**UNITED
          STATES**
 **SECURITIES
          AND EXCHANGE COMMISSION**
 Washington,
          D.C. 20549
 
 **FORM
          10-Q**
 
 (X)  Quarterly
          report pursuant to Section 13 or 15(d)
 of
          the
          Securities Exchange Act of 1934
 **for
          the Quarterly Period Ended March 31, 2006**
 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
                Exact
                    name of registrant as specified in its charter;
                  State
                    of Incorporation;
                  Address
                    and Telephone Number
                IRS
                    Employer
                  Identification
                    No.1-14756
                **Ameren
                    Corporation**
                43-1723446(Missouri
                    Corporation)1901
                    Chouteau AvenueSt.
                    Louis, Missouri 63103(314)
                    621-32221-2967
                **Union
                    Electric Company**
                43-0559760(Missouri
                    Corporation)1901
                    Chouteau AvenueSt.
                    Louis, Missouri 63103(314)
                    621-32221-3672
                **Central
                    Illinois Public Service Company**
                37-0211380(Illinois
                    Corporation)607
                    East Adams StreetSpringfield,
                    Illinois 62739(217)
                    523-3600333-56594
                **Ameren
                    Energy Generating Company**
                37-1395586(Illinois
                    Corporation)1901
                    Chouteau AvenueSt.
                    Louis, Missouri 63103(314)
                    621-32222-95569
                **CILCORP
                    Inc.**
                37-1169387(Illinois
                    Corporation)300
                    Liberty StreetPeoria,
                    Illinois 61602(309)
                    677-52711-2732
                **Central
                    Illinois Light Company**
                37-0211050(Illinois
                    Corporation)300
                    Liberty StreetPeoria,
                    Illinois 61602(309)
                    677-52711-3004
                **Illinois
                    Power Company**
                37-0344645(Illinois
                    Corporation)370
                    South Main StreetDecatur,
                    Illinois 62523(217)
                    424-6600
   
 Indicate
          by check mark whether the registrants: (1) have 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) have been subject to such filing requirements
          for
          the past 90 days. Yes (X)  No
          (
          )
 
 Indicate
          by check mark whether each registrant is a large accelerated filer, an
          accelerated filer, or a non-accelerated filer. See definitions of accelerated
          filer and large accelerated filer in Rule 12b-2 of the Securities Exchange
          Act
          of 1934.
 
 Large
                    Accelerated Filer
                Accelerated
                    Filer
                Non-Accelerated
                    FilerAmeren
                    Corporation
                (X)
                ( 
                     )
                (  
                    )Union
                    Electric Company
                ( 
                    )
                (  
                    )
                (X)Central
                    Illinois Public Service Company
                ( 
                    )
                (  
                    )
                (X)Ameren
                    Energy Generating Company
                (
                     )
                ( 
                     )
                (X)CILCORP
                    Inc.
                ( 
                    )
                ( 
                     )
                (X)Central
                    Illinois Light Company
                ( 
                    )
                ( 
                     )
                (X)Illinois
                    Power Company
                ( 
                    )
                (  
                    )
                (X)
 
 Indicate
          by check mark whether each registrant is a shell company (as defined in
          Rule
          12b-2 of the Securities Exchange Act of 1934).
 
 Ameren
                    Corporation
                Yes
                ( 
                     )
                No
                (X)Union
                    Electric Company
                Yes
                ( 
                     )
                No
                (X)Central
                    Illinois Public Service Company
                Yes
                ( 
                     )
                No
                (X)Ameren
                    Energy Generating Company
                Yes
                (  
                    )
                No
                (X)CILCORP
                    Inc.
                Yes
                ( 
                     )
                No
                (X)Central
                    Illinois Light Company
                Yes
                (  
                    )
                No
                (X)Illinois
                    Power Company
                Yes
                (  
                    )
                No
                (X)
 
 The
          number of shares outstanding of each registrant’s classes of common stock as of
          May 3, 2006 was as follows:
 
