prices; average rates
for electricity in the Midwest; business and economic conditions;  the impact of
the adoption of new accounting standards; interest rates and the availability of
capital;  actions of ratings  agencies and the effects of such actions;  weather
conditions;  fuel  prices  and  availability;   generation  plant  construction,
installation and performance; the impact of current environmental regulations on
utilities and  generating  companies  and the  expectation  that more  stringent
requirements  will be  introduced  over time,  which  could  potentially  have a
negative  financial  effect;  monetary  and fiscal  policies;  future  wages and
employee benefits costs;  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  Company's  generating
facilities  or required to satisfy  energy sales made by the Company;  and legal
and administrative proceedings.

                                       16
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SECURITIES AND EXCHANGE COMMISSION
                              WASHINGTON, DC 20549

                                    FORM 8-K

                                 CURRENT REPORT

     Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

                Date of Report (Date of earliest event reported):
                                February 14, 2002

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

           Missouri                        1-14756              43-1723446
   (State or other jurisdiction          (Commission         (I.R.S. Employer
        of incorporation)                File Number)        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
ITEM 5.  OTHER EVENTS AND REGULATION FD DISCLOSURE

         On February  13,  2002,  Ameren  Corporation  (the  "Registrant")filed
the following with the  Securities and Exchange Commission as exhibits to this
Current Report on Form 8-K: (i) consolidated financial statements as of
December 31, 2001 and 2000, and for each of the three years in the period ended
December 31, 2001, and the report thereon of PricewaterhouseCoopers LLP,
independent accountants, and (ii) the related Management's Discussion and
Analysis of Financial Condition and Results of Operations.

ITEM 7.  EXHIBITS

         (c) Exhibits.

             23       Consent of Independent Accountants.

             99.1     The Registrant's consolidated financial statements as of
                      December 31, 2001 and 2000, and for each of the three
                      years in the period ended December 31, 2001, and the
                      report thereon of PricewaterhouseCoopers LLP, independent
                      accountants.

             99.2     The Registrant's Management's Discussion and Analysis of
                      Financial Condition and Results of Operations.

                                    SIGNATURE

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

                                          AMEREN CORPORATION
                                           (Registrant)

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

Date:  February 14, 2002
Exhibit Index

Exhibit No.                     Description

     23           - Consent of Independent Accountants.

     99.1         - The Registrant's consolidated financial statements as of
                    December 31, 2001 and 2000, and for each of the three years
                    in the period ended December 31, 2001, and the report
                    thereon of PricewaterhouseCoopers LLP, independent
                    accountants.

     99.2         - The Registrant's Management's Discussion and Analysis of
                    Financial Condition and Results of Operations.
EXHIBIT 23
                       CONSENT OF INDEPENDENT ACCOUNTANTS

We  hereby  consent  to the  incorporation  by  reference  in  the  Registration
Statements on Form S-8 (Nos. 333-43737,  333-43743, 333-50793 and 333-72156) and
the Registration  Statement on Form S-3 (No. 333-39400) of Ameren Corporation of
our  report  dated  February  1, 2002  relating  to the  consolidated  financial
statements,  which  appears  in  the  Current  Report  on  Form  8-K  of  Ameren
Corporation dated February 14, 2002.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
St. Louis, Missouri
February 14, 2002
EXHIBIT 99.1
                        Report of Independent Accountants

To the Board of Directors and Shareholders
of Ameren Corporation

In our opinion,  the  accompanying  consolidated  balance sheets and the related
consolidated  statements  of income,  of cash flows and of common  stockholders'
equity  present  fairly,  in all material  respects,  the financial  position of
Ameren  Corporation and its subsidiaries at December 31, 2001, and 2000, and the
results of their  operations and their cash flows for each of the three years in
the period ended  December 31, 2001, in conformity  with  accounting  principles
generally accepted in the United States of America.  These financial  statements
are the  responsibility of the Company's  management;  our  responsibility is to
express  an  opinion  on these  financial  statements  based on our  audits.  We
conducted our audits of these  statements in accordance with auditing  standards
generally  accepted in the United States of America,  which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining, on a
test basis,  evidence  supporting  the amounts and  disclosures in the financial
statements,  assessing the accounting  principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
St. Louis, Missouri
February 1, 2002
AMEREN CORPORATION
                           CONSOLIDATED BALANCE SHEET
                  (Thousands of Dollars, Except Share Amounts)

                                                    December      December
                                                         31,          31,
ASSETS                                                   2001        2000
------                                                  ----         ----
Property and plant, at original cost:
   Electric                                      $ 13,664,168    $ 12,684,366
   Gas                                                532,346         509,746
   Other                                              104,790          97,214
                                                 ------------    ------------
                                                   14,301,304      13,291,326
   Less accumulated depreciation and
     amortization                                   6,535,693       6,204,367
                                                 ------------    ------------
                                                    7,765,611       7,086,959
Construction work in progress:
   Nuclear fuel in process                             96,676         117,789
   Other                                              564,275         500,924
                                                 ------------    ------------
         Total property and plant, net              8,426,562       7,705,672
                                                 ------------    ------------
 Investments and other assets:
   Investments                                         39,432          40,235
   Nuclear decommissioning trust fund                 186,937         190,625
   Other                                              113,493          97,630
                                                 ------------    ------------
         Total investments and other assets           339,862         328,490
                                                 ------------    ------------
  Current assets:
   Cash and cash equivalents                           67,092         125,968
   Accounts receivable - trade (less allowance
       for doubtful  accounts of  $8,783 and
       $8,028, respectively)                          389,127         474,425
   Other accounts and notes receivable                 71,234          56,529
   Materials and supplies, at average cost:
      Fossil fuel                                     158,800         107,572
      Other                                           136,322         119,478
   Other                                               40,939          37,210
                                                 ------------    ------------
         Total current assets                         863,514         921,182
                                                 ------------    ------------
 Regulatory assets:
   Deferred income taxes                              604,092         600,100
   Other                                              166,545         158,986
                                                 ------------    ------------
         Total regulatory assets                      770,637         759,086
                                                 ------------    ------------
 Total Assets                                    $ 10,400,575    $  9,714,430
                                                 ============    ============

CAPITAL AND LIABILITIES
Capitalization:
   Common stock, $.01 par value, 400,000,000
     shares authorized -shares outstanding of
     138,045,639 and 137,215,462, respectively
     (Note 5)                                          $1,380          $1,372
   Other paid-in capital, principally premium
     on common stock                                1,614,206       1,581,339
   Retained earnings                                1,733,558       1,613,960
   Accumulated other comprehensive income               4,417           -
   Other                                               (4,801)          -
                                                 ------------    ------------
         Total common stockholders' equity          3,348,760       3,196,671
   Preferred stock of subsidiaries not subject
     to mandatory redemption  (Note 5)                235,197         235,197
   Long-term debt  (Note 7)                         2,835,378       2,745,068
                                                 ------------    ------------
         Total capitalization                       6,419,335       6,176,936
                                                 ------------    ------------
Minority interest in consolidated subsidiaries          3,534           3,940
Current liabilities:
   Current maturity of long-term debt (Note 7)        138,961          44,444
   Short-term debt                                    641,336         203,260
   Accounts and wages payable                         392,169         462,924
   Accumulated deferred income taxes                   57,787          49,829
   Taxes accrued                                      132,246         124,706
   Other                                              218,525         300,798
                                                 ------------    ------------
        Total current liabilities                   1,581,024       1,185,961
                                                 ------------    ------------
                                       2
Commitments and contingencies (Notes 2, 11
  and 12)
Accumulated deferred income taxes                   1,562,916       1,540,536
Accumulated deferred investment tax credits           157,936         164,120
Regulatory liability                                  172,290         183,541
Other deferred credits and liabilities                503,540         459,396
                                                 ------------    ------------
Total Capital and Liabilities                    $ 10,400,575    $  9,714,430
                                                 ============    ============
See Notes to Consolidated Financial Statements.
3
AMEREN CORPORATION
                        CONSOLIDATED STATEMENT OF INCOME
           (Thousands of Dollars, Except Share and Per Share Amounts)

                                                              December 31,      December 31,       December 31,
For the year ended                                                2001               2000               1999
                                                                  ----               ----               ----
OPERATING REVENUES:
   Electric                                                   $   4,155,240    $   3,526,578    $   3,300,022
   Gas                                                              342,168          323,886          228,298
   Other                                                              8,459            6,366            7,743
                                                              -------------    -------------    -------------
      Total operating revenues                                    4,505,867        3,856,830        3,536,063

OPERATING EXPENSES:
   Operations:
      Fuel and purchased power                                    1,562,164        1,025,221          973,277
      Gas                                                           221,842          209,467          131,449
      Other                                                         708,096          664,544          629,482
                                                              -------------    -------------    -------------
                                                                  2,492,102        1,899,232        1,734,208
   Maintenance                                                      382,105          367,921          370,873
   Depreciation and amortization                                    405,804          383,110          362,971
   Income taxes                                                     300,052          301,192          258,870
   Other taxes                                                      260,817          265,065          246,592
                                                              -------------    -------------    -------------
      Total operating expenses                                    3,840,880        3,216,520        2,973,514

OPERATING INCOME                                                    664,987          640,310          562,549

OTHER INCOME AND (DEDUCTIONS):
   Allowance for equity funds used during construction               12,893            5,298            7,161
   Miscellaneous, net                                                   674           (4,400)         (10,813)
                                                              -------------    -------------    -------------
    Total other income and (deductions)                              13,567              898           (3,652)

INCOME BEFORE INTEREST CHARGES
  AND PREFERRED DIVIDENDS                                           678,554          641,208          558,897

INTEREST CHARGES AND PREFERRED DIVIDENDS:
   Interest                                                         198,648          179,706          168,275
   Allowance for borrowed funds used during construction             (7,925)          (8,292)          (7,123)
   Preferred dividends of subsidiaries                               12,445           12,700           12,650
                                                              -------------    -------------    -------------
      Net interest charges and preferred dividends                  203,168          184,114          173,802
                                                              -------------    -------------    -------------
INCOME BEFORE CUMULATIVE EFFECT OF
  CHANGE IN ACCOUNTING PRINCIPLE                                    475,386          457,094          385,095

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
  PRINCIPLE, NET OF INCOME TAXES                                     (6,841)            -               -
                                                              -------------    -------------    -------------

NET INCOME                                                    $     468,545    $     457,094    $     385,095
                                                              =============    =============    =============

EARNINGS PER COMMON SHARE  - BASIC
   Income before cumulative effect of change in accounting
principle                                                     $        3.46    $        3.33    $        2.81
   Cumulative effect of change in accounting principle, net
of  income taxes                                                       (.05)            -               -
                                                              -------------    -------------    -------------
   EARNINGS PER COMMON SHARE - BASIC
                                                              $        3.41    $        3.33    $        2.81
                                                              =============    =============    =============
EARNINGS PER COMMON SHARE - DILUTED
 Income before cumulative effect of
   change in accounting principle                             $        3.45    $        3.33    $        2.81
   Cumulative effect of change in accounting principle,
   net of income taxes                                                 (.05)            -               -
                                                              -------------    -------------    -------------
   EARNINGS PER COMMON SHARE - DILUTED                        $        3.40    $        3.33    $        2.81
                                                              =============    =============    =============
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (Note 1)             137,320,692      137,215,462      137,215,462
                                                              =============    =============    =============

See Notes to Consolidated Financial Statements.
4
AMEREN CORPORATION
                      CONSOLIDATED STATEMENT OF CASH FLOWS
                             (Thousands of Dollars)

                                                             December 31,     December 31,    December 31,
For the year ended                                             2001               2000            1999
                                                               ----               ----            ----
Cash Flows From Operating:
   Net income                                                $   468,545    $   457,094       $ 385,095
   Adjustments to reconcile net income to net cash
     provided by operating activities:
       Cumulative effect of change in accounting principle         6,841           -              -
       Depreciation and amortization                             393,088         370,776        352,761
       Amortization of nuclear fuel                               29,370          37,101         36,068
       Allowance for funds used during construction              (20,818)       (13,590)        (14,284)
       Deferred income taxes, net                                 28,018          1,699         (22,578)
       Deferred investment tax credits, net                       (6,184)        (6,714)         (7,998)
       Changes in assets and liabilities:
           Receivables, net                                       70,593       (139,845)         34,484
           Materials and supplies                                (68,072)        26,174          (7,432)
           Accounts and wages payable                            (70,755)       121,650          56,456
           Taxes accrued                                           7,540        (30,690)         41,290
           Other, net                                           (100,124)        31,927          63,713
                                                             -----------     -----------    -----------
Net cash provided by operating activities                        738,042        855,582         917,575

Cash Flows From Investing:
   Construction expenditures                                  (1,102,586)      (928,727)       (570,807)
   Allowance for funds used during construction                   20,818         13,590          14,284
   Nuclear fuel expenditures                                     (24,359)       (21,527)        (21,901)
   Other                                                             803         26,241          20,218
                                                                -----------  -----------    -----------
Net cash used in investing activities                         (1,105,324)      (910,423)       (558,206)

Cash Flows From Financing:
   Dividends on common stock                                    (348,819)      (348,527)       (348,527)
   Redemptions -
      Nuclear fuel lease                                         (64,122)       (11,356)        (15,138)
      Long-term debt                                             (63,544)      (420,994)       (174,444)
   Issuances -
      Common stock                                                33,397           -              -
      Nuclear fuel lease                                          13,418          9,109          64,972
      Short-term debt                                            438,076         55,095          79,637
      Long-term debt                                             300,000        702,600         152,150
                                                             -----------     -----------    -----------
Net cash provided by (used in) financing activities              308,406        (14,073)       (241,350)

Net change in cash and cash equivalents                          (58,876)       (68,914)        118,019
Cash and cash equivalents at beginning of year                   125,968        194,882          76,863
                                                             -----------     -----------    -----------
Cash and cash equivalents at end of year                     $    67,092    $   125,968     $   194,882
=======================================================================================================
Cash paid during the periods:
-------------------------------------------------------------------------------------------------------
   Interest (net of amount capitalized)                      $   187,121    $   168,650    $   162,705
   Income taxes                                                  266,352        311,848        247,428
-------------------------------------------------------------------------------------------------------

See Notes to Consolidated Financial Statements.
5
AMEREN CORPORATION
              CONSOLIDATED STATEMENT OF COMMON STOCKHOLDERS' EQUITY
                             (Thousands of Dollars)

                                                           December 31,    December 31,    December 31,
For the year ended                                             2001            2000           1999
                                                               ----            ----           ----
Common stock
   Beginning balance                                       $     1,372    $     1,372    $     1,372
   Shares issued                                                     8          -               -
                                                           -----------    -----------    -----------
                                                                 1,380          1,372          1,372

Other paid-in capital
   Beginning balance                                         1,581,339      1,582,501      1,582,548
   Shares issued                                                33,389          -               -
   Employee stock awards                                          (522)        (1,162)           (47)
                                                           -----------    -----------    -----------
                                                             1,614,206      1,581,339      1,582,501

Retained earnings
   Beginning balance                                         1,613,960      1,505,827      1,472,200
   Net income                                                  468,545        457,094        385,095
   Dividends                                                  (348,947)      (348,961)      (351,468)
                                                           -----------    -----------    -----------
                                                             1,733,558      1,613,960      1,505,827

Accumulated other comprehensive income
   Beginning balance                                              -             -             -
   Change in current period                                      4,417          -             -
                                                           -----------    -----------    -----------
                                                                 4,417          -             -

Other
   Beginning balance                                              -             -             -
   Unamortized restricted stock compensation                    (5,704)         -             -
   Compensation amortized and mark-to-market adjustments           903          -             -
                                                           -----------    -----------    -----------
                                                                (4,801)         -             -
                                                           -----------    -----------    -----------
Total common stockholders' equity                          $ 3,348,760    $ 3,196,671    $ 3,089,700
                                                           ===========    ===========    ===========

Comprehensive income, net of taxes
   Net income                                              $   468,545        457,094        385,095
   Cumulative effect of accounting change                      (11,258)         -            -
   Unrealized net gain on derivative hedging instruments        15,675          -            -
                                                           -----------    -----------    -----------
                                                           $   472,962   $    457,094    $   385,095
                                                           ===========    ===========    ===========

See Notes to Consolidated Financial Statements.
6
AMEREN CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 2001

NOTE 1 - Summary of Significant Accounting Policies

Basis of Presentation
Ameren Corporation (Ameren or the Company) is a holding company registered under
the Public Utility Holding Company Act of 1935 (PUHCA).  In December 1997, Union
Electric Company  (AmerenUE) and CIPSCO  Incorporated  (CIPSCO) combined to form
Ameren, with AmerenUE and CIPSCO's subsidiaries, Central Illinois Public Service
Company (AmerenCIPS) and CIPSCO Investment Company (CIC),  becoming subsidiaries
of Ameren  (the  Merger).  The  outstanding  preferred  shares of  AmerenUE  and
AmerenCIPS were not affected by the Merger.

The  accompanying  consolidated  financial  statements  include the  accounts of
Ameren and its subsidiaries  (collectively,  the Company).  All subsidiaries for
which the Company owns directly or indirectly  more than 50% of the voting stock
are included as consolidated subsidiaries. Ameren's primary operating companies,
AmerenUE,  AmerenCIPS, and AmerenEnergy Generating Company (Generating Company),
a wholly-owned subsidiary of AmerenEnergy Resources Company (Resources 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. The
Company's other principal  subsidiaries  include:  CIC, an investing subsidiary;
AmerenEnergy,   Inc.,  an  energy  trading  and  marketing  subsidiary;   Ameren
Development Company, a nonregulated products and services subsidiary;  Resources
Company, a holding company for the Company's nonregulated generating operations;
and Ameren Services Company, a shared support services  subsidiary.  The Company
also has a 60% 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. All
significant intercompany balances and transactions have been eliminated from the
consolidated financial statements.

References to the Company are to Ameren on a  consolidated  basis.  However,  in
certain  circumstances,  the subsidiaries are separately referred to in order to
distinguish among their different business activities.

Regulation
Ameren is subject to regulation by the Securities and Exchange Commission (SEC).
Certain of Ameren's  subsidiaries  are also  regulated  by the  Missouri  Public
Service  Commission  (MoPSC),   Illinois  Commerce  Commission  (ICC),   Nuclear
Regulatory Commission (NRC) and the Federal Energy Regulatory Commission (FERC).
The  accounting  policies  of the  Company  conform to U.S.  generally  accepted
accounting  principles  (GAAP).  See Note 2 -  Regulatory  Matters  for  further
information.

Property and Plant
The cost of  additions  to, and  betterments  of, units of property and plant is
capitalized.  Cost includes labor, material,  applicable taxes and overheads. An
allowance  for funds used during  construction  is also added for the  Company's
regulated  assets,  and interest during  construction is added for  nonregulated
assets.  Maintenance  expenditures and the renewal of items not considered units
of  property  are  charged to income,  as  incurred.  When units of  depreciable
property are retired,  the original cost and removal cost,  less salvage  value,
are charged to accumulated depreciation.

Depreciation
Depreciation  is provided  over the  estimated  lives of the various  classes of
depreciable  property by applying composite rates on a straight-line  basis. The
provision for depreciation in 2001,  2000, and 1999 was  approximately 3% of the
average depreciable cost.

