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                                 UNITED STATES
                      SECURITIES AND EXCHANGE COMMISSION
                             Washington, DC 20549

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

                                   FORM 10-K

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

                  For the Fiscal Year Ended December 31, 2001

                                      OR

[_] Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

         For the transition period from ____________ to ____________.

                       Commission File Number 333-56594

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

                       AMEREN ENERGY GENERATING COMPANY
            (Exact name of registrant as specified in its charter)
                      Illinois                 37-1395586
                   (State or other          (I.R.S. Employer
                    jurisdiction           Identification No.)
                 of incorporation or
                    organization)

                1901 Chouteau Avenue, St. Louis, Missouri 63103
             (Address of principal executive offices and Zip Code)
      Registrant's telephone number, including area code: (314) 554-3922

       Securities registered pursuant to section 12(b) of the act: none.

       Securities registered pursuant to section 12(g) of the act: none.

   Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X]    No [_]

   Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X].

   As of March 28, 2002, there was no established trading market for the
registrant's common stock.

   As of March 28, 2002, there were 2,000 outstanding shares of Common Stock,
without par value, of the registrant, all of which were owned by the
registrant's parent, AmerenEnergy Development Company.

                     DOCUMENTS INCORPORATED BY REFERENCE.

   None.

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                               TABLE OF CONTENTS

<TABLE>
<CAPTION>
                                                                                        Page
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<C>          <S>                                                                        <C>
PART I

   ITEM 1.   Business..................................................................   1

   ITEM 2.   Properties................................................................  11

   ITEM 3.   Legal Proceedings.........................................................  14

   ITEM 4.   Submission of Matters to a Vote of Security Holders(1)....................  14

PART II

   ITEM 5.   Market for Registrant's Common Equity and Related Stockholder Matters.....  15

   ITEM 6.   Selected Financial Data...................................................  15

   ITEM 7.   Management's Discussion and Analysis of Financial Condition and Results of
             Operations................................................................  16

   ITEM 7A.  Quantitative and Qualitative Disclosures About Market Risk................  32

   ITEM 8.   Financial Statements and Supplementary Data...............................  33

   ITEM 9.   Changes in and Disagreements With Accountants on Accounting and Financial
             Disclosure................................................................  51

PART III

   ITEM 10.  Directors and Executive Officers of the Registrant........................  52

   ITEM 11.  Executive Compensation....................................................  54

   ITEM 12.  Security Ownership of Certain Beneficial Owners and Management............  58

   ITEM 13.  Certain Relationships and Related Party Transactions......................  58

PART IV

   ITEM 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K...........  59

SIGNATURES.............................................................................  62

EXHIBITS...............................................................................  63
</TABLE>
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(1) Not applicable and not included herein.

                                      -i-

<PAGE>

                                    PART I

ITEM 1.  Business.

General

   Our company, AmerenEnergy Generating Company, is an indirect wholly-owned
subsidiary of Ameren Corporation (which, together with its subsidiaries, we
refer to as Ameren) that owns and operates a wholesale electric generation
business. Much of this business was formerly owned and operated by our
affiliate, Central Illinois Public Service Company d/b/a AmerenCIPS, which we
refer to as AmerenCIPS. We were incorporated in the State of Illinois in March
2000. On May 1, 2000, we acquired from AmerenCIPS at net book value the coal
plants described below under "Generating Business," all related fuel, supply,
transportation, maintenance and labor agreements, approximately 45% of
AmerenCIPS employees, and other related rights, assets and liabilities.

Deregulation in Illinois

   In December 1997, the Electric Service Customer Choice and Rate Relief Law
of 1997, which we refer to as the Illinois Customer Choice Law, was enacted and
introduced competition into the retail supply of electric energy in Illinois.
We were formed as part of Ameren's business strategy to respond to the advent
of customer choice in Illinois and the increasingly competitive market for
electric generation services in the Midwest brought about by the Illinois
Customer Choice Law and other factors. As allowed under the Illinois Customer
Choice Law and as part of a plan to divest itself of generating assets,
AmerenCIPS transferred the coal plants to us effective May 1, 2000. The
phase-in of retail direct access began on October 1, 1999 with large industrial
and commercial customers. The remaining commercial and industrial customers in
Illinois were offered choice on December 31, 2000. Under the Illinois Customer
Choice Law, all electric customers in Illinois will be able to choose their
electricity supplier by May 1, 2002. Regulated utilities, like AmerenCIPS, will
continue to provide "bundled service," that is, electricity supply as well as
delivery, to customers who do not choose a competitive supplier.

Ameren Corporation

   St. Louis-based Ameren Corporation (NYSE: AEE) is among the nation's 25
largest investor-owned electric utilities, with $10 billion in assets. Ameren
companies provide energy services to 1.5 million electric customers and 300,000
natural gas customers throughout its 44,500 square mile territory in Missouri
and Illinois. Within the Mid-American Interconnected Network, or MAIN, region,
an area that includes most of Illinois, eastern portions of Missouri and
Wisconsin, and much of peninsular Michigan, Ameren holds the largest market
share of installed generating capacity (approximately 22 percent).

   Ameren Corporation is a public utility holding company registered under the
Public Utility Holding Company Act of 1935, which we refer to as PUHCA, and
does not own or operate any significant assets other than the stock of its
subsidiaries. Ameren Corporation, directly or indirectly, owns all of the
common stock of these principal subsidiary companies:

  .  Union Electric Company, which we refer to as AmerenUE, the largest
     electric utility in the state of Missouri that supplies electric and
     natural gas service to about 1.2 million electric customers and 130,000
     gas customers in Missouri and Illinois.

  .  AmerenCIPS, an electric utility in the state of Illinois that supplies
     electric and natural gas service to about 325,000 electric customers and
     170,000 gas customers in portions of central and southern Illinois.

  .  AmerenEnergy Resources Company, which we refer to as Resources, a holding
     company for Ameren Corporation's nonregulated generation, related
     marketing and fuel procurement businesses.

  .  AmerenEnergy, Inc., which we refer to as Ameren Energy, an energy trading
     company that acts as agent for AmerenUE and our company for the wholesale
     purchase and sale of electricity for terms of less than one year.

                                      1

<PAGE>

  .  Ameren Services Company, which we refer to as Ameren Services, which
     provides shared support services to all of the Ameren companies.

  .  AmerenEnergy Development Company, which we refer to as Development Co.,
     our nonregulated parent company which develops and constructs generating
     facilities. Development Co. is also an exempt wholesale generator and
     leases the operating combustion turbine units from us at our Joppa,
     Illinois location.

  .  AmerenEnergy Marketing Company, which we refer to as Marketing Co., a
     nonregulated wholesale and retail energy marketing company that
     concentrates on wholesale sales of electricity for terms greater than one
     year and retail sales.

  .  AmerenEnergy Fuels and Services Company, which we refer to as Fuels Co., a
     nonregulated subsidiary that manages coal, natural gas and fuel oil
     purchasing for Ameren on a centralized basis.

  .  Our company, an exempt wholesale generator under PUHCA.

   In addition, Ameren Corporation holds, indirectly through AmerenUE and
AmerenCIPS, a 60% ownership interest in Electric Energy, Inc., which we refer
to as 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. Ameren Corporation's indirect
ownership interest in EEI is comprised of AmerenUE's 40% ownership interest in
EEI's common stock and AmerenCIPS' 20% ownership interest in the common stock.
Before mid-year 2002, AmerenCIPS expects to transfer its common stock interest
in EEI to Resources, which will complete the process of achieving a full
divestiture of all electric generating capacity that had been owned by
AmerenCIPS.

Generating Business

   Our generating business included the following as of March 1, 2002:

   Coal and Oil-Fired Plants.  The following stations, which we refer to as our
coal plants because they predominantly use coal for fuel: Four generating
stations (11 units) we acquired from AmerenCIPS (Newton, Coffeen, Meredosia and
Hutsonville in Illinois). These plants can generate approximately 2,695
megawatts of electricity. As of December 31, 2001 and 2000, approximately 82
and 50 days, respectively, supply of coal was in inventory for the coal plants.
We also acquired a coal plant located in Grand Tower, Illinois from AmerenCIPS.
However, this plant has since been repowered with gas turbine generators and
therefore is no longer considered a coal plant.

   Operating Combustion Turbine Units.  The following stations, which we refer
to as our operating combustion turbine units: Six generating stations (Columbia
in Missouri and Kinmundy, Gibson City, Pinckneyville, Grand Tower and Joppa in
Illinois), consisting of 21 newly acquired combustion turbine generating units.
These stations principally use natural gas as fuel (some also have capability
to use oil) and will be used to supply intermediate and peaking power. These
stations can generate approximately 1,635 megawatts of electricity.

   As of December 31, 2001, we had 4,330 megawatts of total generating
capacity. By the end of 2002, we intend to purchase from Development Co. four
combustion turbine generating units at Elgin, Illinois, thereby increasing our
generating capacity to 4,798 megawatts. These combustion turbine generating
units are expected to provide additional capacity of up to 468 megawatts at a
cost of approximately $222 million and be available for commercial operation by
the end of 2002. We currently have no plans to develop additional capacity
beyond 2002.

                                      2

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   The following table sets out detail of fuel supply for our generating
facilities:

<TABLE>
<CAPTION>
Cost of Fuels                                                         Year
-------------                                     --------------------------------------------
                                                    2001     2000     1999     1998     1997
                                                  -------- -------- -------- -------- --------
<S>                                               <C>      <C>      <C>      <C>      <C>
AmerenEnergy Generating Company/AmerenCIPS*
Per Million BTU-- --Coal......................... 121.791c 123.770c 139.700c 152.738c 163.000c
                 --Natural Gas**................. 439.744c       --       --       --       --
                 --System........................ 142.120c 129.169c 140.615c 155.045c       --
</TABLE>
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  *Since May 1, 2000, when AmerenCIPS' electric generating facilities and
   related fuel supply agreements were transferred to our company, we have been
   responsible for fuel costs. Prior to that, fuel costs were the
   responsibility of AmerenCIPS.
 **Prior to 2001, the use of natural gas was minimal. The fuel cost for natural
   gas in 2001 represents the actual cost of the natural gas commodity and
   variable costs for transportation, storage, balancing and fuel losses for
   delivery to the plant gate. In addition, the fixed costs for firm
   transportation and firm storage capacity are included to calculate a "fully
   loaded" fuel cost for the generating facilities.

   Our peak summer electrical demand in 2001 was 3,064 megawatts. Approximately
67% of our generating capability for the 2001 peak summer electrical demand was
fueled by coal and 28% by natural gas.

Power Purchase Agreements

   We have a power purchase agreement with Marketing Co., which we refer to as
the Genco-Marketing Co. agreement. Marketing Co., in turn, has a power purchase
agreement with AmerenCIPS, which we refer to as the Marketing Co.-CIPS
agreement. Under these power purchase agreements, we agree to supply to
Marketing Co., and Marketing Co., in turn, agrees to supply to AmerenCIPS, all
of the energy and capacity needed by AmerenCIPS to fulfill its obligations to
offer service to its retail customers. For capacity and energy needed to meet
its obligations to retail tariff customers, AmerenCIPS pays Marketing Co. fixed
prices. For its fixed-price retail contracts, AmerenCIPS pays Marketing Co. the
price it receives under these contracts. Under the Genco-Marketing Co.
agreement, Marketing Co. "passes through" to us the amounts received under the
Marketing Co.-CIPS agreement. The Marketing Co.-CIPS agreement will terminate
December 31, 2004. The Genco-Marketing Co. agreement will remain in effect
unless terminated by either party upon at least one year's notice, but may not
be terminated prior to December 31, 2004.

   Marketing Co. also purchases power from us under the Genco-Marketing Co.
agreement to supply its obligations under various long-term wholesale contracts
which Marketing Co. has directly with various municipal and cooperative
distribution and other customers. We will also supply power to serve other new
wholesale and retail contracts which Marketing Co. may enter into. Marketing
Co. will pass through to us the prices it receives under these wholesale and
retail contracts. In addition, see "Liquidity and Capital Resources" in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" for information regarding Marketing Co.'s agreements to supply a
portion of the power that it purchases from us to AmerenUE during 2001 and 2002.

   As of December 31, 2001, approximately 65% of the contracted loads portion
of our revenues were attributable to AmerenCIPS and approximately 35% were
attributable to other existing wholesale customers. These percentages exclude
any revenues attributable to Ameren Energy power sales as discussed further
below.

   If Ameren Energy can purchase power for our account at a lower cost than we
can generate it ourselves, that purchased power can be delivered in
satisfaction of our delivery requirements under our Genco-Marketing Co.
agreement and, to the extent we receive fixed prices under the Genco-Marketing
Co. agreement and Marketing Co.-AmerenCIPS agreement, we will receive the
economic benefits of that lower cost power.

   Marketing Co. may sell power from sources other than us. The profits and
losses from these incremental purchases and sales will accrue to Marketing Co.
and not us.

                                      3

<PAGE>

Other Power Sales Arrangements

   Marketing Co. and Ameren Energy (as an agent for us) will market that
portion of the output of our generating facilities which is not subject to the
power purchase agreements described above.

  .  Marketing Co. will sell energy, capacity and other energy related products
     pursuant to wholesale contracts with terms of greater than one year and
     retail contracts. It will do this through new wholesale and retail
     contracts which it may enter into.

  .  Ameren Energy will sell available power either under wholesale contracts
     of less than one year in length, or in spot wholesale market transactions,
     subject to an agreement--the amended joint dispatch agreement --which
     governs the financial and operating arrangements between our generating
     units and the generating units owned by AmerenUE.

   Ameren Energy's primary focus as an energy trading company includes
optimizing the value of our generation portfolio by extracting maximum value
from our excess generating capacity consistent with Ameren's risk management
practices.

   As more of our capacity and energy becomes available for resale following
the expiration of Marketing Co.'s existing contracts, we plan to continue to
utilize Marketing Co. to market most of our output under long-term wholesale
contracts and retail transactions. We expect to maintain a portion of our
output for marketing by Ameren Energy (under short-term wholesale contracts or
in spot wholesale transactions), which should provide a physical hedge to
support our longer term contracts, and should allow Ameren Energy to optimize
the value of our portfolio.

   Marketing Co.'s objective is to be a leading wholesale and retail energy
marketing company in our region. Marketing Co.'s strategy will:

  .  Target the industrial, municipal and large commercial customers and retail
     aggregators who seek price stability;

  .  Optimize new and existing generating assets on an integrated basis with
     its affiliates; and

  .  Differentiate its strategy from competitors by offering term contracts
     supported by generating resources.

   Marketing Co. will initially focus on customers in Missouri, Illinois,
Indiana and Ohio where there is the greatest opportunity for success in the
wholesale markets. It will capitalize on our current and planned generating
capacity by focusing on customers with a need for price certainty and an
aversion to supply risk.

Capital Program and Financing

   For information on our capital program and financial needs, see "Liquidity
and Capital Resources" in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and Note 7 to the "Notes to Financial
Statements" included in this report.

   Pursuant to the indenture relating to our senior notes issued on November 1,
2000, in order to incur additional indebtedness (other than certain
intercompany borrowings and debt assumptions), our company must comply with a
senior debt service coverage test and a senior debt to capital test, both after
giving effect to the additional indebtedness contemplated. For the senior debt
service coverage test, generally, the ratio of our earnings before interest,
tax, depreciation and amortization to interest and principal payments, if any,
on our senior indebtedness must be two and one-half times or greater for the
most recently ended four fiscal quarters at the time of performing the test.
The senior debt to capital test, generally, requires that our ratio of senior
debt to total capital must not exceed 60% as of the most recently ended fiscal
quarter for which financial statements have been prepared. However,
notwithstanding the two tests described above, we may incur such additional
indebtedness if each of Moody's Investors Services, Inc. and Standard & Poor's
Ratings Services provides a ratings reaffirmation of the ratings then in effect
after giving effect to the additional indebtedness. We are

                                      4

<PAGE>

currently in compliance with the senior debt service coverage test and the
senior debt to capital test. See "Liquidity and Capital Resources" in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and Note 4 to the "Notes to Financial Statements" included in this
report for information on our senior notes.

Regulation

Federal Utility Regulation

   Federal Power Act.

   Under the Federal Power Act, the Federal Energy Regulatory Commission, or
FERC, has exclusive rate-making jurisdiction over wholesale sales of energy and
transmission in interstate commerce. FERC regulates the owners of facilities
used for the wholesale sale of energy and transmission in interstate commerce
as "public utilities" under the Federal Power Act. We are a "public utility"
under the Federal Power Act.

   All public utilities subject to FERC jurisdiction are required to obtain
FERC's acceptance of their rate schedules in connection with the wholesale sale
of energy. FERC has approved our Genco-Marketing Co. agreement and related rate
schedules whereby we sell capacity and energy to Marketing Co. FERC has also
approved the Marketing Co.-CIPS agreement whereby Marketing Co. sells capacity
and energy to AmerenCIPS and has approved Marketing Co. making sales of energy
to unaffiliated persons at market-based rates. FERC has also approved the
arrangement and rate schedules whereby Ameren Energy acts as our agent to make
sales of energy on our behalf to unaffiliated persons at market-based prices.
See "Liquidity and Capital Resources" in "Management's Discussion and Analysis
of Financial Condition and Results of Operations" for information regarding
FERC's approval of a power purchase agreement between Marketing Co. and
AmerenUE.

   We are subject to a FERC-approved "code of conduct" which regulates our
arrangements and transactions with our affiliates. Our request for waivers from
FERC to avoid being subject to regulation regarding accounting, record-keeping
and reporting requirements otherwise imposed on utilities subject to FERC
jurisdiction was rejected in April 2001.

   We currently have authority from FERC to issue at any time prior to June 23,
2002 up to $575 million of long-term debt and to have up to $300 million of
short-term debt in aggregate amount outstanding at any time.

    Public Utility Holding Company Act.

   Our parent, Ameren Corporation, is a holding company registered under PUHCA.
Under PUHCA, any entity that owns or controls 10% or more of the outstanding
voting securities of a "public utility company" or a company that is a "holding
company" of a public utility company is subject to regulation under PUHCA,
unless an exemption is obtained or the Securities and Exchange Commission, or
SEC, determines that such entity is not a holding company within the meaning of
PUHCA. A holding company not entitled to an exemption must register. Registered
holding companies are required to limit their utility operations generally to a
single integrated public utility system and only such other businesses as are
functionally related to the operations of the utility system. Except as noted
below, subsidiaries of a registered holding company are subject to regulation
of activities such as issuance of securities, affiliate transactions and
financial reporting requirements.

   Under the Energy Policy Act of 1992, a company engaged exclusively in the
business of owning and/or operating facilities used for the generation of
electric energy exclusively for sale at wholesale may be certified as an
"exempt wholesale generator." An exempt wholesale generator is not a "public
utility company" as defined in PUHCA. We received certification from FERC as an
exempt wholesale generator in 2000 and continued exempt wholesale generator
status orders have been issued by FERC with each combustion turbine generating
unit that has been added to our generating business. We received the necessary
approvals from the Illinois Commerce Commission, or ICC, and the Missouri
Public Service Commission, or MoPSC, finding that the transfer of the coal
plants from AmerenCIPS to us would benefit customers, was in the public
interest and did not violate

                                      5

<PAGE>

applicable state law. Our arrangements with Marketing Co., AmerenCIPS and
Ameren Energy are in compliance with the provisions under PUHCA designed to
prevent affiliate abuse applicable to exempt wholesale generators and
affiliated public utility companies. See "Liquidity and Capital Resources" in
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" for information on a proceeding regarding alleged affiliate abuse
in a power purchase agreement between Marketing Co. and AmerenUE.

   As an exempt wholesale generator, we are exempt from most of the provisions
of PUHCA that otherwise would apply to us as a subsidiary of a registered
holding company. Issuance of securities by us is not subject to approval by the
SEC under PUHCA. The SEC has no jurisdiction over the sale of electricity by us
to affiliates or non-affiliates. The SEC may impose limitations on Ameren
Corporation in connection with its financing for the purpose of investing in
exempt wholesale generators and foreign utility companies if Ameren
Corporation's aggregate investment in such activities exceeds 50% of its
consolidated retained earnings. At December 31, 2001, Ameren Corporation's
aggregate investment in those entities was 31.7% of its consolidated retained
earnings.

State Utility Regulation

   The ICC regulates electric public utility companies under the Illinois
Public Utilities Act, or IPUA. We are not a public utility under the IPUA and
are not subject to regulation by the ICC as to rates, issuance of securities or
other matters.

   We are not subject to the jurisdiction of the MoPSC.

   In December 1997, the Governor of Illinois signed the Illinois Customer
Choice 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 Customer Choice Law include the phasing-in
through 2002 of retail direct access, which allows customers to choose their
electric generation suppliers. The phase-in of retail direct access began on
October 1, 1999, with large commercial and industrial customers principally
comprising the initial group that is entitled to choose suppliers. Retail
direct access was offered to the remaining commercial and industrial customers
on December 31, 2000 and will be offered to residential customers by May 1,
2002.

   In many states, including Illinois, companies who sell electricity directly
to retail customers under deregulation legislation must be registered or
licensed. Marketing Co. has obtained "alternative retail electricity supplier,"
or ARES, status in Illinois and plans to seek comparable status in other states
where retail competition is developing.