 Ameren
                    Corporation
                Common
                    stock, $.01 par value per share - 205,347,020Union
                    Electric Company
                Common
                    stock, $5 par value per share, held by Ameren
                  Corporation
                    (parent company of the registrant) - 102,123,834Central
                    Illinois Public Service Company
                Common
                    stock, no par value, held by Ameren
                  Corporation
                    (parent company of the registrant) - 25,452,373Ameren
                    Energy Generating Company
                Common
                    stock, no par value, held by Ameren Energy
                  Development
                    Company (parent company of the
                  registrant
                    and indirect subsidiary of Ameren
                  Corporation)
                    - 2,000CILCORP
                    Inc.
                Common
                    stock, no par value, held by Ameren
                  Corporation
                    (parent company of the registrant) - 1,000Central
                    Illinois Light Company
                Common
                    stock, no par value, held by CILCORP Inc.
                  (parent
                    company of the registrant and subsidiary of
                  Ameren
                    Corporation) - 13,563,871Illinois
                    Power Company
                Common
                    stock, no par value, held by Ameren
                  Corporation
                    (parent company of the registrant) -
                    23,000,000
 
 
 
  **OMISSION
          OF CERTAIN INFORMATION**
 
 Ameren
          Energy Generating Company and CILCORP Inc. meet the conditions set forth
          in
          General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing
          this
          form with the reduced disclosure format allowed under that General
          Instruction.
 __________________________________________________________________________________________________________________________________________
 
 This
          combined Form 10-Q is separately filed by Ameren Corporation, Union Electric
          Company, Central Illinois Public Service Company, Ameren Energy Generating
          Company, CILCORP Inc., Central Illinois Light Company, and Illinois Power
          Company. Each registrant hereto is filing on its own behalf all of the
          information contained in this quarterly report that relates to such registrant.
          Each registrant hereto is not filing any information that does not relate
          to
          such registrant, and therefore makes no representation as to any such
          information.
  **TABLE
        OF CONTENTS**
 **Page**Glossary
                  of Terms and
                  Abbreviations............................................................................................................................................................................................................................................
              5Forward-looking
                  Statements............................................................................................................................................................................................................................................................
              6**PART
                  I****Financial
                  Information**Item
                  1.Financial
                  Statements (Unaudited)**Ameren
                  Corporation**Consolidated
                  Statement of 
                  Income.........................................................................................................................................................................................................................
              8Consolidated
                  Balance
                  Sheet.....................................................................................................................................................................................................................................
              9Consolidated
                  Statement of Cash
                  Flows..................................................................................................................................................................................................................
              10**Union
                  Electric Company**Consolidated
                  Statement of
                  Income..........................................................................................................................................................................................................................
              11Consolidated
                  Balance
                  Sheet....................................................................................................................................................................................................................................
              12Consolidated
                  Statement of Cash
                  Flows..................................................................................................................................................................................................................
              13**Central
                  Illinois Public Service Company**Statement
                  of
                  Income...................................................................................................................................................................................................................................................
              14Balance
                  Sheet..............................................................................................................................................................................................................................................................
              15Statement
                  of Cash
                  Flows...........................................................................................................................................................................................................................................
              16**Ameren
                  Energy Generating Company**Consolidated
                  Statement of
                  Income..........................................................................................................................................................................................................................
              17Consolidated
                  Balance
                  Sheet.....................................................................................................................................................................................................................................
              18Consolidated
                  Statement of Cash
                  Flows..................................................................................................................................................................................................................
              19**CILCORP
                  Inc.**Consolidated
                  Statement of
                  Income..........................................................................................................................................................................................................................
              20Consolidated
                  Balance
                  Sheet.....................................................................................................................................................................................................................................
              21Consolidated
                  Statement of Cash
                  Flows..................................................................................................................................................................................................................
              22**Central
                  Illinois Light Company**Consolidated
                  Statement of
                  Income..........................................................................................................................................................................................................................
              23Consolidated
                  Balance
                  Sheet.....................................................................................................................................................................................................................................
              24Consolidated
                  Statement of Cash
                  Flows..................................................................................................................................................................................................................
              25**Illinois
                  Power Company**Consolidated
                  Statement of
                  Income..........................................................................................................................................................................................................................
              26Consolidated
                  Balance
                  Sheet.....................................................................................................................................................................................................................................
              27Consolidated
                  Statement of Cash
                  Flows..................................................................................................................................................................................................................
              28Combined
                  Notes to Financial
                  Statements.......................................................................................................................................................................................................................
              29Item
                  2.Management’s
                  Discussion and Analysis of Financial Condition and Results of
                  Operations...............................................................................................................................
              50Item
                  3.Quantitative
                  and Qualitative Disclosures About Market
                  Risk....................................................................................................................................................................................
              64Item
                  4.Controls
                  and
                  Procedures...................................................................................................................................................................................................................................................
              67**PART
                  II****Other
                  Information**Item
                  1.Legal
                  Proceedings...............................................................................................................................................................................................................................................................
              67Item
                  1A.Risk
                  Factors.........................................................................................................................................................................................................................................................................
              67Item
                  2.Unregistered
                  Sales of Equity Securities and Use of
                  Proceeds.....................................................................................................................................................................................
              71Item
                  6.Exhibits.............................................................................................................................................................................................................
              71Signatures............................................................................................................................................................................................................................................................................................
              72
 