Fuel and Gas Costs
In the Company's retail electric utility jurisdictions, the cost of fuel for
electric  generation is reflected in base rates with no provision for changes in
such cost to be  reflected  in billings to  customers  through  fuel  adjustment
clauses. In the Company's retail gas utility jurisdictions, changes in gas costs
are  generally  reflected in billings to gas  customers  through  purchased  gas
adjustment clauses.

                                       7
Nuclear Fuel
The cost of nuclear fuel is  amortized  to fuel expense on a  unit-of-production
basis.   Spent  fuel  disposal  cost  is  charged  to  expense,   based  on  net
kilowatthours generated and sold.

Cash and Cash Equivalents
Cash  and  cash  equivalents  include  cash on hand  and  temporary  investments
purchased with an original maturity of three months or less.

Income Taxes
The  Company  and its  subsidiaries  file a  consolidated  federal  tax  return.
Deferred tax assets and liabilities  are recognized for the tax  consequences of
transactions that have been treated  differently for financial reporting and tax
return purposes, measured using statutory tax rates.

Investment tax credits utilized in prior years were deferred and are being
amortized over the useful lives of the related properties.

Allowance for Funds Used During Construction
Allowance  for  funds  used  during  construction  (AFC) is a  utility  industry
accounting  practice  whereby the cost of borrowed  funds and the cost of equity
funds (preferred and common  stockholders'  equity)  applicable to the Company's
regulated  construction  program are capitalized as a cost of construction.  AFC
does not  represent a current  source of cash funds.  This  accounting  practice
offsets the effect on earnings of the cost of  financing  current  construction,
and treats such financing costs in the same manner as  construction  charges for
labor and materials.

Under  accepted  ratemaking  practice,  cash  recovery  of AFC, as well as other
construction  costs,  occurs when  completed  projects are placed in service and
reflected in customer  rates.  The AFC ranges of rates used were 4% - 10% during
2001, 6% - 10% during 2000, and 5% - 10% during 1999.

Unamortized Debt Discount, Premium and Expense
Discount,  premium and expense associated with long-term debt are amortized over
the lives of the related issues.

Revenue
The  Company  accrues an  estimate  of  electric  and gas  revenues  for service
rendered, but unbilled, at the end of each accounting period.

Energy Contracts
Statement of Financial  Accounting  Standards  (SFAS) No. 133,  "Accounting  for
Derivative  Instruments and Hedging  Activities," became effective on January 1,
2001.  SFAS 133  establishes  accounting and reporting  standards for derivative
instruments,   including  certain  derivative   instruments  embedded  in  other
contracts,   and  for  hedging  activities  and  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, a cash flow hedge, or a foreign  currency hedge will determine
when the gains or losses on the  derivatives  are to be reported in earnings and
when they are to be  reported as a component  of other  comprehensive  income in
stockholders'  equity.  See Note 3 - Risk  Management and  Derivative  Financial
Instruments for further information.

The  Emerging  Issues Task Force of the  Financial  Accounting  Standards  Board
(EITF)  Issue  98-10,   "Accounting  for  Energy  Trading  and  Risk  Management
Activities" became effective on January 1, 1999. EITF 98-10 provides guidance on
the  accounting  for energy  contracts  entered into for the purchase or sale of
electricity,  natural  gas,  capacity  and  transportation.  The EITF  reached a
consensus in EITF 98-10 that sales and purchase  activities being performed need
to be classified as either  trading or  non-trading.  Furthermore,  transactions
that are determined to be trading  activities would be recognized on the balance
sheet  measured at fair value,  with  changes in fair market  value  included in
earnings.

AmerenEnergy, Inc. enters into contracts, some of which are derivatives, for the
sale and  purchase  of  energy on behalf of  AmerenUE  and  Generating  Company.
Derivatives  are  accounted  for  under  SFAS  133 or EITF  98-10  based  on the
Company's intent when entering into the contract.  Virtually all  non-derivative
contracts are accounted for using the accrual or settlement method.

                                       8
Software
Statement of Position (SOP) 98-1, "Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use" became effective on January 1, 1999. SOP
98-1  provides  guidance  on  accounting  for the  costs  of  computer  software
developed or obtained for internal  use.  Under SOP 98-1,  certain  costs may be
capitalized and amortized over some future period.

Evaluation of Assets for Impairment
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of," prescribes  general standards for the recognition and
measurement of impairment  losses.  The Company  determines if long-lived assets
are impaired by comparing their undiscounted expected future cash flows to their
carrying amount.  An impairment loss is recognized if the undiscounted  expected
future cash flows are less than the carrying amount of the asset.  SFAS 121 also
requires that regulatory assets which are no longer probable of recovery through
future  revenues be charged to  earnings  (see Note 2 -  Regulatory  Matters for
further information). As of December 31, 2001, no impairment was identified.

In August 2001, the Financial  Accounting Standards Board (FASB) issued SFAS No.
144,  "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS 144
addresses the financial  accounting and reporting for the impairment or disposal
of  long-lived  assets and  supersedes  SFAS 121.  SFAS 144 retains the guidance
related to calculating and recording impairment losses, but adds guidance on the
accounting  for  discontinued   operations,   previously   accounted  for  under
Accounting  Principles Board Opinion No. 30. SFAS 144 was adopted by the Company
on  January  1,  2002,  and did not  have a  material  effect  on the  Company's
financial position, results of operations or liquidity.

Asset Retirement Obligations
In July  2001,  the FASB  issued  SFAS 143,  "Accounting  for  Asset  Retirement
Obligations."   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.  At this time,  the
Company is assessing the impact of SFAS 143 on its financial  position,  results
of operations  and liquidity  upon  adoption.  However,  SFAS 143 is expected to
result in significant increases to the Company's reported assets and liabilities
as a  result  of  its  ongoing  collection  through  rates  of  and  obligations
associated with Callaway Nuclear Plant decommissioning costs. See Note 12 -
Callaway Nuclear Plant for further information.

Stock Compensation Plans
The Company applies  Accounting  Principles Board Opinion (APB) 25,  "Accounting
for Stock  Issued to  Employees"  in  accounting  for its  plans.  See Note 10 -
Stock-Based Compensation for further information.

Earnings Per Share
The Company's  calculation of diluted earnings per share resulted in dilution of
$.01 for 2001.  There was no difference  between the basic and diluted  earnings
per share amounts in 2000 and 1999. The reconciling item in each of the years is
comprised of assumed  stock option  conversions,  which  increased the number of
shares  outstanding  in the diluted  earnings per share  calculation  by 331,813
shares, 183,201 shares, and 38,786 shares in 2001, 2000 and 1999, respectively.

Use of Estimates
The  preparation  of  financial  statements  in  conformity  with GAAP  requires
management  to make  certain  estimates  and  assumptions.  Such  estimates  and
assumptions  affect reported amounts of assets and liabilities and disclosure of
contingent  assets and  liabilities at the date of the financial  statements and
the reported amounts of revenues and expenses during the reported period. Actual
results could differ from those estimates.

New Accounting Pronouncements
In July 2001, the FASB issued SFAS No. 141,  "Business  Combinations,"  and SFAS
No. 142,  "Goodwill and Other  Intangible  Assets."  SFAS 141 requires  business
combinations to be accounted for under the purchase method of accounting,  which
requires  one  party  in the  transaction  to be  identified  as  the  acquiring
enterprise  and for that party to allocate the purchase  price to the assets and

                                       9
liabilities of the acquired  enterprise based on fair market value. 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 became effective
for the  Company  on  January  1,  2002.  SFAS  141 and  SFAS 142 did not have a
material effect on the Company's  financial  position,  results of operations or
liquidity upon adoption.

Reclassifications
Certain reclassifications have been made to prior years' financial statements to
conform with 2001 reporting.

NOTE 2 - Regulatory Matters

Missouri Electric
In  July  1995,  the  MoPSC  approved  an  agreement  establishing   contractual
obligations  involving AmerenUE'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%  regulatory return on equity (ROE) be shared equally
between customers and stockholders,  and earnings above a 14% ROE be credited to
customers. The formula for computing the credit used twelve-month results ending
June 30, rather than calendar year earnings.

The MoPSC staff proposed  adjustments to AmerenUE's estimated customer credit of
$43 million for the final year of the Original  Plan ended June 30, 1998,  which
were the subject of regulatory proceedings before the MoPSC in 1999. In December
1999,  the MoPSC issued a Report and Order  (Order)  concerning  these  proposed
adjustments.  Based  on the  provisions  of that  Order,  AmerenUE  revised  its
estimated  final year credit of the Original  Plan to $31 million in the quarter
ended December 31, 1999. Subsequently, AmerenUE filed a request for rehearing of
the Order  with the MoPSC,  asking  that it  reconsider  its  decision  to adopt
certain of the MoPSC  staff's  adjustments.  The request was denied by the MoPSC
and in  February  2000,  AmerenUE  filed a Petition  for Writ of Review with the
Circuit Court of Cole County,  Missouri,  requesting that the Order be reversed.
The appeal is pending and the ultimate outcome cannot be predicted; however, the
final decision is not expected to materially impact the financial condition,
results of operations or liquidity of the Company. A partial stay of the Order
was granted by the Court pending the appeal.

A new three-year  experimental  alternative  regulation  plan (the New Plan) was
included in the joint  agreement  authorized  by the MoPSC in its February  1997
order  approving the Merger.  Like the Original  Plan,  the New Plan required an
earnings over a 12.61% ROE up to a 14% ROE be shared equally  between  customers
and  stockholders.  The New Plan also  returned to customers 90% of all earnings
above a 14% ROE up to a 16% ROE. Earnings above a 16% ROE were credited entirely
to  customers.  The New Plan ran from July 1, 1998 through June 30, 2001. In May
2001,  the MoPSC approved a stipulation  and agreement of the parties  regarding
the credit for the plan year ended June 30, 2000 of $28 million, which was paid.
At December 31, 2001,  the Company  recorded an estimated  credit that  AmerenUE
expects to pay its Missouri electric  customers of $40 million for the plan year
ended June 30,  2001.  During the year ended  December  31,  2001,  the  Company
reduced the estimated  credit  previously  recorded for the plan year ended June
30, 2001 by $10 million,  compared to estimated  credits of $65 million recorded
in the year ago  period  for plan  years  ended  June 30,  2001 and 2000.  These
credits were reflected as a reduction in electric revenues.  The final amount of
the 2001 credit will depend on several factors, including approval by the MoPSC.

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  AmerenUE that
proposed to reduce its annual  electric  revenues  ranging  from $213 million to
$250 million.  Factors contributing to the MoPSC staff's recommendation included
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  ranged from 9.04% to 10.04%. The MoPSC is not bound by the MoPSC
staff's  recommendation.  In  January  2002,  the  MoPSC  issued  an order  that
established  the test year to be used to determine rates as July 1, 2000 through
June 30, 2001,  with updates to that test year permitted  through  September 30,
2001.  The MoPSC staff had utilized a test year of July 1, 1999 through June 30,
2000 in its  original  complaint.  In  addition,  the MoPSC  order  stated  that
AmerenUE  would be  permitted to propose an  incentive  regulation  plan in this
proceeding.

                                       10
The MoPSC order also included a revised procedural schedule to allow all parties
additional time to review data and file  testimony,  due to the utilization of a
more current test year. Under the new schedule, the MoPSC staff will file direct
testimony  on March 1, 2002,  with  AmerenUE  and the  Office of Public  Counsel
filing  rebuttal  testimony on May 10, 2002.  Evidentiary  hearings on the MoPSC
staff's  recommendation are scheduled to be conducted before the MoPSC beginning
in July 2002.  In the event  that the MoPSC  ultimately  determines  that a rate
decrease is warranted in this case,  that rate reduction would be retroactive to
April 1,  2002,  regardless  of when the  MoPSC  issues  its  decision.  A final
decision  on this  matter  may not  occur  until  the  fourth  quarter  of 2002.
Depending on the outcome of the MoPSC's decision,  further appeals in the courts
may be warranted.

In the interim, the Company expects to continue  negotiations with all pertinent
parties with the intent to continue with an incentive  regulation plan,  similar
in form to the New  Plan.  The  Company  cannot  predict  the  outcome  of these
negotiations and their impact on the Company's  financial  position,  results of
operations or liquidity; however, the impact could be material.

Gas
In October  2000,  the MoPSC  approved a $4 million  annual  rate  increase  for
natural gas  service in  AmerenUE's  Missouri  jurisdiction.  The rate  increase
became  effective  November 1, 2000.  In February  1999,  the ICC  approved a $9
million  total annual rate  increase for natural gas service in  AmerenUE's  and
AmerenCIPS'  Illinois  jurisdictions.  The increase became effective in February
1999.

Midwest ISO and Alliance RTO
In 1998,  AmerenUE and AmerenCIPS  joined a group of companies  that  originally
supported  the formation of the Midwest  Independent  System  Operator  (Midwest
ISO).  An ISO  operates,  but does not own,  electric  transmission  systems and
maintains  system  reliability and security,  while  facilitating  wholesale and
retail competition through the elimination of "pancaked" transmission rates. The
Midwest  ISO is  regulated  by the FERC.  The FERC  conditionally  approved  the
formation of the Midwest ISO in September 1998.

In December 1999,  the FERC issued Order 2000 relating to Regional  Transmission
Organizations  (RTOs) that would meet certain  characteristics  such as size and
independence.  RTOs,  including  ISOs,  are entities that ensure  comparable and
non-discriminatory  access to regional electric transmission systems. Order 2000
calls on all transmission owners to join RTOs.

In the fourth quarter of 2000,  the Company  announced its intention to withdraw
from the Midwest ISO and to join the 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  Company's  estimated  obligation  under the  Midwest  ISO
agreement for costs incurred by the Midwest ISO, plus  estimated exit costs.  In
2001, the Company announced that it had signed an agreement to join the Alliance
RTO.  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.  This  settlement  agreement  was approved by the
FERC.  The Company's  withdrawal  from the Midwest ISO remains  subject to MoPSC
approval. In July 2001, the FERC conditionally approved the formation, including
the rate structure, of the Alliance RTO. However, on December 20, 2001, the FERC
issued an order that  reversed its  position  and rejected the  formation of the
Alliance  RTO.  Instead,  the FERC  granted  RTO status to the  Midwest  ISO and
ordered  the  Alliance  RTO  Companies  and the  Midwest  ISO to discuss how the
Alliance RTO business  model could be  accommodated  within the Midwest ISO. The
Alliance  RTO  members  have until  February  19,  2002 to respond to the FERC's
December 2001 order.  At this time, the Company is evaluating its  alternatives,
including the possible appeal of the FERC's  December 2001 order,  and is unable
to determine  the impact that the FERC's  latest  ruling will have on its future
financial condition, results of operations or liquidity.

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

                                       11
Under the Illinois Law, retail direct access,  which allows  customers to choose
their  electric  generation  suppliers,  will be phased in over  several  years.
Access for  commercial  and  industrial  customers  occurred  over a period from
October 1999 to December 2000, and access for  residential  customers will occur
after May 1, 2002.

As a  requirement  of the Illinois Law, in March 1999,  AmerenUE and  AmerenCIPS
filed  delivery  service  tariffs with the ICC.  These  tariffs would be used by
electric customers who choose to purchase their power from alternate  suppliers.
In August 1999, the ICC issued an order approving the delivery  service tariffs,
with an allowed rate of return on equity of 10.45%.  In December 2000,  AmerenUE
and AmerenCIPS filed revised Illinois delivery service tariffs with the ICC. The
purpose  of the  filing  was to update  financial  information  that was used to
establish the initial rates and to propose new rates.  Additionally,  the filing
establishes  tariffs for residential  customers who may choose to purchase their
power from alternate  suppliers beginning in May 2002. In December 2001, the ICC
issued an Order approving the delivery service tariffs,  with an allowed rate of
return on equity of 11.35%.

Under the Illinois  Law, the Company is subject to a  residential  electric rate
decrease of up to 5% in 2002, to the extent its rates exceed the Midwest utility
average at that time. In 2001, the Company's  Illinois electric rates were below
the Midwest utility average.

The Illinois Law also  contains a provision  requiring  that  one-half of excess
earnings  from the  Illinois  jurisdiction  for the years 1998  through  2004 be
refunded to Ameren's  Illinois  customers.  Excess  earnings  are defined as the
portion of the two-year average annual rate of return on common equity in excess
of 1.5% of the two-year average of an Index, as defined in the Illinois Law. The
Index is defined as the sum of the average for the twelve months ended September
30 of the  average  monthly  yields of the 30-year  U.S.  Treasury  bonds,  plus
prescribed  percentages ranging from 4% to 7%. Filings must be made with the ICC
on, or before,  March 31 of each year 2000  through  2005.  The  Company did not
record any estimated refunds to Illinois customers in 2001.

In  conjunction  with another  provision  of the  Illinois  Law, on May 1, 2000,
following the receipt of all required  state and federal  regulatory  approvals,
AmerenCIPS  transferred  its  electric  generating  assets and  liabilities,  at
historical net book value, to Generating  Company,  in exchange for a promissory
note from  Generating  Company in the  principal  amount of  approximately  $552
million and Generating Company common stock (the Transfer).  The promissory note
bears  interest  at 7% and has a term of five years  payable  based on a 10-year
amortization.   The  transferred  assets  represent  a  generating  capacity  of
approximately 2,900 megawatts.  Approximately 45% of AmerenCIPS'  employees were
transferred to Generating Company as part of the transaction.

In conjunction with the Transfer, an electric power supply agreement was entered
into between  Generating Company and its newly created  nonregulated  affiliate,
AmerenEnergy   Marketing  Company  (Marketing  Company),   also  a  wholly-owned
subsidiary of Resources  Company.  Under this  agreement,  Marketing  Company is
entitled to purchase all of the Generating  Company's energy and capacity.  This
agreement may not be terminated  until at least  December 31, 2004. In addition,
Marketing   Company  entered  into  an  electric  power  supply  agreement  with
AmerenCIPS to supply it sufficient  energy and capacity to meet its  obligations
as a public  utility.  This  agreement  expires  December 31,  2004.  Power will
continue to be jointly dispatched between AmerenUE and Generating Company.

The creation of the new subsidiaries and the transfer of AmerenCIPS'  generating
assets and liabilities had no effect on the consolidated financial statements of
Ameren as of the date of the Transfer.

In August 1999, the Company filed a transmission system rate case with the FERC.
This filing was primarily  designed to implement rates, terms and conditions for
transmission  service for  wholesale  customers  and those  retail  customers in
Illinois  who choose  other  suppliers  as allowed  under the  Illinois  Law. In
January  2000,  the Company and other  parties to the rate case  entered  into a
settlement  agreement resolving all issues pending before the FERC. In May 2000,
the FERC  approved the  settlement  and allowed the  settlement  rates to become
effective as of the first quarter of 2000.

                                       12
The provisions of the Illinois Law could also result in lower revenues,  reduced
profit margins and increased  costs of capital and operations  expense.  At this
time,  the Company is unable to determine  the impact of the Illinois Law on the
Company's future financial condition, results of operations or liquidity.