Regional Transmission Organizations and Independent System Operators

   All owners of transmission facilities subject to FERC jurisdiction must make
their transmission system available for use by all generators of electricity in
an open and non-discriminatory manner. Marketing Co. and Ameren Energy arrange
to transmit the power we generate and that Marketing Co. and Ameren Energy sell
to customers by reserving transmission on the system of Ameren and other
transmission owners through Open Access Transmission Tariffs. FERC is fostering
better transmission access and more liquid markets for transmission capacity by
encouraging the formation of independently operated Regional Transmission
Organizations, or RTOs. Under FERC Order 2000, an RTO is an entity that
satisfies minimum characteristics (independence, scope and regional
configuration, operational authority and short-term reliability) and minimum
functions (tariff administration and design, congestion management, parallel
path flow, ancillary services, information access, market monitoring, planning
and expansion and interregional coordination). The introduction of RTOs will
eliminate "pancaked" transmission rates within RTOs making it more feasible for
Marketing Co. and Ameren Energy to sell the electricity we generate over a
broader market.

                                      6

<PAGE>

   In the fourth quarter of 2000, Ameren Corporation announced its intention to
withdraw from the Midwest Independent System Operator, or the Midwest ISO, and
to join the Alliance Regional Transmission Organization, or the Alliance RTO.
For more information on Ameren Corporation's withdrawal from the Midwest ISO
and its entry into the Alliance RTO, including related regulatory proceedings,
see "Liquidity and Capital Resources" in "Management's Discussion and Analysis
of Financial Condition and Results of Operations."

Environmental Regulation

   We must comply with federal, state and local environmental regulations
relating to the safety and health of personnel, the public and the environment,
including the identification, generation, storage, handling, transportation,
disposal, recordkeeping, labeling, reporting of and emergency response in
connection with hazardous and toxic materials, safety and health standards, and
environmental protection requirements, including standards and limitations
relating to the discharge of air and water pollutants. Failure to comply with
any such statutes or regulations could have material adverse effects on us,
including the imposition of criminal or civil liability by regulatory agencies
or civil fines and liability to private parties, and the required expenditure
of funds to bring us into compliance. All required permits under air and water
pollution control regulations have been obtained, are pending or are in the
process of being applied for with respect to our operating combustion turbine
units and additional units, which we refer to as the committed units, that we
expect to acquire at the Elgin Energy Center commencing in August 2002. We have
no reason to believe that we will be unable to obtain pending permits in a
timely manner.

   The operator of the Joppa station, through its parent corporation, is
responsible for environmental compliance for the Joppa station. The Joppa
station is not included within our SO\\2\\ and NO\\x\\ emission allowance
compliance programs.

    Air Emission Compliance.

   We believe we are currently in material compliance with all applicable state
and federal air regulations through a combination of unit-specific and
system-wide compliance strategies. We believe all necessary approvals and
reporting procedures have been implemented with the Illinois Environmental
Protection Agency, or the IEPA, the Missouri Department of Natural Resources,
or the MDNR, and the United States Environmental Protection Agency, or the
USEPA. We employ an emissions averaging and trading program to comply with
certain sulfur dioxide and nitrogen oxides regulations.

    Sulfur Dioxide (SO\\2\\).

   SO\\2\\ emissions are regulated under Title IV of the Federal Clean Air Act
Amendments of 1990, or CAAA, by the USEPA New Source Performance Standards, or
NSPS, and by the IEPA regulations and operating permit requirements. Meredosia
unit 4/boiler 6 and Newton units 1 and 2 are subject to Subpart D of the NSPS
and have 0.8 pounds of SO\\2\\-per-million British thermal units, or BTU ("lb
SO\\2\\/mmBTU") and 1.2 lb SO\\2\\/mmBTU emission standards, respectively.
Coffeen, Hutsonville and the remaining units at Meredosia are subject to
state-only plant lb SO\\2\\/hr emission limitations ranging from 8,536 lb/hr to
55,555 lb/hr. The Grand Tower repowered combined cycle plant is subject to
Subpart Da and Subpart GG of the NSPS. Our simple cycle combustion turbine
units at Columbia, Kinmundy, Gibson City, Pinckneyville, and the committed
units at Elgin, are subject to Subpart GG of the NSPS.

   Title IV establishes an allowance trading program with two phases introduced
over five years. Phase II of the Title IV SO\\2\\ program went into effect
January 1, 2000 and includes all of our coal plants, operating combustion
turbine units and the committed units.

   With the implementation of Phase II, our units will need to obtain SO\\2\\
allowances to meet these new requirements. There are presently no flue gas
desulfurization systems at our stations which could reduce SO\\2\\

                                      7

<PAGE>

emissions. We burn lower-sulfur Illinois coal at the Coffeen station and
low-sulfur Powder River Basin coal at the Newton station to help lower annual
emissions of SO\\2\\. In addition, the repowering and resulting conversion of
the Grand Tower station to natural gas has provided additional reductions in
SO\\2\\ emissions.

   After giving effect to the above compliance measures, we estimate that there
will be an annual shortfall between the number of allowances allocated to each
of our units and expected annual emissions. The current strategy for our plants
is to purchase allowances at market value or to transfer allowances at cost
from the bank of surplus allowances owned by our affiliate, AmerenUE. The
AmerenUE SO\\2\\ allowance bank was approximately 392,000 allowances at the end
of 2001. In January 2001, we exchanged 162,840 SO\\2\\ allowances with vintages
of 2006 and later with AmerenUE for 120,000 SO\\2\\ allowances with vintages of
2002 and earlier. The market value of the allowances exchanged was
approximately equal. We completed this exchange because we experienced a
shortfall of SO\\2\\ allowances in 2000 and 2001 and we are projecting a
shortfall in SO\\2\\ allowances in 2002 under current generation plans. This
transaction was recorded at the historical cost of the allowances. We may alter
our generation plan or increase our use of low-sulfur coal to improve our
position in SO\\2\\ allowances.

    Nitrogen Oxides (NO\\x\\).

   NO\\x\\ emissions are regulated under Title IV of the CAAA, by NSPS and by
the IEPA operating permit requirements. All of our combustion turbine units are
subject to Subpart GG of the NSPS. Meredosia unit 4/boiler 6 and Newton units 1
and 2 are subject to Subpart Da of the NSPS and have 0.3 lb NO\\x\\/mmBTU and
0.7 lb NO\\x\\/mmBTU emission standards respectively. All coal-fired units at
Coffeen, Hutsonville, Meredosia and Newton are subject to the CAAA Title IV,
Phase II NO\\x\\ limitations beginning on January 1, 2000 and ranging from 0.45
lb NO\\x\\/mmBTU to 0.86 lb NO\\x\\/mmBTU.

   In order to comply with the annual NO\\x\\ limitations under Phase II of the
Title IV NO\\x\\ program, a unit must either meet the individual limit for the
boiler type or achieve equivalent compliance by means of an averaging plan. In
June 2001, we submitted a revised averaging plan to the IEPA. Ameren has chosen
to utilize a system-wide averaging plan for all of our generating facilities,
as the compliance strategy for Phase II NO\\x\\ requirements. The IEPA has
issued a permit approving the averaging plan. Emission data through February
2002 indicates that our units are in compliance with the approved averaging
plan.

   Illinois has adopted NO\\x\\ control regulations that affect our stations.
In December 2000, the Illinois Pollution Control Board, or IPCB enacted
regulations designed to comply with USEPA's "SIP Call" rule. The regulations
contain a tonnage cap on NO\\x\\ emissions based on 0.15 lb NO\\x\\/mmBTU
during the ozone season and are effective May 31, 2004. The ozone season is
defined as May 1 through September 30.

   Under the IEPA regulations, NO\\x\\ compliance can be achieved through an
emission allowance trading program. Each unit would be allocated NO\\x\\
emission allowances annually for the ozone season. In order to comply with the
proposed rules, we will need to rely on strategies beyond allowance trading.
Ameren plans to employ several NO\\x\\ emission reduction technologies
including selective catalytic reduction, low NO\\x\\ burner and overfire air
retrofit, repowering and combustion optimization. We estimate making capital
expenditures of $210 million to comply with these regulations, of which
approximately $50 million was spent in 2001. We believe we can meet the NO\\x\\
requirements with these strategies.

   In accordance with the terms of regulations issued by the MDNR, our Columbia
combusion turbine units are subject to an emission limit of .35 lb
NO\\x\\/mmBTU during the ozone season. We are in the process of applying for an
operating permit for the Columbia units. Pending its issuance, we are allowed
to operate the units under the construction permit issued by the MDNR.

    New Source Review.

   In the fall of 1999, the USEPA initiated enforcement actions against 32
coal-fired generating units for alleged new source review, or NSR, violations.
The USEPA claims that the units failed to install pollution

                                      8

<PAGE>

control technology following various major unit modifications. We have not been
named in these enforcement actions and, to date, we have not received requests
for information concerning potential NSR violations at our generating
facilities.

    Particulates and Opacity.

   In July 1997, the USEPA 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 USEPA for resolution. The USEPA 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 SO\\2 and NOx
emissions from our power plants by 2008. At this time, we are unable to predict
the ultimate impact of these revised air quality standards on our future
financial condition, results of operations or liquidity. \\

   For all of our coal plants, operating permit conditions allow operation
during periods of opacity exceedances that are due to startup, shutdown,
malfunction and breakdown. Excess opacity emissions have occurred at each of
our coal plants, as is common at many coal-fired generating units. We deploy
engineering practices, such as load reductions, designed to minimize the
magnitude and duration of opacity exceedances.

   Other Air Pollutant Considerations.

   In December 1999, the USEPA issued a decision to regulate mercury emissions
from coal-fired power plants by 2008. The USEPA is expected to propose
regulations by 2004. These regulations have the potential to add significant
capital and/or operating costs to our generating system after 2005. On July 20,
2001, the USEPA issued proposed Best Available Retrofit Technology 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
SO\\2 and NOx emissions. These rules could also add significant pollution
control costs to our generating system between 2008 and 2012. At this time, we
are unable to predict the ultimate impact of these revised air quality
standards on our future financial condition, results of operations or
liquidity. \\

   In addition, the United States Congress has been working on legislation to
consolidate the numerous air pollution regulations facing the utility and power
generating 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 any such legislation are expected to be incurred in phases
from 2007 through 2015. At this time, we are unable to predict the ultimate
impact of the above expected regulations and this legislation on our future
financial condition, results of operations, or liquidity; however, the impact
could be material.

   The IPCB has issued a nonbinding informational order concerning
environmental regulation of natural gas-fired, peak-load electrical operating
facilities, or peaker plants, such as most of our combustion turbine generating
units. In its informational order, the IPCB recommends that the State of
Illinois tighten current environmental regulations concerning peaker plants. In
response to the informational order, IEPA may propose more stringent
regulations for peaker plants.

   Water and Waste Water Compliance.

   Our stations are permitted under the National Pollutant Discharge
Elimination System, or the NPDES, which is administered by the IEPA. Wastewater
treatment facilities have been provided to ensure compliance

                                      9

<PAGE>

with permitted discharge limits. NPDES sampling data currently indicate general
compliance with permit requirements.

   Our Newton, Grand Tower and Meredosia stations all have active unlined ash
impoundment systems. We close ash ponds when storage capacity becomes
exhausted. Under Illinois law, the closure of ash ponds must comply with
landfill and certain groundwater regulations. In general, fly ash basins
constructed in the future will have to be lined at a greater cost than
facilities used historically.

   Solid and Hazardous Waste Compliance.

   Coal-fired generating facilities create fly ash and bottom ash as
by-products of the coal combustion process. Accordingly, the primary large
volume waste for our coal plants is fly ash and, to a lesser extent, bottom
ash. Depending upon the station, fly ash is typically disposed of at an
off-site commercial landfill or onsite at a permitted landfill, or treated
through a surface impoundment system or used by cement kilns. Bottom ash is
either disposed of on site in a surface impoundment system or is used by third
parties for road cinders or building or roofing materials.

   Newton Landfill.  The Newton Phase I landfill operated from 1978 until its
final closure in 1998. Waste product (scrubber sludge) from a now retired
sulfur dioxide removal system, fly ash and bottom ash from our coal plants were
deposited into the Phase I landfill. The Newton station currently operates a
Phase II landfill permitted for chemical and industrial wastes. Low volume
plant wastes, fly ash and bottom ash from the Newton station are deposited into
the Newton Phase II landfill. The landfill's design includes all modern
components of a solid waste disposal facility including leachate collection,
comprehensive groundwater monitoring and leak detection, liners and cap
materials, and load checking and gate control requirements. The Newton Phase II
landfill is located directly adjacent and south of the Newton Phase I landfill.
A shallow groundwater plume (approximately 12 feet below the ground surface) of
ash leachate exists south of the Phase I landfill and will be intercepted
during the construction of future Phase II landfill areas or cells. On March
18, 2002, the IEPA issued a violation notice relating to the maintenance of a
berm surrounding the Phase II landfill as well as alleging reporting
violations. Pursuant to the IEPA's request, we are in the process of preparing
a compliance commitment agreement to address the agency's concerns.

   Coffeen Landfill.  The Coffeen station currently back hauls fly ash to a
former coal mine for disposal or sends such wastes to permitted commercial
landfills or for use as product material in cement kilns. Bottom ash is
deposited in a pond. We are considering various other disposal alternatives.
Although construction of the landfill is not anticipated at this time, the
Coffeen station has obtained a permit to construct and operate a landfill for
chemical and industrial waste. The Coffeen station has also applied for an
underground injection control permit for the disposal of ash in a former mine
works under the station.

   Meredosia and Hutsonville.  Our remaining coal plants do not operate coal
combustion landfill facilities. Fly ash and bottom ash is either sent to
permitted commercial landfills or sluiced through a surface impoundment system.
Ash from surface impoundments is periodically removed and shipped to cement
kilns, landfilled or used for other beneficial purposes as authorized under
Illinois law.

   Although proposals have been made from time to time to change the
classification of ash from coal-fired electric generating facilities under
federal law, ash is not currently classified as a hazardous waste. The USEPA
recently announced its intent to develop national standards to address the
disposal of coal combustion wastes in landfills, surface impoundments and
mines. If ash is reclassified as a hazardous waste or very stringent national
ash disposal standards are adopted, the operating costs of our coal plants
would increase.

   The potential exists for past or future discreet instances of soil and
groundwater contamination at each of our coal plants due to their vintage and
the nature of their operation. We expect to rely on a contractual indemnity
from AmerenCIPS in the event we incur remediation costs at the sites of our
coal plants on account of environmental contamination that occurred prior to
our acquisition of the coal plants from AmerenCIPS.

                                      10

<PAGE>

   See "Liquidity and Capital Resources" in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and Note 7 to the
"Notes to Financial Statements" included in this report for additional
information on our environmental matters.

Employees

   We employ approximately 750 people primarily at our coal plants. Seventy-two
percent of our employees are represented by the International Brotherhood of
Electrical Workers Local 702 and the International Union of Operating Engineers
Local 148. The current collective bargaining agreements with these locals
extend until June 30, 2002.

   We believe that we have a good relationship with our employees.

ITEM 2.  Properties.

   The following are brief summaries of the coal plants that we acquired from
AmerenCIPS, the operating combustion turbine units and the committed units that
we expect to acquire at the Elgin station in 2002.

Coal Plants Acquired from AmerenCIPS

   The table below depicts selected characteristics of each of our coal plants.

<TABLE>
<CAPTION>
                                     Net Megawatt
                                      Installed     2001 Capacity Full Load Heat Rate
Facility                 Year Built Capability/(1)/    Factor          (Btu/kWh)
--------                 ---------- --------------  ------------- -------------------
<S>                      <C>        <C>             <C>           <C>
Newton Unit 1...........    1977         557            72.6%           10,103
Newton Unit 2...........    1982         575            53.1%           10,099
Coffeen Unit 1..........    1965         340            51.3%           10,209
Coffeen Unit 2..........    1972         560            45.4%           10,086
Meredosia Unit 1........    1948          62            23.4%           13,290
Meredosia Unit 2........    1949          62            23.4%           13,290
Meredosia Unit 3........    1960         215            47.0%            9,955
Meredosia Unit 4 (Oil)..    1975         168             3.8%           10,821
Hutsonville Unit 3......    1953          76            47.0%           10,811
Hutsonville Unit 4......    1954          77            42.6%           10,680
Hutsonville Diesel (Oil)    1968           3               0%            2,750
</TABLE>
--------
(1) This information represents generating capacity anticipated to be available
    for dispatch from the facility into the electric transmission grid at the
    time of the expected 2002 peak summer electrical demand.

   Newton Station

   The Newton station is located outside the town of Newton, Illinois, and
operates as a base-load facility. The station consists of two essentially
identical steam-electric generating units. The units are equipped with
electrostatic precipitators for control of particulate emissions. Both Unit 1
and Unit 2 use low NO\\x burners for NOx control. SO2 is controlled on Units 1
and 2 by burning low-sulfur coal, which is currently acquired from the Powder
River Basin. \\

   Coffeen Station

   The Coffeen station is located just outside the town of Coffeen, Illinois
and operates as a base-load facility. The station consists of two
steam-electric generating units. Units 1 and 2 are equipped with electrostatic
precipitators for particulate control. Units 1 and 2 have no special provisions
for SO\\2 control. Both units employ cyclone burners with an over-fire air
system installed in 1999 and 2000. Selective catalytic reduction systems will
be installed on Unit 2 during 2002 and on Unit 1 during 2003. \\

                                      11

<PAGE>

   Meredosia Station

   The Meredosia station is located on the Illinois River, in the town of
Meredosia, Illinois. The station consists of four steam-electric generating
units. Units 1, 2 and 3 are coal-fired units. Units 1, 2 and 3 operate as
intermediate facilities. Unit 4 is a peaking facility and is a pressurized,
reheat, oil-fired unit. Units 1, 2 and 3 are equipped with electrostatic
precipitators for control of particulates; Unit 4 has no precipitator. Units 1
and 2 have no special provisions for NO\\x control. Unit 3 has ABB-CE level 1
low NOx burners installed in 1997. The Unit 4 boiler is equipped with over-fire
air and gas recirculation to allow NOx control. None of the units have
provisions for control of SO2 emissions. \\

   Hutsonville Station

   The Hutsonville station is located along the Wabash River, outside of
Hutsonville, Illinois, and operates as an intermediate facility. The station
currently consists of two steam-electric generating units (Units 3 and 4) and a
three megawatt diesel oil-fired generator. Units 1 and 2 were retired in place
in 1982. Units 3 and 4 are identical coal-fired steam-electric generating
units. The units are equipped with electrostatic precipitators for control of
particulate emissions. The units have no special provisions for NO\\x or SO2
control. \\

Combustion Turbine and Combined Cycle Units

   The table below depicts select characteristics of each of our operating
combustion turbine units.

<TABLE>
<CAPTION>
                                                                                   Projected Net
                                              Net                                    Heat Rate
                    Commercial              Megawatt                               (natural gas
                    Operation              Installed                               HHV) per Unit
Facility               Date    No. Units Capability (1)    Fuel     Configuration    (Btu/kWh)
--------            ---------- --------- -------------- ----------- -------------- -------------
<S>                 <C>        <C>       <C>            <C>         <C>            <C>
Pinckneyville (1-4)     6/00       4          176       natural gas  simple cycle      9,784
Pinckneyville (5-8)   6-7/01       4          144       natural gas  simple cycle     12,338
Gibson City........   6-7/00       2          232        dual fuel   simple cycle     11,479
Joppa(2)...........     9/00       3          186       natural gas  simple cycle        N/A
Kinmundy...........   4-5/01       2          234        dual fuel   simple cycle     11,479
Columbia...........   6-7/01       4          144       natural gas  simple cycle     12,338
Grand Tower Station
  (repowered) (1/3)     6/01       1          249       natural gas combined cycle     7,801
Grand Tower Station
  (repowered) (2/4)    12/01       1          270       natural gas combined cycle     7,328
</TABLE>
--------
(1) This information represents generating capacity anticipated to be available
    for dispatch from the facility into the electric transmission grid at the
    time of the expected 2002 peak summer electrical demand.
(2) We have leased the Joppa units to Development Co., and will receive fixed
    lease payments which are not based on actual output or performance of the
    units.

Operating Combustion Turbine Units

   Pinckneyville Station

   The Pinckneyville station, a 320 megawatt simple cycle plant, is located
approximately three miles northeast of Pinckneyville, Illinois. The station is
a peaking plant and was initially commissioned for commercial operation in June
2000 with four GE LM6000 combustion turbine generators rated at 44 megawatts
and fired on natural gas. Four additional GE PG6581B combustion turbine
generators rated at 36 megawatts and fired on natural gas were subsequently
installed and became operational in June and July of 2001. Coolers and
mechanical chillers are used to increase the rated capacity during peak days.

                                      12

<PAGE>

   Gibson City Station

   The Gibson City station, a 232 megawatt simple cycle peaking facility, is
located within the Jordan Industrial Park in Gibson City, Illinois. The station
consists of two Siemens Westinghouse W501D5A gas combustion turbines operating
on simple cycle. The gas combustion turbines are equipped with dual fuel
combustors and have dry, low NO\\x while burning natural gas and water
injection for NOx control while burning fuel oil. The units became available
for commercial operation in June and July 2000. The units are equipped with the
most advanced noise-muffling system available for combustion turbines. \\

   Joppa Station

   We own three combustion turbine generators which we are leasing on a
long-term basis to Development Co. Lease revenues commenced in October 2000.
These three combustion turbines have been in operation since 1974 at another
location, and have been refurbished and relocated to the Joppa, Illinois site.
Each combustion turbine generator set utilizes a GE model MS7001B combustion
turbine rated at approximately 62 megawatts. The refurbishment included
increasing the gas turbine firing temperature, increasing the inlet airflow by
upgrading the variable inlet guide vanes, adding an inlet "fogging" cooling
system and converting the combustion system from fuel oil to natural gas. All
units became operational in September 2000.