 This
        Form
        10-Q contains “forward-looking” statements within the meaning of Section 21E of
        the Securities Exchange Act of 1934, as amended. Forward-looking statements
        are
        all statements other than statements of historical fact, including those
        statements that are identified by the use of the words “anticipates,”
“estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar
        expressions. Forward-looking statements should be read with the cautionary
        statements and important factors included on page 6 of this Form 10-Q under
        the
        heading “Forward-looking Statements”.
  4
 **GLOSSARY
        OF TERMS AND ABBREVIATIONS**
 
 We
        use
        the words “our,” “we” or “us” with respect to certain information that relates
        to all Ameren Companies, as defined below. When appropriate, subsidiaries
        of
        Ameren are named specifically as we discuss their various business
        activities.
  ***AERG*** -
        AmerenEnergy Resources Generating Company, a CILCO subsidiary that operates
        a
        non-rate-regulated electric generation business in Illinois.
 ***AFS*** -
        Ameren
        Energy Fuels and Services Company, a Development Company subsidiary that
        procures fuel and natural gas and manages the related risks for the Ameren
        Companies.
 ***Ameren*** -
        Ameren
        Corporation and its subsidiaries on a consolidated basis. In references to
        financing activities, acquisition activities, or liquidity arrangements,
        Ameren
        is defined as Ameren Corporation, the parent.
 ***Ameren
        Companies*** -
        The
        individual registrants within the Ameren consolidated group.
 ***Ameren
        Energy*** -
        Ameren
        Energy, Inc., an Ameren Corporation subsidiary that serves as a power marketing
        and risk management agent for UE and Genco primarily for transactions of
        less
        than one year.
 ***Ameren
        Services*** - ****** Ameren
        Services Company, an Ameren Corporation subsidiary that provides support
        services to Ameren and its subsidiaries.
 ***APB*** -
        Accounting Principles Board.
 ***ARO*** - Asset
        retirement obligations.
 ***Baseload*** - ****** The
        minimum amount of electric power delivered or required over a given period
        of
        time at a steady rate.
 ***Capacity
        factor*** - A
        percentage measure that indicates how much of an electric power generating
        unit’s capacity was used during a specific period.
 ***CILCO*** -
        Central
        Illinois Light Company, a CILCORP subsidiary that operates a rate-regulated
        electric transmission and distribution business, a primarily non-rate-regulated
        electric generation business through AERG, and a rate-regulated natural gas
        transmission and distribution business, all in Illinois, as AmerenCILCO.
        CILCO
        owns all of the common stock of AERG.
 ***CILCORP*** -
        CILCORP
        Inc., an Ameren Corporation subsidiary that operates as a holding company
        for
        CILCO and various non-rate-regulated subsidiaries.
 ***CIPS*** -
        Central
        Illinois Public Service Company, an Ameren Corporation subsidiary that operates
        a rate-regulated electric and natural gas transmission and distribution business
        in Illinois as AmerenCIPS.
 ***CT*** -
        Combustion turbine electric generation equipment used primarily for peaking
        capacity.
 ***CUB*** -
        Citizens Utility Board.
 ***Development
        Company*** -
        Ameren
        Energy Development Company, a Resources Company subsidiary and Genco parent,
        which primarily develops and constructs generating facilities for
        Genco.
 ***DOE*** -
        Department of Energy, a U.S. government agency.
 ***DRPlus*** -
        Ameren
        Corporation’s dividend reinvestment and direct stock purchase plan.
 ***Dynegy*** -
        Dynegy
        Inc.
 ***EEI*** -
        Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary (40% owned
        by
        UE and 40% owned by Development Company) that operates electric generation
        and
        transmission facilities in Illinois. The remaining 20% is owned by Kentucky
        Utilities Company.
 ***ELPC*** -
        Environmental Law and Policy Center.
 ***EPA*** -
        Environmental Protection Agency, a U.S. government agency.
 ***Equivalent
        availability factor*** - A
        measure that indicates the percentage of time an electric power generating
        unit
        was available for service during a specific period.
 ***ERISA*** -
        Employee Retirement Income Security Act of 1974, as amended.
 ***Exchange
        Act*** -
        Securities Exchange Act of 1934, as amended.
 ***FASB*** -
        Financial Accounting Standards Board, a rulemaking organization that establishes
        financial accounting and reporting standards in the United States.
 ***FERC*** -
        The
        Federal Energy Regulatory Commission, a U.S. government agency.
 ***FIN*** -
        FASB
        Interpretation Number. A FIN statement is an explanation intended to clarify
        accounting pronouncements previously issued by the FASB.
 ***GAAP*** -
        Generally accepted accounting principles in the United States.
 ***Genco*** -
        Ameren
        Energy Generating Company, a Development Company subsidiary that operates
        a
        non-rate-regulated electric generation business in Illinois and
        Missouri.
 ***Gigawatthour*** -
        One
        thousand megawatthours.
 ***Heating
        degree-days*** -
        The
        summation of negative differences between the mean daily temperature and
        a 65-
        degree Fahrenheit base. This statistic is useful as an indicator of demand