Missouri Electric Restructuring
In Missouri,  where  approximately 70% of the Company's retail electric revenues
are derived,  restructuring  bills have been  introduced but no legislation  has
been passed.  Furthermore, no restructuring legislation is expected to be passed
by the Missouri state legislature in 2002. The potential  negative  consequences
of  electric  industry  restructuring  could  be  significant  and  include  the
impairment and write-down of certain assets, including  generation-related plant
and net regulatory assets, lower revenues,  reduced profit margins and increased
costs of capital and operations expense. At December 31, 2001, the Company's net
investment  in  generation  facilities  related  to  its  Missouri  jurisdiction
approximated  $2.8 billion and was included in electric plant  in-service on the
Company's  balance  sheet.  In addition,  at December 31,  2001,  the  Company's
Missouri net  generation-related  regulatory  assets  approximated $449 million.

Regulatory Assets and Liabilities
In accordance  with SFAS No. 71 "Accounting  for the Effects of Certain Types of
Regulation,"  the Company has deferred  certain costs pursuant to actions of its
regulators,  and is currently recovering such costs in electric rates charged to
customers.

At December 31, the Company had recorded the following regulatory assets and
regulatory liability:
--------------------------------------------------------------------------------
In Millions                                              2001         2000
--------------------------------------------------------------------------------
Regulatory Assets:
  Income taxes (a)                                        $604        $600
  Callaway costs (b)                                        84          88
  Unamortized loss on reacquired debt(c)                    28          31
  Recoverable costs - contaminated facilities (d)           26           6
  Merger costs (e)                                          12          17
  Other                                                     17          17
--------------------------------------------------------------------------------
Regulatory Assets                                         $771        $759
--------------------------------------------------------------------------------
Regulatory Liability:
  Income taxes                                            $172        $184
--------------------------------------------------------------------------------
Regulatory Liability                                      $172        $184
--------------------------------------------------------------------------------
(a)  See Note 8 - Income Taxes.
(b)  Represents  Callaway  Nuclear Plant  operations and  maintenance  expenses,
     property  taxes and carrying costs  incurred  between the plant  in-service
     date and the date the plant was  reflected in rates.  These costs are being
     amortized over the remaining life of the plant (through 2024).
(c)  Represents  losses  related  to  refunded  debt.  These  amounts  are being
     amortized  over the lives of the related  new debt issues or the  remaining
     lives of the old debt issues if no new debt was issued.
(d)  Represents  the   recoverable   portion  of  accrued   environmental   site
     liabilities.
(e)  Represents  the  portion  of  merger-related  expenses  applicable  to  the
     Missouri retail  jurisdiction.  These costs are being  amortized  within 10
     years, based on a MoPSC order.

The Company  continually  assesses the  recoverability of its regulatory assets.
Under  current  accounting  standards,  regulatory  assets  are  written  off to
earnings  when it is no longer  probable  that such  amounts  will be  recovered
through future revenues.  However,  as noted in the above  paragraphs,  electric
industry  restructuring  legislation may impact the recoverability of regulatory
assets in the future.

NOTE 3 - Risk Management and Derivative Financial Instruments

The Company handles market risks in accordance with established policies,  which
may include entering into various derivative transactions.  In the normal course
of  business,  the  Company  also faces risks that are either  non-financial  or
non-quantifiable.  The Company'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.

                                     13
Market Risk
The Company engages in price risk management  activities  related to electricity
and fuel. In addition to physically  buying and selling these  commodities,  the
Company uses  derivative  financial  instruments  to manage  market risks and to
reduce exposure  resulting from fluctuations in interest rates and the prices of
electricity  and  fuel.  Hedging  instruments  used  include  futures,   forward
contracts,  options and swaps. The primary use of these instruments is to manage
and hedge  contractual  commitments and to reduce exposure  related to commodity
market prices and interest rate volatility.

Credit Risk
Credit risk represents the loss that would be recognized if counterparties  fail
to perform as contracted.  New York Mercantile  Exchange  (NYMEX) traded futures
contracts  are  supported by the  financial  and credit  quality of the clearing
members of the NYMEX and have nominal  credit risk.  On all other  transactions,
the  Company  is exposed to credit  risk in the event of  nonperformance  by the
counterparties in the transaction.

The  Company's  physical and  financial  instruments  are subject to credit risk
consisting of trade  accounts  receivables  and executory  contracts with market
risk exposures.  The risk associated with trade  receivables is mitigated by the
large  number of customers in a broad range of industry  groups  comprising  the
Company's  customer  base.  No  customer  represents  greater  than  10%  of the
Company's accounts receivable. The Company's revenues are primarily derived from
sales of electricity and natural gas to customers in Missouri and Illinois.  The
Company analyzes each counterparty's  financial condition prior to entering into
forwards,  swaps,  futures or option  contracts.  The Company  also  establishes
credit limits for these counterparties and monitors the appropriateness of these
limits on an  ongoing  basis  through a credit  risk  management  program  which
involves  daily  exposure  reporting to senior  management,  master  trading and
netting agreements,  and credit support management (e.g.,  letters of credit and
parental guarantees).

Derivative Financial Instruments
In January 2001, the Company  adopted SFAS No. 133,  "Accounting  for Derivative
Instruments and Hedging Activities." The impact of that adoption resulted in the
Company  recording a cumulative  effect  charge of $7 million after taxes to the
income statement, and a cumulative effect adjustment of $11 million after income
taxes  to  Accumulated   Other   Comprehensive   Income  (OCI),   which  reduced
stockholders' equity. In June 2001, the Derivatives  Implementation Group (DIG),
a committee of the 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 be accounted for as normal purchases and sales if certain
criteria are met. This guidance was effective  beginning  July 1, 2001,  and did
not have a material  impact on the  Company's  financial  condition,  results of
operations or liquidity. However, in October and again in December 2001, the DIG
revised this guidance, with the revisions generally effective April 1, 2002. The
Company  does not expect the  impact of the DIG's  revisions  to have a material
effect on the Company's financial condition, results of operations, or liquidity
upon adoption.

SFAS 133 requires all derivatives to be recognized on the balance sheet at their
fair value. On the date that the Company 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   Company   reevaluates   its
classification of individual derivative transactions daily.

Changes in the fair value of  derivatives  are  recorded  each period in current
earnings or OCI,  depending on whether a derivative  is  designated as part of a
hedge transaction and, if it is, the type of hedge  transaction.  For fair-value
hedge transactions,  changes in the fair value of the derivative  instrument are
offset in the income  statement by changes in the hedged item's fair value.  For
cash-flow  hedge  transactions,  changes  in the fair  value  of the  derivative
instrument  are  reported  in  OCI.  The  gains  and  losses  on the  derivative
instrument  that are  reported  in OCI will be  reclassified  as earnings in the
periods in which  earnings are impacted by the  variability of the cash flows of
the  hedged  item.  The  ineffective  portion  of all  hedges is  recognized  in
current-period earnings.
                                       14
The Company utilizes derivatives principally to manage the risk of changes in
market prices for natural gas, fuel,  electricity  and emission  credits.  Price
fluctuations  in  natural  gas,  fuel and  electricity  cause (1) an  unrealized
appreciation or  depreciation  of the Company's firm  commitments to purchase or
sell when purchase or sales 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 Company 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 Company.

As of December 31, 2001,  the Company has recorded the fair value of  derivative
financial instrument assets of $17 million in Other Assets and the fair value of
derivative  financial  instrument  liabilities  of $18 million in Other Deferred
Credits and Liabilities.

Cash Flow Hedges
The Company  routinely  enters into  forward  purchase and sales  contracts  for
electricity  based  on  forecasted  levels  of  economic   generation  and  load
requirements.  The relative balance between load and economic  generation varies
throughout the year. The contracts  typically cover a period of twelve months or
less.  The  purpose  of these  contracts  is to  hedge  against  possible  price
fluctuations in the spot market for the period covered under the contracts.  The
Company formally  documents all  relationships  between hedging  instruments and
hedged  items,  as  well as its  risk  management  objective  and  strategy  for
undertaking various hedge transactions.

As of  December  31,  2001,  a gain of $7  million  ($4.3  million,  after  tax)
associated with interest rate swaps for debt to be issued was in OCI and will be
amortized  over the life of the debt  ultimately  issued  or will be  recognized
immediately to the income  statement if a  determination  is made that debt will
not be issued.

For the year ended December 31, 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 OCI due to
transactions going to delivery, was approximately $15 million.

As of  December  31,  2001,  the  entire  net  gain  on  derivative  instruments
accumulated  in OCI is expected  to be  recognized  in earnings  during the next
twelve months upon delivery of the commodity being hedged.

Other Derivatives
The Company enters into option transactions to manage the Company's positions in
sulfur  dioxide (SO2)  allowances,  coal,  heating oil, and  electricity.  These
transactions  are  treated as  non-hedge  transactions  under SFAS 133.  The net
change in the market  value of S02 options is  recorded  as  electric  revenues,
while the net change in the market value of coal,  heating oil, and  electricity
options is recorded as fuel and purchased power in the income statement.

The Company has entered into fixed-price  forward  contracts for the purchase of
fuel.  While these contracts meet the definition of a derivative under SFAS 133,
the Company  records  these  transactions  as normal  purchases and normal sales
because the contracts are expected to result in physical delivery.  In September
2001,  the DIG issued  guidance  regarding  the  accounting  treatment  for fuel

                                       15
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  that extends the quantity to be purchased at a fixed price are
not eligible to qualify for the normal  purchases and sales exception under SFAS
133.  This guidance is effective as of April 1, 2002.  The Company  continues to
evaluate the impact of this guidance on its future financial condition,  results
of operations or liquidity; however, the impact is not expected to be material.

NOTE 4 - Nuclear Fuel Lease

The Company has a lease  agreement  that provides for the financing of a portion
of its nuclear  fuel.  At December  31, 2001,  the maximum  amount that could be
financed  under the  agreement  was $120  million.  Pursuant to the terms of the
lease, the Company has assigned to the lessor certain  contracts for purchase of
nuclear fuel. The lessor  obtains,  through the issuance of commercial  paper or
from direct loans under a committed  revolving  credit agreement from commercial
banks, the necessary funds to purchase the fuel and make interest  payments when
due.

The Company is obligated to reimburse  the lessor for  expenditures  for nuclear
fuel,  interest and related costs under the lease.  Obligations under this lease
become due as any leased  nuclear  fuel is  consumed at the  Company's  Callaway
Nuclear  Plant.  No  leased  nuclear  fuel was  consumed  in 2001.  The  Company
reimbursed  the  lessor  $13  million in 2000 and $16  million  during  1999 for
amounts consumed under the lease.

The Company has capitalized the cost,  including  certain interest costs, of the
leased  nuclear  fuel and has  recorded  the  related  lease  obligation.  Total
interest  charges  under the lease were $4 million in 2001,  $8 million in 2000,
and $5 million in 1999.  Interest  charges for these years were based on average
interest rates of approximately  5% for 2001 and 7% for 2000 and 1999.  Interest
charges of $4 million in 2001,  $6 million in 2000,  and $4 million in 1999 were
capitalized.

NOTE 5 - Shareholder Rights Plan and Preferred Stock of Subsidiaries

In October 1998,  the  Company's  Board of Directors  approved a share  purchase
rights plan designed to assure  shareholders  of fair and equal treatment in the
event of a proposed takeover. The rights will be exercisable only if a person or
group acquires 15% or more of Ameren's common stock or announces a tender offer,
the  consummation of which would result in ownership by a person or group of 15%
or more of the common stock.  Each right will entitle the holder to purchase one
one-hundredth of a newly issued preferred stock at an exercise price of $180. If
a person or group  acquires 15% or more of Ameren's  outstanding  common  stock,
each right will  entitle  its holder  (other than such person or members of such
group) to purchase,  at the right's  then-current  exercise  price,  a number of
Ameren's  common shares having a market value of twice such price.  In addition,
if Ameren is  acquired  in a merger or other  business  combination  transaction
after a person or group has  acquired 15% or more of the  Company's  outstanding
common  stock,  each right will entitle its holder to  purchase,  at the right's
then-current  exercise price, a number of the acquiring  company's common shares
having a market value of twice such price.  The  acquiring  person or group will
not be entitled to exercise these rights.  The SEC approved the plan under PUHCA
in December 1998. The rights were issued as a dividend  payable January 8, 1999,
to shareholders  of record on that date;  these rights expire in 2008. One right
will  accompany  each new  share of Ameren  common  stock  issued  prior to such
expiration date.

At December 31, 2001 and 2000, AmerenUE and AmerenCIPS had 25 million shares and
4.6 million shares respectively, of authorized preferred stock.

                                       16
Outstanding preferred stock is entitled to cumulative dividends and is
redeemable at the prices shown in the following table:
------------------------------------------------------------------------------------------------

------------------------------------------------------------------------------------------------

Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption:
------------------------------------------------------------------------------------------------
Dollars in Millions at December 31,
Redemption Price      2001        2000
                                                           (per share)
Without par value and stated value of $100 per
share--
$7.64 Series     - 330,000 shares                      $103.82 - note (a)      $33         $33
$5.50 Series A   -  14,000 shares                       110.00                   1           1
$4.75 Series     -  20,000 shares                       102.176                  2           2
$4.56 Series     - 200,000 shares                       102.47                  20          20
$4.50 Series     - 213,595 shares                       110.00 - note (b)       21          21
$4.30 Series     -  40,000 shares                       105.00                   4           4
$4.00 Series     - 150,000 shares                       105.625                 15          15
$3.70 Series     -  40,000 shares                       104.75                   4           4
$3.50 Series     - 130,000 shares                       110.00                  13          13

With par value of $100 per share--
4.00% Series     - 150,000 shares                       101.00                  15          15
4.25% Series     -  50,000 shares                       102.00                   5           5
4.90% Series     -  75,000 shares                       102.00                   8           8
4.92% Series     -  50,000 shares                       103.50                   5           5
5.16% Series     -  50,000 shares                       102.00                   5           5
1993 Auction     - 300,000 shares                       100.00 - note (c)       30          30
6.625% Series    - 125,000 shares                       100.00                  12          12

Without par value and stated value of $25 per share--
$1.735 Series  - 1,657,500 shares                        25.00                  42          42
-----------------------------------------------------------------------------------------------
TOTAL PREFERRED STOCK OF SUBSIDIARIES NOT SUBJECT TO MANDATORY
REDEMPTION                                                                    $235        $235
-----------------------------------------------------------------------------------------------
(a)  Beginning February 15, 2003, eventually declining to $100 per share.
(b)  In the event of voluntary liquidation, $105.50.
(c)  Dividend  rates,  and the  periods  during  which  such rates  apply,  vary
     depending on the Company's  selection of certain  defined  dividend  period
     lengths. The average dividend rate during 2001 was 3.63%.
NOTE 6 - Short-Term Borrowings

Short-term  borrowings of the Company consist of bank loans and commercial paper
(maturities  generally  within 1-45 days).  At December 31, 2001 and 2000,  $641
million  and  $203  million,   respectively,   of  short-term   borrowings  were
outstanding.  The  weighted  average  interest  rates on  short-term  borrowings
outstanding at December 31, 2001 and 2000, were 1.9% and 6.7%, respectively.

At  December  31,  2001,  the  Company  had  committed  bank  lines  of  credit,
aggregating  $156 million,  all of which were unused and available at such date.
These lines 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 Company also has bank credit agreements  totaling $700 million,  expiring at
various dates between 2002 and 2003, that support the Company's commercial paper
programs.  At December 31, 2001, all of the bank credit  agreements were unused;
however, due to commercial paper borrowings and other commitments,  $126 million
of such borrowing capacity was available.

                                       17
The  Company  has money  pool  agreements  with and among  its  subsidiaries  to
coordinate  and  provide  for  certain   short-term  cash  and  working  capital
requirements.   Separate  money  pools  are  maintained  between  regulated  and
nonregulated  businesses.  Interest is  calculated  at varying rates of interest
depending on the  composition of internal and external funds in the money pools.
This debt and the related interest represent  intercompany  balances,  which are
eliminated at the Ameren Corporation consolidated level.
NOTE 7 - Long-Term Debt
--------------------------------------------------------------------------------
Long-term debt outstanding at December 31,                    2001      2000
--------------------------------------------------------------------------------
In Millions
--------------------------------------------------------------------------------
First Mortgage Bonds - note (a)
--------------------------------------------------------------------------------
8.33%  Series due 2002                                       $75       $75
  6 3/8% Series Z due 2003                                      40        40
  7.65%  Series due 2003                                       100       100
  6 7/8% Series due 2004                                       188       188
  7 3/8% Series due 2004                                        85        85
  7 1/2% Series X due 2007                                      50        50
  6 3/4% Series due 2008                                       148       148
  6.625% Series due 2011                                       150         -
  7.61% 1997 Series due 2017                                    40        40
  8 3/4% Series due 2021                                       125       125
  8 1/4% Series due 2022                                       104       104
  8%       Series due 2022                                      85        85
  7.15%  Series due 2023                                        75        75
  7%       Series due 2024                                     100       100
  6.125% Series due 2028                                        60        60
  5.45%  Series due 2028 - note (b)                             44        44
  Other  5.375%-7.05% due 2002 through 2008                     93       123
--------------------------------------------------------------------------------
                                                             1,562     1,442
--------------------------------------------------------------------------------
Environmental Improvement/Pollution Control Revenue Bonds
--------------------------------------------------------------------------------
  1991 Series due 2020 - note (c)                               43        43
  1992 Series due 2022 - note (c)                               47        47
  1993 Series A 6 3/8% due 2028                                 35        35
  1993 Series C-1 5.95% due 2026 (h)                            35        35
  1998 Series A due 2033 - note (c)                             60        60
  1998 Series B due 2033 - note (c)                             50        50
  1998 Series C due 2033 - note (c)                             50        50
  2000 Series A 5.5% due 2014 (h)                               51        51
  2000 Series A due 2035 - note (c)                             64        64
  2000 Series B due 2035 - note (c)                             63        63
  2000 Series C due 2035 - note (c)                             60        60
  Other  5%-5.90% due 2026 through 2028                         60        60
--------------------------------------------------------------------------------
                                                               618       618
--------------------------------------------------------------------------------
Subordinated Deferrable Interest Debentures
--------------------------------------------------------------------------------
  7.69% Series A due 2036 - note (d)                            66        66
--------------------------------------------------------------------------------
Unsecured Loans
--------------------------------------------------------------------------------
  Commercial Paper                                              -         19
  1991 Senior Medium Term Notes 8.60% due through 2005          27        33
  1994 Senior Medium Term Notes 6.61% due through 2005          31        39
  2000 Senior Notes 7.61% due 2004                              40        40
  2000 Senior Notes Series C 7 3/4% due 2005 - note (e)        225       225
  2000 Senior Notes Series D 8.35% due 2010 - note (f)         200       200
  2001 Floating Rate Notes due 2003 - note (g)                 150        -
--------------------------------------------------------------------------------
                                                               673       556
--------------------------------------------------------------------------------
Nuclear Fuel Lease                                              63       114
--------------------------------------------------------------------------------
Unamortized Discount and Premium on Debt                        (8)       (7)
--------------------------------------------------------------------------------
Maturities Due Within One Year                                (139)      (44)
--------------------------------------------------------------------------------
Total Long-Term Debt                                        $2,835    $2,745
--------------------------------------------------------------------------------

                                       18
(a)  At December 31,  2001,  a majority of the property and plant was  mortgaged
     under, and subject to liens of, the respective indentures pursuant to which
     the bonds were issued.
(b)  Environmental Improvement Series
(c)  Interest  rates,  and the  periods  during  which  such rates  apply,  vary
     depending on the  Company's  selection of certain  defined rate modes.  The
     average interest rates for the year 2001 are as follows: 1991 Series 3.15%
                  1992 Series               3.11%
                  1998 Series A             3.07%
                  1998 Series B             3.07%
                  1998 Series C             3.04%
                  2000 Series A             2.99%
                  2000 Series B             2.97%
                  2000 Series C             3.03%
(d)  During  the  terms  of the  debentures,  the  Company  may,  under  certain
     circumstances,  defer the  payment of interest  for up to five  years.
(e)  Interest is payable semiannually in arrears on May 1 and November 1 of each
     year,  commencing  May 1, 2001.  Principal  will be payable on  November 1,
     2005.
(f)  Interest is payable semiannually in arrears on May 1 and November 1 of each
     year,  commencing  May 1, 2001.  Principal  will be payable on  November 1,
     2010.
(g)  Interest is payable  quarterly  commencing  March 12,  2002.  Principal  is
     payable on December 12, 2003.  The per annum interest rate on the notes for
     each  interest  period  will be a floating  rate equal to three month LIBOR
     plus a spread of 0.95%.
(h)  Variable rate tax-exempt  pollution  control  indebtedness was converted to
     long-term fixed rates.
Maturities of long-term debt through 2006 are as follows:
----------------------------------------------------------
(In Millions)                             Principal Amount
----------------------------------------------------------
                                2002            $139
                                2003             340
                                2004             344
                                2005             259
                                2006              20
----------------------------------------------------------
In January 2002,  Ameren  Corporation  issued 5.70% Notes totaling $100 million.
Interest  is  payable  semi-annually  on  February  1 and August 1 of each year,
beginning August 1, 2002, and on the date of maturity,  February 1, 2007. Ameren
Corporation  received  net  proceeds  of $99.1  million  after a discount to the
public and deduction of  underwriters'  commissions.  With the proceeds,  Ameren
Corporation reduced its short-term borrowings.