   Kinmundy Station

   The Kinmundy station, a 234 megawatt simple cycle plant, is located
approximately three miles east of Patoka, Illinois. The station is a peaking
facility and consists of two Siemens Westinghouse W501D5A gas turbines
operating on simple cycle. The gas combustion turbines are equipped with dual
fuel combustors and have water injection for NO\\x control while burning fuel
oil. Unit 1 and Unit 2 became operational in April and May 2001, respectively.
\\

   Columbia Station

   The Columbia Energy Center is a 144 megawatt (net) station consisting of
four GE PG6581B combustion turbines. The Columbia Energy Center is located on
the eastern edge of Columbia, Missouri. These units are equipped with dry, low
NO\\x combustors for NOx control that fire on natural gas. These units became
operational in June and July of 2001. \\

   Grand Tower Station (repowered)

   The Grand Tower station, a 519 megawatt (net) repowered combined cycle
plant, is located in southern Illinois on the Mississippi River approximately
90 miles southwest of Carbondale, Illinois. The repowered project configuration
is an intermediate load facility and includes two Siemens Westinghouse 501FD
gas turbine generators to re-power the existing steam turbines for combined
cycle operation. New heat recovery steam generators with duct-firing capability
were installed to produce steam from the hot gas combustion turbine exhaust
gases. The steam is used to power the existing steam turbines for power
production. The gas combustion turbines burn only natural gas. The first unit
was operational in June 2001 and the second unit was operational in December
2001.

Committed Units

   Elgin Station

   The Elgin Energy Center, a 468 megawatt simple cycle plant, is located on
the southeast border of Elgin, Illinois. The station will be a peaking facility
and will consist of four Siemens Westinghouse W501D5A gas turbines operating in
simple cycle. The gas combustion turbines will be equipped with dry, low NO\\x
combustors for NOx \\control that fire on natural gas. Project construction
began in 2001 and the anticipated commercial operation dates are August 1, 2002
for Unit 1; September 1, 2002 for Unit 2; October 1, 2002 for Unit 3; and
November 1, 2002 for Unit 4.

                                      13

<PAGE>

ITEM 3.  Legal Proceedings.

   We are involved in 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. We believe that the final
disposition of these proceedings will not have a material adverse effect on our
company's financial position, results of operations or liquidity. For more
information on our legal and administrative proceedings, see "Liquidity and
Capital Resources" in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and Note 7 to the "Notes to Financial
Statements" included in this report.

                          Forward-Looking Statements

   Statements made in this report which are not based on historical facts, are
"forward-looking" and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
"forward-looking" statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions and
financial performance. In connection with the "Safe Harbor" provisions of the
Private Securities Litigation Reform Act of 1995, we are 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 effects of increased competition in the future;

  .  the impact on us of current regulations related to the phasing-in of the
     opportunity for some customers to choose alternative energy suppliers in
     Illinois;

  .  the effects of Ameren's 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 and electricity,
     including the use of financial and derivative instruments and volatility
     of changes in market prices;

  .  wholesale and retail pricing for electricity in the Midwest;

  .  business and economic conditions;

  .  interest rates and the availability of capital;

  .  actions of rating agencies and the effects of such actions;

  .  weather conditions;

  .  the impact of the adoption of new accounting standards;

  .  fuel prices and availability;

  .  generation plant construction, installation and performance;

  .  the impact of current environmental regulations on 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
     our generating facilities or required to satisfy energy sales made on our
     behalf; and

  .  legal and administrative proceedings.

                                      14

<PAGE>

                                    PART II

ITEM 5.  Market for Registrant's Common Equity and Related Stockholder Matters.

   There is no established trading market for our common stock. As of March 28,
2002, our parent, Development Co., was the only shareholder of record of our
common stock.

ITEM 6.  Selected Financial Data.

                Summary Historical Financial and Operating Data

   The historical operating data presented below reflects our operations since
May 1, 2000. The historical financial data presented below is derived from our
audited financial statements included elsewhere in this report.

<TABLE>
<CAPTION>
                                                        For the period from
                                                            May 1, 2000
                                     For the year ended       through
                                     December 31, 2001   December 31, 2000
                                     ------------------ -------------------
                                                 (In thousands)
     <S>                             <C>                <C>
     Operating revenues.............     $  985,819         $  479,701
     Operating income...............        195,152            103,268
     Net income.....................         75,924             43,808
     EBITDA.........................        253,290            134,179

     As of December 31,
     Current assets.................     $  193,396         $  240,427
     Total assets...................      1,756,928          1,393,662
     Long-term debt.................        423,880            423,676
     Subordinated intercompany notes        508,082            601,626
     Total liabilities..............      1,482,548          1,349,852
     Total stockholder's equity.....        274,380             43,810
</TABLE>

                                      15

<PAGE>

ITEM 7.  Management's Discussion and Analysis of Financial Condition and
Results of Operations.

                                   Overview

   AmerenEnergy Generating Company (the Company or Genco) is an indirect
nonregulated electric generating subsidiary of AmerenEnergy Resources Company
(Resources), which is a subsidiary of Ameren Corporation (Ameren). Ameren is a
holding company registered under the Public Utility Holding Company Act of 1935
(PUHCA). Ameren's other primary operating companies are Union Electric Company
(AmerenUE) and Central Illinois Public Service Company (AmerenCIPS). In
conjunction with the Illinois Electric Service Customer Choice and Rate Relief
Law of 1997 and following the receipt of all required state and federal
regulatory approvals, AmerenCIPS transferred its electric generating assets and
related liabilities on May 1, 2000 at historical net book value, to Genco, a
newly created nonregulated company, in exchange for a subordinated promissory
note in the amount of $552 million from the Company and 1,000 shares of the
Company's common stock. Through a series of transactions on May 1, 2000
following the issuance of the Company's common stock to AmerenCIPS,
AmerenEnergy Development Company (Development Co.) acquired all of outstanding
shares of the Company's common stock.

   Resources is a holding company for Ameren's nonregulated electric generation
business whose principal subsidiaries include the Company, Development Co.,
AmerenEnergy Fuels and Services Company (Fuels Co.) and AmerenEnergy Marketing
Company (Marketing Co.). The Company qualifies as an exempt wholesale generator
under PUHCA and acts as Resources' primary vehicle for the ownership and
operation of its nonregulated electric generation assets. Development Co.
develops and constructs generation assets for the Company, and the Company
purchases generation assets from Development Co. when the assets are available
for commercial operation. Fuels Co. acts as the Company's agent and manages the
Company's coal, natural gas and fuel oil procurement and supply. Marketing Co.
sells wholesale energy, capacity and other energy products for terms in excess
of one year, and makes sales to the retail market. In addition, AmerenEnergy,
Inc. (AmerenEnergy), Ameren's wholly owned energy trading and marketing
subsidiary, acts as agent for the Company and enters into contracts for the
wholesale purchase and sale of energy on its behalf for terms of less than one
year.

   Ameren Services Company (Ameren Services), a wholly owned subsidiary of
Ameren, provides shared support services for Ameren and all Ameren
subsidiaries, including the Company. Charges are based upon the actual costs
incurred by Ameren Services, as required by PUHCA.

   On May 1, 2000, the Company and Marketing Co. entered into an electric power
supply agreement (the Genco-Marketing Co. agreement) (amended August 14, 2000
and March 30, 2001) under which Marketing Co. is entitled to purchase all of
the Company's energy and capacity. Any energy that Marketing Co. does not
purchase will be released to AmerenEnergy, which will seek to market it on the
Company's behalf. Also on May 1, 2000, Marketing Co. and AmerenCIPS entered
into an electric power supply agreement (the Marketing Co.-CIPS agreement)
(amended March 30, 2001) to supply sufficient power to meet AmerenCIPS' native
load and other requirements. A portion of the capacity and energy supplied by
the Company to Marketing Co. is resold to AmerenCIPS for resale. The portion of
these sales to AmerenCIPS that is used for resale to native load customers is
at rates (which approximate the historical regulated rates for generation)
specified by the Illinois Commerce Commission (ICC). The portion of the sales
to AmerenCIPS resold to those retail customers allowed choice of an electric
supplier under state law is at fixed market-based prices. Other capacity and
energy purchased by Marketing Co. from the Company will be used by Marketing
Co. to serve its obligations under various long-term wholesale contracts it
assumed from AmerenCIPS and other long-term wholesale and retail contracts
Marketing Co. has or will enter into. The Marketing Co.-CIPS agreement expires
December 31, 2004 and the Genco-Marketing Co. agreement may be terminated upon
at least one year's notice given by either party, but in no event can it be
terminated prior to December 31, 2004. See Note 2--Related Party Transactions
to the "Notes to Financial Statements."

   Prior to AmerenCIPS' transfer of its generating assets to the Company on May
1, 2000, AmerenCIPS and AmerenUE jointly dispatched their generation pursuant
to a joint dispatch agreement. In connection with the asset transfer,
AmerenCIPS assigned its electric generation rights and obligations under this
agreement to the

                                      16

<PAGE>

Company and the agreement was amended to reflect the fact that the Company now
owns and operates the generation assets previously owned by AmerenCIPS. As a
result, the Company jointly dispatches generation with AmerenUE under an
amended joint dispatch agreement. Under the amended agreement, the Company and
AmerenUE are entitled to serve load requirements from their own least-cost
generation first, and then will allow the other company access to any available
excess generation. All of the Company's sales to Marketing Co. are considered
load requirements. Sales made by the Company to other customers through
AmerenEnergy, as the Company's agent, are not considered load requirements.

   The assets transferred to the Company in May 2000 included the five
coal-fired electric generating stations located in Newton, Coffeen, Meredosia,
Grand Tower (now a combined cycle gas-fired electric generating station) and
Hutsonville, Illinois (referred to as the coal plants) along with other rights,
assets and liabilities related to the generation of electricity by AmerenCIPS.
These electric generating facilities had a combined total generating capacity
of 2,860 megawatts at the time of the transfer. Seven hundred and fifty
employees, or approximately 45% of AmerenCIPS' workforce, were also transferred
to the Company as part of the transfer of the coal plants.

   In June and July of 2000, the Company acquired six combustion turbine
generating units at Pinckneyville and Gibson City, Illinois from Development
Co. at Development Co.'s historical net book value. The total installed cost of
these combustion turbine generating units was approximately $200 million. These
units represent 408 megawatts of capacity.

   In September 2000, the Company also acquired three combustion turbine
generating units at Joppa, Illinois from an affiliate at the affiliate's
historical net book value. The total installed cost of these combustion turbine
generators was approximately $73 million. These units represent 186 megawatts
of capacity. The Company entered into an operating lease agreement with
Development Co. for these units at the Joppa site wherein the three combustion
turbine generating units were leased to Development Co. for a minimum term of
fifteen years expiring September 30, 2015. The Company receives rental payments
under the lease in fixed monthly amounts that vary over the term of the lease
and range from $0.8--$1.0 million per month. Development Co. is entitled to all
of the output produced from the three units and is responsible for all
operating expenses. Development Co. entered into an agreement with Midwest
Electric Power, Inc., an affiliate, under which Midwest Electric Power, Inc.
provides operations and maintenance services at the Joppa site. On November 1,
2000, Development Co. and Marketing Co. entered into an electric power supply
agreement, referred to as the Development Co.-Marketing Co. agreement. The
Development Co.-Marketing Co. agreement entitles Marketing Co. to all of the
output from the Joppa site. The Development Co.-Marketing Co. agreement
contains a monthly capacity charge that approximates the lease payments
Development Co. makes to the Company and an energy charge equal to the variable
costs of operating the combustion turbine generating units.

   During the second quarter of 2001, the Company acquired seven combustion
turbine generating units at Kinmundy, Pinckneyville, and Grand Tower, Illinois
and Columbia, Missouri from Development Co. at Development Co.'s historical net
book value. The total installed cost of the combustion turbine generating units
was approximately $315 million. These units represent 542 megawatts of
capacity. During the third quarter of 2001, the Company acquired four
combustion turbine generating units at Pinckneyville, Illinois and Columbia,
Missouri from Development Co. at Development Co.'s historical net book value.
The total installed cost of the combustion turbine generating units was
approximately $74 million and represents 144 megawatts of capacity. During the
fourth quarter of 2001, the Company purchased from Development Co. a combustion
turbine generating unit at Grand Tower, Illinois, for approximately $140
million. This combined cycle combustion turbine generating unit together with
the purchases made during the second and third quarters of 2001 provided
incremental capacity of 851 megawatts in 2001 at a cost of approximately $529
million.

   With additional plant improvements made during 2001, the Company had 4,330
megawatts of generating capacity at December 31, 2001. See "Liquidity and
Capital Resources" below for further information.

   The Illinois Electric Service Customer Choice and Rate Relief Law of 1997
provides for retail direct access, which allows customers to choose their
electric generation supplier, to be phased in over several years. The

                                      17

<PAGE>

phase-in of retail direct access began on October 1, 1999, with large
industrial and commercial customers principally comprising the initial group.
The remaining commercial and industrial customers in Illinois were offered
choice on December 31, 2000. Retail direct access will be offered to
residential customers on May 1, 2002. The Company is unable to predict the
ultimate impact that retail direct access in Illinois will have on its future
financial condition, results of operations or liquidity.

   In order to satisfy its regulatory load requirements for 2001, AmerenUE,
through a competitive bidding process, entered into a one year electric power
supply agreement with Marketing Co. (the Marketing Co.--AmerenUE agreement) to
purchase 450 megawatts of capacity and energy at market-based rates. Marketing
Co. acquired the power to supply AmerenUE from the Company pursuant to the
Genco-Marketing Co. agreement. The Marketing Co.--AmerenUE agreement expires
May 31, 2002. See "Regulatory Matters" below for information regarding
regulatory proceedings relating to the Marketing Co.--AmerenUE agreement. Also,
see Note 2--Related Party Transactions to the "Notes to Financial Statements."

                                      18

<PAGE>

                             Results Of Operations

   The Company has financial statements available only for the period since May
1, 2000. Prior to that date, all operations of the coal plants now owned by the
Company were fully integrated with, and therefore results of operations were
consolidated into the financial statements of, AmerenCIPS, whose business was
to generate, transmit and distribute electricity and to provide other utility
customer support services. The following table sets forth the results of
operations for the periods indicated and will serve as the reference for the
discussion to follow:

<TABLE>
<CAPTION>
                                                                            For the period   For the period
                                              For the       For the period   May 1, 2001      May 1, 2000
                                             year ended     January 1, 2001    through          through
                                            December 31,        through      December 31,     December 31,
                                                2001        April 30, 2001       2001             2000
(In thousands)                             ---------------  --------------- ---------------  ---------------
                                                              (Unaudited)    (Unaudited)
<S>                                        <C>              <C>             <C>              <C>
OPERATING REVENUES:
   Electric--intercompany................. $       656,530  $      191,982  $       464,548  $       372,179
   Electric...............................         316,552          73,244          243,308          105,104
   Other--intercompany....................          12,603           4,192            8,411            2,418
   Other..................................             134              --              134               --
                                           ---------------  --------------  ---------------  ---------------
       Total operating revenues...........         985,819         269,418          716,401          479,701
                                           ---------------  --------------  ---------------  ---------------
OPERATING EXPENSES:
   Operations:
       Fuel and purchased power...........         562,370         151,667          410,703          235,320
       Other..............................          99,982          31,190           68,792           53,956
                                           ---------------  --------------  ---------------  ---------------
                                                   662,352         182,857          479,495          289,276
   Maintenance............................          56,728          12,141           44,587           45,725
   Depreciation and amortization..........          53,007          15,080           37,927           28,277
   Other taxes............................          18,580           7,938           10,642           13,155
                                           ---------------  --------------  ---------------  ---------------
          Total operating expenses........         790,667         218,016          572,651          376,433
                                           ---------------  --------------  ---------------  ---------------
Operating income..........................         195,152          51,402          143,750          103,268
       Interest expense--intercompany.....          41,036          14,004           27,032           29,537
       Interest expense...................          34,034          11,284           22,750            5,344
       Other income, net..................          (5,131)         (2,108)          (3,023)          (2,634)
                                           ---------------  --------------  ---------------  ---------------
Income before income taxes................         125,213          28,267           96,991           71,021
   Income taxes...........................          47,296          11,242           36,054           27,213
                                           ---------------  --------------  ---------------  ---------------
Income before cumulative effect of
  change in accounting principle..........          77,917          17,026           60,937           43,808
Cumulative effect of change in accounting
  principle, net of income taxes..........          (1,993)         (1,993)              --               --
                                           ---------------  --------------  ---------------  ---------------
NET INCOME................................ $        75,924  $       14,987  $        60,937  $        43,808
                                           ===============  ==============  ===============  ===============
Kilowatthours sales.......................  26,865,512,345   8,187,547,192   18,677,965,153   13,977,790,850
</TABLE>

Earnings

   Net income for the year ended December 31, 2001 increased $32 million or 73%
compared to the period from May 1, 2000 through December 31, 2000. The increase
in earnings was due to comparing a twelve month operating period for 2001 to
the eight month operating period for 2000, as well as higher average period
sales volumes in 2001 versus 2000. Net income for the period from May 1, 2001
through December 31, 2001 compared to the same period in 2000 increased $17
million or 39% primarily due to sales associated with the Genco-Marketing Co.
agreement, as well as sales of the Company's increased available generation
through

                                      19

<PAGE>

AmerenEnergy. Kilowatthours sold increased 4.7 billion or 34% for the eight
months in 2001 compared to the same period in 2000. The Company experienced
higher intercompany electric revenues during the eight and twelve month periods
in 2001 compared to the eight month period in 2000 primarily associated with
the twelve month Marketing Co.--AmerenUE agreement established in 2001, offset
by lower electric revenues generated through AmerenEnergy over those same
periods due to lower energy prices. See "Liquidity and Capital
Resources--Resource Planning" below for further discussion regarding this
agreement.

Operating Revenues

   Operating revenues for the year ended December 31, 2001 compared to the
period from May 1, 2000 through December 31, 2000, increased $506 million or
106%. Intercompany electric revenues increased approximately $284 million or
76% for the year 2001 over the 2000 eight month period. This increase was
primarily due to the longer operating period, as well as higher average period
sales volumes in 2001 versus 2000 associated with the Genco--Marketing Co.
agreement, the Marketing Co.--AmerenUE agreement, and sales through
AmerenEnergy. Third-party electric revenues from AmerenEnergy's marketing
efforts increased $211 million or 201% for the year 2001 compared to the eight
month period in the prior year as kilowatthours sold increased 228%.

   Operating revenues for the period from May 1, 2001 through December 31,
2001, increased $237 million or 49% compared to the period from May 1, 2000
through December 31, 2000. Comparing the same periods, intercompany electric
revenues increased $92 million or 25% primarily associated with sales from the
Genco--Marketing Co. agreement resulting from the 2001 Marketing Co.--AmerenUE
agreement, new wholesale customers and increases in demand from existing
customers as kilowatthours sold increased 19%. Third-party electric revenues
from AmerenEnergy's marketing efforts increased $138 million or 131% for the
2001 eight month period compared to the same period in the prior year as
kilowatthours sold increased 149%; however, lower electric margins were
realized on these sales primarily due to lower energy prices from 2000.

Operating Expenses

   Fuel and purchased power costs for the year ended December 31, 2001
increased $327 million or 139% compared to the period from May 1, 2000 through
December 31, 2000 primarily due to the longer operating period and increased
generation sold under the Genco--Marketing Co. agreement. Fuel and purchased
power costs for the period from May 1, 2001 through December 31, 2001 increased
$175 million or 75% compared to the same period in 2000 primarily as a result
of increased purchased power for interchange sales and to satisfy Marketing
Co.'s 2001 Marketing Co.--AmerenUE agreement, coupled with an increase in
blended fuel costs associated with combustion turbine generating units being
used to satisfy certain load requirements. Intercompany power purchases from
the joint dispatch and other agreements were approximately $381 million for the
twelve month 2001 period and $119 million for the eight month 2000 period.

   Other operating expenses consist primarily of wages, employee benefits,
professional service expenses and expenses associated with support services
provided by Ameren Services. Other operating expenses for the year ended
December 31, 2001 increased $46 million or 85% compared to the period from May
1, 2000 through December 31, 2000 primarily due to the longer operating period,
as well as due to the new combustion turbine generating units added in the
second and third quarters of 2001. Support services provided by Ameren Services
were based on actual costs incurred and were $28 million and $18 million for
the year ended December 31, 2001 and for the period from May 1, 2000 through
December 31, 2000, respectively. For the period from May 1, 2001 through
December 31, 2001, other operating expenses increased $15 million or 27% from
the comparable 2000 period primarily due to the new combustion turbine
generating units added in the second and third quarters of 2001. Support
services provided by Ameren Services were $17 million and $18 million for the
eight month periods ended December 31, 2001 and 2000, respectively.

   Depreciation and amortization expense for the year ended December 31, 2001
increased approximately $25 million or 87% compared to the period from May 1,
2000 through December 31, 2000 due to the longer

                                      20

<PAGE>

operating period, as well as due to the new combustion turbine generating units
added during the second and third quarters of 2001. For the periods from May 1,
2001 through December 31, 2001, depreciation and amortization expense increased
approximately $10 million or 34% from the comparable 2000 period primarily due
to the new combustion turbine generating units added during the second and
third quarters of 2001.