        for
        electricity and natural gas for winter space heating for residential and
        commercial customers.
 ***ICC*** -
        Illinois Commerce Commission, a state agency that regulates the Illinois
        utility
        businesses and operations of CIPS, CILCO, and IP.
 ***Illinois
        Customer Choice Law*** -
        Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which
        provided for electric utility restructuring and introduced competition into
        the
        retail supply of electric energy in Illinois.
 ***Illinois
        EPA*** -
        Illinois Environmental Protection Agency, a state government
        agency.
 ***IP*** - ****** Illinois
        Power Company, which was acquired from Dynegy by, and became a subsidiary
        of,
        Ameren Corporation on September 30, 2004. IP operates a rate-regulated electric
        and natural gas transmission and distribution business in Illinois as
        AmerenIP.
 ***IP
        SPT*** -
        Illinois Power Special Purpose Trust, which was created as a subsidiary of
        Illinois Power Securitization Limited
  5
 Liability
        Company to issue TFNs as allowed under the Illinois Customer Choice Law.
        Pursuant to FIN 46R, IP SPT is a variable-interest entity, as the equity
        investment is not sufficient to permit IP SPT to finance its activities without
        additional subordinated debt.
 ***Kilowatthour*** - ****** A
        measure
        of electricity consumption equivalent to the use of 1,000 watts of power
        over a
        period of one hour.
 ***LIBOR*** - London
        Interbank Offered Rate, an interest rate that banks charge each other for
        loans.
 ***Marketing
        Company*** - ****** Ameren
        Energy Marketing Company, a Development Company subsidiary that markets power,
        primarily for periods over one year.
 ***Medina
        Valley*** -
        AmerenEnergy ****** Medina
        Valley Cogen (No. 4) LLC and its subsidiaries, which are all Development
        Company
        subsidiaries, which indirectly own a 40-megawatt gas-fired electric generation
        plant.
 ***Megawatthour*** -
        One
        thousand kilowatthours.
 ***MGP*** - ****** Manufactured
        gas plant.
 ***MISO*** - ****** Midwest
        Independent Transmission System Operator, Inc.
 ***MISO
        Day Two Energy Market*** - ****** A
        market
        that began operating on April 1, 2005. It uses market-based pricing,
        incorporating transmission congestion and line losses, to compensate market
        participants for power. The previous system required generators to make advance
        reservations for transmission service.
 ***Missouri
        OPC*** *-* Missouri
        Office of the Public Counsel, which was established to represent the interests
        of Missouri utility customers in proceedings before the MoPSC.
 ***Money
        pool*** - ****** Borrowing
        agreements among Ameren and its subsidiaries to coordinate and provide for
        certain short-term cash and working capital requirements. Separate money
        pools
        are maintained between rate-regulated and non-rate-regulated businesses.
        These
        are referred to as the utility money pool and the non-state-regulated subsidiary
        money pool, respectively.
 ***Moody’s*** - ****** Moody’s
        Investors Service Inc., a credit rating agency.
 ***MoPSC*** -
        Missouri Public Service Commission, a state agency that regulates the Missouri
        utility business and operations of UE.
 ***NO*** ***x*** ****** - ****** Nitrogen
        oxide.
 ***Noranda*** -
        Noranda Aluminum, Inc.
 ***NYMEX*** -
        New
        York Mercantile Exchange.
 ***OCI*** - ****** Other
        comprehensive income (loss) as defined by GAAP.
 ***PJM
        -*** PJM
        Interconnection LLC.
 ***PUHCA
        1935*** -
        The
        Public Utility Holding Company Act of 1935, which was repealed effective
        February 8, 2006, by the Energy Policy Act of 2005 enacted on August 8,
        2005.
 ***PUHCA
        2005*** - The
        Public Utility Holding Company Act of 2005, enacted as part of the Energy
        Policy
        Act of 2005, effective February 8, 2006.
 ***Resources
        Company*** -
        Ameren
        Energy Resources Company, an Ameren Corporation subsidiary that consists
        of
        non-rate-regulated operations, including Development Company, Genco, Marketing
        Company, AFS, and Medina Valley.
 ***S&P*** -
        Standard & Poor’s Ratings Services, a credit rating agency that is a
        division of The McGraw Hill Companies, Inc.
 ***SEC*** -
        Securities and Exchange Commission, a U.S. government agency.
 ***SFAS*** - ****** Statement
        of Financial Accounting Standards, the accounting and financial reporting
        rules
        issued by the FASB.
 ***SO*** ***2*** - ****** Sulfur
        dioxide.
 ***TFN*** -
        Transitional Funding Trust Notes issued by IP SPT as allowed under Illinois’
deregulation legislation. IP must designate a portion of cash received from
        customer billings to pay the TFNs. The proceeds received by IP are remitted
        to
        IP SPT. The proceeds are restricted for the sole purpose of making payments
        of
        principal and interest on, and paying other fees and expenses related to,
        the
        TFNs. Since the application of FIN 46R, IP does not consolidate IP SPT.
        Therefore, the obligation to IP SPT appears on IP’s balance sheet.
 ***UE*** - ****** Union
        Electric Company, an Ameren Corporation subsidiary that operates a
        rate-regulated electric generation, transmission and distribution business,
        and
        a rate-regulated natural gas transmission and distribution business in Missouri,
        as AmerenUE.
 