The Company anticipates  securing additional financing in 2002. In January 2002,
Ameren Corporation filed a shelf registration statement with the SEC on Form S-3
which,  upon its  effective  date,  will allow the offering from time to time of
various forms of debt and equity  securities,  up to an aggregate offering price
of $1 billion.  The  proceeds  from any sale of such  securities  may be used to
finance  the  Company's   subsidiaries'  ongoing  construction  and  maintenance
programs,  to  redeem,  repurchase,  repay or retire  outstanding  indebtedness,
including  indebtedness  of the  Company's  subsidiaries,  to finance  strategic
investments in or future  acquisitions of other entities or other assets and for
other  general  corporate  purposes.  At this  time,  the  Company  is unable to
determine  the amount of the  additional  financing,  as well as the  additional
financing's impact on the Company's financial position, results of operations or
liquidity.

NOTE 8 - Income Taxes
Total income tax expense for 2001 resulted in an effective tax rate of 39% on
earnings before income taxes (39% in 2000 and 1999).

Principal reasons such rates differ from the statutory federal rate:
--------------------------------------------------------------------------------
                                                 2001       2000      1999
--------------------------------------------------------------------------------
Statutory federal income tax rate:                 35%       35%       35%
Increases (Decreases) from:
  Depreciation differences                          2         2         1
  State tax                                         3         3         4
  Other                                            (1)       (1)       (1)
--------------------------------------------------------------------------------
Effective income tax rate                          39%       39%       39%
--------------------------------------------------------------------------------

                                       19
Income tax expense components:
--------------------------------------------------------------------------------
In Millions                                      2001      2000      1999
--------------------------------------------------------------------------------
Taxes currently payable (principally
  Federal):
Included in operating expenses                  $ 280     $ 307     $ 287
Included in other income--
     Miscellaneous, net                             6        (2)       (3)
--------------------------------------------------------------------------------
                                                  286       305       284
Deferred taxes (principally federal):
Included in operating expenses--
     Depreciation differences                       9        (5)        3
     Other                                         19         7       (23)
Included in other income--
     Other                                         -          -        (2)
--------------------------------------------------------------------------------
                                                   28         2       (22)
Deferred investment tax credits,
  Amortization:
Included in operating expenses                     (8)       (8)       (8)
--------------------------------------------------------------------------------
Total income tax expense                        $ 306     $ 299     $ 254
--------------------------------------------------------------------------------
In accordance with SFAS 109,  "Accounting for Income Taxes," a regulatory asset,
representing the probable recovery from customers of future income taxes,  which
is expected to occur when temporary differences reverse, was recorded along with
a  corresponding   deferred  tax  liability.   Also,  a  regulatory   liability,
recognizing  the lower  expected  revenue  resulting  from reduced  income taxes
associated  with amortizing  accumulated  deferred  investment tax credits,  was
recorded.  Investment  tax credits have been  deferred  and will  continue to be
credited to income over the lives of the related property.

The Company adjusts its deferred tax liabilities for changes enacted in tax laws
or rates.  Recognizing  that regulators will probably reduce future revenues for
deferred tax  liabilities  initially  recorded at rates in excess of the current
statutory  rate,  reductions in the deferred tax liability  were credited to the
regulatory liability.

Temporary differences gave rise to the following deferred tax assets and
deferred tax liabilities at December 31:
--------------------------------------------------------------------------------
In Millions                                                     2001     2000
--------------------------------------------------------------------------------
Accumulated Deferred Income Taxes:
  Depreciation                                                $1,040    $1,043
  Regulatory assets, net                                         434       417
  Capitalized taxes and expenses                                 184       181
  Deferred benefit costs                                         (68)      (73)
  Other                                                           31        22
--------------------------------------------------------------------------------
Total net accumulated deferred income tax liabilities         $1,621    $1,590
--------------------------------------------------------------------------------
NOTE 9 - Retirement Benefits

The Company has defined  benefit  retirement  plans covering  substantially  all
employees  of  AmerenUE,  AmerenCIPS,  and Ameren  Services  Company and certain
employees of Resources Company and its  subsidiaries.  Benefits are based on the
employees' years of service and compensation.  The Company's plans are funded in
compliance with income tax regulations and federal funding requirements.

Pension costs for 2001 and 2000 were $4 million and $3 million, respectively, of
which 16% and 21%, respectively, were charged to construction accounts.

                                       20
Funded Status of Ameren's Pension Plans:
--------------------------------------------------------------------------------
 In Millions                                                    2001     2000
--------------------------------------------------------------------------------
Change in benefit obligation
 Net benefit obligation at beginning of year                  $ 1,362   $1,257
  Service cost                                                     32       30
  Interest cost                                                   100       98
  Plan amendments                                                  -        28
  Actuarial loss                                                   14       38
  Benefits paid                                                   (90)     (89)
--------------------------------------------------------------------------------
Net benefit obligation at end of year                           1,418    1,362
--------------------------------------------------------------------------------
Change in plan assets *
Fair value of plan assets at beginning of year                  1,359    1,427
  Actual return on plan assets                                     45      (20)
  Employer contributions                                            1        1
  Benefits paid                                                   (90)     (89)
--------------------------------------------------------------------------------
Fair value of plan assets at end of year                        1,225    1,359
--------------------------------------------------------------------------------

Funded status - deficiency/(excess)                               193        3
Unrecognized net actuarial gain/(loss)                            (33)     160
Unrecognized prior service cost                                   (77)     (82)
Unrecognized net transition asset                                   5        6
--------------------------------------------------------------------------------
Accrued pension cost at December 31                           $    88   $   87
--------------------------------------------------------------------------------
* Plan assets consist principally of common stocks and fixed income securities.
  Components of Ameren's Net Periodic Pension Benefit Cost:
--------------------------------------------------------------------------------
In Millions                             2001    2000     1999
--------------------------------------------------------------------------------
Service cost                           $  32    $  30    $  33
Interest cost                            100       98       91
Expected return on plan assets          (115)    (110)    (104)
Amortization of:
    Transition asset                      (1)      (1)      (1)
    Prior service cost                     9        7        7
    Actuarial gain                       (21)      (2)     (21)
--------------------------------------------------------------------------------
Net periodic benefit cost              $   4    $    3   $    24
--------------------------------------------------------------------------------
Weighted-average Assumptions for Actuarial Present Value of Projected Benefit
Obligations:
--------------------------------------------------------------------------------
                                        2001    2000
--------------------------------------------------------------------------------
Discount rate at measurement date       7.25%   7.50%
Expected return on plan assets          8.50%   8.50%
Increase in future compensation         4.25%   4.50%
--------------------------------------------------------------------------------
On January 1, 2000, the AmerenUE and the AmerenCIPS postretirement benefit plans
combined to form the Ameren  Plans.  The Ameren  Plans cover  substantially  all
employees  of  AmerenUE,  AmerenCIPS,  and Ameren  Services  Company and certain
employees of Resources Company and its subsidiaries. The AmerenUE and AmerenCIPS
postretirement plans' information for 1999 is presented separately. Following is
the postretirement plan information related to Ameren's plans as of December 31.

Ameren's funding policy is to annually fund the Voluntary  Employee  Beneficiary
Association trusts (VEBA) with the lesser of the net periodic cost or the amount
deductible  for federal income tax purposes.  Postretirement  benefit costs were
$63  million  and  $58  million  for  2001  and  2000,  respectively,  of  which
approximately 18% and 17%,  respectively were charged to construction  accounts.
Ameren's transition  obligation at December 31, 2001 is being amortized over the
next 12 years.

The MoPSC and the ICC allow the  recovery  of  postretirement  benefit  costs in
rates to the extent that such costs are funded.

                                       21
Funded Status of Ameren's Postretirement Benefit Plans:
--------------------------------------------------------------------------------
 In Millions                                                   2001        2000
--------------------------------------------------------------------------------
Change in benefit obligation
Net benefit obligation at beginning of year                 $ 589         $ 492
  Service cost                                                 23            20
  Interest cost                                                47            43
  Plan amendments                                              -            (26)
  Actuarial loss                                               80            94
  Benefits paid                                               (38)          (34)
--------------------------------------------------------------------------------
Net benefit obligation at end of year                         701           589
--------------------------------------------------------------------------------

Change in plan assets *
Fair value of plan assets at beginning of year                290           269
  Actual return on plan assets                                (17)           (4)
  Employer contributions                                       65            59
  Benefits paid                                               (38)          (34)
--------------------------------------------------------------------------------
Fair value of plan assets at end of year                      300           290
--------------------------------------------------------------------------------

Funded status - deficiency                                    401           299
Unrecognized net actuarial gain                              (134)          (14)
Unrecognized prior service cost                                 2             2
Unrecognized net transition obligation                       (180)         (196)
--------------------------------------------------------------------------------
Postretirement benefit liability at December 31             $  89         $  91
--------------------------------------------------------------------------------
* Plan assets consist principally of common stocks, bonds and money market
instruments.
Components of Ameren's Net Periodic Postretirement Benefit Cost:
--------------------------------------------------------------------------------
In Millions                                                 2001      2000
--------------------------------------------------------------------------------
Service cost                                                $ 23     $ 19
Interest cost                                                 47       43
Expected return on plan assets                               (25)     (18)
Amortization of:
    Transition obligation                                     16       16
    Actuarial (gain)/loss                                      2       (2)
--------------------------------------------------------------------------------
Net periodic benefit cost                                   $ 63     $ 58
--------------------------------------------------------------------------------

Assumptions for the Obligation Measurements:
--------------------------------------------------------------------------------
                                                            2001     2000
--------------------------------------------------------------------------------
Discount rate at measurement date                           7.25%    7.50%
Expected return on plan assets                              8.50%    8.50%
Medical cost trend rate                                     5.25%    5.00%
--------------------------------------------------------------------------------
A 1% increase in the medical  cost trend rate is  estimated  to increase the net
periodic   cost   and  the   accumulated   postretirement   benefit   obligation
approximately  $7 million and $55  million,  respectively.  A 1% decrease in the
medical cost trend rate is  estimated to decrease the net periodic  cost and the
accumulated  postretirement benefit obligation  approximately $7 million and $51
million, respectively.

AmerenUE's  plans  cover  substantially  all  employees  of  AmerenUE as well as
certain employees of Ameren Services Company.  Postretirement benefit costs were
$46 million for 1999,  of which  approximately  18% was charged to  construction
accounts.

                                       22
Components of AmerenUE's Net Periodic Postretirement Benefit Cost:
--------------------------------------------------------------------------------
In Millions                                      1999
--------------------------------------------------------------------------------
Service cost                                     $15
Interest cost                                     25
Expected return on plan assets                    (6)
Amortization of transition obligation             12
--------------------------------------------------------------------------------
Net periodic benefit cost                        $46
--------------------------------------------------------------------------------

AmerenCIPS'  plans cover  substantially  all  employees of AmerenCIPS as well as
certain employees of Ameren Services Company.  Postretirement benefit costs were
$3 million for 1999,  of which  approximately  10% was  charged to  construction
accounts.

Components of AmerenCIPS' Net Periodic Postretirement Benefit Cost:
--------------------------------------------------------------------------------
In Millions                                      1999
--------------------------------------------------------------------------------
Service cost                                      $3
Interest cost                                      9
Expected return on plan assets                    (9)
Amortization of:
    Transition obligation                          6
    Actuarial gain                                (6)
--------------------------------------------------------------------------------
Net periodic benefit cost                         $3
--------------------------------------------------------------------------------

NOTE 10 - Stock-Based Compensation

The Company has a long-term  incentive  plan (the Plan) for eligible  employees,
which provides for the grant of options,  performance awards,  restricted stock,
dividend  equivalents and stock appreciation  rights. The Company applies APB 25
in  accounting  for its  stock-based  compensation.  The Company has adopted the
disclosure-only  method of fair  value  data  under  SFAS 123,  "Accounting  for
Stock-Based Compensation."

Under the Plan, 141,788 restricted shares of the Company's stock were granted at
$39.60 in 2001. Upon the achievement of certain Company  performance levels, the
restricted stock award vests over a period of seven years, beginning at the date
of grant, and include  provisions  requiring  certain stock ownership levels. An
accelerated  vesting  provision is also included in the Plan,  which reduces the
vesting  period from seven years to three years.  The Company  records  unearned
compensation (as a component of stockholders'  equity) equal to the market value
of the  restricted  stock  on  the  date  of  grant  and  charges  the  unearned
compensation to expense over the vesting  period.  In accordance with APB 25 and
under SFAS 123, the Company's  compensation expense relating to restricted stock
awards totaled $903,000 in 2001.

Also  under the terms of the Plan,  options  may be  granted at a price not less
than the fair market  value of the common  shares at the date of grant.  Granted
options vest over a period of five years,  beginning  at the date of grant,  and
provide for acceleration of exercisability of the options upon the occurrence of
certain  events,  including  retirement.  Outstanding  options expire on various
dates  through  2010.  Under the Plan,  subject to adjustment as provided in the
Plan,  four million shares have been  authorized to be issued or delivered under
the Company's Plan. In accordance with APB 25, no compensation  expense has been
recognized for the Company's  stock options.  If the fair value method set forth
under SFAS 123 had been used to account for  options,  the effects on net income
and earnings would have been immaterial.

                                       23
The following table summarizes stock option activity during 2001, 2000 and 1999:
---------------------------------------------------------------------------------------------------------------------
                                                   2001                     2000                        1999
---------------------------------------------------------------------------------------------------------------------
                                                     Weighted                  Weighted                   Weighted
                                                      Average                   Average                    Average
                                                     Exercise                  Exercise                   Exercise
                                         Shares        Price        Shares       Price         Shares       Price
---------------------------------------------------------------------------------------------------------------------
Outstanding at beginning of year         2,430,532     $35.38      1,834,108     $38.22       1,095,180     $39.41
---------------------------------------------------------------------------------------------------------------------
Granted                                       -           -          957,100      31.00         768,100      36.63
Exercised                                  106,416      38.31        295,693      38.41          11,162      37.20
Cancelled or expired                        83,009      35.77         64,983      37.38          18,010      42.45
---------------------------------------------------------------------------------------------------------------------
Outstanding at end of year               2,241,107     $35.23      2,430,532     $35.38       1,834,108     $38.22
---------------------------------------------------------------------------------------------------------------------
Exercisable at end of year                 572,092     $38.74        312,736     $39.58         391,456     $39.06
---------------------------------------------------------------------------------------------------------------------
Additional information about stock options outstanding at December 31, 2001:
--------------------------------------------------------------------------------
  Exercise      Outstanding       Weighted      Exercisable
    Price          Shares       Average Life      Shares
                                  (Years)
--------------------------------------------------------------------------------
$31.00               908,500        8.1          8,000
 35.50                   800        3.6            800
 35.875               35,880        3.3         35,880
 36.625              633,050        7.0        148,550
 38.50               102,985        5.1         71,170
 39.25               464,616        6.2        215,066
 39.8125               5,300        6.5          2,650
 43.00                89,976        3.8         89,976
--------------------------------------------------------------------------------

The fair values of stock options were estimated using a binomial option-pricing
model with the following assumptions:

--------------------------------------------------------------------------------
 Grant Date      Risk-free        Option Term        Expected        Expected
               Interest Rate                        Volatility    Dividend Yield
--------------------------------------------------------------------------------
  2/11/00        6.81%           10 years            17.39%           6.61%

  2/12/99        5.44%           10 years            18.80%           6.51%

  6/16/98        5.63%           10 years            17.68%           6.55%

  4/28/98        6.01%           10 years            17.63%           6.55%

  2/10/97        5.70%           10 years            13.17%           6.53%

  2/7/96         5.87%           10 years            13.67%           6.32%
--------------------------------------------------------------------------------

NOTE 11 - Commitments and Contingencies

The  Company  is  engaged  in a capital  program  under  which  expenditures  of
apprxomately  $3.5  billion,   including  AFC  and  capitalized  interest,   are
anticipated   over  the  next  five  years.   This  estimate   includes  capital
expenditures for the purchase of new combustion  turbine  generating  facilities
and for the replacement of four steam  generators at its Callaway Nuclear Plant.
In addition,  this estimate  includes  capital  expenditures  for  transmission,
distribution and other generation related activities,  as well as for compliance
with new NOx control regulations,  as discussed later in this Note.  Commitments
have been made with regard to certain of these capital expenditures.

The Company has committed to purchase  combustion  turbine generator  equipment,
which  will add nearly  1,400  megawatts  to its net  peaking  capacity  and are
expected  to cost  approximately  $630  million.  The  Company  plans to add 710
megawatts (approximately 470 megawatts at Resources Company and 240 megawatts at
AmerenUE) of combustion  turbine  generating  capacity during 2002.  Total costs
expected  to  be  incurred  for  these  combustion   turbine   generating  units
approximate  $340 million.  Due to expected  increased  demand,  and the need to

                                       24
maintain  appropriate  reserve  margins,  the  Company  believes  it  will  need
additional  regulated  generating  capacity  in the  future.  In 2002,  AmerenUE
expects to purchase up to 500  megawatts of capacity for the summer.  Additional
future resource options under  consideration by the Company include the transfer
of  AmerenUE's  Illinois-based  electric and gas business to  AmerenCIPS.  Other
alternatives  include  the  addition  of 650  megawatts  of  combustion  turbine
generating  units.  These units are  estimated to cost $280 million and would be
added subsequent to 2004. As of December 31, 2001, the Company had noncancelable
reservation  commitments  of $22 million  related to the  potential  purchase of
these  units.  The Company  continually  reviews  its  genertion  portfolio  and
expected electrical neeeds, and as result,  could modify its plan for generation
asset  purchases,  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, the type of generation asset technology
that will be employed, or whether capacity may be purchased, among other things.
Changes to the  Company's  plans for future  generating  needs  could  result in
losses being incurred by the Company, which could be material.