Maintenance

   Maintenance expense for the year ended December 31, 2001 compared to the
period from May 1, 2001 through December 31, 2001, increased approximately $11
million or 24% primarily due to the longer operating period. For the period
from May 1, 2001 through December 31, 2001 compared to the same prior year
period, maintenance expense decreased approximately $1 million or 2% primarily
as a result of the timing of generating station maintenance.

Other Taxes

   Other taxes for the year ended December 31, 2001 compared to the period from
May 1, 2001 through December 31, 2001, increased approximately $5 million or
41% primarily due to the longer operating period. For the period from May 1,
2001 through December 31, 2001 compared to the same prior year period, other
taxes decreased approximately $3 million or 19% primarily due to reduced
property taxes resulting from a change in applicable law.

Interest Expense

   Interest expense for the year ended December 31, 2001 compared to the period
from May 1, 2001 through December 31, 2001, increased approximately $40 million
or 115% primarily due to the longer operating period, as well as due to the
Company's issuance of debt securities (the Senior Notes as defined below) in
the fourth quarter 2000. For the period from May 1, 2001 through December 31,
2001 compared to the same prior year period, interest expense increased
approximately $15 million or 43% primarily due to the issuance of the Senior
Notes in the fourth quarter 2000 partially offset by a reduction in the
principal balance outstanding on the $552 million subordinated intercompany
promissory note to AmerenCIPS. See "Liquidity and Capital Resources--Financing
Activities" below for a discussion of the Senior Notes.

                        Liquidity And Capital Resources

   Cash provided by operating activities totaled $130 million and $97 million
for the year ended December 31, 2001 and for the period from May 1, 2000
through December 31, 2000, respectively. This increase in cash provided by
operating activities in 2001 was due to the longer operating period, higher
average period sales volumes in 2001 versus 2000 due to increased available
generating capacity and a change in working capital requirements.

   Cash flows used in investing activities totaled $247 million and $570
million for the year ended December 31, 2001 and for the period from May 1,
2000 through December 31, 2000, respectively. For the year ended December 31,
2001, cash flows used in investing activities related primarily to the purchase
of new combustion turbine generating units (594 megawatts) and capital
expenditures at the coal plants of $347 million partially offset by repayments
of short-term loans the Company has made to Ameren's non-utility money pool,
discussed below, of $100 million. For the period from May 1, 2000 through
December 31, 2000, cash flows used in investing activities related primarily to
the purchase of new combustion turbine generating units (851 megawatts) and
capital expenditures at the coal plants of $345 million, advances to
Development Co. for the purchase of combustion turbine generating units of $125
million and short-term loans to Ameren's non-utility money pool of $100 million.

   Capital expenditures are expected to be approximately $300 million in 2002.
For the five-year period 2002 through 2006, construction expenditures are
estimated to be approximately $600 million. This estimate includes

                                      21

<PAGE>

capital expenditures that will be incurred by the Company for the purchase of
new combustion turbine generating facilities (468 megawatts) and improvements
made to existing facilities, as well as for compliance with new nitrogen oxide
(NO\\x\\) control regulations, as discussed below under "Environmental."
Capital expenditures at the Company's existing coal-fired plants are expected
to be approximately $300 million in total for the period 2002 through 2006,
excluding any capital expenditures required to comply with the NO\\x\\
emissions standards discussed below under "Environmental." See "Future Capacity
Additions" below and Note 7--Commitments and Contingencies to the "Notes to
Financial Statements" for further discussion on future capital expenditures.

   Capital requirements for the 2002 through 2006 period are expected to be
provided from internally generated funds as well as external and affiliated
financing sources. See "Financing Activities" below.

Future Capacity Additions

   By the end of 2002, the Company intends to purchase from Development Co.
four combustion turbine generating units at Elgin, Illinois. These combustion
turbine generating units are expected to provide additional capacity of 468
megawatts at a cost of approximately $222 million and be available for
commercial operation by the end of 2002.

   Due to market conditions and other factors, the Company has re-evaluated its
capacity needs and future planned purchases of combustion turbine generating
units through 2005. The Company has reduced its previously expected capacity
additions through 2005 from 1,560 megawatts to its current estimate of 468
megawatts (which represents the Elgin, Illinois project referred to above).
Projected total expenditures for the capacity additions in the 2002 through
2006 period accordingly were reduced from the $752 million previously expected
to $222 million. Resources sold rights to develop 325 megawatts of generating
capacity planned for commercial operation in 2003 and is actively pursuing a
third party assignment of an additional 117 megawatt unit planned for
commercial operation in 2002. Resources has assigned to its regulated
affiliate, AmerenUE, contractual rights to four combustion turbine generating
units totaling 650 megawatts which were planned for commercial operation by the
Company in 2004 and 2005 at a cost of approximately $280 million. The Company
has no contingent liabilities to Resources or any other person in connection
with the units that have been assigned.

Resource Planning

   In order to satisfy its regulatory load requirements for 2001, AmerenUE,
through a competitive bidding process, purchased under a one year contract 450
megawatts of capacity and energy from Marketing Co. at market-based rates.
Marketing Co. acquired the power to supply AmerenUE from the Company. For 2002,
AmerenUE, again through a competitive bidding process, has entered into another
one year contract with Marketing Co. for the purchase of 200 megawatts of
additional capacity and energy at lower prices than in 2001. Marketing Co.
expects to acquire the power to supply AmerenUE from the Company and other
sources. Additional future resource options under consideration by AmerenUE
include the transfer of AmerenUE's Illinois-based electric business to
AmerenCIPS, which would be supplied by Marketing Co., which may obtain its
power from the Company and other sources.

   In the ordinary course of business, Ameren 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 NO\\x\\ control regulation for utility
boilers in the state consistent with a United States Environmental Protection
Agency (USEPA) program aimed at reducing ozone levels in the Eastern United
States. As a result of these state requirements, the Company anticipates a 75%
reduction from current

                                      22

<PAGE>

levels of NO\\x\\ emissions from its power plant boilers in Illinois by the
year 2004. The Company estimates spending approximately $210 million for
capital expenditures to comply with these rules, of which approximately $50
million was spent in 2001. The 2001 costs were primarily associated with the
installation of a new low-NO\\x\\ burner technology on unit 2 of the Newton
coal plant, which has been completed, and of Selective Catalytic Reduction
technology on unit 2 of the Coffeen coal plant, which remains under
construction.

   The Company has applied for Early Reduction NO\\x\\ credits which would
allow it to manage compliance strategies by either purchasing NO\\x\\ control
equipment or utilizing credits. The Company may be eligible for such credits
due to the current low NO\\x\\ emission rates of some of its power plant
boilers under current state regulations.

   In July 1997, the USEPA 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 USEPA for resolution. The USEPA 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
(SO\\2\\) and NO\\x\\ 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 USEPA issued a decision to regulate mercury emissions
from coal-fired power plants by 2008. The USEPA is scheduled to propose
regulations by 2004. These regulations have the potential to add significant
capital and/or operating costs to the Company's generating system after 2005.
On July 20, 2001, the USEPA issued proposed Best Available Retrofit Technology
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 SO\\2\\ and NO\\x\\ emissions. These rules could also add
significant pollution control costs to the Company's generating system between
2008 and 2012. 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 addition, the United States Congress has been working on legislation to
consolidate the numerous air pollution regulations facing the utility and power
generating 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.

   The Company is involved in remediation activities to address onsite and
offsite impacts from the ash handling operations at its coal plants. Such
activities are not considered material in nature and costs relating to those
activities may be subject to indemnification by AmerenCIPS pursuant to the
provisions of the electric generating asset transfer arrangement executed on
May 1, 2000, referred to above under "Overview".

   See Note 7--Commitments and Contingencies to the "Notes to Financial
Statements" for further discussion of environmental matters.

Financing Activities

   Cash flows provided by financing activities totaled $118 million for the
year ended December 31, 2001 compared to cash flows provided by financing
activities of $467 million for the period from May 1, 2000 through December 31,
2000. The Company's principal financing activity during 2001 consisted of a
capital contribution from Ameren of $150 million and borrowings from the
non-utility money pool of approximately $62 million which were partially offset
by the principal payments made on the subordinated intercompany notes to Ameren
and AmerenCIPS. The Company used the capital contribution to repay $100 million
of short-term intercompany borrowings and $50 million principal on the $552
million subordinated intercompany note held by AmerenCIPS.

                                      23

<PAGE>

   The Company's principal financing activities for the period from May 1, 2000
through December 31, 2000 included the issuance of a $50 million subordinated
intercompany note payable to Ameren and the issuance on November 1, 2000, of
Senior Notes, 7.75% Series A and 8.35% Series B due 2005 and 2010, respectively
(Senior Notes). The proceeds received from the Senior Notes (net of
underwriting commissions) were $423.6 million, excluding transaction costs.
With the proceeds of the Senior Notes, the Company repaid $220 million of
short-term intercompany borrowings used to acquire combustion turbine
generating units, prefunded $125 million of combustion turbine generating units
which became available for commercial operation in 2001 and funded
approximately $19 million of capital expenditures incurred in 2000. The
remainder of the proceeds, after transaction costs, were loaned to Ameren's
non-utility money pool until such time as the Company needed the proceeds for
working capital or capital expenditures. The Company filed a registration
statement with the Securities and Exchange Commission (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 Notes and Series D Notes which
are identical in all material respects to the Series A Notes and Series B
Notes, respectively, except that the new series of notes do not contain
transfer restrictions and are registered.

   The Company's capital structure includes a $552 million subordinated
intercompany note that it issued to AmerenCIPS as part of the purchase price
for the transfer of the coal plants and a $50 million subordinated intercompany
note issued to Ameren. For the year ended December 31, 2001, principal payments
made on the AmerenCIPS and Ameren notes were approximately $90 million and $4
million, respectively. No principal payments were made on either intercompany
note for the period from May 1, 2000 through December 31, 2000. The two
subordinated intercompany notes each have a term of five years and bear
interest at 7% per annum based on a 10-year amortization schedule.

   The Company expects to issue in 2002 approximately $275 million of
additional debt to permanently finance generating capacity additions.

   The Company has the ability to borrow up to $400 million from Ameren through
a non-utility money pool agreement. However, the total amount available to the
Company at any time is reduced by the amount of borrowings from the non-utility
money pool by other Ameren nonregulated companies and is increased to the
extent other Ameren nonregulated companies advance surplus funds to the
non-utility money pool or external borrowing sources are used by Ameren to
increase the available amounts.

   At December 31, 2001, approximately $12 million of funds were available
through the non-utility money pool not including additional funds available
through uncommitted bank lines. The non-utility money pool was established to
coordinate and provide for short-term cash and working capital requirements of
Ameren's nonregulated activities and is administered by Ameren Services.
Interest is calculated at varying rates of interest depending on the
composition of internal and external funds in the non-utility money pool. For
the year ended December 31, 2001 and for the period from May 1, 2000 through
December 31, 2000, the average interest rate for borrowings from the
non-utility money pool was 4.08 % and 6.52 %, respectively. Intercompany
interest income to the Company for loans to the non-utility money pool over
those same periods was $3 million and $1 million, respectively. At December 31,
2001, the Company had no amounts loaned to the non-utility money pool and had
outstanding borrowings of approximately $62 million.

   The following table summarizes the Company's committed credit support as of
December 31, 2001:

<TABLE>
<CAPTION>
                                   Amount of commitment expiration per period
                                   -------------------------------------------
                                   Total amounts Less than
                                     committed    1 year   1-3 years 4-5 years
                                   ------------- --------- --------- ---------
                                                  (In millions)
  <S>                              <C>           <C>       <C>       <C>
  Guarantees (a)..................     $312        $ --      $312       $--
  Other commercial commitments (b)      400         200       200        --
                                       ----        ----      ----       ---
     Total commercial commitments.     $712        $200      $512       $--
                                       ====        ====      ====       ===
</TABLE>
--------
(a) Ameren's "aggregate investment" in Exempt Wholesale Generators (EWGs) (such
    as the Company) and foreign utility companies is limited under PUHCA to an
    amount not greater than 50% of Ameren's

                                      24

<PAGE>

   consolidated retained earnings unless SEC approval is obtained to make
   additional investments. Aggregate investment includes all amounts invested,
   or committed to be invested, for which there is recourse, directly or
   indirectly, to the registered holding company and includes guarantees by
   Ameren of obligations of the Company. At December 31, 2001, Ameren had
   capacity to increase its aggregate investment in EWGs by $307 million.
(b) See Note 2--Related Party Transactions to the "Notes to Financial
    Statements" for further discussion.

   The following table summarizes the Company's contractual obligations as of
December 31, 2001:

<TABLE>
<CAPTION>
                                          Less than
                                           1 year   1-3 years 4-5 years
                                          --------- --------- ---------
                                                  (In millions)
        <S>                               <C>       <C>       <C>
        Long-term debt (a)...............   $ 47      $461      $ --
        Operating leases.................     (c)       (c)       (c)
        Other long-term obligations (b)..    179       367       213
                                            ----      ----      ----
           Total contractual obligations.   $226      $828      $213
                                            ====      ====      ====
</TABLE>
--------
(a) See Note 2--Related Party Transactions to the "Notes to Financial
    Statements" for further discussion.
(b) Represents purchase contracts for coal and natural gas. See Note
    7--Commitments and Contingencies under Notes to Financial Statements for
    discussion regarding coal commitments.
(c) Less than $1 million.

   During 2001, an excess earnings complaint was filed against the Company's
affiliate, AmerenUE, by the Missouri Public Service Commission (MoPSC) staff.
One issue under the complaint involves the amended joint dispatch agreement and
the prices at which AmerenUE is able to purchase capacity and energy from the
Company (for a discussion of the 2001 Marketing Co.--AmerenUE agreement see
"Resource Planning" above and "Regulatory Matters" below). Evidentiary hearings
on the MoPSC staff's complaint are scheduled to be conducted before the MoPSC
beginning in July 2002. A final decision on this matter may not occur until the
fourth quarter of 2002. As a result of the uncertainty created by the excess
earnings complaint as well as other factors, in 2001 Moody's, Standard & Poor's
and Fitch rating agencies changed their outlooks for Ameren's and AmerenUE's
long-term debt ratings from stable to negative. In connection with this outlook
change for Ameren and AmerenUE, Standard & Poor's also assigned a negative
outlook to its ratings of the Company and AmerenCIPS. Any reduction of Ameren's
long-term debt rating may have an adverse impact on the Company's financial
position, results of operations or liquidity, including increasing the cost of
future borrowings; however, management is unable to determine such impact. As
of December 31, 2001, the ratings of the Company's Senior Notes by these rating
agencies were as follows:

<TABLE>
<CAPTION>
                                                Standard
                                        Moody's & Poor's Fitch
                                        ------- -------- -----
                 <S>                    <C>     <C>      <C>
                 Senior Notes--due 2005    A3     BBB+   BBB+
                 Senior Notes--due 2010  Baa2     BBB+   BBB+
</TABLE>

Regulatory Matters

   In May 2001, the MoPSC filed pleadings with the Federal Energy Regulatory
Commission (FERC) and the SEC relating to AmerenUE's agreement to purchase 450
megawatts of capacity and energy from Marketing Co. during 2001 (the Marketing
Co.--Ameren UE agreement). The Missouri Office of Public Counsel (Missouri OPC)
also filed pleadings with the FERC in this matter. The pleadings requested the
FERC to reject Marketing Co.'s proposed market-based rates alleging concerns
about affiliate abuse and the overall competitiveness of the market and
requested the FERC to set for hearing the appropriate level of cost-based
rates, or in the alternative, set for hearing whether Marketing Co. has
demonstrated that its proposed market-based rates will be just and reasonable.
In the second quarter of 2001, the FERC issued an order which accepted the
power sales agreement (with minor modifications), without hearing or
suspension, and rejected the pleadings of the MoPSC and the

                                      25

<PAGE>

Missouri OPC. In the third quarter of 2001, the MoPSC filed with the FERC a
request for clarification of its order in the following two respects: (1) that
it does not insulate the power sales agreement from a finding of invalidity by
the SEC under PUHCA and (2) that it does not preempt the MoPSC from inquiring
into the reasonableness of the agreement. The FERC issued an order granting the
MoPSC's request for clarification. Under the terms of the FERC's order, the
power sales agreement became effective June 1, 2001.

   The MoPSC's SEC pleading requests an investigation into the contractual
relationship between the Company, Marketing Co. and AmerenUE in the context of
the 2001 Marketing Co.-AmerenUE agreement and requests that the SEC find that
such relationship violates a provision of PUHCA which requires state utility
commission approval of power sales contracts between an electric utility
company and an affiliated EWG, like the Company. The Company believes that the
MoPSC's approval of the power sales agreement under PUHCA is not required
because the Company is not a party to the agreement. As a remedy, the MoPSC
proposes that the SEC require AmerenUE to contract directly with the Company
and submit such contract to the MoPSC for review. The SEC has not responded to
this matter to date. At this time, management is unable to predict the outcome
of this proceeding or the ultimate impact on the Company's future financial
position, results of operations or liquidity.

Electric Transmission Matters--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, Ameren announced its intention to withdraw
from the Midwest ISO and to join the Alliance RTO. In 2001, Ameren 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. Ameren'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 companies have
filed a request for rehearing with the FERC urging it to reverse the findings
of its December 2001 order. To preserve their right to a judicial appeal, the
Alliance RTO companies have also filed a petition for review with the U.S.
Court of Appeals for the District of Columbia Circuit. On March 6, 2002, the
Alliance RTO companies and National Grid (the managing member of the
transmission company formed by the Alliance RTO companies) filed a motion for a
declaratory order with the FERC asking for approval of a proposed division of
responsibilities between National Grid and the Midwest ISO. It also sought
approval for the Alliance RTO companies to purchase services from the Midwest
ISO at incremental costs and asked the FERC to endorse the rate design and
revenue distribution methodology that it approved in 2001, adjusted to take
into account that it would now apply to a single RTO. The Company does not own
transmission assets; however, it pays AmerenUE and AmerenCIPS for the use of
their transmission lines to transmit power. At this time, the Company is unable
to determine the impact that the FERC's December 2001 ruling will have on its
future financial condition, results of operations or liquidity.

                                      26

<PAGE>

                              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 $2 million after taxes to the income statement,
comprised of $0.5 million for the ineffective portion of cash flow hedges and
$1.5 million for discontinued hedges, and a cumulative effect adjustment of $3
million after income taxes to Accumulated Other Comprehensive Income (OCI),
which reduced stockholder's equity. (See Note 3--Risk Management and Derivative
Financial Instruments under Notes to 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. 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 was 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.

   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.

   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.

                                      27

<PAGE>

                                     Labor

   Certain employees of the Company and its affiliated companies are
represented by the International Brotherhood of Electrical Workers Local 702
and the International Union of Operating Engineers Local 148. These employees
comprise approximately 72% of the Company's workforce. Labor agreements
covering virtually all represented employees of the Company expire on June 30,
2002.

          Quantitative And Qualitative Disclosures About Market Risk.

   Market risk represents the risk of changes in value of a physical asset or
financial instrument, derivative or non-derivative, caused by fluctuations in
market variables (e.g., interest rates, 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 risks 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 comprised of senior-level Ameren
officers. Policies set by this committee are applicable to the Company, as well
as to Ameren's other subsidiaries.

Interest Rate Risk

   The Company is exposed to market risk through changes in interest rates
through its issuance of both variable rate and fixed rate debt. 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. At December 31,
2001, the Company had $62 million of variable rate non-utility money pool
borrowings outstanding.

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 resources and credit quality
of the clearing members of 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 subject to credit risk
consist primarily of accounts receivable and executory contracts with market
risk exposures. The Company's revenues are primarily derived from the sales of
electricity to Marketing Co. as described in Note 2--Related Party Transactions
to the "Notes to Financial Statements". Approximately $98 million of the
Company's accounts receivable are related party receivables from Marketing Co.
No other customer represents greater than 10% of the Company's accounts
receivable. 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).

                                      28

<PAGE>

Commodity Price Risk

   The Company is exposed to changes in market prices for electricity and fuel.
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 the Company's exposure to commodity price risk for purchased
power and excess electricity sales, AmerenEnergy manages market risks
associated with changing market prices for electricity purchased and sold on
behalf of the Company.

   Although the Company cannot completely eliminate the effects of elevated
prices and price volatility, its strategy is designed to minimize the effect of
these market conditions on the results of operations. The 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
dampen 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
been limited to transactions that are expected to reduce price risk exposure
for the Company.

   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. AmerenEnergy enters into
contracts for the sale and purchase of energy on behalf of the Company. The
Company is ultimately responsible for the performance of these contracts.
Currently, virtually all of AmerenEnergy's transactions are considered
non-trading activities. See "Accounting Matters" above and Note 3--Risk
Management and Derivative Financial Instruments to the "Notes to Financial
Statements" for discussion of SFAS 133.

Electricity Price Risk

   The Company measures its electricity position as total generating resources
available, given historical forced outage rates, planned outages and forward
market prices, less projected fixed price load requirements. The Company
considers the contracts in place through the end of 2004 to supply full
requirements to AmerenCIPS' native load and fixed price market-based retail
customers plus Marketing Co.'s wholesale contract commitments transferred to
Marketing Co. from AmerenCIPS, to be load requirements. The Company's
electricity and capacity price risks are primarily mitigated by the
Genco-Marketing Co. agreement, the Marketing Co.-CIPS agreement, and Marketing
Co.'s fixed price wholesale contract commitments and are therefore the largest
single protection against falling electricity and capacity prices.