 _________________________________________________
 
 
 **FORWARD-LOOKING
        STATEMENTS**
 
 Statements
        in this report not based on historical facts are considered “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” provi-sions of the Private
        Securities Litigation Reform Act of 1995, we are providing this cautionary
        statement to identify important factors that could cause actual results to
        differ materially from those anticipated. The following factors, in addition
        to
        those discussed elsewhere in this report and in our other filings with the
        SEC,
        could cause actual results to differ materially from management expectations
        suggested in such forward-looking statements:
  ·
              regulatory
                  actions, including changes in regulatory policies and ratemaking
                  determinations;
 ·
              the
                  impact of changes to the joint dispatch agreement among UE, CIPS,
                  and
                  Genco;
 ·
              changes
                  in laws and other governmental actions, including monetary and
                  fiscal
                  policies;
   6
  ·
              the
                  effects of increased competition in the future due to, among other
                  things,
                  deregulation of certain aspects of our business at both the state
                  and
                  federal levels, and the implementation of deregulation, such as
                  when the
                  current electric rate freeze and current power supply contracts
                  expire in
                  Illinois at the end of 2006;
 ·
              the
                  effects of participation in the
                  MISO;
 ·
              the
                  availability of fuel such as coal, natural gas and enriched uranium
                  used
                  to produce electricity; the availability of purchased power and
                  natural
                  gas for distribution; and the level and volatility of future market
                  prices
                  for such commodities, including the ability to recover the costs
                  for such
                  commodities;
 ·
              the
                  effectiveness of our risk management strategies and the use of
                  financial
                  and derivative instruments;
 ·
              prices
                  for power in the Midwest;
 ·
              business
                  and economic conditions, including their impact on interest rates;
 ·
              disruptions
                  of the capital markets or other events that make the Ameren Companies’
                  access to necessary capital more difficult or
                  costly;
 ·
              the
                  impact of the adoption of new accounting standards and the application
                  of
                  appropriate technical accounting rules and guidance;
 ·
              actions
                  of credit rating agencies and the effects of such actions;
 ·
              weather
                  conditions and other natural phenomena;
 ·
              generation
                  plant construction, installation and performance, including costs
                  associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident
                  and its future operation;
 ·
              operation
                  of UE’s nuclear power facility, including planned and unplanned outages,
                  and decommissioning costs;
 ·
              the
                  effects of strategic initiatives, including acquisitions and divestitures;
 ·
              the
                  impact of current environmental regulations on utilities and power
                  generating companies and the expectation that more stringent requirements
                  will be introduced over time, which could have a negative financial
                  effect;
 ·
              labor
                  disputes and future wage and employee benefits costs, including
                  changes in
                  returns on benefit plan assets;
 ·
              changes
                  in the energy markets, environmental laws or regulations, interest
                  rates,
                  or other factors that could adversely affect assumptions in connection
                  with the IP acquisition;
 ·
              the
                  impact of conditions imposed by regulators in connection with their
                  approval of Ameren’s acquisition of
                  IP;
 ·
              the
                  inability of our counterparties to meet their obligations with
                  respect to
                  contracts and financial instruments;
 ·
              the
                  cost and availability of transmission capacity for the energy generated
                  by
                  the Ameren Companies’ facilities or required to satisfy energy sales made
                  by the Ameren Companies;
 ·
              legal
                  and administrative proceedings; and
 ·
              acts
                  of sabotage, war, terrorism or intentionally disruptive acts.
 