The Company has commitments for the purchase of coal under long-term  contracts.
Coal contract commitments, including transportation costs, for 2002 through 2006
are  estimated  to  total  $2.0  billion.   Total  coal   purchases,   including
transportation  costs, for 2001, 2000 and 1999 were $562 million,  $507 million,
and $603 million,  respectively.  The Company also has existing  contracts  with
pipeline and natural gas  suppliers to provide,  transport and store natural gas
for distribution and electric generation.  Gas-related contract cost commitments
for 2002  through  2006 are  estimated to total $253  million.  Total  delivered
natural gas costs were $222 million for 2001,  $209  million for 2000,  and $131
million for 1999. The Company's  nuclear fuel commitments for 2002 through 2006,
including  uranium  concentrates,  conversion,  enrichment and fabrication,  are
expected to total $76  million,  and are expected to be  substantially  financed
under the nuclear  fuel lease.  Nuclear fuel  expenditures  were $24 million for
2001,  and $22  million  in each of the years 2000 and 1999.  Additionally,  the
Company has  long-term  contracts  with other  utilities  to  purchase  electric
capacity.  These  commitments  for 2002 through 2006 are estimated to total $301
million.  During  2001,  2000 and 1999,  electric  capacity  purchases  were $31
million, $40 million, and $44 million, respectively.

In  1999,  AmerenCIPS  and two of its  coal  suppliers  executed  agreements  to
terminate  their existing coal supply  contracts,  effective  December 31, 1999.
Under  these  agreements,  AmerenCIPS  has  made  termination  payments  to  the
suppliers totaling  approximately $52 million.  These termination  payments were
recorded as an unusual charge in the fourth  quarter of 1999,  equivalent to $31
million, after income taxes, or 23 cents per share.

The Company's insurance coverage for Callaway Nuclear Plant at December 31,
2001, was as follows:

Type and Source of Coverage
--------------------------------------------------------------------------------
(In Millions)                                  Maximum              Maximum
                                             Coverages           Assessments
                                                                 For Single
                                                                  Incidents
--------------------------------------------------------------------------------
Public Liability:
     American Nuclear Insurers                   $ 200              $  -
     Pool Participation                          9,338                88  (a)
--------------------------------------------------------------------------------
                                                $9,538  (b)         $ 88
--------------------------------------------------------------------------------
Nuclear Worker Liability:
     American Nuclear Insurers                   $ 200  (c)         $  3
--------------------------------------------------------------------------------
Property Damage:
     Nuclear Electric Insurance Ltd.            $2,750  (d)         $ 23
--------------------------------------------------------------------------------
Replacement Power:
     Nuclear Electric Insurance Ltd.             $ 490  (e)         $  5
--------------------------------------------------------------------------------
(a)  Retrospective premium under the Price-Anderson  liability provisions of the
     Atomic  Energy  Act of 1954,  as  amended  (Price-  Anderson).  Subject  to
     retrospective  assessment with respect to loss from an incident at any U.S.
     reactor, payable at $10 million per year. Price-Anderson expires in 2002.
(b)  Limit of liability for each incident under Price-Anderson.
(c)  Industry limit for potential  liability from workers  claiming  exposure to
     the hazard of nuclear radiation.
(d)  Includes premature decommissioning costs.
(e)  Weekly  indemnity of $3.5 million,  for 52 weeks which  commences after the
     first 12 weeks of an  outage,  plus  $2.8  million  per week for 110  weeks
     thereafter.
--------------------------------------------------------------------------------

                                       25
Price-Anderson  limits the liability  for claims from an incident  involving any
licensed  U.S.  nuclear  facility.  The limit is based on the number of licensed
reactors and is adjusted at least every five years based on the  Consumer  Price
Index.  Utilities  owning a  nuclear  reactor  cover  this  exposure  through  a
combination  of private  insurance  and mandatory  participation  in a financial
protection pool, as established by Price-Anderson.

If losses from a nuclear  incident at Callaway  exceed the limits of, or are not
subject  to,  insurance,  or if  coverage is not  available,  the  Company  will
self-insure the risk. Although the Company has no reason to anticipate a serious
nuclear   incident,   if  one  did  occur,   it  could  have  a  material,   but
indeterminable,  adverse effect on the Company's financial position,  results of
operations or liquidity.

The State of Illinois has developed a NOx control regulation for utility boilers
in the State  consistent with a United States  Environmental  Protection  Agency
(EPA) program aimed at reducing ozone levels in the Eastern United States.  As a
result  of  these  state  requirements,  Generating  Company  anticipates  a 75%
reduction  from current  levels of NOx emissions from its power plant boilers in
Illinois by the year 2004.  Generating Company estimates spending  approximately
$210  million for capital  expenditures  to comply  with these  rules,  of which
approximately  $50 million  was spent in 2001.  On February  13,  2002,  the EPA
proposed  similar rules for Missouri which require an approximate  64% reduction
from current  levels of NOx emissions.  AmerenUE  estimates  approximately  $140
million  will be required to be spent to comply with these rules for NOx control
on the AmerenUE  generating  system by 2005. The Company is still evaluating the
impact of the EPA's  regulations  as applied to its Missouri  operations and may
challenge  certain  aspects of those rules.  In summary,  the Company  currently
estimates that its capital expenditures to comply with the final NOx regulations
could  range from $300  million to $350  million.  This  estimate  includes  the
assumption  that the  regulations  will  require the  installation  of Selective
Catalytic  Reduction (SCR) technology on some of the Company's units, as well as
additional controls.

Under both Illinois and Missouri  regulatory  programs,  Generating  Company and
AmerenUE  have  applied for Early  Reduction  NOx credits  which would allow the
companies  to manage  compliance  strategies  by either  purchasing  NOx control
equipment or utilizing credits.  Generating Company and AmerenUE may be eligible
for  such  credits  due to the  current  low NOx  emission  rates of some of the
Companies' boilers under current state regulations.

In July 1997,  the EPA issued  regulations  revising  the  National  Ambient Air
Quality  Standards  for  ozone  and  particulate   matter.  The  standards  were
challenged by industry and some states,  and arguments were eventually  heard by
the U. S. Supreme  Court.  On February 27,  2001,  the Supreme  Court upheld the
standards  in large part,  but remanded a number of  significant  implementation
issues back to the EPA for  resolution.  The EPA is  currently  working on a new
rulemaking  to address  the issues  raised by the  Supreme  Court.  New  ambient
standards may require significant additional reductions in SO2 and NOx emissions
from the Company's  power plants by 2008. At this time, the Company is unable to
predict the ultimate impact of these revised air quality standards on its future
financial condition, results of operations or liquidity.

In December 1999, the EPA issued a decision to regulate mercury  emissions from
coal-fired power plants by 2008. The EPA is scheduled to propose  regulations by
2004.  These  regulations  have the potential to add significant  capital and/or
operating costs to the Ameren  generating  systems after 2005. On July 20, 2001,
the EPA issued proposed Best Available Retrofit  Technology (BART) guidelines to
address  visibility  impairment  (so called  "Regional  Haze") across the United
States from sources of air pollution,  including  coal-fired  power plants.  The
guidelines are to be used by States to mandate  pollution  control  measures for
SO2 and NOx emissions.  These rules could also add significant pollution control
costs to the Ameren generating systems between 2008 and 2012.

In addition,  the United  States  Congress has been  working on  legislation  to
consolidate the numerous air pollution  regulations facing the utility industry.
This "multi-pollutant"  legislation is expected to be deliberated in Congress in
2002.  While the cost to comply  with such  legislation,  if  enacted,  could be
significant,  it is  anticipated  that the costs would be less than the combined
impact of the new National Ambient Air Quality  Standards,  mercury and Regional
Haze   regulations,   discussed  above.   Pollution  control  costs  under  such
legislation  are  expected to be incurred in phases from 2007 through  2015.  At
this time,  the  Company is unable to predict the  ultimate  impact of the above
expected  regulations and this  legislation on its future  financial  condition,
results of operations, or liquidity; however, the impact could be material.

                                       26
The Company is involved in a number of remediation actions to clean up hazardous
waste sites as required by federal and state law.  Such  statutes  require  that
responsible  parties fund remediation  actions regardless of fault,  legality of
original disposal, or ownership of a disposal site. AmerenUE and AmerenCIPS have
been identified by the federal or state governments as a potentially responsible
party (PRP) at several contaminated sites.

The Company  owns or is otherwise  responsible  for 14 former  manufactured  gas
plant (MGP) sites in Illinois.  The ICC permits the recovery of remediation  and
litigation  costs  associated  with certain former MGP sites located in Illinois
from the Company's  Illinois  electric and natural gas utility customers through
environmental adjustment clause rate riders. To be recoverable,  such costs must
be  prudently  and properly  incurred  and are subject to annual  reconciliation
review by the ICC. Through  December 31, 2001, the total costs deferred,  net of
recoveries  from  insurers  and  through  environmental  adjustment  clause rate
riders, was $26 million.

In addition,  the Company owns or is otherwise  responsible  for 10 MGP sites in
Missouri and 1 in Iowa. Unlike Illinois,  the Company does not have in effect in
Missouri a rate rider mechanism which permits  remediation costs associated with
MGP sites to be recovered from utility customers,  and the Company has no retail
utility operations in Iowa.

In June 2000, the EPA notified AmerenUE and numerous other companies that former
landfills  and lagoons in Sauget,  Illinois,  may contain  soil and  groundwater
contamination.  These  sites are known as Sauget  Area 1 and Sauget Area 2. From
approximately  1926 until 1976,  AmerenUE  operated a power generating  facility
adjacent to Sauget Area 2 and currently owns and operates electric  transmission
and distribution facilities in or near Sauget Area 1.

In September 2000, the United States  Department of Justice was granted leave by
the United States District Court - Southern District of Illinois to add numerous
additional  parties,  including  AmerenUE,  to a preexisting lawsuit between the
government and others. The government seeks recovery of response costs under the
Comprehensive   Environmental   Response  Compensation  Liability  Act  of  1980
(commonly  known as  CERCLA  or  Superfund),  incurred  in  connection  with the
remediation of Sauget Area 1. The Company  believes that the final resolution of
this  lawsuit  and the  remediation  of Sauget  Area 1 will not have a  material
adverse effect on its financial position, results of operations or liquidity.

With  respect to Sauget Area 2,  AmerenUE has joined with other PRPs to evaluate
the extent of potential  contamination.  At this time,  the Company is unable to
predict the ultimate impact of the Sauget Area 2 site on its financial position,
results of operations or liquidity.

On September 13, 2001, the EPA proposed in the Federal Register that Sauget Area
1 and  Sauget  Area 2 be listed  on the  National  Priorities  List  (NPL).  The
inclusion of a site on the NPL allows the EPA to access  Superfund  trust monies
to fund site remediations.

In addition,  the Company's  operations,  or that of its predecessor  companies,
involve the use,  disposal  and, in  appropriate  circumstances,  the cleanup of
substances regulated under environmental  protection laws. The Company is unable
to  determine  the impact  these  actions  may have on the  Company's  financial
position, results of operations or liquidity.

Certain   employees  of  the  Company  are  represented  by  the   International
Brotherhood  of  Electrical  Workers and the  International  Union of  Operating
Engineers.   These  employees  comprise   approximately  66%  of  the  Company's
workforce. Contracts with collective bargaining units representing approximately
30% of  these  employees  will  expire  in 2002.  In  addition,  contracts  with
collective  bargaining units  representing  approximately 70% of these employees
will expire in 2003.

Regulatory  changes enacted and being considered at the federal and state levels
continue to change the structure of the utility industry and utility regulation,
as well as encourage increased competition.  At this time, the Company is unable
to  predict  the  impact of these  changes  on the  Company's  future  financial
condition,  results of operations or liquidity.  See Note 2 - Regulatory Matters
for further information.

The Company is involved in other  legal and  administrative  proceedings  before
various  courts and  agencies  with  respect to matters  arising in the ordinary
course of  business,  some of which  involve  substantial  amounts.  The Company
believes  that  the  final  disposition  of  these  proceedings  will not have a
material  adverse  effect on its  financial  position,  results of operations or
liquidity.

                                       27
NOTE 12 - Callaway Nuclear Plant

Under the Nuclear  Waste Policy Act of 1982,  the  Department of Energy (DOE) is
responsible  for the permanent  storage and disposal of spent nuclear fuel.  The
DOE  currently  charges  one mill per  nuclear-generated  kilowatthour  sold for
future  disposal of spent fuel.  Electric  utility  rates  charged to  customers
provide  for  recovery  of such  costs.  The  DOE is not  expected  to have  its
permanent  storage  facility for spent fuel  available  until at least 2015. The
Company has sufficient storage capacity at the Callaway Nuclear Plant site until
2020 and has the capability for additional storage capacity through the licensed
life of the plant.  The delayed  availability of the DOE's disposal  facility is
not expected to adversely affect the continued operation of the Callaway Nuclear
Plant.

Electric  utility  rates  charged to customers  provide for recovery of Callaway
Nuclear  Plant  decommissioning  costs over the life of the  plant,  based on an
assumed 40-year life, ending with expiration of the plant's operating license in
2024.  The  Callaway  site is  assumed  to be  decommissioned  using  the  DECON
(immediate    dismantlement)    method.    Decommissioning    costs,   including
decontamination,  dismantling  and site  restoration,  are  estimated to be $585
million in current year dollars and are  expected to escalate  approximately  4%
per year through the end of  decommissioning  activity in 2033.  Decommissioning
costs are charged to  depreciation  expense  over  Callaway's  service  life and
amounted to  approximately  $7 million in each of the years 2001, 2000 and 1999.
Every three  years,  the MoPSC and ICC require the Company to file  updated cost
studies for decommissioning Callaway, and electric rates may be adjusted at such
times to reflect changed estimates. The latest studies were filed in 1999. Costs
collected  from customers are deposited in an external trust fund to provide for
Callaway's decommissioning.  Fund earnings are expected to average approximately
9% annually through the date of decommissioning.  If the assumed return on trust
assets is not earned, the Company believes it is probable that any such earnings
deficiency  will be recovered in rates.  Trust fund  earnings,  net of expenses,
appear  on  the   consolidated   balance  sheet  as  increases  in  the  nuclear
decommissioning  trust  fund  and  in  the  accumulated  provision  for  nuclear
decommissioning.

The staff of the SEC has questioned certain accounting practices of the electric
utility industry, regarding the recognition,  measurement, and classification of
decommissioning   costs  for  nuclear  generating   stations  in  the  financial
statements  of electric  utilities.  In response  to these  questions,  the FASB
issued SFAS No. 143, "Accounting for Asset Retirement Obligations" (see Note 1 -
Summary of Significant Accounting Policies).

NOTE 13 - Fair Value of Financial Instruments

The following  methods and  assumptions  were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate that
value:

Cash and Temporary Investments/Short-Term Borrowings
The carrying amounts  approximate fair value because of the short-term  maturity
of these instruments.

Marketable Securities
The fair  value is based on  quoted  market  prices  obtained  from  dealers  or
investment managers.

Nuclear Decommissioning Trust Fund
The fair value is estimated based on quoted market prices for securities.

Preferred Stock of Subsidiaries
The fair value is estimated  based on the quoted  market  prices for the same or
similar issues.

Long-Term Debt
The fair  value is  estimated  based on the  quoted  market  prices  for same or
similar  issues or on the  current  rates  offered  to the  Company  for debt of
comparable maturities.

Derivative Financial Instruments
Market prices used to determine fair value are based on management's  estimates,
which  take  into   consideration   factors   like  closing   exchange   prices,
over-the-counter prices, and time value of money and volatility factors.

                                       28
Carrying amounts and estimated fair values of the Company's financial
instruments at December 31:
2001              2000
--------------------------------------------------------------------------------
In Millions                                 Carrying    Fair   Carrying   Fair
                                             Amount    Value    Amount    Value
--------------------------------------------------------------------------------
Long-term debt (including current portion)   $2,974   $3,052   $2,789   $2,841
Preferred stock                                 235      207      235      186
--------------------------------------------------------------------------------
The Company has investments in debt and equity securities that are held in trust
funds for the  purpose of funding the nuclear  decommissioning  of its  Callaway
Nuclear Plant (see Note 12 - Callaway Nuclear Plant). The Company has classified
these  investments  in debt and equity  securities as available for sale and has
recorded  all such  investments  at their fair market value at December 31, 2001
and 2000. In 2001, 2000 and 1999, the proceeds from the sale of investments were
$230 million,  $61 million,  and $83 million,  respectively.  Using the specific
identification method to determine cost, the gross realized gains on those sales
were approximately $4 million for 2001, $1 million for 2000, and $11 million for
1999.  Net  realized  and  unrealized  gains and  losses  are  reflected  in the
accumulated  provision for nuclear  decommissioning on the consolidated  balance
sheet,  which is  consistent  with the method used by the Company to account for
the decommissioning costs recovered in rates.

Costs and fair values of investments in debt and equity securities in the
nuclear decommissioning trust fund at December 31 were as follows:
--------------------------------------------------------------------------------
2001 (In Millions)                       Gross Unrealized
Security Type              Cost         Gain         (Loss)    Fair Value
--------------------------------------------------------------------------------
Debt Securities            $57           $2          $ -        $59
Equity Securities           78           44            -        122
Cash Equivalents             6            -            -          6
--------------------------------------------------------------------------------
                          $141          $46          $ -       $187
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
2000 (In Millions)                       Gross Unrealized
Security Type               Cost        Gain         (Loss)    Fair Value
--------------------------------------------------------------------------------
Debt Securities           $71            $3          $ -        $74
Equity Securities          52            61            -        113
Cash Equivalents            4             -            -          4
--------------------------------------------------------------------------------
                         $127           $64          $ -       $191
--------------------------------------------------------------------------------
The contractual maturities of investments in debt securities at December 31,
2001 were as follows:
--------------------------------------------------------------------------------
(In Millions)                           Cost       Fair Value
--------------------------------------------------------------------------------
Less than 5 years                       $20          $21
5 years to 10 years                      22           23
Due after 10 years                       15           15
--------------------------------------------------------------------------------
                                        $57          $59
--------------------------------------------------------------------------------

                                       29
NOTE 14 - Segment Information

Ameren's  principal  business  segment is  comprised  of the  utility  operating
companies  that  provide  electric  and gas service in portions of Missouri  and
Illinois. The other reportable segment includes the nonutility subsidiaries,  as
well as the Company's 60% interest in Electric Energy, Inc.

The accounting  policies of the segments are the same as those described in Note
1  -  Summary  of  Significant   Accounting  Policies.   Segment  data  includes
intersegment  revenues,  as well as a charge  allocating costs of administrative
support services to each of the operating companies. These costs are accumulated
in a separate subsidiary,  Ameren Services Company,  which provides a variety of
support  services  to Ameren and its  subsidiaries.  The Company  evaluates  the
performance of its segments and allocates  resources to them, based on revenues,
operating income and net income.