   The portion of the Company's capacity which is not covered by the agreements
and contracts discussed above will be managed either by Marketing Co.
(generally for wholesale transactions over one year and retail sales) or
AmerenEnergy (generally for wholesale transactions under one year). The
Company's strategy is to continue to utilize Marketing Co. to offer most of its
output under long-term wholesale contracts as more of the Company's capacity
and energy becomes available for resale as existing contracts expire.
AmerenEnergy expects to extract additional value from the generating facilities
by selling energy in excess of the needs of Marketing Co. Also, AmerenEnergy
will purchase power on the Company's behalf when power is available for
purchase at lower cost than the Company's cost of generation. Such power would
be purchased to satisfy the Company's delivery requirements under its agreement
with Marketing Co., which Marketing Co. will use to meet its obligations under
the load requirements discussed above.

                                      29

<PAGE>

   The amended joint dispatch agreement includes a sharing mechanism which
provides the Company a benefit when it is able to use relatively low-cost
generation available from AmerenUE to meet its long-term fixed price sales
obligations as an alternative or supplement to its own generating resources.
Conversely, the Company forgoes some of the potential gain that would arise
from high peak power prices in short-term or spot markets because AmerenUE has
the right to use the Company's available energy (i.e., energy not sold by the
Company to Marketing Co.) to the extent such energy is less expensive than
energy produced from AmerenUE's next economically dispatchable generating unit.
The price payable to the Company in these circumstances would likely be lower
than peak market prices. Under the amended joint dispatch agreement, the
Company and AmerenUE also share revenues when sales are made from AmerenUE's or
the Company's generating facilities to third parties on a short-term or spot
basis.

Fuel Price Risk

   The Company forecasts forward fuel exposure based on historical unit
availability, load requirements, forward fuel prices and forward electricity
prices. This practice substitutes market purchases to supply load requirements
when the price to purchase electricity is less than the cost to produce
electricity, and creates forecasted fuel exposure when generation will be used
to cover forecasted electricity sales.

   Natural gas and coal price risks are managed by Fuels Co. acting as the
Company's agent. 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.

   Over 95% of the required 2002 supply of coal for the Company's coal plants
has been acquired at fixed prices. As such, the Company has minimal coal price
risk for 2002. In addition, at least 78% of the coal requirements through 2006
are covered by contracts. Under the existing requirements contracts, the
capacity and energy requirements can be substantially satisfied by operation of
the Company's coal plants and accordingly, the fuel position with respect to
such contracts is covered. See Note 7--Commitments and Contingencies to the
"Notes to Financial Statements" for discussion regarding coal commitments.

   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. This is done by structuring various supply agreements to maintain
access to multiple gas pools and supply basins and reduce the impact of price
volatility. For the year ended December 31, 2001 and for the period from May 1,
2000 through December 31, 2000, natural gas costs were approximately $30
million and $5 million, respectively.

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. The Company primarily
uses derivatives to optimize the value of its physical and contractual
positions. The Company 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.

                                      30

<PAGE>

   The following summarizes changes in the fair value of all mark to market
contracts during 2001:

<TABLE>
<CAPTION>
                                                                                       (In millions)
<S>                                                                                    <C>
Fair value of contracts at January 1, 2001                                                  $(9)
Contracts at January 1, 2001 which were realized or otherwise settled during 2001             9
Changes in fair values attributable to changes in valuation techniques and assumptions       --
Fair value of new contracts entered into during 2001                                         --
Other changes in fair value                                                                   2
                                                                                            ---
Fair value of contracts outstanding at December 31, 2001                                    $ 2
                                                                                            ===
</TABLE>

   Fair value of contracts as of December 31, 2001 were as follows:

<TABLE>
<CAPTION>
                                                                            Maturity
                                                           ------------------------------------------
                                                           less than  1-3   4-5  in excess  Total fair
                                                            1 year   years years of 5 years value (a)
                                                           --------- ----- ----- ---------- ----------
                                                                          (In millions)
<S>                                                        <C>       <C>   <C>   <C>        <C>
Sources of fair value:
   Prices actively quoted.................................    $--     $--   $--     $--        $--
   Prices provided by other external sources (b)..........      2      --    --      --          2
   Prices based on models and other valuation methods (c).     (d)     --    --      --         (d)
                                                              ---     ---   ---     ---        ---
Total.....................................................    $ 2     $--   $--     $--        $ 2
                                                              ===     ===   ===     ===        ===
</TABLE>
--------
(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 SO\\2\\ options valued based on a Black-Scholes model
    that includes information from external sources and Company estimates.
(d) Less than $1 million.

                             Safe Harbor Statement

   Statements made in this report which are not based on historical facts, are
"forward-looking" and, accordingly, involve risks and uncertainties that could
cause actual results to differ materially from those discussed. Although such
"forward-looking" statements have been made in good faith and are based on
reasonable assumptions, there is no assurance that the expected results will be
achieved. These statements include (without limitation) statements as to future
expectations, beliefs, plans, strategies, objectives, events, conditions and
financial performance. In connection with the "Safe Harbor" provisions of the
Private Securities Litigation Reform Act of 1995, 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; the effects of Ameren's 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; wholesale and retail pricing for electricity in the Midwest;
business and economic conditions; interest rates and the availability of
capital; actions of rating agencies and the effects of such actions; weather
conditions; the impact of the adoption of new accounting standards; fuel prices
and availability; generation plant construction, installation and performance;
the impact of current environmental

                                      31

<PAGE>

regulations on 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 on the Company's behalf;
and legal and administrative proceedings.

ITEM 7A.  Quantitative and Qualitative Disclosures About Market Risk.

   Information required to be reported by this item is included under
"Quantitative And Qualitative Disclosures About Market Risk" in "Management's
Discussion and Analysis of Financial Conditions and Results of Operations"
under Item 7 herein and Note 3--Risk Management and Derivative Financial
Instruments included in the "Notes to Financial Statements" under Item 8 herein.

                                      32

<PAGE>

ITEM 8.  Financial Statements and Supplementary Data.

                       REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Shareholder
of AmerenEnergy Generating Company

   In our opinion, the financial statements listed in the index appearing under
Item 14(A)(1) present fairly, in all material respects, the financial position
of AmerenEnergy Generating Company, a wholly-owned subsidiary of Ameren
Corporation, at December 31, 2001 and 2000 and the results of its operations
and its cash flows for the year ended December 31, 2001 and for the period May
1, 2000 to December 31, 2000, 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 audit. We
conducted our audit 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 audit provides a reasonable basis
for our opinion.

                                          /S/  PRICEWATERHOUSECOOPERS LLP

                                          PricewaterhouseCoopers LLP
                                          St. Louis, Missouri
                                          February 1, 2002

                                      33

<PAGE>

                       AMEREN ENERGY GENERATING COMPANY

                                 BALANCE SHEET
                   (In thousands of dollars, Except Shares)

<TABLE>
<CAPTION>
                                                                       December 31, December 31,
                               ASSETS                                      2001         2000
                               ------                                  ------------ ------------
<S>                                                                    <C>          <C>
Current assets:
   Cash and cash equivalents..........................................  $    2,063   $      596
   Accounts receivable--intercompany..................................     121,172       57,887
   Accounts receivable................................................       8,464       10,694
   Other receivables--intercompany....................................          --      125,850
   Materials and supplies, at average cost............................
       Fossil fuel....................................................      39,949       24,791
       Other..........................................................      19,951       19,120
   Other current assets...............................................       1,797        1,489
                                                                        ----------   ----------
          Total current assets........................................     193,396      240,427
                                                                        ----------   ----------
Property and plant at cost, net:
   Electric Plant.....................................................   2,140,287    1,574,724
   Other..............................................................         363           29
                                                                        ----------   ----------
       Property and plant, at original cost...........................   2,140,650    1,574,753
   Less accumulated depreciation......................................    (688,689)    (647,872)
                                                                        ----------   ----------
                                                                         1,451,961      926,881
   Construction work in progress......................................      60,423       24,136
                                                                        ----------   ----------
          Total property and plant, net...............................   1,512,384      951,017
                                                                        ----------   ----------
Advances for committed units--intercompany............................          --      125,000
Deferred income taxes, net............................................      37,809       69,918
Other assets..........................................................      13,339        7,300
                                                                        ----------   ----------
TOTAL ASSETS..........................................................  $1,756,928   $1,393,662
                                                                        ==========   ==========

                LIABILITIES AND STOCKHOLDER'S EQUITY
                ------------------------------------
Current liabilities:
   Current portion of subordinated notes payable--intercompany........  $   46,592   $   43,544
   Accounts and wages payable.........................................      63,374       40,652
   Accounts and wages payable--intercompany...........................     181,171       13,318
   Notes payable--intercompany........................................      61,700           --
   Current portion of income tax payable--intercompany................      18,478       15,874
   Taxes accrued......................................................      11,965       26,277
   Interest accrued...................................................       5,690        5,690
   Interest payable--intercompany.....................................       6,504        3,801
   Other..............................................................       3,028        4,587
                                                                        ----------   ----------
          Total current liabilities...................................     398,502      153,743
                                                                        ----------   ----------
Other deferred credits................................................       4,690          609
Accumulated deferred investment tax credits...........................      16,890       18,233
Income tax payable--intercompany......................................     177,096      195,509
Long-term debt, net...................................................     423,880      423,676
Subordinated notes payable--intercompany..............................     461,490      558,082
Stockholder's equity:
   Common stock, no par value, 10,000 shares authorized--2,000 shares
     outstanding......................................................           2            2
   Other paid in capital..............................................     150,000           --
   Retained earnings..................................................     119,732       43,808
   Accumulated other comprehensive income.............................       4,646           --
                                                                        ----------   ----------
          Total stockholder's equity..................................     274,380       43,810
                                                                        ----------   ----------
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY............................  $1,756,928   $1,393,662
                                                                        ==========   ==========
</TABLE>

                      See Notes to Financial Statements.

                                      34

<PAGE>

                       AMEREN ENERGY GENERATING COMPANY

                              STATEMENT OF INCOME
                                (In thousands)

<TABLE>
<CAPTION>
                                                                                        For the
                                                                                         period
                                                                         For the year May 1, 2000
                                                                            ended       through
                                                                         December 31, December 31,
                                                                             2001         2000
                                                                         ------------ ------------
<S>                                                                      <C>          <C>
OPERATING REVENUES:
   Electric--intercompany...............................................   $656,530     $372,179
   Electric.............................................................    316,552      105,104
   Other--intercompany..................................................     12,603        2,418
   Other................................................................        134           --
                                                                           --------     --------
          Total operating revenues......................................    985,819      479,701
                                                                           --------     --------
OPERATING EXPENSES:
   Operations:
       Fuel and purchased power.........................................    562,370      235,320
       Other............................................................     99,982       53,956
                                                                           --------     --------
                                                                            662,352      289,276
   Maintenance..........................................................     56,728       45,725
   Depreciation and amortization........................................     53,007       28,277
   Other taxes..........................................................     18,580       13,155
                                                                           --------     --------
          Total operating expenses......................................    790,667      376,433
                                                                           --------     --------
Operating income........................................................    195,152      103,268
   Interest expense--intercompany.......................................     41,036       29,537
   Interest expense.....................................................     34,034        5,344
   Other income, net....................................................     (5,131)      (2,634)
                                                                           --------     --------
Income before income taxes..............................................    125,213       71,021
   Income taxes.........................................................     47,296       27,213
                                                                           --------     --------
Income before cumulative effect of change in accounting principle.......     77,917       43,808
Cumulative effect of change in accounting principle, net of income taxes     (1,993)          --
                                                                           --------     --------
NET INCOME..............................................................   $ 75,924     $ 43,808
                                                                           ========     ========
</TABLE>


                      See Notes to Financial Statements.

                                      35

<PAGE>

                       AMEREN ENERGY GENERATING COMPAN Y

                            STATEMENT OF CASH FLOWS
                                (In thousands)

<TABLE>
<CAPTION>
                                                                                       For the period
                                                                          For the year  May 1, 2000
                                                                             ended        through
                                                                          December 31,  December 31,
                                                                              2001          2000
                                                                          ------------ --------------
<S>                                                                       <C>          <C>
Cash Flows From Operating:
   Net income............................................................  $  75,924     $  43,808
   Adjustments to reconcile net income to net cash provided by operating
     activities:
       Cumulative effect of change in accounting principle...............      1,993            --
       Depreciation and amortization.....................................     53,007        28,277
       Deferred income taxes, net........................................     28,651         5,981
       Deferred investment tax credits...................................       (841)       (1,495)
       Changes in assets and liabilities:
          Receivables, net...............................................    (35,055)      (68,581)
          Materials and supplies.........................................    (15,989)        9,895
          Accounts and wages payable.....................................     49,821        47,429
          Taxes accrued..................................................    (14,312)       26,277
          Income tax payable--intercompany...............................    (15,809)       (8,212)
          Interest accrued and payable...................................      2,703         9,491
          Other, net.....................................................        260         4,408
                                                                           ---------     ---------
Net cash provided by operating activities................................    130,353        97,278
                                                                           ---------     ---------
Cash Flows From Investing:
   Construction expenditures.............................................   (346,892)     (470,241)
   Intercompany notes receivable--short-term.............................     99,850       (99,850)
                                                                           ---------     ---------
Net cash used in investing activities....................................   (247,042)     (570,091)
                                                                           ---------     ---------
Cash Flows From Financing:
   Issuances--
       Intercompany notes payable--long-term.............................         --        50,000
       Long-term debt....................................................         --       423,643
   Debt issuance costs...................................................         --        (6,621)
   Paid in capital.......................................................    150,000            --
   Intercompany notes payable--short-term................................     61,700            --
   Intercompany notes payable--long-term.................................    (93,544)           --
                                                                           ---------     ---------
Net cash provided by financing activities................................    118,156       467,022
                                                                           ---------     ---------

Net Change In Cash And Cash Equivalents..................................      1,467        (5,791)
Cash and cash equivalents at beginning of period.........................        596         6,387
                                                                           ---------     ---------
Cash and cash equivalents at end of period...............................  $   2,063     $     596
                                                                           =========     =========
Cash paid during the periods:
   Interest..............................................................  $  40,642     $  26,073
   Income taxes..........................................................     36,156        13,524
                                                                           =========     =========
</TABLE>

SUPPLEMENTAL DISCLOSURE OF NONCASH TRANSACTIONS:

   In the second quarter of 2000, AmerenCIPS' generating assets were
transferred to the Company in exchange for a subordinated promissory note in
the principal amount of $552 million and the Company's common stock. See Notes
2 and 5 for further discussion of this transaction. In the fourth quarter of
2001, the Company purchased a combustion turbine generating unit at Grand
Tower, Illinois for approximately $140 million. This amount was included in
accounts payable at December 31, 2001.

                       See Notes to Financial Statements

                                      36

<PAGE>

                       AMEREN ENERGY GENERATING COMPANY

                   STATEMENT OF COMMON STOCKHOLDER'S EQUITY
                                (In thousands)

<TABLE>
<CAPTION>
                                                                       For the period
                                                          For the year  May 1, 2000
                                                             ended        through
                                                          December 31,  December 31,
                                                              2001          2000
                                                          ------------ --------------
<S>                                                       <C>          <C>
Common stock.............................................   $      2      $     2
Other paid in capital....................................
   Beginning balance.....................................         --           --
   Change in current period..............................    150,000           --
                                                            --------      -------
                                                             150,000           --
Retained earnings........................................
   Beginning balance.....................................     43,808           --
   Net income............................................     75,924       43,808
                                                            --------      -------
                                                             119,732       43,808
Accumulated other comprehensive income...................
   Beginning balance.....................................         --           --
   Change in current period..............................      4,646           --
                                                            --------      -------
                                                               4,646           --
                                                            --------      -------
Total common stockholder's equity........................   $274,380      $43,810
                                                            ========      =======
Comprehensive income, net of tax.........................
   Net income............................................   $ 75,924      $43,808
   Cumulative effect of accounting change................     (3,378)          --
   Unrealized net gain on derivative hedging instruments.      8,024           --
                                                            --------      -------
                                                            $ 80,570      $43,808
                                                            ========      =======
</TABLE>



                      See Notes to Financial Statements.

                                      37

<PAGE>

                       AMEREN ENERGY GENERATING COMPANY

                         NOTES TO FINANCIAL STATEMENTS

                               December 31, 2001

Note 1--Summary of Significant Accounting Policies

Basis of Presentation

   AmerenEnergy Generating Company (Genco or the Company), is an indirect
nonregulated electric generating subsidiary of AmerenEnergy Resources Company
(Resources), which is a subsidiary of Ameren Corporation (Ameren). Ameren is a
holding company registered under the Public Utility Holding Company Act of 1935
(PUHCA). Ameren's other primary operating companies are Union Electric Company
(AmerenUE) and Central Illinois Public Service Company (AmerenCIPS). In
conjunction with the Illinois Electric Service Customer Choice and Rate Relief
Law of 1997 and following the receipt of all required state and federal
regulatory approvals, AmerenCIPS transferred its electric generating assets and
related liabilities on May 1, 2000, at historical net book value, to Genco, a
newly created nonregulated company, in exchange for a subordinated promissory
note in the amount of $552 million from the Company and 1,000 shares of the
Company's common stock.

   Resources is a holding company for Ameren's nonregulated electric generation
business whose principal subsidiaries include the Company, AmerenEnergy
Development Company (Development Co.), AmerenEnergy Fuels and Services Company
(Fuels Co.) and AmerenEnergy Marketing Company (Marketing Co.). The Company
qualifies as an exempt wholesale generator under PUHCA and acts as Resources'
primary vehicle for the ownership and operation of its nonregulated electric
generation assets. Development Co., the Company's parent, develops and
constructs generation assets for the Company, and the Company purchases
generation assets from Development Co. when the assets are available for
commercial operation. Fuels Co. acts as the Company's agent and manages the
Company's coal, natural gas and fuel oil procurement and supply. Marketing Co.
sells wholesale energy, capacity and other energy products for terms in excess
of one year, and makes sales to the retail markets. In addition, AmerenEnergy,
Inc. (AmerenEnergy), Ameren's wholly owned energy trading and marketing
subsidiary, acts as agent for the Company and enters into contracts for the
wholesale purchase and sale of energy on its behalf for terms of less than one
year.

   The Company has financial statements available only for the period since May
1, 2000. Prior to that, all operations of the Company's coal plants were fully
integrated with, and therefore results of operations were consolidated into the
financial statements of, AmerenCIPS, whose business was to generate, transmit
and distribute electricity and to provide other customer support services.

Property and Plant

   The cost of additions to, and betterments of, units of property and plant is
capitalized. Cost includes labor, material, applicable taxes, capitalized
interest and overheads. 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 for the year ended December 31, 2001 and for the
period from May 1, 2000 through December 31, 2000 was approximately 3% of the
average depreciable costs on an annualized basis.

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.

                                      38

<PAGE>

Materials and Supplies

   Materials and supplies are stated at average cost.

Income Taxes

   The Company is included in the consolidated federal income tax return filed
by Ameren. As a subsidiary of Ameren, the Company could be considered jointly
and severably liable for assessments of additional tax on the consolidated
group. Income taxes are allocated to the individual companies based on their
respective taxable income or loss. The Company's provision for income taxes has
been presented based on federal and state taxes the Company would have
presented on a stand-alone company basis. 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.

Interest Capitalized

   Interest is capitalized in accordance with Statement of Financial Accounting
Standards (SFAS) No. 34, "Capitalization of Interest Cost." For the year ended
December 31, 2001 and for the period from May 1, 2000 through December 31,
2000, interest expense capitalized was $1.3 million and $0.8 million,
respectively.

Unamortized Debt Discount and Expense

   Discount and expense associated with long-term debt are amortized over the
life of the related issue.

Advances for Committed Units

   Advances for committed combustion turbine generating units at December 31,
2000 represented amounts loaned to Development Co. under a committed unit
contribution agreement. See Note 2--Related Party Transactions for further
discussion of this agreement.

Revenue

   The Company records electric revenues for service rendered, at the end of
each accounting period. See Note 2--Related Party Transactions for further
discussion of electric power supply agreements.

Energy Contracts

   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 are to be recognized on the
balance sheet measured at fair value, with changes in fair market value
included in earnings.

   AmerenEnergy enters into contracts, some of which are derivatives, for the
sale and purchase of energy on behalf of the 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.

                                      39

<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 No. 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. 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. SFAS 144 did not have a material effect on the
Company's financial position, results of operations or liquidity.

Use of Estimates

   The preparation of financial statements in conformity with United States
generally accepted accounting principles 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 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 was 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.

   In addition, 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.

Reclassifications

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

                                      40

<PAGE>

Note 2--Related Party Transactions

   The Company has transactions in the normal course of business with Ameren
and certain of its subsidiaries. These transactions primarily consist of power
purchases and sales, services received or rendered, borrowings and lendings.
The transactions with these affiliates are reported as intercompany
transactions.