 Given
        these uncertainties, undue reliance should not be placed on these
        forward-looking statements. Except to the extent required by the federal
        securities laws, we undertake no obligation to publicly update or revise
        any
        forward-looking statements to reflect new information or future
        events.
 7
 
  PART
            I.   FINANCIAL INFORMATION
 ITEM
            1.  FINANCIAL
            STATEMENTS


**AMEREN
                CORPORATION****CONSOLIDATED
                STATEMENT OF INCOME****(Unaudited)
                (In millions, except per share amounts)****Three
                Months Ended**
              **March
                31,****2006**
            
            **2005****Operating
                Revenues:**Electric
            **$**
            **1,211**
            
            $
            1,129Gas
            
            **589**
            
            
            496Other
            
            **-**
            
            
            1Total
                operating revenues
            
            **1,800**
            
            
            1,626**Operating
                Expenses:**Fuel
                and purchased power
            
            **525**
            
            
            416Gas
                purchased for resale
            
            **453**
            
            
            354Other
                operations and maintenance
            
            **348**
            
            
            345Depreciation
                and amortization
            
            **165**
            
            
            157Taxes
                other than income taxes
            
            **113**
            
            
            91Total
                operating expenses
            
            **1,604**
            
            
            1,363**Operating
                Income**
            
            **196**
            
            
            263**Other
                Income and Expenses:**Miscellaneous
                income
            
            **4**
            
            
            7Total
                other income
            
            **4**
            
            
            7**Interest
                Charges**
            
            **76**
            
            
            74**Income
                Before Income Taxes, Minority Interest****and
                Preferred Dividends of Subsidiaries**
            
            **124**
            
            
            196**Income
                Taxes**
            
            **44**
            
            
            71**Income
                Before Minority Interest and Preferred Dividends of
                Subsidiaries**
            
            **80**
            
            
            125**Minority
                Interest and Preferred Dividends of Subsidiaries**
            
            **(10**
            **)**
            
            (4
            )**Net
                Income**
            **$**
            **70**
            
            $
            121**Earnings
                per Common Share – Basic and Diluted**
            **$**
            **0.34**
            
            $
            0.62**Dividends
                per Common Share**
            **$**
            **0.635**
            
            $
            0.635**Average
                Common Shares Outstanding**
            
            **204.8**
            
            
            195.3




The accompanying notes are an integral part of these
      consolidated financial statements.




8




**AMEREN
                    CORPORATION****CONSOLIDATED
                    BALANCE SHEET****(Unaudited)
                    (In millions, except per share amounts)****March
                    31,**
                
                **December
                    31,****2006**
                
                **2005****ASSETS****Current
                    Assets:**Cash
                    and cash equivalents
                **$**
                **29**
                
                $
                96Accounts
                    receivable – trade (less allowance for doubtfulaccounts
                    of $30 and $22, respectively)
                
                **527**
                
                
                552Unbilled
                    revenue
                
                **290**
                
                
                382Miscellaneous
                    accounts and notes receivable
                
                **82**
                
                
                31Materials
                    and supplies
                
                **423**
                
                
                572Other
                    current assets
                
                **112**
                
                
                185Total
                    current assets
                
                **1,463**
                
                
                1,818**Property
                    and Plant, Net**
                
                **13,854**
                
                
                13,572**Investments
                    and Other Assets:**Investments
                    in leveraged leases
                
                **50**
                
                
                50Nuclear
                    decommissioning trust fund
                
                **259**
                
                
                250Goodwill
                
                **976**
                
                
                976Intangible
                    assets
                
                **264**
                
                
                246Other
                    assets
                
                **627**
                
                
                419Regulatory
                    assets
                
                **821**
                
                
                831Total
                    investments and other assets
                
                **2,997**
                
                
                2,772**TOTAL
                    ASSETS**
                **$**
                **18,314**
                
                $
                18,162**LIABILITIES
                    AND STOCKHOLDERS' EQUITY****Current
                    Liabilities:**Current
                    maturities of long-term debt
                **$**
                **147**
                