The table below presents information about the reported revenues, net income,
and total assets of Ameren for the years ended December 31:
--------------------------------------------------------------------------------
                           Utility                      Reconciling
(In Millions)             Operations       Other          Items         Total
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
2001
--------------------------------------------------------------------------------
Revenues                     $5,063         $248         $(805)*        $4,506
Net income                      467            2            -              469
Total assets                 11,171          240        (1,010)         10,401
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
2000
--------------------------------------------------------------------------------
Revenues                     $4,120         $294         $(557)*        $3,857
Net income                      457           -             -              457
Total assets                 10,777          287        (1,350)          9,714
--------------------------------------------------------------------------------

-----------------------------------------------------------------------------
1999
--------------------------------------------------------------------------------
Revenues                     $3,467         $243         $(174)*        $3,536
Net income                      384            1            -              385
Total assets                  8,825          435           (82)          9,178
--------------------------------------------------------------------------------
* Elimination of intercompany revenues.

Specified items included in segment profit/loss for the years ended December 31:
--------------------------------------------------------------------------------
                                   Utility               Reconciling
(In Millions)                     Operations    Other       Items       Total
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
2001
--------------------------------------------------------------------------------
Interest expense                     $231       $11       $(43)*        $199
Depreciation and amortization
    expense                           382        12         12           406
Income tax expense                    289         7          4           300
--------------------------------------------------------------------------------

--------------------------------------------------------------------------------
2000
--------------------------------------------------------------------------------
Interest expense                     $205       $12       $(37)*        $180
Depreciation and amortization
    expense                           360        13         10           383
Income tax expense                    297         4         -            301
-------------------------------------------------------------------------------

--------------------------------------------------------------------------------
1999
--------------------------------------------------------------------------------
Interest expense                     $163        $9       $(4)*        $168
Depreciation and amortization
    expense                           349        12         2           363
Income tax expense                    261        (2)        -           259
--------------------------------------------------------------------------------
*Elimination of intercompany interest charges

                                       30
Specified item related to segment assets as of December 31:
--------------------------------------------------------------------------------
                                   Utility               Reconciling
(In Millions)                     Operations    Other       Items       Total
--------------------------------------------------------------------------------
2001
--------------------------------------------------------------------------------
 Expenditures for additions
   to long-lived assets            $1,059       $10       $34         $1,103
--------------------------------------------------------------------------------
2000
--------------------------------------------------------------------------------
  Expenditures for additions
   to long-lived assets              $872       $45       $12           $929
--------------------------------------------------------------------------------
1999
--------------------------------------------------------------------------------
  Expenditures for addition
   to long-lived asset               $342      $179       $50           $571
---------------------------------------------------------------------------------
SELECTED QUARTERLY INFORMATION  (Unaudited)
--------------------------------------------------------------------------------
(Thousands of Dollars, Except Per Share Amounts)
--------------------------------------------------------------------------------
                           Operating     Operating     Net       Earnings Per
                            Revenues        Income    Income     Common Share
Quarter Ended:                                        (Loss)
-------------------------------------------------------------------------------
March 31, 2001       (a)   $1,024,528   $  116,086   $   58,492   $    .43
March 31, 2000       (a)      825,376      108,578       61,393        .45

June 30, 2001        (b)    1,057,016      145,203       94,630        .69
June 30, 2000        (b)      940,708      159,206      113,585        .83

September 30, 2001          1,431,613      310,422      266,576       1.94
September 30, 2000   (c)    1,195,723      305,685      256,137       1.87

December 31, 2001             992,710       93,276       48,847        .35
December 31, 2000    (d)      895,023       66,841       25,979        .19
(a)  The first  quarter of 2001 and 2000 included  credits to Missouri  electric
     customers that reduced net income  approximately $9 million, or 6 cents per
     share and $6 million, or 4 cents per share, respectively. The first quarter
     of  2001  also  included  an  unusual  charge  for  the  adoption  of a new
     accounting  standard  related to  derivatives  that  reduced  net income $7
     million, or 5 cents per share.
(b)  The second  quarter of 2001  included a reduction  to  previously  recorded
     credits  to  Missouri   electric   customers   that  increased  net  income
     approximately  $15 million,  or 10 cents per share.  The second  quarter of
     2000  included  credits to Missouri  electric  customers  that  reduced net
     income approximately $3 million, or 2 cents per share.
(c)  The third quarter of 2000 included credits to Missouri  electric  customers
     that reduced net income  approximately  $11 million,  or 8 cents per share.
(d)  The fourth quarter of 2000 included credits to Missouri electric  customers
     that reduced net income  approximately $17 million,  or 12 cents per share.
     The fourth  quarter of 2000 also included an unusual  charge related to the
     withdrawal from the Midwest ISO that reduced net income $15 million,  or 11
     cents  per  share.  (See  Note  2  -  Regulatory  Matters  under  Notes  to
     Consolidated Financial Statements for further information).

Other  changes on  quarterly  earnings are due to the effect of weather on sales
and other factors that are characteristic of public utility operations.

                                       31
EXHIBIT 99.2

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

OVERVIEW

Ameren Corporation (Ameren or the Company) is a holding company registered under
the Public Utility Holding Company Act of 1935 (PUHCA).  In December 1997, Union
Electric Company  (AmerenUE) and CIPSCO  Incorporated  (CIPSCO) combined to form
Ameren, with AmerenUE and CIPSCO's subsidiaries, Central Illinois Public Service
Company (AmerenCIPS) and CIPSCO Investment Company (CIC),  becoming subsidiaries
of Ameren (the  Merger).  As a result of the Merger,  Ameren has a 60% ownership
interest in Electric  Energy,  Inc. (EEI),  which is consolidated  for financial
reporting   purposes.   Since  the  Merger,   Ameren  has  formed   several  new
subsidiaries,  including AmerenEnergy,  Inc. (AmerenEnergy),  Ameren Development
Company, AmerenEnergy Resources Company (Resources Company), and Ameren Services
Company.  AmerenEnergy,  an energy trading and marketing  subsidiary,  primarily
serves as a power  marketing  agent for  AmerenUE  and  AmerenEnergy  Generating
Company (Generating Company), the nonregulated electric generating subsidiary of
Resources Company,  and provides a range of energy and risk management  services
to targeted customers.  Ameren Development Company is a nonregulated  subsidiary
encompassing  various  nonregulated  energy  products  and  services.  Resources
Company holds  Ameren's  nonregulated  generating  operations.  Ameren  Services
Company provides shared support services to Ameren and all of its  subsidiaries.

References  to the Company  are to Ameren on a  consolidated  basis.  In certain
circumstances,   the  subsidiaries  are  separately  referred  to  in  order  to
distinguish among their different business activities.

RESULTS OF OPERATIONS

Earnings
Earnings  for 2001,  2000 and 1999,  were $469  million  ($3.41 per share before
dilution),  $457 million  ($3.33 per share) and $385 million  ($2.81 per share),
respectively.  Earnings  and earnings per share  increased  over the  three-year
period primarily due to: the rate of 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.

In 2001, the Company recorded an after-tax,  unusual charge of $7 million,  or 5
cents per share,  representing  the  impact of the  required  adoption  of a new
accounting  standard related to derivative  financial  instruments (see Note 3 -
Risk Management and Derivative Financial Instruments under Notes to Consolidated
Financial Statements for further  information).  In 2000, the Company recorded a
$25 million  unusual charge to earnings in connection  with its withdrawal  from
the Midwest ISO. The charge reduced  earnings $15 million,  net of income taxes,
or  11  cents  per  share  (see  discussion   below  under  "Electric   Industry
Restructuring"  and Note 2 -  Regulatory  Matters  under  Notes to  Consolidated
Financial Statements for further  information).  In 1999, the Company recorded a
$52 million  nonrecurring  charge to earnings in  connection  with coal contract
terminations  with two coal suppliers.  The charge reduced earnings $31 million,
net of income taxes, or 23 cents per share (see discussion below under "Electric
Operations"  and  Note  11  -  Commitments  and  Contingencies  under  Notes  to
Consolidated Financial Statements for further information).

The  Company  estimates  that  ongoing  earnings  per share for the year  ending
December 31, 2002,  will range between $3.15 and $3.45 per share.  This estimate
incorporates  significant  assumptions,  including  resolution of the regulatory
issues  associated with the Company's  Missouri retail electric  operations (see
discussion  below under "Rate  Matters"  and Note 2 - Regulatory  Matters  under
Notes to  Consolidated  Financial  Statements  for  further  information).  This
estimate assumes a future form of incentive regulation relative to the Company's
Missouri electric  operations,  which could include electric rate reductions and
additional  customer  credits.  This  estimate is also  subject to,  among other
things,  changing energy markets,  and economic and weather  conditions.  Actual
results could differ  materially from the assumptions used in the Company's 2002
earnings per share estimate.
Electric Operations
Electric Revenues                         Variations from Prior Year
--------------------------------------------------------------------------------
In Millions                                2001     2000     1999
--------------------------------------------------------------------------------
Rate variations                            $  -      $ -      $(17)
Credit to customers                           75      (27)       5
Effect of abnormal weather                    10       (4)     (53)
Growth and other                             117      136       78
Interchange sales                            480      135      159
EEI sales                                    (53)     (13)      24
--------------------------------------------------------------------------------
                                           $ 629    $ 227    $ 196
--------------------------------------------------------------------------------
Electric  revenues for 2001 increased  $629 million,  compared to the prior year
period,  primarily  driven  by a  19%  increase  in  total  kilowatthour  sales.
Interchange sales increased 85%;  however,  lower electric margins were realized
on these sales due to lower energy prices in the wholesale markets.  Residential
sales  were  comparable  to the  prior  year  while  commercial  sales  rose 1%.
Industrial  sales rose 11%  primarily due to a new electric  service  industrial
contract  effective  August 2000.  Revenues  were also  favorably  impacted by a
reduction in the estimated credits to Missouri electric  customers (see Note 2 -
Regulatory Matters under Notes to Consolidated  Financial Statements for further
information). These increases were partially offset by reduced EEI sales.

Electric  revenues for 2000 increased  $227 million,  compared to the prior year
period,  primarily  due to an 8%  increase  in total  kilowatthour  sales.  This
increase was primarily driven by a 35% increase in interchange  sales reflecting
the marketing efforts of AmerenEnergy.  In addition,  residential and commercial
sales rose 6% and 8%, respectively, while industrial and wholesale sales rose 3%
and 41%, respectively. These increases were offset in part by an increase in the
credits to Missouri  electric  customers (see Note 2 - Regulatory  Matters under
Notes to Consolidated Financial Statements for further information).

Electric revenues for 1999 increased $196 million,  compared to 1998,  primarily
due to a 9% increase in total  kilowatthour  sales.  This increase was primarily
driven by a 53% increase in interchange  sales, due to strong marketing  efforts
at  AmerenEnergy  and a 12%  increase  in EEI sales.  Also  contributing  to the
revenue  increase was a decrease in the credit to Missouri  electric  customers,
partially  offset by the credit to  Illinois  electric  customers  (see Note 2 -
Regulatory Matters under Notes to Consolidated  Financial Statements for further
information).   Partially   offsetting   these   increases,    weather-sensitive
residential  and  commercial  sales  decreased  2% and 1%,  respectively,  while
industrial  sales  remained  flat. In addition,  revenues were lower due to rate
decreases in both Missouri and Illinois  (see Note 2 - Regulatory  Matters under
Notes to Consolidated Financial Statements for further information).
Fuel and Purchased Power                          Variations from Prior Year
--------------------------------------------------------------------------------
In Millions                                           2001     2000     1999
--------------------------------------------------------------------------------
Fuel:
     Generation                                      $ (19)   $  49    $  10
     Price                                              28      (33)     (15)
     Generation efficiencies and other                  (6)     (13)      (8)
     Coal contract termination payments                  -      (52)      52
Purchased power                                        579       92      117
EEI                                                    (45)       9       37
--------------------------------------------------------------------------------
                                                     $ 537    $  52    $ 193
--------------------------------------------------------------------------------
The $537 million  increase in fuel and purchased power costs for 2001,  compared
to 2000, was primarily due to increased  purchased power,  resulting from higher
interchange sales and the spring 2001 refueling outage at the Company's Callaway
Nuclear Plant, in addition to higher blended fuel costs.

The $52 million increase in fuel and purchased power costs for 2000, compared to
1999, was primarily due to increased  generation and purchased power,  resulting
from higher  sales  volume,  partially  offset by lower fuel  costs,  due to the
termination of certain coal contracts in the fourth quarter of 1999.

                                       2
The $193 million  increase in fuel and purchased power costs for 1999,  compared
to  1998,  was  primarily  due to  increased  generation  and  purchased  power,
resulting from higher sales volume,  increased fuel and purchased power costs at
EEI and coal contract termination payments discussed below,  partially offset by
lower fuel costs.

In the fourth quarter of 1999, AmerenCIPS and two of its coal suppliers executed
agreements to terminate their existing coal supply contracts  effective December
31, 1999. Under these  agreements,  AmerenCIPS made termination  payments to the
suppliers totaling  approximately $52 million.  These termination  payments were
recorded  as an  unusual  charge in the fourth  quarter  of 1999.  See Note 11 -
Commitments and Contingencies under Notes to Consolidated  Financial  Statements
for further information.

Gas Operations

Gas revenues in 2001 increased $18 million,  compared to 2000,  primarily due to
higher gas costs  recovered  through  the  Company's  purchased  gas  adjustment
clauses,  partially  offset by lower total sales of 9% resulting  from unusually
warm winter  weather.  Gas revenues in 2000  increased $96 million,  compared to
1999, primarily due to increases in retail sales, due to unusually cold weather,
and an annualized $4 million Missouri gas rate increase,  which became effective
in November 2000. Gas revenues in 1999 increased $12 million,  compared to 1998,
primarily  due to an  annualized $9 million  Illinois gas rate  increase,  which
became  effective in February 1999 (see Note 2 - Regulatory  Matters under Notes
to Consolidated  Financial  Statements for further  information)  and higher gas
costs recovered through the Company's purchased gas adjustment clauses.

Gas costs in 2001  increased  $12 million,  compared to 2000,  primarily  due to
higher gas  prices,  partially  offset by lower total  sales.  Gas costs in 2000
increased  $78  million,  compared to 1999,  primarily  due to higher  sales and
higher gas prices.  Gas costs in 1999  increased $13 million,  compared to 1998,
primarily due to higher gas prices, partially offset by lower total sales.

Other Operating Expenses
Other  operating  expense  variations in 1999 through 2001  reflected  recurring
factors,  such  as  growth,  inflation,   labor  and  benefit  variations,   the
capitalization  of  certain  costs  as a result  of a  Missouri  Public  Service
Commission  (MoPSC) Order and charges for estimated costs relating to withdrawal
from the Midwest ISO as discussed below.

Other  operating  expenses  increased  $44  million in 2001,  compared  to 2000,
primarily  due  to  higher  employee  benefit  costs  in  2001,  resulting  from
increasing  healthcare  costs,  changes in actuarial  assumptions and investment
performance  of  employee  benefit  plans'  assets  and  increased  professional
services.  Other operating  expenses,  excluding the Midwest ISO-related unusual
charge,  increased  $10 million in 2000,  compared to 1999.  This  increase  was
primarily  due to increases in injuries  and damages  expense,  and higher labor
expenses, offset in part by lower employee benefit costs in 2000, resulting from
changes in actuarial assumptions. Other operating expenses decreased $18 million
in 1999,  compared to 1998.  This  decrease was primarily due to the 1998 charge
for a targeted  employee  separation plan and related reduced  workforce and the
capitalization  of certain costs  (including  computer  software costs) that had
previously been expensed for the Company's  Missouri  electric  operations.  The
capitalization  was a result of the MoPSC Order  received in December  1999 (see
Note 2 - Regulatory Matters under Notes to Consolidated Financial Statements for
further  information).  These  decreases were partially  offset by 1999 expenses
associated with electric industry deregulation in Illinois.

In November 2000, the Company announced that it was withdrawing from the Midwest
ISO to  become a  member  of the  Alliance  Regional  Transmission  Organization
(Alliance  RTO). In the fourth  quarter of 2000,  the Company  recorded a pretax
unusual charge to earnings of $25 million ($15 million after income taxes, or 11
cents per share) as a result of the  Company's  decision  to  withdraw  from the
Midwest ISO.  This charge  related to Ameren's  estimated  obligation  under the
Midwest ISO agreement for costs incurred by the Midwest ISO, plus estimated exit
costs. See discussion below under "Electric Industry Restructuring" and Note 2 -
Regulatory Matters under Notes to Consolidated  Financial Statements for further
information.

Maintenance  expenses increased $14 million in 2001, compared to 2000, primarily
due to a refueling outage at the Callaway Nuclear Plant in 2001. The spring 2001
refueling was completed in 45 days.  There was not a refueling in 2000. The next
refueling is scheduled for the fall of 2002.  Maintenance  expenses decreased $3

                                       3
million in 2000,  compared to 1999. This decrease was primarily the result of no
Callaway Nuclear Plant refueling  outage in 2000,  partially offset by increased
scheduled fossil power plant maintenance and tree-trimming activity. Maintenance
expenses  increased  $59 million in 1999,  compared to 1998.  This  increase was
primarily  due to increased  fossil power plant  maintenance  and  tree-trimming
activity.

Depreciation and amortization  expense  increased $23 million and $20 million in
2001 and 2000,  respectively,  compared to prior year periods,  due to increased
depreciable  property,  primarily  resulting  from the  addition  of  combustion
turbine generating facilities (see discussion below under "Liquidity and Capital
Resources"  and  "Electric  Industry  Restructuring"  for further  information).
Depreciation and amortization expense in 1999 was comparable to 1998.

Taxes
Income tax expense for 2001 was comparable to 2000. Income tax expense increased
$42 million in 2000,  compared to 1999, due to higher pretax income.  Income tax
expense  decreased  $9 million in 1999,  compared to 1998,  due to lower  pretax
income.

Other tax expense decreased $4 million in 2001, compared to 2000,  primarily due
to a  decrease  in  gross  receipts  taxes  related  to the  Company's  Illinois
jurisdiction. Other tax expense increased $18 million in 2000, compared to 1999,
primarily  due to a  change  in the  property  tax  assessment  in the  state of
Illinois.  Other tax expense  decreased  $26 million in 1999,  compared to 1998,
primarily  due to a decrease in gross  receipts  taxes  related to the Company's
Illinois jurisdiction.

Other Income and Deductions
Miscellaneous, net decreased $5 million in 2001, compared to 2000, primarily due
to decreased charitable contributions.  Miscellaneous,  net decreased $6 million
in  2000,  compared  to 1999,  due to the  prior  period  write-off  of  certain
nonregulated investments, partially offset by increased charitable contributions
in 2000. Miscellaneous,  net increased $8 million in 1999, compared to 1998, due
to the write-off of certain  nonregulated  investments  in 1999 and gains on the
sale of property realized in 1998 but not in 1999.

Interest
Interest  expense  increased  $19  million  and $11  million  in 2001 and  2000,
respectively,  compared to prior year periods,  primarily due to increased  debt
levels related to the construction and purchase of combustion turbine generating
facilities  (see  discussion  below under  "Liquidity  and Capital  Resources"),
partially offset by lower interest rates. Interest expense decreased $13 million
in 1999,  compared to 1998,  primarily due to a lower amount of debt outstanding
throughout the year.