   On May 1, 2000, AmerenCIPS transferred its electric generating assets and
related liabilities, at net book value, to the Company, in exchange for a
subordinated promissory note from the Company in the principal amount of $552
million and 1,000 shares of the Company's common stock. The transferred assets
represented generating capacity of approximately 2,860 megawatts at the time of
the transfer. Approximately 45% of AmerenCIPS' employees were transferred to
the Company as part of the transaction. The significant components of net
assets transferred are as follows:

<TABLE>
<CAPTION>
                                                 (In millions)
                                                 -------------
                 <S>                             <C>
                 Cash...........................     $  6
                 Other receivable--intercompany.       26
                 Material and supplies..........       54
                 Other current assets...........        6
                 Property and plant, net........      635
                                                     ----
                 Total assets transferred.......     $727
                                                     ----

                 Accounts payable...............     $  6
                 Other current liabilities......        3
                 Other deferred credits.........        2
                 Deferred investment tax credits       20
                 Deferred tax liabilities, net..      144
                                                     ----
                 Total liabilities transferred..     $175
                                                     ----
                 Net assets transferred.........     $552
                                                     ====
</TABLE>

   In June and July of 2000, the Company acquired combustion turbine generating
units at Pinckneyville and Gibson City, Illinois from Development Co. at
Development Co.'s historical net book value. The total installed cost of these
combustion turbine generating units was approximately $200 million.

   In September 2000, the Company also acquired three combustion turbine
generating units at Joppa, Illinois from an affiliate at the affiliate's
historical net book value. The total installed cost of these combustion turbine
generators was approximately $73 million. The Company entered into an operating
lease agreement with Development Co. for these units at the Joppa site wherein
the three combustion turbine generating units were leased to Development Co.
for a minimum term of fifteen years expiring September 30, 2015. The Company
receives rental payments under the lease in fixed monthly amounts that vary
over the term of the lease and range from $0.8--$1.0 million per month.
Development Co. is entitled to all of the output produced from the three units
and is responsible for all operating expenses. Development Co. entered into an
agreement with Midwest Electric Power, Inc., an affiliate, under which Midwest
Electric Power, Inc. provides operations and maintenance services at the Joppa
site. On November 1, 2000, Development Co. and Marketing Co. entered into an
electric power supply agreement, referred to as the Development Co.-Marketing
Co. agreement. The Development Co.-Marketing Co. agreement entitles Marketing
Co. to all of the output from the Joppa site. The Development Co.-Marketing Co.
agreement contains a monthly capacity charge that approximates the lease
payments Development Co. makes to the Company and an energy charge equal to the
variable costs of operating the combustion turbine generating units.

   On November 1, 2000, the Company and Resources, on behalf of itself and
Development Co. (the "Developers"), in conjunction with the financing described
in Note 4--Long-Term Debt, entered into a committed unit contribution
agreement, whereby the Company agreed to advance $125 million in cash to the
Developers in exchange for the delivery of combustion turbine generating units
at Kinmundy and Grand Tower,

                                      41

<PAGE>

Illinois, scheduled to be commercially available in mid-2001. Under this
agreement, the purchase price of the combustion turbine generating units
delivered to the Company in 2001 was reduced by the amount advanced to the
Developers. At December 31, 2000, the amount advanced to the Developers under
the committed unit contribution agreement was recorded as advances for
committed units--intercompany. Development Co. delivered the Kinmundy and Grand
Tower units during 2001.

Intercompany Financing

   The Company's $552 million note to AmerenCIPS is a subordinated intercompany
note. The Company and AmerenCIPS have agreed that debt service on this note
during its term will be payable solely from ''available cash,'' defined as cash
available after payment by Company of all its operating and maintenance
expenses, debt service, capital expenditures, taxes and reasonable reserves for
working capital and other corporate purposes as determined by the Company at
its discretion. Any installment payment amount which is not paid when due
because of the available cash limitation will be payable when available cash
becomes sufficient to permit the payment, or else carried forward until
maturity. The Company may not prepay the AmerenCIPS subordinated note in whole
or in part prior to the stated maturity, May 1, 2005, without the prior written
consent of the holders of a majority of the outstanding Senior Notes (as
further described in Note 4--Long-Term Debt) and such approvals as are required
under the terms of any other senior indebtedness. However, with the consent of
AmerenCIPS, the Company may prepay the AmerenCIPS subordinated note in whole or
in part with proceeds derived from other debt or equity securities it may issue
which rank subordinate and junior to senior indebtedness. The AmerenCIPS
subordinated note may not be transferred by AmerenCIPS except to another
wholly-owned subsidiary of Ameren. Resources has agreed with the Company that,
in the event that upon maturity the AmerenCIPS subordinated note has not been
paid in full or refinanced with other subordinated intercompany indebtedness
with terms at least as subordinate, then Resources will assume the Company's
obligations under the AmerenCIPS subordinated note (subject to regulatory
approval), with no further liability to the Company, or contribute sufficient
funds to the Company as equity or subordinated debt to enable the Company to
pay in full the remaining balance of the AmerenCIPS subordinated note.

   On June 30, 2000, the Company issued a second subordinated intercompany note
in the amount of $50 million to Ameren. This note is subordinated to all senior
debt as well as to the subordinated note held by AmerenCIPS. The two
subordinated intercompany notes each have a term of five years and bear
interest at 7% based on a 10-year amortization schedule.

   The aggregate maturities of the subordinated intercompany notes payable are
as follows (In millions):

<TABLE>
                          <S>                     <C>
                          Year Ended December 31,
                             2002................ $ 47
                             2003................   50
                             2004................   53
                             2005................  358
                                                  ----
                                                  $508
                                                  ====
</TABLE>

Electric Power Supply Agreements

   On May 1, 2000 (amended August 14, 2000 and March 30, 2001), an electric
power supply agreement was entered into between the Company and Marketing Co.,
referred to as the Genco--Marketing Co. agreement. Also on May 1, 2000,
Marketing Co. entered into an electric power supply agreement with AmerenCIPS,
referred to as the Marketing Co.--CIPS agreement (amended March 30, 2001), to
supply sufficient power to meet AmerenCIPS' native load requirements. A portion
of the capacity and energy supplied by the Company to Marketing Co. is resold
to AmerenCIPS for resale. The portion of these sales to AmerenCIPS that is used
for resale to native load customers is at rates (which approximate the
historical regulated rates for generation) specified by the Illinois Commerce
Commission (ICC). The portion of the sales to AmerenCIPS resold to those retail
customers allowed choice of an electric supplier under state law is at fixed
market-based prices. Other capacity and energy

                                      42

<PAGE>

purchased by Marketing Co. from the Company will be used by Marketing Co. to
serve its obligations under various long-term wholesale contracts it assumed
from AmerenCIPS and other long-term wholesale and retail contracts Marketing
Co. has or will enter into. The Marketing Co.--CIPS agreement expires December
31, 2004 and the Genco--Marketing Co. agreement may be terminated upon at least
one year's notice given by either party, but in no event can it be terminated
prior to December 31, 2004. For the year ended December 31, 2001 and for the
period from May 1, 2000 through December 31, 2000, $623 million and $341
million, respectively, of the Company's electric revenues were derived under
the Genco--Marketing Co. agreement. No other customer represents greater than
10% of the Company's revenues.

   In order to satisfy its regulatory load requirements for 2001, AmerenUE,
through a competitive bidding process, entered into a one year electric power
supply agreement with Marketing Co. (the Marketing Co.--AmerenUE agreement) to
purchase 450 megawatts of capacity and energy at market-based rates. Marketing
Co. acquired the power to supply AmerenUE from the Company. The Marketing
Co.--AmerenUE agreement expires May 31, 2002.

Joint Dispatch Agreement

   Prior to AmerenCIPS' transfer of its generating assets to the Company on May
1, 2000, AmerenCIPS and AmerenUE jointly dispatched their generation pursuant
to a joint dispatch agreement. In connection with the asset transfer,
AmerenCIPS assigned its electric generation rights and obligations under the
joint dispatch agreement to the Company and the agreement was amended to
reflect the fact that the Company now owns and operates the generation assets
previously owned by AmerenCIPS. As a result, the Company jointly dispatches
generation with AmerenUE under an amended joint dispatch agreement. Under the
amended agreement, the Company and AmerenUE are entitled to serve load
requirements from their own least-cost generation first, and then will allow
the other company access to any available excess generation. All of the
Company's sales to Marketing Co. are considered load requirements. Sales made
by the Company to other customers through AmerenEnergy, as the Company's agent,
are not considered load requirements. For the year ended December 31, 2001 and
for the period from May 1, 2000 through December 31, 2000, $317 million and
$105 million, respectively, of the Company's electric revenues were derived
through the sale of the Company's available generation through AmerenEnergy and
$33 million and $31 million, respectively, of the Company's electric revenues
were derived through sales of available generation to AmerenUE through the
amended joint dispatch agreement.

Ameren Services Charges

   The Company's financial statements include charges for services that Ameren
Services Company (Ameren Services), a wholly owned subsidiary of Ameren,
provides to the Company. Ameren Services provides the Company with certain
support functions such as accounting, finance, corporate planning, audit and
compliance service, investor relations, legal, corporate development,
regulatory, risk management, and tax services. In addition to support
functions, Ameren Services provides the Company with specialized support
functions, including information technology, human resources, environmental
resources, purchasing and materials management, and public affairs.

   Charges are based upon the actual costs incurred by Ameren Services. Charges
are billed monthly to the Company and are included in other operating expenses
in the accompanying Statement of Income. These charges were allocated to the
Company based on utilization or other methods which management believes to be
reasonable. For the year ended December 31, 2001 and for the period from May 1,
2000 through December 31, 2000, charges to the Company were $28 million and $18
million, respectively.

Other

   For the year ended December 31, 2001, and for the period from May 1, 2000
through December 31, 2000, intercompany power purchases from the amended joint
dispatch and other agreements was approximately $381 million and $119 million,
respectively.

                                      43

<PAGE>

   The Company has the ability to borrow up to $400 million from Ameren through
a non-utility money pool agreement. However, the total amount available to the
Company at any time is reduced by the amount of borrowings from the non-utility
money pool by other Ameren nonregulated companies and is increased to the
extent other Ameren nonregulated companies advance surplus funds to the
non-utility money pool or external borrowing sources are used by Ameren to
increase the available amounts.

   At December 31, 2001, approximately $12 million of funds were available
through the non-utility money pool not including additional funds available
through uncommitted bank lines. The non-utility money pool was established to
coordinate and provide for short-term cash and working capital requirements of
Ameren's nonregulated activities and is administered by Ameren Services.
Interest is calculated at varying rates of interest depending on the
composition of internal and external funds in the non-utility money pool. For
the year ended December 31, 2001 and for the period from May 1, 2000 through
December 31, 2000, the average interest rate for borrowings from the
non-utility money pool was 4.08% and 6.52%, respectively. Intercompany interest
income to the Company for loans to the non-utility money pool over those same
periods was $3 million and $1 million, respectively. At December 31, 2001, the
Company had no amounts loaned to the non-utility money pool and had outstanding
borrowings of approximately $62 million.

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 (RMSC), which is
comprised of senior-level Ameren officers.

Market Risk

   Fuels Co. and AmerenEnergy, on behalf of the Company, engage in price risk
management activities related to electricity and fuel. In addition to buying
and selling these commodities, the Company uses derivative financial
instruments to manage market risks and reduce exposure resulting from
fluctuations in the prices of electricity and fuel. Hedging instruments 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 resources and credit quality
of the clearing members of 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 subject to credit risk
consist primarily of accounts receivable and executory contracts with market
risk exposures. The Company's revenues are primarily derived from the sales of
electricity to Marketing Co. as described in Note 2 -- Related Party
Transactions under Notes to Financial Statements. Approximately $98 million of
the Company's accounts receivable are related party receivables from Marketing
Co. No other customer represents greater than 10% of the Company's accounts
receivable. 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).

                                      44

<PAGE>

Derivative Financial Instruments

   In January 2001, the Company adopted Statement of Financial Accounting
Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging
Activities." The impact of the adoption resulted in the Company recording a
cumulative effect charge of $2 million after taxes to the income statement,
comprised of $0.5 million for ineffective portion of cash flow hedges and $1.5
million for discontinued hedges, and a cumulative effect adjustment of $3
million after income taxes to Accumulated Other Comprehensive Income (OCI),
which reduced stockholder's equity. 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. 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.

   SFAS 133 requires all derivatives to be recognized on the balance sheet at
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 re-evaluates 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.

   The Company utilizes derivatives principally to manage the risk of changes
in market prices for fuel, electricity and emission credits. Price fluctuations
in 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. The Company primarily uses derivatives to
optimize the value of its physical and contractual positions. The Company
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 approximately $7 million in Other
Assets and derivative financial instrument liabilities of approximately $4
million in Other Deferred Credits.

Cash Flow Hedges

   The Company routinely enters into forward purchase and sales contracts for
electricity based on forecasted levels of economic generation in excess of load
requirements. The relative balance between load and economic

                                      45

<PAGE>

generation varies throughout the year and is monitored by the RMSC. The
contracts typically cover a period of twelve months or less. The purpose of
these contracts is to hedge against possible price fluctuations in the spot
market for the period covered under the contracts. The 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. This process includes linking all derivatives that are
designated as cash flow hedges to specific forecasted transactions. The Company
also formally assesses (both at hedge's inception and on an ongoing basis)
whether the derivatives used in hedging transactions have historically been
highly effective in offsetting changes in the cash flows of hedged items and
whether those derivatives are expected to remain highly effective in future
periods.

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

   Interest rate swaps are reflected at fair value in the Company's balance
sheet and the related gains and losses on these agreements are deferred in
stockholder's equity (as a component of other comprehensive income). 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 pre-tax 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 $4
million.

Other Derivatives

   The Company enters into option transactions to manage its positions in
heating oil and electricity. These transactions are treated as non-hedge
transactions under SFAS 133. Therefore, the net change in the market value of
heating oil and electricity options is recorded as fuel and purchased power in
the statement of income.

   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 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--Long-Term Debt

   On November 1, 2000, the Company issued $225 million of Senior Notes, Series
A due 2005 (Series A Notes) and $200 million of Senior Notes, Series B due 2010
(Series B Notes) (collectively, the Senior Notes) in a Rule 144A transaction
sold to institutional investors. In the first quarter of 2001, the Company
filed a registration statement on Form S-4 to register the Senior Notes under
the Securities Act of 1933, as amended, to permit an exchange offer of the
Senior Notes. In June 2001, all holders completed their exchange of the Senior
Notes for new Series C Notes and Series 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.

                                      46

<PAGE>

   Interest accrues on the Series C Notes at a rate of 7.75% per year and is
payable semiannually in arrears on May 1 and November 1 of each year. Principal
of the Series C Notes will be payable on November 1, 2005. Interest accrues on
the Series D Notes at a rate of 8.35% per year and is payable semiannually in
arrears on May 1 and November 1 of each year. Principal of the Series D Notes
will be payable on November 1, 2010. The proceeds received from the Senior
Notes were $423.6 million before transaction costs. Debt covenants limit the
Company's ability to, among other things, sell assets, create liens and engage
in mergers, consolidations or similar transactions. At December 31, 2001 and
2000, the Company was in compliance with all applicable debt covenants.

   Long-term debt outstanding at December 31, excluding intercompany notes, was:

<TABLE>
<CAPTION>
                                                     2001    2000
                                                     ----    ----
                                                     (In millions)
               <S>                                   <C>     <C>
               7.75% Senior Notes, Series C due 2005 $225    $225
               8.35% Senior Notes, Series D due 2010  200     200
                                                     ----    ----
                                                      425     425
               Unamortized discount on debt.........   (1)     (1)
                                                     ----    ----
               Total Long-Term Debt................. $424    $424
                                                     ====    ====
</TABLE>

Note 5--Income Taxes

   Total income tax expense for the year ended December 31, 2001 and for the
period from May 1, 2000 through December 31, 2000 resulted in effective tax
rates of 38% on earnings before income taxes.

   Principal reasons such tax rates differed from the statutory federal rate
were as follows:

<TABLE>
<CAPTION>
                                                            For the period
                                                 For the     May 1, 2000
                                                year ended     through
                                               December 31,  December 31,
                                                   2001          2000
                                               ------------ --------------
     <S>                                       <C>          <C>
     Statutory federal income tax rate              35%           35%
     Increases (decreases) from:
        Depreciation differences..............       1            --
        Amortization of investment tax credit.      (1)           (2)
        State income tax......................       3             5
        Other.................................      --            --
                                                    --            --
     Effective income tax rate................      38%           38%
                                                    ==            ==
</TABLE>

   Income tax expense components:

<TABLE>
<CAPTION>
                                                          For the period
                                             For the year  May 1, 2000
                                                ended        through
                                             December 31,  December 31,
                                                 2001          2000
                                             ------------ --------------
                                                    (In millions)
       <S>                                   <C>          <C>
       Current tax expense
       U.S. Federal.........................     $16           $19
       State and local......................       3             4
                                                 ---           ---
          Total current income taxes........     $19           $23
                                                 ---           ---
       Deferred tax expense.................      29             6
       Amortization of investment tax credit      (1)           (2)
                                                 ---           ---
          Total tax expense.................     $47           $27
                                                 ===           ===
</TABLE>

                                      47

<PAGE>

   In accordance with SFAS 109, as a result of the step-up in basis for tax
purposes of the transferred assets from AmerenCIPS to the Company, an
additional tax basis for the Company and a deferred intercompany tax gain for
AmerenCIPS of approximately $552 million was recorded, resulting in a deferred
tax asset for the Company of approximately $219 million and an equivalent
balance of income tax payable - intercompany. This transaction was recorded as
a non-cash transaction. The deferred tax asset and intercompany tax payable are
being amortized and paid, respectively, over twenty years, the approximate
remaining life of the transferred assets.

   Other deferred income taxes reflect the net tax effects of temporary
differences between the carrying amount of assets and liabilities for financial
reporting purposes and amounts used for income tax purposes. Significant
components of the Company's deferred tax assets and liabilities are as follows:

<TABLE>
<CAPTION>
                                             December 31, December 31,
                                                 2001         2000
                                             ------------ ------------
                                                   (In millions)
          <S>                                <C>          <C>
          Deferred tax assets:
             Tax basis step-up..............     $196         $211
             Tax basis of coal contract.....        4            9
             Investment tax credits.........        7            8
             Other..........................        1           --
                                                 ----         ----
                                                  208          228
          Deferred tax liabilities:
             Property timing differences....      165          158
             Other..........................        5           --
                                                 ----         ----
                                                  170          158
                                                 ----         ----
                 Net deferred tax asset.....     $ 38         $ 70
                                                 ====         ====
</TABLE>

Note 6--Retirement Benefits

   Ameren has defined benefit retirement plans covering substantially all
employees of the Company. Benefits are based on the employees' years of service
and compensation. Ameren's plans are funded in compliance with income tax
regulations and federal funding requirements. The Company, along with other
subsidiaries of Ameren, is a participant in Ameren's plans and is responsible
for its proportional share of the costs. The Company's share of the pension
costs for the year ended December 31, 2001 and for the period from May 1, 2000
through December 31, 2000 were $0.4 million and $0.5 million, respectively, of
which approximately 4% and 1%, respectively, were charged to construction
accounts.

   In addition to providing pension benefits, the Company provides certain
health care and life insurance benefits for retired employees. On January 1,
2000, the AmerenUE and AmerenCIPS postretirement medical benefit plans combined
to form the Ameren Postretirement Benefit Plans (Ameren Postretirement Plans).
The Ameren Postretirement Plans cover substantially all employees of the
Company. The Ameren Postretirement Plans are funded in compliance with income
tax regulations and federal funding requirements. The Company, along with other
subsidiaries of Ameren, is a participant in the Ameren Postretirement Plans and
is responsible for its proportional share of the costs. The Company's share of
the postretirement benefit costs for the year ended December 31, 2001 and for
the period from May 1, 2000 through December 31, 2000 were $3.1 million and
$1.8 million, respectively, of which approximately 5% was charged to
construction accounts in 2001.

Note 7--Commitments and Contingencies

   The Company has commitments for the purchase of coal under long-term
contracts. Coal contract commitments, including transportation costs, for the
period 2002 through 2006 are estimated to total $727 million. Over 95% of
Company's requirements for its coal plants has been acquired at fixed prices
for 2002 and

                                      48

<PAGE>

at least 78% of the coal requirements through 2006 are covered by contracts.
Total coal purchases, including transportation costs, for the year ended
December 31, 2001 and for the period from May 1, 2000 through December 31, 2000
were approximately $162 million and $95 million, respectively. The Company also
has existing contracts with pipeline and natural gas suppliers to provide
transportation and storage of natural gas for electric generation. Gas-related
contract cost commitments for the period 2002 through 2006 are estimated to
total $31 million. Total delivered natural gas costs were approximately $32
million and $7 million for the year ended December 31, 2001 and for the period
from May 1, 2000 through December 31, 2000, respectively.

   The Company intends to purchase from Development Co. four combustion turbine
generating units at Elgin, Illinois. These combustion turbine generating units
are expected to provide additional capacity of up to 468 megawatts at a cost of
approximately $222 million and be available for commercial operation by the end
of 2002.

   Due to market conditions and other factors, the Company has re-evaluated its
capacity needs and future planned purchases of combustion turbine units through
2005. The Company has reduced its previously expected capacity additions
through 2005 from 1,560 megawatts to its current estimate of 468 megawatts
(which represents the Elgin, Illinois project referred to above). Projected
total expenditures for the capacity additions in the 2002 through 2006 period
accordingly have been reduced from $752 million to $222 million. Resources sold
rights to develop 325 megawatts of generating capacity planned for commercial
operation in 2003 and is actively pursuing a third party assignment of an
additional 117 megawatt unit planned for commercial operations in 2002.
Resources has assigned to its regulated affiliate, AmerenUE, contractual rights
to four combustion turbine generating units totalling 650 megawatts which were
planned for commercial operation by the Company in 2004 and 2005.