                $
                96Short-term
                    debt
                
                **467**
                
                
                193Accounts
                    and wages payable
                
                **338**
                
                
                706Taxes
                    accrued
                
                **129**
                
                
                131Other
                    current liabilities
                
                **418**
                
                
                361Total
                    current liabilities
                
                **1,499**
                
                
                1,487**Long-term
                    Debt, Net**
                
                **5,508**
                
                
                5,354**Preferred
                    Stock of Subsidiary Subject to Mandatory
                    Redemption**
                
                **19**
                
                
                19**Deferred
                    Credits and Other Liabilities:**Accumulated
                    deferred income taxes, net
                
                **1,973**
                
                
                1,969Accumulated
                    deferred investment tax credits
                
                **126**
                
                
                129Regulatory
                    liabilities
                
                **1,151**
                
                
                1,132Asset
                    retirement obligations
                
                **524**
                
                
                518Accrued
                    pension and other postretirement benefits
                
                **804**
                
                
                760Other
                    deferred credits and liabilities
                
                **184**
                
                
                218Total
                    deferred credits and other liabilities
                
                **4,762**
                
                
                4,726**Preferred
                    Stock of Subsidiaries Not Subject to Mandatory
                    Redemption**
                
                **195**
                
                
                195**Minority
                    Interest in Consolidated Subsidiaries**
                
                **17**
                
                
                17**Commitments
                    and Contingencies (Notes 2, 8 and 9)****Stockholders'
                    Equity:**Common
                    stock, $.01 par value, 400.0 shares authorized,205.2
                    and 204.7 shares outstanding, respectively
                
                **2**
                
                
                2Other
                    paid-in capital, principally premium on common stock
                
                **4,427**
                
                
                4,399Retained
                    earnings
                
                **1,939**
                
                
                1,999Accumulated
                    other comprehensive loss
                
                **(44**
                **)**
                
                (24
                )Other
                
                **(10**
                **)**
                
                (12
                )Total
                    stockholders’ equity
                
                **6,314**
                
                
                6,364**TOTAL
                    LIABILITIES AND STOCKHOLDERS' EQUITY**
                **$**
                **18,314**
                
                $
                18,162


The accompanying notes are an integral part of these
      consolidated financial statements.


9




**AMEREN
                  CORPORATION****CONSOLIDATED
                  STATEMENT OF CASH FLOWS****(Unaudited)
                  (In millions)****Three
                  Months**
                **Ended
                  March 31,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **70**
              
              $
              121Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **154**
              
              
              135Amortization
                  of nuclear fuel
              
              **9**
              
              
              8Amortization
                  of debt issuance costs and premium/discounts
              
              **4**
              
              
              3Deferred
                  income taxes and investment tax credits, net
              
              **8**
              
              
              1Other
              
              **7**
              
              
              (5
              )Changes
                  in assets and liabilities, excluding the effects of
                  acquisitions:Receivables,
                  net
              
              **104**
              
              
              20Materials
                  and supplies
              
              **151**
              
              
              60Accounts
                  and wages payable
              
              **(324**
              **)**
              
              (168
              )Taxes
                  accrued
              
              **(1**
              **)**
              
              87Assets,
                  other
              
              **18**
              
              
              (1
              )Liabilities,
                  other
              
              **40**
              
              
              46Pension
                  and other postretirement benefit obligations, net
              
              **47**
              
              
              50Net cash
                  provided by operating activities
              
              **287**
              
              
              357**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(179**
              **)**
              
              (210
              )CT
                  acquisitions
              
              **(292**
              **)**
              
              -Nuclear
                  fuel expenditures
              
              **(24**
              **)**
              
              (3
              )Other
              
              **1**
              
              
              11Net
                  cash used in investing activities
              
              **(494**
              **)**
              
              (202
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **(130**
              **)**
              
              (124
              )Short-term
                  debt, net
              
              **274**
              
              
              4Redemptions,
                  repurchases, and maturities:Long-term
                  debt
              
              **(31**
              **)**
              
              (189
              )Issuances:Common
                  stock
              
              **27**
              
              
              30Long-term
                  debt
              
              **-**
              
              
              85Net
                  cash provided by (used in) financing activities
              
              **140**
              
              
              (194
              )Net
                  change in cash and cash equivalents
              
              **(67**
              **)**
              
              (39
              )Cash
                  and cash equivalents at beginning of year
              
              **96**
              
              
              69Cash
                  and cash equivalents at end of period
              **$**
              **29**
              
              $
              30


The accompanying notes are an integral part of these
      consolidated financial statements.