LIQUIDITY AND CAPITAL RESOURCES

Cash provided by operating activities totaled $738 million for 2001, compared to
$856  million for 2000,  and $918  million for 1999.  Cash flow from  operations
decreased over the three-year  period  principally  due to the timing of credits
provided to the  Company's  Missouri  electric  customers and changes in working
capital requirements, partially offset by increased earnings.

Cash flows used in investing  activities totaled $1.1 billion,  $910 million and
$558  million,   for  the  years  ended  December  31,  2001,   2000  and  1999,
respectively.  Expenditures in 2001 for constructing  new or improving  existing
facilities,  net of  allowance  for funds used  during  construction,  were $1.1
billion,  $915 million for 2000,  and $557  million for 1999.  Included in these
amounts  were  approximately  $424  million for the  purchase of new  combustion
turbine  generating  facilities  in 2001 and $350  million in 2000.  The Company
added 820 megawatts and 692 megawatts of combustion turbine generating  capacity
during 2001 and 2000,  respectively.  In addition, the Company spent $24 million
in 2001 and $22 million in both 2000 and 1999, to acquire nuclear fuel.

Capital  expenditures  are expected to approximate $800 million in 2002. For the
five-year period 2002 through 2006,  construction  expenditures are estimated to
approximate $3.5 billion. This estimate includes capital expenditures related to
the purchase of new  combustion  turbine  generating  facilities  (see Note 11 -
Commitments and Contingencies under Notes to Consolidated  Financial  Statements
for further  information),  and the replacement of four steam  generators at
its  Callaway  Nuclear  Plant.  In  addition,  this  estimate  includes  capital
expenditures  for  transmission,   distribution  and  other   generation-related
activities,  as well as for  compliance  with new NOx  control  regulations,  as

                                       4
discussed  below.  The Company  plans to add 710  megawatts  (approximately  470
megawatts at  Resources  Company and 240  megawatts  at AmerenUE) of  combustion
turbine generating capacity during 2002. Total costs expected to be incurred for
these  combustion  turbine  generating units  approximate  $340 million.  Due to
expected increased demand, and the need to maintain appropriate reserve margins,
the Company believes it will need additional  regulated  generating  capacity in
the  future.  In 2002,  AmerenUE  expects to  purchase  up to 500  megawatts  of
capacity for the summer.  Additional future resource options under consideration
by the Company  include the transfer of AmerenUE's  Illinois-based  electric and
gas  business to  AmerenCIPS.  Other  alternatives  include the  addition of 650
megawatts of combustion  turbine  generating units. These units are estimated to
cost $280  million and would be added  subsequent  to 2004.  As of December  31,
2001,  the  Company had  noncancelable  reservation  commitments  of $22 million
related to the  potential  purchase  of these  units.  The  Company  continually
reviews its generation portfolio and expected electrical needs, and as a result,
could modify its plan for generation  asset  purchases,  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,
the type of  generation  asset  technology  that will be  employed,  or  whether
capacity may be purchased,  among other things.  Changes to the Company's  plans
for  future  generating  needs  could  result in losses  being  incurred  by the
Company, which could be material.

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

Environmental

The State of Illinois has developed a NOx control regulation for utility boilers
in the State  consistent with a United States  Environmental  Protection  Agency
(EPA) program aimed at reducing ozone levels in the Eastern United States.  As a
result  of  these  state  requirements,  Generating  Company  anticipates  a 75%
reduction  from current  levels of NOx emissions from its power plant boilers in
Illinois by the year 2004.  Generating Company estimates spending  approximately
$210  million for capital  expenditures  to comply  with these  rules,  of which
approximately  $50 million  was spent in 2001.  On February  13,  2002,  the EPA
proposed  similar rules for Missouri which require an approximate  64% reduction
from current  levels of NOx emissions.  AmerenUE  estimates  approximately  $140
million  will be required to be spent to comply with these rules for NOx control
on the AmerenUE  generating  system by 2005. The Company is still evaluating the
impact of the EPA's  regulations  as applied to its Missouri  operations and may
challenge  certain  aspects of those rules.  In summary,  the Company  currently
estimates that its capital expenditures to comply with the final NOx regulations
could  range from $300  million to $350  million.  This  estimate  includes  the
assumption  that the  regulations  will  require the  installation  of Selective
Catalytic  Reduction (SCR) technology on some of the Company's units, as well as
additional controls.

Under both Illinois and Missouri  regulatory  programs,  Generating  Company and
AmerenUE  have  applied for Early  Reduction  NOx credits  which would allow the
companies  to manage  compliance  strategies  by either  purchasing  NOx control
equipment or utilizing credits.  Generating Company and AmerenUE may be eligible
for  such  credits  due to the  current  low NOx  emission  rates of some of the
Companies' boilers under current regulations.

In July 1997,  the EPA issued  regulations  revising  the  National  Ambient Air
Quality  Standards  for  ozone  and  particulate   matter.  The  standards  were
challenged by industry and some states,  and arguments were eventually  heard by
the U. S. Supreme  Court.  On February 27,  2001,  the Supreme  Court upheld the
standards  in large part,  but remanded a number of  significant  implementation
issues back to the EPA for  resolution.  The EPA is  currently  working on a new
rulemaking  to address  the issues  raised by the  Supreme  Court.  New  ambient
standards may require significant  additional reductions in sulfur dioxide (SO2)
and NOx  emissions  from the Company's  power plants by 2008. At this time,  the
Company is unable to predict the  ultimate  impact of these  revised air quality
standards on its future financial condition, results of operations or liquidity.

                                       5
In December 1999, the EPA issued a decision to regulate  mercury  emissions from
coal-fired power plants by 2008. The EPA is scheduled to propose  regulations by
2004.  These  regulations  have the potential to add significant  capital and/or
operating  costs to the Ameren  generating  system after 2005. On July 20, 2001,
the EPA issued proposed Best Available Retrofit  Technology (BART) guidelines to
address  visibility  impairment  (so called  "Regional  Haze") across the United
States from sources of air pollution,  including  coal-fired  power plants.  The
guidelines are to be used by States to mandate  pollution  control  measures for
SO2 and NOx emissions.  These rules could also add significant pollution control
costs to the Ameren generating systems between 2008 and 2012.

In addition,  the United  States  Congress has been  working on  legislation  to
consolidate the numerous air pollution  regulations facing the utility industry.
This "multi-pollutant"  legislation is expected to be deliberated in Congress in
2002.  While the cost to comply  with such  legislation,  if  enacted,  could be
significant,  it is  anticipated  that the costs would be less than the combined
impact of the new National Ambient Air Quality  Standards,  mercury and Regional
Haze   regulations,   discussed  above.   Pollution  control  costs  under  such
legislation  are  expected to be incurred in phases from 2007 through  2015.  At
this time,  the  Company is unable to predict the  ultimate  impact of the above
expected  regulations and this  legislation on its future  financial  condition,
results of operations, or liquidity; however, the impact could be material.

See  Note  11 -  Commitments  and  Contingencies  under  Notes  to  Consolidated
Financial Statements for further discussion of environmental matters and Note 12
- Callaway Nuclear Plant under Notes to Consolidated  Financial Statements for a
discussion of Callaway Nuclear Plant decommissioning costs.

Financing Activities
Cash flows provided by financing activities were $308 million for 2001, compared
to cash flows used in  financing  activities  of $14  million  for 2000 and $241
million for 1999.  The  Company's  principal  financing  activities  during 2001
included  the  issuance of $300  million of  long-term  debt and $438 million of
short-term  debt,  offset by the redemption of $64 million of long-term debt and
the payment of dividends on common  stock.  The  Company's  principal  financing
activities  during 2000 and 1999 included the issuances of $703 million and $152
million of long-term  debt, the  redemptions of $421 million and $174 million of
long-term debt and the payment of dividends on common stock, respectively.

In December 2001, Ameren  Corporation issued Floating Rate Notes (FRNs) totaling
$150  million.  Interest  accrues  on the  FRNs  at  three  month  LIBOR  (reset
quarterly)  plus  0.95%  and is  payable  quarterly  commencing  in March  2002.
Principal  of the FRNs is payable in  December  2003.  With the  proceeds of the
FRNs,  Ameren  Corporation  reduced  its  short-term  borrowings.  See  Note 7 -
Long-Term  Debt under Notes to  Consolidated  Financial  Statements  for further
discussion.

In  September  2001,  the Company  began  issuing new shares of common  stock to
satisfy  requirements under the Ameren dividend  reinvestment and stock purchase
plan (DRPlus) and in December  2001, it began issuing new shares of common stock
in connection with its 401(k) plans. Previously,  these requirements were met by
purchasing outstanding shares. Under these plans, the Company issued 830,177 new
shares of common stock in 2001.

In January 2002,  Ameren  Corporation  issued 5.70% Notes totaling $100 million.
Interest  is  payable  semi-annually  on  February  1 and August 1 of each year,
beginning August 1, 2002, and on the date of maturity, February 1, 2007. The net
proceeds were used to reduce short-term borrowings.

In December 2001, the interest rate mode on AmerenCIPS' three series of variable
rate  tax-exempt  pollution  control  indebtedness  totaling  $104  million  was
converted to long-term fixed rates. Terms of the indebtedness  ranged from 5% to
5.95% with maturities through 2026.

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% due June 2011. Until the release date as described in
the registration statement, the senior notes will be secured by a related series
of  AmerenCIPS'  first mortgage  bonds.  The proceeds of these senior notes were
used to repay short-term debt and first mortgage bonds maturing in June 2001.

                                       6
In November 2000,  Generating Company issued $225 million principal amount 7.75%
Senior  Notes,  Series A due 2005  (Series A Notes) and $200  million  principal
amount 8.35% Senior Notes, Series B due 2010 (Series B Notes) (collectively, the
Senior Notes).  Generating Company filed an S-4 registration  statement with the
SEC in 2001 to register the Senior Notes under the  Securities  Act of 1933,  as
amended,  to permit an exchange offer of the Senior Notes.  In 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.  With  the  proceeds  of the  Senior  Notes,
Generating  Company  reduced its short-term  borrowings  incurred in conjunction
with the construction of completed  combustion  turbine  generating  facilities,
paid for the construction of certain combustion turbine  facilities,  and funded
working capital and other capital expenditure needs. See Note 7 - Long-Term Debt
under Notes to Consolidated Financial Statements for further discussion.

In 2002,  Generating  Company  expects to issue  additional  debt to permanently
finance generating capacity additions. This additional debt issuance could be up
to $250 million and is expected to be issued in early 2002.

The Company anticipates  securing additional financing in 2002. In January 2002,
Ameren Corporation filed a shelf registration statement with the SEC on Form S-3
which,  upon its  effectiveness,  will allow the  offering  from time to time of
various forms of debt and equity  securities,  up to an aggregate offering price
of $1 billion.  The  proceeds  from any sale of such  securities  may be used to
finance  the  Company's   subsidiaries'  ongoing  construction  and  maintenance
programs,  to  redeem,  repurchase,  repay or retire  outstanding  indebtedness,
including  indebtedness  of the  Company's  subsidiaries,  to finance  strategic
investments in or future  acquisitions of other entities or other assets and for
other  general  corporate  purposes.  At this  time,  the  Company  is unable to
determine  the amount of the  additional  financing,  as well as the  additional
financing's impact on the Company's financial position, results of operations or
liquidity.

The  Company  plans to  continue  utilizing  short-term  debt to support  normal
operations and other temporary  requirements.  The Company 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 commercial  paper  (maturities  generally  within 1 to 45
days) and bank loans. At December 31, 2001, the Company had committed bank lines
of credit  aggregating  $156 million,  all of which were unused and available at
such date.  These lines 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 Company has bank credit  agreements,  expiring at various dates between 2002
and 2003, that support  commercial paper programs totaling $700 million of which
$400 million is for the Company's  own use and for the use of its  subsidiaries.
The  remaining  $300  million  is  for  the  use  of  the  Company's   regulated
subsidiaries.  At December  31,  2001,  all of the bank credit  agreements  were
unused; however, due to commercial paper borrowings and other commitments,  $126
million of such borrowing  capacity was available.  The Company had $641 million
of  short-term  borrowings  outstanding  at  December  31,  2001.  See  Note 6 -
Short-Term  Borrowings  under Notes to  Consolidated  Financial  Statements  for
further information.

AmerenUE also has a lease  agreement  that provides for the financing of nuclear
fuel. At December 31, 2001,  the maximum amount that could be financed under the
agreement was $120 million. Cash used in financing for 2001 included $64 million
of  redemptions  under the lease for  nuclear  fuel,  offset by $13  million  of
issuances.  At December 31, 2001, $63 million was financed under the lease.  See
Note 4 - Nuclear Fuel Lease under Notes to Consolidated Financial Statements for
further information.

The following table summarizes the Company's committed credit availability as of
December 31, 2001:
Amount of commitment expiration per period
--------------------------------------------------------------------------------------------
In Millions                                      Total      Less than 1    1 - 3     4 - 5
                                                 amounts       year        years     years
                                                 committed
--------------------------------------------------------------------------------------------
Lines of credit and credit agreements (a)        $856          $656        $200     $ -
--------------------------------------------------------------------------------------------
(a)  See Note 6 - Short-Term  Borrowings  under Notes to Consolidated  Financial
     Statements for further discussion.
7
The following table summarizes the Company's contractual obligations as of
December 31, 2001:
--------------------------------------------------------------------------------
In Millions                                       Less than  1 - 3    4 - 5
                                                    1 year   years    years
--------------------------------------------------------------------------------
Long-term debt and capital lease obligations (a)    $  139   $  684   $  279
Operating leases                                        13       27       19
Other long-term obligations (b)                        739    1,339      654
--------------------------------------------------------------------------------
Total cash contractual obligations                  $  891   $2,050   $  952
--------------------------------------------------------------------------------
(a)  See Note 7 - Long-Term  Debt and Note 4 - Nuclear Fuel Lease under Notes to
     Consolidated Financial Statements for further discussion.
(b)  Represents  purchase  contracts for coal,  gas,  nuclear fuel, and electric
     capacity.

During 2001,  as a result of the  uncertainty  created from the excess  earnings
complaint filed against AmerenUE (see discussion below under "Rate Matters"), as
well as other  factors,  Moody's,  Standard & Poor's and Fitch  rating  agencies
changed their outlooks for Ameren Corporation's long-term unsecured debt ratings
from  stable to  negative.  As of  December  31,  2001,  the  ratings  of Ameren
Corporation by these rating agencies were as follows:
--------------------------------------------------------------------------------
                                     Moody's    Standard & Poor's     Fitch
--------------------------------------------------------------------------------
     Unsecured Debt                   A2               A               A+
     Commercial Paper                 P-1              A-1             F1

If the ratings of AmerenUE's  first mortgage bonds,  currently rated as Aa3, A+,
and AA, for  Moody's,  Standard & Poor's,  and Fitch,  respectively,  fall below
investment  grade,  lenders on AmerenUE's $300 million revolving credit facility
may elect not to make advances  and/or  declare  outstanding  borrowings due and
payable. In addition,  a decrease in the Company's ratings may reduce its access
to capital  and/or  increase  the costs of  borrowings  resulting  in a negative
impact on earnings.

DIVIDENDS

Common stock dividends paid in 2001,  2000, and 1999 resulted in payout rates of
74%, 76%, and 90%, respectively,  of the Company's net income. Dividends paid to
common stockholders in relation to net cash provided by operating activities for
the same periods were 47%, 41% and 38%.

The Board of Directors does not set specific  targets or payout  parameters when
declaring common stock dividends;  however,  the Board considers various issues,
including the Company's  historic  earnings and cash flow;  projected  earnings,
cash flow and potential cash flow  requirements;  dividend payout rates at other
utilities; return on investments with similar risk characteristics;  and overall
business  considerations.  On February 8, 2002,  the Ameren  Board of  Directors
declared a quarterly  common stock dividend of 63.5 cents per share,  to holders
of record on March 11, 2002, payable March 29, 2002.

RATE MATTERS

On June 30, 2001, AmerenUE's experimental alternative regulation plan (the Plan)
for its  Missouri  retail  electric  customers  expired (see Note 2 - Regulatory
Matters under Notes to Consolidated Financial Statements for further information
about the Plan). On July 2, 2001, the MoPSC staff filed with the MoPSC an excess
earnings  complaint against AmerenUE that proposed to reduce its annual electric
revenues ranging from $213 million to $250 million.  Factors contributing to the
MoPSC  staff's  recommendation  included  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 ranged from 9.04% to 10.04%.
The MoPSC is not bound by the MoPSC staff's recommendation. In January 2002, the
MoPSC  issued an order that  established  the test year to be used to  determine
rates as July 1, 2000  through  June 30,  2001,  with  updates to that test year
permitted  through  September 30, 2001. The MoPSC staff had utilized a test year
of July 1, 1999 through June 30, 2000 in its  original  complaint.  In addition,
the MoPSC order stated that AmerenUE  would be permitted to propose an incentive
regulation plan in this proceeding.

                                       8
The MoPSC order also included a revised procedural schedule to allow all parties
additional time to review data and file  testimony,  due to the utilization of a
more current test year. Under the new schedule, the MoPSC staff will file direct
testimony  on March 1, 2002,  with  AmerenUE  and the  Office of Public  Counsel
filing  rebuttal  testimony on May 10, 2002.  Evidentiary  hearings on the MoPSC
staff's  recommendation are scheduled to be conducted before the MoPSC beginning
in July 2002.  In the event  that the MoPSC  ultimately  determines  that a rate
decrease is warranted in this case,  that rate reduction would be retroactive to
April 1,  2002,  regardless  of when the  MoPSC  issues  its  decision.  A final
decision  on this  matter  may not  occur  until  the  fourth  quarter  of 2002.
Depending on the outcome of the MoPSC's decision, further appeals in the courts
may be warranted.

In the interim, the Company expects to continue  negotiations with all pertinent
parties  with the intent to continue  with an  incentive  regulation  plan.  The
Company cannot predict the outcome of these negotiations and their impact on the
Company's financial position,  results of operations or liquidity;  however, the
impact could be material.

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

ELECTRIC INDUSTRY RESTRUCTURING

Federal
Steps taken and being  considered  at the federal and state  levels  continue to
change the  structure of the electric  industry and utility  regulation.  At the
federal level, the Energy Policy Act of 1992 reduced various restrictions on the
operation  and  ownership of  independent  power  producers and gave the Federal
Energy Regulatory Commission (FERC) the authority to order electric utilities to
provide transmission access to third parties.

Order 888 and Order 889, issued by the FERC, are intended to promote competition
in the wholesale electric market. The FERC requires  transmission-owning  public
utilities,  such as AmerenUE and AmerenCIPS,  to provide transmission access and
service to others in a manner similar and comparable to that which the utilities
have by virtue of ownership.  Order 888 requires that a single tariff be used by
the utility in providing  transmission service.  Order 888 also provides for the
recovery of stranded costs, under certain  conditions,  related to the wholesale
business.

Order 889 established the standards of conduct and information requirements that
transmission owners must adhere to in doing business under the open access rule.
Under Order 889, utilities must obtain transmission service for their own use in
the same manner their  customers will obtain  service,  thus  mitigating  market
power through control of transmission facilities.  In addition, under Order 889,
utilities must separate their merchant  function  (buying and selling  wholesale
power) from their transmission and reliability functions.