   In the ordinary course of business, Ameren evaluates various 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.

   Capital expenditures at the Company's existing coal-fired plants are
expected to be approximately $300 million in total for the period 2002 through
2006, excluding any capital expenditures required to comply with nitrogen oxide
(NO\\x\\) emissions standards discussed below.

   In January 2001, the Company exchanged 162,840 sulfur dioxide (SO\\2\\)
allowances with vintages of 2006 and later with AmerenUE for 120,000 SO\\2\\
allowances with vintages of 2002 and earlier. This transaction was recorded at
the historical cost of the allowances. The market value of the allowances
exchanged was approximately equal. The Company completed this exchange because
it experienced a shortfall of SO\\2\\ allowances in 2000 and 2001 and is
projecting a shortfall in SO\\2\\ allowances in 2002 under current generation
plans. The Company may alter its generation plan or increase its use of
low-sulfur coal to improve its position in SO\\2\\ allowances.

   The State of Illinois has developed a NO\\x\\ control regulation for utility
boilers in the State consistent with a United States Environmental Protection
Agency (USEPA) program aimed at reducing ozone levels in the Eastern United
States. As a result of these state requirements, the Company anticipates a 75%
reduction from current levels of NO\\x\\ emissions from its power plant boilers
in Illinois by the year 2004. The Company estimates spending approximately $210
million for capital expenditures to comply with these rules, of which
approximately $50 million was spent in 2001. The 2001 costs were primarily
associated with the installation a new low-NO\\x\\ burner technology on unit 2
of the Company's Newton coal plant, which has been completed, and of Selective
Catalytic Reduction technology on unit 2 of the Company's Coffeen coal plant,
which remains under construction.

   The Company has applied for Early Reduction NO\\x\\ credits which would
allow it to manage compliance strategies by either purchasing NO\\x\\ control
equipment or utilizing credits. The Company may be eligible for such credits
due to the current low NO\\x\\ emission rates of some of its power plant
boilers under current state regulations.

                                      49

<PAGE>

   In July 1997, the USEPA issued regulations revising the National Ambient Air
Quality Standards for ozone and particulate matter. The standards were
challenged by industry representatives 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 USEPA for resolution. The USEPA 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 SO\\2\\
and NO\\x\\ 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 USEPA 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 Company's generating systems after 2005. On
July 20, 2001, the USEPA issued proposed Best Available Retrofit Technology
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 SO\\2\\ and NO\\x\\ emissions. These rules could also add
significant pollution control costs to Company's generating system between 2008
and 2012. 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 operation or liquidity.

   In addition, the United States Congress has been working on legislation to
consolidate the numerous air pollution regulations facing the utility and power
generating 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.

   The Company is involved in remediation activities to address onsite and
offsite impacts from the ash handling operations at its coal plants. Such
activities are not considered material in nature and costs relating to those
activities may be subject to indemnification by AmerenCIPS pursuant to the
provisions of the electric generating asset transfer arrangement executed on
May 1, 2000, referred to above under Note 2--Related Party Transactions.

   The Illinois Electric Service Customer Choice and Rate Relief Law of 1997
provides for retail direct access, which allows customers to choose their
electric generation supplier, to be phased in over several years. The phase-in
of retail direct access began on October 1, 1999, with large industrial and
commercial customers principally comprising the initial group. The remaining
commercial and industrial customers in Illinois were offered choice on December
31, 2000. Retail direct access will be offered to residential customers on May
1, 2002. The Company is unable to predict the ultimate impact that retail
direct access in Illinois will have on its future financial condition, results
of operation or liquidity.

   Certain employees of the Company and its affiliated companies are
represented by the International Brotherhood of Electrical Workers Local 702
and the International Union of Operating Engineers Local 148. These employees
comprise approximately 72% of the Company's workforce. Labor agreements
covering virtually all represented employees of the Company expire on June 30,
2002.

   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. 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.

                                      50

<PAGE>

Note 8--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.

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. See
Note 3--Risk Management and Derivative Financial Instruments for further
discussion regarding the fair market value of the Company's derivative
financial instruments.

   Carrying amounts and estimated fair values of the Company's financial
instruments at December 31:

<TABLE>
<CAPTION>
                                                    2001           2000
                                               -------------- --------------
                                               Carrying Fair  Carrying Fair
                                                Amount  Value  Amount  Value
                                               -------- ----- -------- -----
                                                       (In millions)
    <S>                                        <C>      <C>   <C>      <C>
    Long-term debt (including current portion)   $424   $451    $424   $441
                                                 ====   ====    ====   ====
</TABLE>

ITEM 9.  Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.

   None.

                                      51

<PAGE>

                                   PART III

ITEM 10.  Directors and Executive Officers of the Registrant.

Directors and Executive Officers

   Except as otherwise indicated below, each of our officers and directors have
served in their positions since our company was formed. The following are our
officers and directors:

<TABLE>
             <S>                <C>
             Daniel F. Cole.... President and Director
             Paul A. Agathen... Senior Vice President and Director
             Warner L. Baxter.. Senior Vice President--Finance
                                and Director
             R. Alan Kelley.... Senior Vice President--Operations
             Garry L. Randolph. Senior Vice President
             Thomas R. Voss.... Senior Vice President
             David A. Whiteley. Senior Vice President
             Michael J. Montana Vice President--Supply Services
             Robert L. Powers.. Vice President--Technical Services
             Jerry L. Simpson.. Vice President--Power Operations
             Steven R. Sullivan Vice President, General Counsel and
                                Secretary
             Jerre E. Birdsong. Vice President and Treasurer
             Martin J. Lyons... Controller
</TABLE>

   Daniel F. Cole, President and Director. Mr. Cole is also a Senior Vice
President of AmerenUE, AmerenCIPS and Ameren Services. AmerenUE employed Mr.
Cole in 1976 as an engineer. He was named AmerenUE's Manager--Resource Planning
in 1996 and General Manager--Corporate Planning in 1997. In 1998, Mr. Cole was
elected as Vice President of Corporate Planning of Ameren Services. Mr. Cole
was elected to his present positions at AmerenUE and Ameren Services in 1999
and at our company and AmerenCIPS in 2001. Age: 48.

   Paul A. Agathen, Senior Vice President and Director. Mr. Agathen is also a
Senior Vice President of AmerenUE, AmerenCIPS and Ameren Services. Mr. Agathen
was employed by AmerenUE in 1975 as an attorney. He was named General Attorney
of AmerenUE in 1982, Vice President, Environmental and Safety in 1994 and
Senior Vice President in 1996. He was elected to his present position at Ameren
Services on December 31, 1997 and at our company, AmerenUE and AmerenCIPS in
2001. Other directorships: AmerenUE since 1998; AmerenCIPS since 1997. Age: 54.

   Warner L. Baxter, Senior Vice President--Finance and Director. Mr. Baxter
was elected as an officer of our company in July 2000. Mr. Baxter is also a
Senior Vice President of Ameren Corporation, AmerenUE, AmerenCIPS, and Ameren
Services. Mr. Baxter worked for Price Waterhouse (now PricewaterhouseCoopers
LLP) from 1983 until his appointment as Assistant Controller of AmerenUE in
1995. He was promoted to Controller in 1996 and was elected Vice President and
Controller of Ameren Corporation, AmerenUE, and Ameren Services in 1998. He was
elected Vice President and Controller of AmerenCIPS in 1999 and of our company
in 2000. Mr. Baxter was elected to his present position at our company, Ameren
Corporation, AmerenUE, AmerenCIPS and Ameren Services in 2001. He has been a
director of our company since 2001. Other directorships: AmerenUE since 1999;
AmerenCIPS since 1999. Age: 40.

   R. Alan Kelley, Senior Vice President--Operations. Mr. Kelley had also been
the President of EEI since 1987 and was elected Chairman of the Board of EEI in
2000. He had also been Vice President--Energy Supply of AmerenUE from 1988 to
1997 and a Vice President of Ameren Services from 1997 to 2000. Age: 49.

                                      52

<PAGE>

   Garry L. Randolph, Senior Vice President. Mr. Randolph was elected as an
officer of our company in 2001. Mr. Randolph is also a Senior Vice President of
AmerenUE and AmerenCIPS. He was employed by AmerenUE in 1977 as an engineer and
elected Vice President, Nuclear Operations in 1992, Vice President and Chief
Nuclear Officer in 1997, Senior Vice President and Chief Nuclear Officer in
2000, and Senior Vice President--Generation and Chief Nuclear Officer in 2001.
Age: 53.

   Thomas R. Voss, Senior Vice President. Mr. Voss was elected as an officer of
our company in 2001. Mr. Voss is also a Senior Vice President of AmerenUE,
AmerenCIPS and Ameren Services. Mr. Voss was employed by AmerenUE in 1969 as an
engineer. After four years of military service, he returned to AmerenUE and
from 1975 to 1988, held various positions including district manager and
distribution operating manager. Mr. Voss was elected Vice President of
AmerenCIPS in 1998. He was elected to his present position with AmerenUE,
AmerenCIPS and Ameren Services in 1999. Mr. Voss was elected director of
AmerenUE and AmerenCIPS in 2001. Age: 54.

   David A. Whiteley, Senior Vice President. Mr. Whiteley was elected as an
officer of our company in 2001. Mr. Whiteley is also a Senior Vice President of
AmerenUE, AmerenCIPS and Ameren Services. Mr. Whiteley was employed by AmerenUE
in 1978 as an engineer and in 1993 was named manager of transmission planning
and later manager of electrical engineering and transmission planning. In 2000,
Mr. Whiteley was elected Vice President of Ameren Services responsible for
engineering and construction and later energy delivery technical services. Age:
45.

   Michael J. Montana, Vice President--Supply Services. Mr. Montana was elected
as an officer of our company in November 2000. Mr. Montana is also Vice
President--Supply Services of AmerenUE, AmerenCIPS and Ameren Services. He
joined AmerenUE as an engineer in 1971 and had also served as Purchasing
Department Buyer from 1973 to 1976, executive assistant from 1976 to 1984,
manager of Industrial Relations from 1984 to 1988 and Vice President of
Industrial Relations from 1988 to 1995 of AmerenUE. He was elected Vice
President of Ameren Services in 1997 and Vice President of AmerenCIPS in 1998.
Age: 55.

   Robert L. Powers, Vice President--Technical Services. Mr. Powers was elected
as an officer of our company in July 2000. Mr. Powers was also elected Vice
President of EEI in February 1990 and was elected President of that company in
May 2000. Before joining EEI, Mr. Powers was Site Manager for Quality Assurance
at AmerenUE's Callaway Nuclear plant from 1976 to 1985 and Manager of Quality
Improvement Process from 1985 to 1989. Mr. Powers began his power plant
experience with Bechtel Power Corporation as a mechanical field engineer at
AmerenUE's Labadie plant in 1970. Age: 53.

   Jerry L. Simpson, Vice President--Power Operations. Mr. Simpson had also
been a Vice President of AmerenCIPS until 2000. Mr. Simpson joined AmerenCIPS
in 1978 as an engineer at the Newton Station. He held staff positions in
AmerenCIPS' Power Production and Environmental Affairs departments before being
named Assistant Superintendent at the Grand Tower station in 1986. Mr. Simpson
was named Plant Manager at the Grand Tower station in 1991 and Plant Manager at
the Meredosia station in 1994. Age: 45.

   Steven R. Sullivan, Vice President, General Counsel and Secretary. Mr.
Sullivan has also been Vice President, General Counsel and Secretary of Ameren
Corporation, AmerenUE, AmerenCIPS, Ameren Services and Ameren Energy since
1998. Mr. Sullivan was previously employed by Anheuser Busch Companies, Inc. as
an attorney from 1995 to 1998. Age: 41.

   Jerre E. Birdsong, Vice President and Treasurer. Mr. Birdsong has also been
Treasurer of AmerenUE since 1993, Ameren Corporation since 1996, AmerenCIPS and
Ameren Services since 1997, and Ameren Energy since 1998. In addition to being
Treasurer, he was elected to the position of Vice President in 2001. Age: 47.

   Martin J. Lyons, Controller. Mr. Lyons was appointed as Controller of our
company in October 2001. At the same time, he was also appointed as Controller
of Ameren Corporation, AmerenUE, AmerenCIPS and Ameren Services. Mr. Lyons
worked for PricewaterhouseCoopers LLP for 13 years prior to his appointment as
Controller. Age: 35.

                                      53

<PAGE>

Compliance with Section 16(a) of the Exchange Act.

   Not applicable.

ITEM 11.  Executive Compensation.

   Our management is provided a competitive total compensation package which
includes benefits comparable to that provided to other Ameren management
employees. As noted in the information above, several of our management
personnel also have duties with other Ameren entities and may spend the
majority of their time at those duties. In general, all of our management
employees are paid through our affiliate Ameren Services. We pay all the direct
costs of our employee compensation and our proportionate share of direct and
indirect compensation expense for those employees who spend a portion of their
time working for other Ameren entities. Allocation methodologies for
compensation are subject to review by the SEC under PUHCA.

Compensation Tables

   The following tables contain compensation information, for the periods
indicated, for (a) our President, (b) the four other most highly compensated
executive officers of our company who were serving as executive officers at the
end of 2001 and (c) G.L. Rainwater who relinquished his position as President
of our company on August 30, 2001 when he was elected President and Chief
Operating Officer of Ameren Corporation, AmerenUE and Ameren Services.

                          Summary Compensation Table

<TABLE>
<CAPTION>
                                                                    Long-Term
                                    Annual Compensation            Compensation
                               ----------------------------- ------------------------
                                                             Restricted
                                                               Stock     Securities
          Name and                                             Awards    Underlying       All Other
    Principal Position(1)      Year(2) Salary($) Bonus($)(3)   ($)(4)   Options(#)(5) Compensation($)(6)
    ---------------------      ------- --------- ----------- ---------- ------------- ------------------
<S>                            <C>     <C>       <C>         <C>        <C>           <C>
D.F. Cole.....................  2001    246,667     70,220    138,012          --           12,691
President                       2000    215,000     59,300         --      32,600            9,286

G.L. Randolph.................  2001    291,000     74,900    174,594          --           20,062
Senior Vice President           2000    276,000     78,700         --      14,100           11,729

P.A. Agathen..................  2001    285,000     69,600    171,019          --           37,167
Senior Vice President           2000    272,000     71,800         --      32,600           27,408

W.L. Baxter...................  2001    248,000     61,600     92,784          --            5,095
Senior Vice President--Finance  2000    220,000     47,000         --      14,100            4,634

T.R. Voss.....................  2001    244,000     61,200    146,410          --           15,531
Senior Vice President           2000    230,000     63,500         --      32,600            9,711

G.L. Rainwater................  2001    446,667    139,430    251,997          --           24,762
Former President(7)             2000    400,000    115,200         --      32,600            9,450
</TABLE>
--------
(1) Includes compensation received as an officer of Ameren Corporation and its
    subsidiaries, including our company.
(2) Our company began doing business in May 2000.
(3) Amounts for each fiscal year represent bonus compensation earned for that
    year payable in the subsequent year.
(4) Restricted Stock Awards relate to Ameren Corporation common stock. This
    column is based on the $41.57 closing price of Ameren Corporation common
    stock on February 9, 2001, the date the restricted stock was awarded. The
    number of restricted shares of Ameren Corporation common stock held at
    fiscal year end and the value of such holdings, based on the number of
    restricted shares for which restrictions have not lapsed

                                      54

<PAGE>

   times the closing market price at December 31, 2001 ($42.30 per share), was
   3,532 shares and $149,404 for Mr. Cole; 4,468 shares and $188,996 for Mr.
   Randolph; 4,376 shares and $185,105 for Mr. Agathen; 2,374 shares and
   $100,420 for Mr. Baxter; 3,746 shares and $158,456 for Mr. Voss; and 6,448
   shares and $272,750 for Mr. Rainwater. Upon the achievement of certain
   company performance levels, restricted shares vest equally over a seven-year
   period from the date of grant (one-seventh on each anniversary date). The
   vesting period is reduced from seven years to three years if Ameren
   Corporation's ongoing earnings per share achieve a prescribed growth rate
   over the three-year period. Restricted stock that would otherwise vest
   remain restricted until prescribed minimum stock ownership levels are
   satisfied by the officer. Dividends declared on restricted shares are
   reinvested in additional shares of Ameren Corporation common stock, which
   vest concurrently with the restricted shares. The officers are entitled to
   voting privileges associated with the restricted shares to the extent the
   restricted shares have not been forfeited.
(5) Options relate to Ameren Corporation common stock.
(6)/ Amounts include matching contributions to Ameren Corporation's 401(k) plan
     and above-market earnings on deferred compensation. For fiscal year 2001,
     amount includes (a) matching contributions to the 401(k) plan and (b)
     above-market earnings on deferred compensation, as follows: /

<TABLE>
                         <S>            <C>    <C>
                                           (a)     (b)
                         D.F. Cole..... $7,657 $ 3,573
                         G.L. Randolph.  7,664   9,308
                         P.A. Agathen..  6,787  26,970
                         W.L. Baxter...      0   4,274
                         T.R. Voss.....  6,771   5,944
                         G.L. Rainwater  7,462  12,051
</TABLE>

For fiscal year 2001, amount also includes the dollar value of insurance
premiums paid by Ameren Corporation with respect to term life insurance for the
benefit of the executive officer, as follows:

<TABLE>
                             <S>            <C>
                             D.F. Cole..... $1,461
                             G.L. Randolph.  3,090
                             P.A. Agathen..  3,410
                             W.L. Baxter...    821
                             T.R. Voss.....  2,816
                             G.L. Rainwater  5,249
</TABLE>

(7) G.L. Rainwater served as our President until August 30, 2001.

                      Aggregated Option Exercises in 2001
                            and Year-End Values(1)

<TABLE>
<CAPTION>
                                                                      Value of
                                           Unexercised              In-the-Money
                 Shares     Value    Options at Year End(#)   Options at Year End($)(2)
               Acquired on Realized ------------------------- -------------------------
    Name       Exercise(#)    $     Exercisable Unexercisable Exercisable Unexercisable
    ----       ----------- -------- ----------- ------------- ----------- -------------
<S>            <C>         <C>      <C>         <C>           <C>         <C>
D.F. Cole.....     --         --       5,982       42,568        23,337      420,049
G.L. Randolph.     --         --      14,675       27,825        53,156      222,894
P.A. Agathen..     --         --      34,625       68,375       114,651      533,884
W.L. Baxter...     --         --      13,375       27,825        45,103      222,894
T.R. Voss.....     --         --       6,682       42,568        27,834      420,049
G.L. Rainwater     --         --      19,875       66,425        78,928      526,474
</TABLE>
--------
(1) No options were granted in 2001.
(2) These columns represent the excess of the closing price of Ameren
    Corporation's common stock of $42.30 per share, as of December 31, 2001,
    above the exercise price of the options. The amounts under the Exercisable
    column report the "value" of options that are vested and therefore could be
    exercised. The Unexercisable column reports the "value" of options that are
    not vested and therefore could not be exercised as of December 31, 2001.

                                      55

<PAGE>

Ameren Retirement Plan

   Most salaried employees of Ameren and its subsidiaries earn benefits under
the Ameren Retirement Plan immediately upon employment. Benefits generally
become vested after five years of service. On an annual basis a bookkeeping
account in a participant's name is credited with an amount equal to a
percentage of the participant's pensionable earnings for the year. Pensionable
earnings equals base pay, overtime and annual bonuses, which are equivalent to
amounts shown as "Annual Compensation" in the Summary Compensation Table. The
applicable percentage is based on the participant's age as of December 31 of
that year. If the participant was an employee prior to July 1, 1998, an
additional transition credit percentage is credited to the participant's
account through 2007 (or an earlier date if the participant had less than 10
years of service on December 31, 1998).

<TABLE>
<CAPTION>
                              Regular Credit  Transition Credit
         Participant's Age on for Pensionable    Pensionable     Total
             December 31         Earnings*        Earnings      Credits
         -------------------- --------------- ----------------- -------
         <S>                  <C>             <C>               <C>
             Less than 30....        3%                1%           4%
             30 to 34........        4%                1%           5%
             35 to 39........        4%                2%           6%
             40 to 44........        5%                3%           8%
             45 to 49........        6%              4.5%        10.5%
             50 to 54........        7%                4%          11%
             55 and over.....        8%                3%          11%
</TABLE>
--------
 *An additional regular credit of 3% is received for pensionable earnings above
     the Social Security wage base.

   These accounts also receive interest credits based on the average yield for
one-year U.S. Treasury Bills for the previous October, plus 1%. In addition,
some annuity benefits earned by participants under prior plans as of December
31, 1997 were converted to additional credit balances under the retirement plan
as of January 1, 1998. When a participant terminates employment, the amount
credited to the participant's account is converted to an annuity or paid to the
participant in a lump sum. The participant can also choose to defer
distribution, in which case the account balance is credited with interest at
the applicable rate until the future date of distribution. Benefits are not
subject to any deduction for Social Security or other offset amounts.