In 1998,  AmerenUE and AmerenCIPS  joined a group of companies  that  originally
supported the  formation of the Midwest ISO. An ISO operates,  but does not own,
electric  transmission  systems and maintains  system  reliability and security,
while facilitating  wholesale and retail competition  through the elimination of
"pancaked"  transmission  rates.  The Midwest ISO is regulated by the FERC.  The
FERC conditionally approved the formation of the Midwest ISO in September 1998.

In December 1999,  the FERC issued Order 2000 relating to Regional  Transmission
Organizations  (RTOs) that would meet certain  characteristics  such as size and
independence.  RTOs,  including  ISOs,  are entities that ensure  comparable and
non-discriminatory access to regional electric transmission systems. Order 2000
calls on all transmission owners to join RTOs.

In the fourth quarter of 2000,  the Company  announced its intention to withdraw
from the Midwest ISO and to join the 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  Company's  estimated  obligation  under the  Midwest  ISO
agreement for costs incurred by the Midwest ISO, plus  estimated exit costs.  In
2001, the Company announced that it had signed an agreement to join the Alliance
RTO.  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.  This  settlement  agreement  was approved by the
FERC.  The Company's  withdrawal  from the Midwest ISO remains  subject to MoPSC
approval. In July 2001, the FERC conditionally approved the formation, including
the rate structure, of the Alliance RTO. However, on December 20, 2001, the FERC
issued an order that  reversed its  position  and rejected the  formation of the
Alliance  RTO.  Instead,  the FERC  granted  RTO status to the  Midwest  ISO and
ordered  the  Alliance  RTO  Companies  and the  Midwest  ISO to discuss how the
Alliance RTO business  model could be  accommodated  within the Midwest ISO. The
Alliance  RTO  members  have until  February  19,  2002 to respond to the FERC's
December 2001 order.  At this time, the Company is evaluating its  alternatives,
including the possible appeal of the FERC's  December 2001 order,  and is unable
to determine  the impact that the FERC's  latest  ruling will have on its future
financial condition, results of operations or liquidity.

                                       9
Illinois
In December 1997, the Governor of Illinois signed the Electric  Service Customer
Choice and Rate Relief Law of 1997 (the  Illinois  Law)  providing  for electric
utility restructuring in Illinois.  This legislation introduces competition into
the supply of electric energy at retail in Illinois.

Major  provisions  of the  Illinois Law include 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 represented approximately 16% of the Company's total sales during 2001.
As of December  31, 2001,  the impact of Illinois  retail  direct  access on the
Company's   financial   condition,   results  of  operations  or  liquidity  was
immaterial.  Retail  direct  access  will be  offered  to  Illinois  residential
customers on May 1, 2002.

Under the Illinois  Law, the Company is subject to a  residential  electric rate
decrease of up to 5% in 2002, to the extent its rates exceed the Midwest utility
average at that time. In 2001, the Company's  Illinois electric rates were below
the Midwest utility average.

The Illinois Law also contains a provision  allowing for the potential  recovery
of a  portion  of  stranded  costs,  which  represent  costs  that  would not be
recoverable in a restructured environment, through a transition charge collected
from  customers  who choose an alternate  electric  supplier.  In addition,  the
Illinois  Law  contains a provision  requiring a portion of excess  earnings (as
defined  under the Illinois  Law) for the years 1998 through 2004 to be refunded
to  customers.  See Note 2 -  Regulatory  Matters  under  Notes to  Consolidated
Financial Statements for further information.

In  conjunction  with another  provision  of the  Illinois  Law, on May 1, 2000,
following the receipt of all required  state and federal  regulatory  approvals,
AmerenCIPS  transferred  its  electric  generating  assets and  liabilities,  at
historical net book value, to Generating  Company,  in exchange for a promissory
note from  Generating  Company in the  principal  amount of  approximately  $552
million and Generating Company common stock (the Transfer).  The promissory note
bears  interest  at 7% and has a term of five years  payable  based on a 10-year
amortization.   The  transferred  assets  represent  a  generating  capacity  of
approximately 2,900 megawatts.  Approximately 45% of AmerenCIPS'  employees were
transferred to Generating Company as part of the transaction.

In conjunction with the Transfer, an electric power supply agreement was entered
into between  Generating Company and its newly created  nonregulated  affiliate,
AmerenEnergy   Marketing  Company  (Marketing  Company),   also  a  wholly-owned
subsidiary of Resources  Company.  Under this  agreement,  Marketing  Company is
entitled to purchase  all of  Generating  Company's  energy and  capacity.  This
agreement may not be terminated  until at least  December 31, 2004. In addition,
Marketing   Company  entered  into  an  electric  power  supply  agreement  with
AmerenCIPS to supply it sufficient  energy and capacity to meet its  obligations
as a public  utility.  This  agreement  expires  December 31,  2004.  Power will
continue to be jointly dispatched between AmerenUE and Generating Company.

The creation of the new subsidiaries and the transfer of AmerenCIPS'  generating
assets and liabilities had no effect on the consolidated financial statements of
Ameren as of the date of the Transfer.

The provisions of the Illinois Law could also result in lower revenues,  reduced
profit margins and increased  costs of capital and operations  expense.  At this
time,  the Company is unable to determine  the impact of the Illinois Law on the
Company's future financial condition, results of operations or liquidity.

Missouri
In Missouri, where approximately 70% of the Company's retail electric revenues
are derived,  restructuring  bills have been  introduced but no legislation  has
been passed.  Furthermore, no restructuring legislation is expected to be passed
by the Missouri state legislature in 2002.

                                       10
Summary
In  summary,  the  potential  negative  consequences  associated  with  electric
industry restructuring could be significant and could include the impairment and
writedown  of  certain  assets,  including   generation-related  plant  and  net
regulatory assets, lower revenues, reduced profit margins and increased costs of
capital and  operations  expenses.  Conversely,  a deregulated  marketplace  can
provide earnings enhancement  opportunities.  The Company will continue to focus
on cost control to ensure that it maintains a competitive cost structure.  Also,
in Illinois,  the Company's actions included the establishment of a nonregulated
generating   subsidiary,   the  expansion  of  its  generation   assets,   which
strengthened its trading and marketing operations in order to retain its current
customers  and obtain new  customers,  and the  enhancement  of its  information
systems. Management believes that these actions position the Company well in the
competitive Illinois marketplace.  In Missouri, the Company is actively involved
in  all  major   deliberations   taking  place  surrounding   electric  industry
restructuring  in an effort to ensure that  restructuring  legislation,  if any,
contains an orderly  transition and is equitable to the Company's  shareholders.
At this time,  the Company is unable to predict the ultimate  impact of electric
industry  restructuring on the Company's future financial condition,  results of
operations or liquidity.

CONTINGENCIES

See Note 2 - Regulatory  Matters,  Note 11 - Commitments and  Contingencies  and
Note  12  -  Callaway  Nuclear  Plant  under  Notes  to  Consolidated  Financial
Statements for material issues existing at December 31, 2001.

ACCOUNTING MATTERS

In January 2001, the Company adopted Statement of Financial Accounting Standards
(SFAS) No. 133, "Accounting for Derivative  Instruments and Hedging Activities."
The impact of that  adoption  resulted  in the Company  recording  a  cumulative
effect  charge  of $7  million  after  taxes  to  the  income  statement,  and a
cumulative  effect  adjustment of $11 million after income taxes to  Accumulated
Other Comprehensive Income (OCI), which reduced  stockholders' equity. (See Note
3 -  Risk  Management  and  Derivative  Financial  Instruments  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  Company's
financial condition,  results of operations or liquidity upon adoption. However,
in October and again in December 2001,  the DIG revised this guidance,  with the
revisions effective April 1, 2002. The Company does not expect the impact of the
DIG's revisions to have a material effect on the Company's financial  condition,
results of operations, or liquidity upon adoption.

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 as of
April 1, 2002. The Company  continues to evaluate the impact of this guidance on
its future financial  condition,  results of operations and liquidity;  however,
the impact is not expected to be material.

In July 2001, the FASB issued SFAS No. 141,  "Business  Combinations,"  and SFAS
No. 142,  "Goodwill and Other  Intangible  Assets."  SFAS 141 requires  business
combinations to be accounted for under the purchase method of accounting,  which
requires  one  party  in the  transaction  to be  identified  as  the  acquiring
enterprise  and for that party to allocate the purchase  price to the assets and
liabilities of the acquired  enterprise based on fair market value. 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 became effective
for the  Company  on  January  1,  2002.  SFAS  141 and  SFAS 142 did not have a
material effect on the Company's  financial  position,  results of operations or
liquidity upon adoption.

                                       11
In addition,  in July 2001, the FASB issued SFAS No. 143,  "Accounting for Asset
Retirement  Obligations."  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.  At this time,  the
Company is assessing the impact of SFAS 143 on its financial  position,  results
of operations  and liquidity  upon  adoption.  However,  SFAS 143 is expected to
result in significant increases to the Company's reported assets and liabilities
as a  result  of  its  ongoing  collection  through  rates  of  and  obligations
associated with Callaway Nuclear Plant decommissioning costs.

In August 2001, the FASB issued SFAS No. 144,  "Accounting for the Impairment or
Disposal of Long-Lived Assets." SFAS 144 addresses the financial  accounting and
reporting for the  impairment or disposal of  long-lived  assets and  supersedes
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of." SFAS 144 retains the guidance  related to calculating
and  recording  impairment  losses,  but adds  guidance  on the  accounting  for
discontinued  operations,  previously accounted for under Accounting  Principles
Board  Opinion  No. 30.  SFAS 144 was adopted by the Company on January 1, 2002.
SFAS 144 did not have a material  effect on the  Company's  financial  position,
results of operations or liquidity upon adoption.

EFFECTS OF INFLATION AND CHANGING PRICES

The Company's  rates for retail  electric and gas utility  service are generally
regulated by the MoPSC and the Illinois Commerce  Commission  (ICC).  Non-retail
electric rates are regulated by the FERC.

The  current  replacement  cost of the  Company's  utility  plant  substantially
exceeds its recorded historical cost. Under existing regulatory  practice,  only
the historical cost of plant is recoverable  from customers.  As a result,  cash
flows  designed to provide  recovery of historical  costs  through  depreciation
might not be adequate to replace plants in future years. Regulatory practice has
been  modified  for the  Company's  generation  portion of its  business  in its
Illinois  jurisdiction  and may be  modified  in the  future  for the  Company's
Missouri   jurisdiction  (see  Note  2  -  Regulatory  Matters  under  Notes  to
Consolidated  Financial Statements for further  information).  In addition,  the
impact on common stockholders is mitigated to the extent depreciable property is
financed with debt that is repaid with dollars of less purchasing power.

In the Company's  retail electric  utility  jurisdictions,  the cost of fuel for
electric  generation is reflected in base rates with no provision for changes in
such cost to be  reflected  in billings to  customers  through  fuel  adjustment
clauses.  Changes in gas costs  relating  to retail  gas  utility  services  are
generally  reflected in billings to customers  through  purchased gas adjustment
clauses.  The Company is impacted by changes in market prices for natural gas to
the  extent  it  must  purchase  natural  gas  to  run  its  combustion  turbine
generators.  The Company has structured  various  supply  agreements to maintain
access to multiple  gas pools and supply  basins to  minimize  the impact to the
financial  statements (see  discussion  below under  "Commodity  Price Risk" for
further information).

Inflation continues to be a factor affecting operations, earnings, stockholders'
equity and financial performance.

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 Company'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 Company  handles  market risks in accordance  with  established
policies,  which may include entering into various derivative  transactions.  In
the normal  course of  business,  the  Company  also faces risks that are either
non-financial or  non-quantifiable.  Such risks  principally  include  business,
legal, and operational risk and are not represented in the following analysis.

The Company'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.

                                       12
Interest Rate Risk
The  Company  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,   auction-rate   long-term  debt  and
auction-rate  preferred stock. The Company 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 1% in 2002,  as  compared  to 2001,  the  Company's
interest  expense  would  increase by  approximately  $13 million and net income
would  decrease by  approximately  $8 million.  This amount has been  determined
using  the  assumptions  that  the  Company's  outstanding  variable-rate  debt,
commercial paper, auction-rate long-term debt, and auction-rate preferred stock,
as of December 31, 2001,  continued to be outstanding  throughout 2002, and that
the average  interest  rates for these  instruments  increased 1% over 2001. The
model does not  consider the effects of the reduced  level of potential  overall
economic  activity  that would exist in such an  environment.  In the event of a
significant  change in interest rates,  management  would likely take actions to
further  mitigate  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 Company's financial
structure.

Credit Risk
Credit risk represents the loss that would be recognized if counterparties  fail
to perform as contracted.  New York Mercantile  Exchange  (NYMEX) traded futures
contracts  are  supported by the  financial  and credit  quality of the clearing
members of the NYMEX and have nominal  credit risk.  On all other  transactions,
the  Company  is exposed to credit  risk in the event of  nonperformance  by the
counterparties in the transaction.

The  Company's  physical and  financial  instruments  are subject to credit risk
consisting of trade  accounts  receivables  and executory  contracts with market
risk exposures.  The risk associated with trade  receivables is mitigated by the
large  number of customers in a broad range of industry  groups  comprising  the
Company's  customer  base.  No  customer  represents  greater  than  10%  of the
Company's accounts receivable. The Company's revenues are primarily derived from
sales of electricity and natural gas to customers in Missouri and Illinois.  The
Company analyzes each counterparty's  financial condition prior to entering into
forwards,  swaps,  futures or option  contracts.  The Company  also  establishes
credit limits for these counterparties and monitors the appropriateness of these
limits on an  ongoing  basis  through a credit  risk  management  program  which
involves  daily  exposure  reporting to senior  management,  master  trading and
netting agreements,  and credit support management (e.g.,  letters of credit and
parental guarantees).

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

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

                                       13
The  Company's   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 Company's  operating
subsidiaries,  and for managing  fuel and natural gas price  risks.  Fixed price
forward contracts,  as well as futures and options,  are all instruments,  which
may be used to manage these risks.  The  majority of the  Company's  fuel supply
contracts  are  physical  forward  contracts.  Since the Company does not have a
provision  similar  to the PGA for its  electric  operations,  the  Company  has
entered into several long-term contracts with various suppliers to purchase coal
and  nuclear  fuel  to  manage  its  exposure  to  fuel  prices  (see  Note 11 -
Commitments and Contingencies under Notes to Consolidated  Financial  Statements
for further  information).  Over 95% of the required 2002 supply of coal for the
Company's  coal plants has been  acquired at fixed prices for 2002. In addition,
approximately  70%  of  the  coal  requirements  through  2006  are  covered  by
contracts.  With  regard  to  the  Company's  nonregulated  electric  generating
operations,  the Company 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 Company'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.

Although  the  Company  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 Company'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 Company's  strategy also utilizes physical assets through storage,
operator and balancing  agreements to minimize price  volatility.  The Company'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 Company's
primary use of derivatives has involved transactions that are expected to reduce
price risk exposure for the Company.

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

Equity Price Risk
The Company  maintains  trust  funds,  as  required  by the  Nuclear  Regulatory
Commission  and  Missouri  and Illinois  state laws,  to fund  certain  costs of
nuclear  decommissioning  (see Note 12 - Callaway  Nuclear  Plant under Notes to
Consolidated  Financial Statements for further information).  As of December 31,
2001,  these  funds were  invested  primarily  in  domestic  equity  securities,
fixed-rate,   fixed-income  securities,  and  cash  and  cash  equivalents.   By
maintaining a portfolio that includes long-term equity investments,  the Company
is  seeking  to  maximize   the   returns  to  be   utilized  to  fund   nuclear
decommissioning  costs. However, the equity securities included in the Company'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 Company  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 Company's  exposure to equity price market
risk is, in large part, mitigated, due to the fact that the Company is currently
allowed to recover its decommissioning costs in its rates.

                                       14
Fair Value of Contracts
The Company  utilizes  derivatives  principally to manage the risk of changes in
market prices for natural gas, fuel,  electricity  and emission  credits.  Price
fluctuations  in  natural  gas,  fuel and  electricity  cause (1) an  unrealized
appreciation or  depreciation  of the Company's firm  commitments to purchase or
sell when purchase or sales 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 Company 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 Company.

The following summarizes changes in the fair value of all contracts marked to
market during 2001:
--------------------------------------------------------------------------------
In Millions
--------------------------------------------------------------------------------
Fair value of contracts at January 1, 2001                        $(30)
Contracts at January 1, 2001 which were realized or
otherwise settled during 2001                                       30
Changes in fair values attributable to changes in valuation
techniques and assumptions                                           -
Fair value of new contracts entered into during 2001                 4
Other changes in fair value                                         (5)
--------------------------------------------------------------------------------
Fair value of contracts outstanding at December 31, 2001           $(1)
--------------------------------------------------------------------------------

Fair value of contracts as of December 31, 2001 were as follows:
--------------------------------------------------------------------------------------------------------------------
In Millions                                       Maturity     Maturity 1-3     Maturity      Maturity    Total
                                                  less than    years            4-5 years    in excess    fair
Sources of fair value                             1 year                                     of 5 years   value (a)
--------------------------------------------------------------------------------------------------------------------
Prices actively quoted                           $-            $(2)            $ -            $ -          $(2)
Prices provided by other external sources (b)     5              -               -              -            5
Prices based on models and other
valuation methods (c)                             -             (2)             (1)            (1)          (4)
--------------------------------------------------------------------------------------------------------------------
     Total                                       $5            $(4)            $(1)           $(1)         $(1)
--------------------------------------------------------------------------------------------------------------------
(a)  Contracts  valued  at ($1  million)  were  with  noninvestment-grade  rated
     counterparties.
(b)  Principally   power  forward  hedges  valued  based  on  NYMEX  prices  for
     over-the-counter contracts.
(c)  Principally coal and SO2 options valued based on a Black-Scholes model that
     includes information from external sources and Company estimates.
15
SAFE HARBOR STATEMENT

Statements  made in this annual  report to  stockholders  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
Company 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 subsequent securities filings,  could cause results to differ materially from
management expectations as suggested by such "forward-looking"  statements:  the
effects  of the  pending  AmerenUE  excess  earnings  complaint  case and  other
regulatory actions,  including changes in regulatory policy; changes in laws and
other  governmental  actions;  the impact on the Company 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  Company's  business  at both the state and federal  levels;  the effects of
participation in a FERC approved RTO, including  activities  associated with the
Midwest ISO and the Alliance  RTO;  future  market prices for fuel and purchased
power,  electricity,  and  natural  gas,  including  the  use of  financial  and
derivative instruments and volatility of changes in market prices; average rates
for electricity in the Midwest; business and economic conditions;  the impact of
the adoption of new accounting standards; interest rates and the availability of
capital;  actions of ratings  agencies and the effects of such actions;  weather
conditions;  fuel  prices  and  availability;   generation  plant  construction,
installation and performance; the impact of current environmental regulations on
utilities and  generating  companies  and the  expectation  that more  stringent
requirements  will be  introduced  over time,  which  could  potentially  have a
negative  financial  effect;  monetary  and fiscal  policies;  future  wages and
employee benefits costs;  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  Company's  generating
facilities  or required to satisfy  energy sales made by the Company;  and legal
and administrative proceedings.

                                       16