   In some cases pension benefits under the retirement plan are reduced to
comply with maximum limitations imposed by the Internal Revenue Code. A
supplemental retirement plan is maintained by Ameren to provide for a
supplemental benefit equal to the difference between the benefit that would
have been paid if those Internal Revenue Code limitations were not in effect
and the reduced benefit payable as a result of those Internal Revenue Code
limitations. The plan is unfunded and is not a qualified plan under the
Internal Revenue Code.

   The following table shows the estimated annual retirement benefits,
including supplemental benefits, which would be payable to each executive
officer listed if he were to retire at age 65 at his 2001 base salary and
annual bonus, and payments were made in the form of a single life annuity.

<TABLE>
<CAPTION>
                                                 Estimated
                                    Year of 65th  Annual
                     Name             Birthday    Benefit
                     ----           ------------ ---------
                     <S>            <C>          <C>
                     D.F. Cole.....     2018     $144,000
                     G.L. Randolph.     2013      164,000
                     P.A. Agathen..     2012       89,000
                     W.L. Baxter...     2026      141,000
                     T.R. Voss.....     2012      136,000
                     G.L. Rainwater     2011      179,000
</TABLE>

                                      56

<PAGE>

Change of Control Severance Plan

   Under the Ameren Corporation Change of Control Severance Plan, designated
officers of Ameren, including current officers of our company named in the
Summary Compensation Table, are entitled to receive severance benefits if their
employment is terminated under specified circumstances within three years after
a "change of control." A "change of control" occurs, in general, if:

  .  any individual, entity or group acquires 20% or more of the outstanding
     common stock of Ameren Corporation or of the combined voting power of the
     outstanding voting securities of Ameren Corporation;

  .  individuals who, as of the effective date of the severance plan,
     constitute the board of directors of Ameren Corporation, or who have been
     approved by a majority of the board, cease for any reason to constitute a
     majority of the board; or

  .  Ameren Corporation enters into specified business combinations, unless
     some requirements are met regarding continuing ownership of the
     outstanding common stock and voting securities of Ameren Corporation and
     the membership of its board of directors.

   Severance benefits are based upon a severance period of two or three years,
depending on the officer's position. An officer entitled to severance will
receive the following:

  .  salary and unpaid vacation pay through the date of termination;

  .  a pro rata bonus for the year of termination, and base salary and bonus
     for the severance period;

  .  continued employee welfare benefits for the severance period;

  .  a cash payment equal to the actuarial value of the additional benefits the
     officer would have received under Ameren's qualified and supplemental
     retirement plans if employed for the severance period;

  .  up to $30,000 for the cost of outplacement services; and

  .  reimbursement for any excise tax imposed on those benefits as excess
     payments under the Internal Revenue Code.

Committees of the Board of Directors

   Our board of directors does not have standing committees. The board
committees (including the Human Resources Committee) of our parent company,
Ameren Corporation, perform committee functions for our board.

Compensation Committee Interlocks and Insider Participants

   We do not have a compensation committee and there is no other committee of
our board of directors that performs similar functions. The Human Resources
Committee of Ameren Corporation considered compensation matters with respect to
our executive officers. Some of our executive officers serve on the boards of
directors of other Ameren companies whose executive officers serve on our board
of directors.

Director Compensation

   The members of our board of directors are executive officers of Ameren
Corporation or its subsidiaries, and they do not receive any compensation for
their services as our directors.

                                      57

<PAGE>

ITEM 12.  Security Ownership of Certain Beneficial Owners and Management.

   Development Co. owns 2,000 shares of our common stock, which constitute all
of our outstanding capital stock. Resources owns all of the outstanding shares
of capital stock of Development Co. and Ameren Corporation owns all of the
outstanding shares of capital stock of Resources. The ownership interests of
our directors and executive officers in Ameren Corporation common stock as of
February 1, 2002 are set forth below.

                       Securities of Ameren Corporation

<TABLE>
<CAPTION>
                                                     Shares of Common Stock
                                                     of Ameren Corporation
                                                    Beneficially Owned(1)(2)
    Name of Holder                                   as of February 1, 2002
    --------------                                  ------------------------
    <S>                                             <C>
    Paul A. Agathen................................          61,238
    Warner L. Baxter...............................          22,984
    Daniel F. Cole.................................          23,380
    Gary L. Rainwater(3)...........................          47,920
    Gary L. Randolph...............................          28,818
    Thomas R. Voss.................................          24,183
                                                            -------
    All directors and executive officers as a group         320,907
                                                            =======
</TABLE>
--------
(1) This column lists voting securities including restricted stock held by
    executive officers over which the officers have voting power but no
    investment power. Also includes shares issuable within 60 days upon the
    exercise of stock options as follows: Mr. Agathen, 51,700; Mr. Baxter,
    20,425; Mr. Cole, 17,075; Mr. Rainwater, 35,000; Mr. Randolph, 21,725; and
    Mr. Voss, 17,775. Reported shares include those for which a director or
    executive officer has voting or investment power because of joint or
    fiduciary ownership of the shares or a relationship with the record owner,
    most commonly a spouse, even if that director or executive officer does not
    claim beneficial ownership.
(2)/ Shares beneficially owned by all directors and executive officers in the
     aggregate do not exceed one percent of any class of equity securities
     outstanding. /
(3) Mr. Rainwater served as our President until August 30, 2001.

ITEM 13.  Certain Relationships and Related Party Transactions.

   None.

                                      58

<PAGE>

                                    PART IV

ITEM 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K.

(A) Financial Statements:

<TABLE>
<CAPTION>
                                                                                                   Page
                                                                                                  Number
                                                                                                  ------
<S>                                                                                               <C>
(1) Financial Statements of Ameren Energy Generating Company which are included at Item 8 of this
    report.

    (a) Report of Independent Accountants........................................................   33

    (b) Balance Sheet at December 31, 2000 and 2001..............................................   34

    (c) Statement of Income for the Period May 1, 2000 through December 31, 2000 and the Year
        Ended December 31, 2001..................................................................   35

    (d) Statement of Cash Flows for the Period May 1, 2000 through December 31, 2000 and the
        Year Ended December 31, 2001.............................................................   36

    (e) Statement of Common Stockholder's Equity for the Period May 1, 2000 through
        December 31, 2000 and the Year Ended December 31, 2001...................................   37

    (f) Notes to Financial Statements............................................................   38
</TABLE>

(2) Financial Statement Schedule

   None.

(3) Exhibits filed with this report are listed on the "Exhibit Index".

(B) Reports on Form 8-K

   None.

(C) Exhibits.

<TABLE>
<CAPTION>
Exhibit
Number                                              Description
-------                                             -----------
<C>     <S>
  3.1   Articles of Incorporation of AmerenEnergy Generating Company (the "Company"), filed March 2,
        2000 (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4
        (Commission File No. 333-56594)).

  3.2   Amendment to Articles of Incorporation of the Company, filed April 19, 2000 (incorporated by
        reference to Exhibit 3.2 to the Company's Registration Statement on Form S-4 (Commission File No.
        333-56594)).

  3.3   By-laws of the Company (incorporated by reference to Exhibit 3.3 to the Company's Registration
        Statement on Form S-4 (Commission File No. 333-56594)).

  4.1   Indenture dated as of November 1, 2000, between the Company and The Bank of New York, as
        Trustee, relating to senior notes (the "Indenture") (incorporated by reference to Exhibit 4.1 to the
        Company's Registration Statement on Form S-4 (Commission File No. 333-56594)).

  4.2   First Supplemental Indenture to the Indenture, dated as of November 1, 2000 (incorporated by
        reference to Exhibit 4.2 to the Company's Registration Statement on Form S-4 (Commission File
        No. 333-56594)).
</TABLE>

                                      59

<PAGE>

<TABLE>
<CAPTION>
Exhibit
Number                                              Description
-------                                             -----------
<C>     <S>
   4.3  Form of Second Supplemental Indenture to the Indenture, dated as of June 12, 2001 (incorporated by
        reference to Exhibit 4.3 to the Company's Registration Statement on Form S-4 (Commission File No.
        333-56594)).

   4.4  Form of Note (included in Exhibit 4.2).

   4.5  Form of Exchange Note (included in Exhibit 4.3).

   4.6  Registration Rights Agreement, dated as of November 1, 2000, among the Company and the initial
        purchasers thereunder (incorporated by reference to Exhibit 4.6 to the Company's Registration
        Statement on Form S-4 (Commission File No. 333-56594)).

  10.1  Asset Transfer Agreement between the Company and Central Illinois Public Service Company d/b/a
        AmerenCIPS ("AmerenCIPS") (incorporated by reference to Exhibit 10 to AmerenCIPS' quarterly
        report on Form 10-Q for the quarter ended June 30, 2000).

  10.2  Amended Electric Power Supply Agreement between the Company and AmerenEnergy Marketing
        Company ("Marketing Co.") (incorporated by reference to Exhibit 10.2 to the Company's Registration
        Statement on Form S-4 (Commission File No. 333-56594)).

  10.3  Second Amended Electric Power Supply Agreement between the Company and Marketing Co.
        (incorporated by reference to Exhibit 10.1 to Ameren Corporation's ("Ameren's") quarterly report on
        Form 10-Q for the quarter ended March 31, 2001).

  10.4  Electric Power Supply Agreement between Marketing Co. and AmerenCIPS (incorporated by
        reference to Exhibit 10.3 to the Company's Registration Statement on Form S-4 (Commission File
        No. 333-56594)).

  10.5  Amended Electric Power Supply Agreement between Marketing Co. and AmerenCIPS (incorporated
        by reference to Exhibit 10.2 to Ameren's quarterly report on Form 10-Q for the quarter ended
        March 31, 2001).

  10.6  Power Sales Agreement between Marketing Co. and Union Electric Company d/b/a AmerenUE
        ("AmerenUE") (incorporated by reference to Exhibit 10.1 to AmerenUE's quarterly report on Form
        10-Q for the quarter ended September 30, 2001).

  10.7  Amended Joint Dispatch Agreement among the Company, AmerenCIPS and AmerenUE (incorporated
        by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-4 (Commission File
        No. 333-56594)).

  10.8  Agency Agreement among the Company, AmerenUE, Marketing Co. and Ameren Energy, Inc.
        (incorporated by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-4
        (Commission File No. 333-56594)).

  10.9  General Services Agreement between Ameren Services Company ("Ameren Services") and
        AmerenEnergy Resources Company ("Resources") (incorporated by reference to Exhibit 10.6 to the
        Company's Registration Statement on Form S-4 (Commission File No. 333-56594)).

 10.10  Fuel Services Agreement between AmerenEnergy Fuels and Services Company and Resources
        (incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-4
        (Commission File No. 333-56594)).

 10.11  Form of Parallel Operating Agreement between the Company and Ameren Services (incorporated by
        reference to Exhibit 10.8 to the Company's Registration Statement on Form S-4 (Commission File
        No. 333-56594)).
</TABLE>

                                      60

<PAGE>

<TABLE>
<CAPTION>
Exhibit
Number                                            Description
-------                                           -----------
<C>     <S>
 10.12  Committed Unit Contribution Agreement between the Company and Resources (on behalf of itself
        and AmerenEnergy Development Company ("Development Co.")) (incorporated by reference to
        Exhibit 10.9 to the Company's Registration Statement on Form S-4 (Commission File No. 333-
        56594)).

 10.13  Lease Agreement between the Company and Development Co. (incorporated by reference to Exhibit
        10.10 to the Company's Registration Statement on Form S-4 (Commission File No. 333-56594)).

 10.14  Alliance Agreement establishing the Alliance Independent Transmission System Operator, Inc.,
        Alliance Transmission Company, Inc. and Alliance Transmission Company, LLC and Amendment to
        Admit AmerenCIPS and AmerenUE (incorporated by reference to Exhibit 10.1 to Ameren's quarterly
        report on Form 10-Q for the quarter ended June 30, 2001).

 10.15* Long-Term Incentive Plan of 1998 (incorporated by reference to Exhibit 10.1 to Ameren's annual
        report on Form 10-K for the year ended December 31, 1998).

 10.16* Change of Control Severance Plan (incorporated by reference to Exhibit 10.2 to Ameren's annual
        report on Form 10-K for the year ended December 31, 1998).

 10.17* Ameren's Deferred Compensation Plan for Members of the Ameren Leadership Team as amended and
        restated effective January 1, 2001 (incorporated by reference to Exhibit 10.1 to Ameren's annual
        report on Form 10-K for the year ended December 31, 2000).

 10.18* Ameren's Deferred Compensation Plan for Members of the Board of Directors (incorporated by
        reference to Exhibit 10.4 to Ameren's annual report on Form 10-K for the year ended December 31,
        1998).

 10.19* Ameren's Executive Incentive Compensation Program Elective Deferral Provisions for Members of
        the Ameren Leadership Team as amended and restated effective January 1, 2001 (incorporated by
        reference to Exhibit 10.2 to Ameren's annual report on Form 10-K for the year ended December 31,
        2000).

 12.1** Statement of Computation of Ratio of Earnings to Fixed Charges.
</TABLE>
--------
*  Management compensatory plan or arrangement.
** Filed herewith.
Note:  Reports of Ameren Corporation on Forms 10-K, 10-Q and 8-K are on file
     with the Securities and Exchange Commission (the "SEC") under File No.
     1-14756.

     Reports of Union Electric Company on Forms 10-K, 10-Q and 8-K are on file
     with the SEC under File No. 1-2967.

     Reports of Central Illinois Public Service Company on Forms 10-K, 10-Q and
     8-K are on file with the SEC under File No. 1-3672.

                                      61

<PAGE>

                                  SIGNATURES

   Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Annual Report to be
signed on its behalf by the undersigned, thereunto duly authorized, on March
28, 2002.

                                          AMEREN ENERGY GENERATING COMPANY
                                            (Registrant)

                                                   /S/  DANIEL F. COLE
                                          By: _______________________________
                                                       Daniel F. Cole
                                                         President

Date: March 28, 2002

   Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.

          Signature                       Title                  Date
          ---------                       -----                  ----

     /S/  DANIEL F. COLE      President and                 March 28, 2002
----------------------------- Director (Principal Executive
       Daniel F. Cole         Officer)

    /S/  PAUL A. AGATHEN      Senior Vice President         March 28, 2002
----------------------------- and Director
       Paul A. Agathen

    /S/  WARNER L. BAXTER     Senior Vice                   March 28, 2002
----------------------------- President--Finance and
      Warner L. Baxter        Director (Principal Financial
                              Officer)

    /S/  MARTIN J. LYONS      Controller (Principal         March 28, 2002
----------------------------- Accounting Officer)
       Martin J. Lyons

                                      62

<PAGE>

                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
Exhibit
Number                                              Description
------                                              -----------
<C>     <S>
  3.1.. Articles of Incorporation of AmerenEnergy Generating Company (the "Company"), filed March 2,
        2000 (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4
        (Commission File No. 333-56594)).

  3.2.. Amendment to Articles of Incorporation of the Company, filed April 19, 2000 (incorporated by
        reference to Exhibit 3.2 to the Company's Registration Statement on Form S-4 (Commission File
        No. 333-56594)).

  3.3.. By-laws of the Company (incorporated by reference to Exhibit 3.3 to the Company's Registration
        Statement on Form S-4 (Commission File No. 333-56594)).

  4.1.. Indenture, dated as of November 1, 2000, between the Company and The Bank of New York, as
        Trustee, relating to senior notes (the "Indenture") (incorporated by reference to Exhibit 4.1 to the
        Company's Registration Statement on Form S-4 (Commission File No. 333-56594)).

  4.2.. First Supplemental Indenture to the Indenture, dated as of November 1, 2000 (incorporated by
        reference to Exhibit 4.2 to the Company's Registration Statement on Form S-4 (Commission File
        No. 333-56594)).

  4.3.. Form of Second Supplemental Indenture to the Indenture, dated as of June 12, 2001 (incorporated by
        reference to Exhibit 4.3 to the Company's Registration Statement on Form S-4 (Commission File
        No. 333-56594)).

  4.4.. Form of Note (included in Exhibit 4.2).

  4.5.. Form of Exchange Note (included in Exhibit 4.3).

  4.6.. Registration Rights Agreement, dated as of November 1, 2000, among the Company and the initial
        purchasers thereunder (incorporated by reference to Exhibit 4.6 to the Company's Registration
        Statement on Form S-4 (Commission File No. 333-56594)).

 10.1.. Asset Transfer Agreement between the Company and Central Illinois Public Service Company d/b/a
        AmerenCIPS ("AmerenCIPS") (incorporated by reference to Exhibit 10 to AmerenCIPS' quarterly
        report on Form 10-Q for the quarter ended June 30, 2000).

 10.2.. Amended Electric Power Supply Agreement between the Company and AmerenEnergy Marketing
        Company ("Marketing Co.") (incorporated by reference to Exhibit 10.2 to the Company's Registration
        Statement on Form S-4 (Commission File No. 333-56594)).

 10.3.. Second Amended Electric Power Supply Agreement between the Company and Marketing Co.
        (incorporated by reference to Exhibit 10.1 to Ameren Corporation's ("Ameren's") quarterly report on
        Form 10-Q for the quarter ended March 31, 2001).

 10.4.. Electric Power Supply Agreement between Marketing Co. and AmerenCIPS (incorporated by
        reference to Exhibit 10.3 to the Company's Registration Statement on Form S-4 (Commission File
        No. 333-56594)).

 10.5.. Amended Electric Power Supply Agreement between Marketing Co. and AmerenCIPS (incorporated
        by reference to Exhibit 10.2 to Ameren's quarterly report on Form 10-Q for the quarter ended
        March 31, 2001).

 10.6.. Power Sales Agreement between Marketing Co. and Union Electric Company d/b/a AmerenUE
        ("AmerenUE") (incorporated by reference to Exhibit 10.1 to AmerenUE's quarterly report on
        Form 10-Q for the quarter ended September 30, 2001).
</TABLE>

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<PAGE>

<TABLE>
<CAPTION>
Exhibit
Number                                             Description
------                                             -----------
<C>      <S>
  10.7   Amended Joint Dispatch Agreement among the Company, AmerenCIPS and AmerenUE
         ("AmerenUE") (incorporated by reference to Exhibit 10.4 to the Company's Registration Statement
         on Form S-4 (Commission File No. 333-56594)).

  10.8   Agency Agreement among the Company, AmerenUE, Marketing Co. and Ameren Energy, Inc.
         (incorporated by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-4
         (Commission File No. 333-56594)).

  10.9   General Services Agreement between Ameren Services Company ("Ameren Services") and
         AmerenEnergy Resources Company ("Resources") (incorporated by reference to Exhibit 10.6 to the
         Company's Registration Statement on Form S-4 (Commission File No. 333-56594)).

 10.10   Fuel Services Agreement between AmerenEnergy Fuels and Services Company and Resources
         (incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-4
         (Commission File No. 333-56594)).

 10.11   Form of Parallel Operating Agreement between the Company and Ameren Services (incorporated by
         reference to Exhibit 10.8 to the Company's Registration Statement on Form S-4 (Commission File
         No. 333-56594)).

 10.12   Committed Unit Contribution Agreement between the Company and Resources (on behalf of itself
         and AmerenEnergy Development Company ("Development Co.")) (incorporated by reference to
         Exhibit 10.9 to the Company's Registration Statement on Form S-4 (Commission File No. 333-
         56594)).

 10.13   Lease Agreement between the Company and Development Co. (incorporated by reference to Exhibit
         10.10 to the Company's Registration Statement on Form S-4 (Commission File No. 333-56594)).

 10.14   Alliance Agreement establishing the Alliance Independent Transmission System Operator, Inc.,
         Alliance Transmission Company, Inc. and Alliance Transmission Company, LLC and Amendment to
         Admit AmerenCIPS and AmerenUE (incorporated by reference to Exhibit 10.1 to Ameren's quarterly
         report on Form 10-Q for the quarter ended June 30, 2001).

 10.15*  Long-Term Incentive Plan of 1998 (incorporated by reference to Exhibit 10.1 to Ameren's annual
         report on Form 10-K for the year ended December 31, 1998).

 10.16*  Change of Control Severance Plan (incorporated by reference to Exhibit 10.2 to Ameren's annual
         report on Form 10-K for the year ended December 31, 1998).

 10.17*  Ameren's Deferred Compensation Plan for Members of the Ameren Leadership Team as amended and
         restated effective January 1, 2001 (incorporated by reference to Exhibit 10.1 to Ameren's annual
         report on Form 10-K for the year ended December 31, 2000).

 10.18*  Ameren's Deferred Compensation Plan for Members of the Board of Directors (incorporated by
         reference to Exhibit 10.4 to Ameren's annual report on Form 10-K for the year ended December 31,
         1998).

 10.19*  Ameren's Executive Incentive Compensation Program Elective Deferral Provisions for Members of
         the Ameren Leadership Team as amended and restated effective January 1, 2001 (incorporated by
         reference to Exhibit 10.2 to Ameren's annual report on Form 10-K for the year ended December 31,
         2000).

  12.1** Statement of Computation of Ratio of Earnings to Fixed Charges.
</TABLE>
--------
*Management compensatory plan or arrangement.

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<PAGE>

**Filed herewith.
Note: Reports of Ameren Corporation on Forms 10-K, 10-Q and 8-K are on file
      with the Securities and Exchange Commission (the "SEC") under File No.
      1-14756.

     Reports of Union Electric Company on Forms 10-K, 10-Q and 8-K are on file
     with the SEC under File No. 1-2967.

     Reports of Central Illinois Public Service Company on Forms 10-K, 10-Q and
     8-K are on file with the SEC under File No. 1-3672.

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