10




**UNION
                  ELECTRIC COMPANY****CONSOLIDATED
                  STATEMENT OF INCOME****(Unaudited)
                  (In millions)****Three
                  Months Ended****March
                  31,****2006**
              
              
              **2005****Operating
                  Revenues:**Electric
              **$**
              **567**
              
              $
              533Gas
              
              **69**
              
              
              75Total
                  operating revenues
              
              **636**
              
              
              608**Operating
                  Expenses:**Fuel
                  and purchased power
              
              **192**
              
              
              144Gas
                  purchased for resale
              
              **44**
              
              
              45Other
                  operations and maintenance
              
              **171**
              
              
              181Depreciation
                  and amortization
              
              **80**
              
              
              76Taxes
                  other than income taxes
              
              **59**
              
              
              55Total
                  operating expenses
              
              **546**
              
              
              501**Operating
                  Income**
              
              **90**
              
              
              107**Other
                  Income and Expenses:**Miscellaneous
                  income
              
              **3**
              
              
              7Miscellaneous
                  expense
              
              **(2**
              **)**
              
              (2
              )Total
                  other income
              
              **1**
              
              
              5**Interest
                  Charges**
              
              **35**
              
              
              25**Income
                  Before Income Taxes and Equity****in
                  Income of Unconsolidated Investment**
              
              **56**
              
              
              87**Income
                  Taxes**
              
              **19**
              
              
              31**Income
                  Before Equity in Income****of
                  Unconsolidated Investment**
              
              **37**
              
              
              56**Equity
                  in Income of Unconsolidated Investment**
              
              **14**
              
              
              1**Net
                  Income**
              
              **51**
              
              
              57**Preferred
                  Stock Dividends**
              
              **1**
              
              
              1**Net
                  Income Available to Common Stockholder**
              **$**
              **50**
              
              $
              56


The accompanying notes as they relate to UE are an integral
        part of these consolidated financial statements.


11




**UNION
                  ELECTRIC COMPANY****CONSOLIDATED
                  BALANCE SHEET****(Unaudited)
                  (In millions, except per share amounts)****March
                  31,**
              
              **December
                  31,****2006**
              
              **2005****ASSETS****Current
                  Assets:**Cash
                  and cash equivalents
              **$**
              **1**
              
              $
              20Accounts
                  receivable – trade (less allowance for doubtfulaccounts
                  of $6 and $6, respectively)
              
              **152**
              
              
              190Unbilled
                  revenue
              
              **107**
              
              
              133Miscellaneous
                  accounts and notes receivable
              
              **61**
              
              
              7Accounts
                  receivable – affiliates
              
              **46**
              
              
              53Current
                  portion of intercompany note receivable – CIPS
              
              **6**
              
              
              6Materials
                  and supplies
              
              **190**
              
              
              199Other
                  current assets
              
              **50**
              
              
              57Total
                  current assets
              
              **613**
              
              
              665**Property
                  and Plant, Net**
              
              **7,668**
              
              
              7,379**Investments
                  and Other Assets:**Nuclear
                  decommissioning trust fund
              
              **259**
              
              
              250Intercompany
                  note receivable – CIPS
              
              **61**
              
              
              61Intangible
                  assets
              
              **63**
              
              
              63Other
                  assets
              
              **505**
              
              
              269Regulatory
                  assets
              
              **578**
              
              
              590Total
                  investments and other assets
              
              **1,466**
              
              
              1,233**TOTAL
                  ASSETS**
              **$**
              **9,747**
              
              $
              9,277**LIABILITIES
                  AND STOCKHOLDERS' EQUITY****Current
                  Liabilities:**Current
                  maturities of long-term debt
              **$**
              **11**
              
              $
              4Short-term
                  debt
              
              **445**
              
              
              80Borrowings
                  from money pool
              
              **1**
              
              
              -Accounts
                  and wages payable
              
              **78**
              
              
              274Accounts
                  and wages payable – affiliates
              
              **99**
              
              
              134Taxes
                  accrued
              
              **76**
              
              
              59Other
                  current liabilities
              
              **146**
              
              
              96Total
                  current liabilities
              
              **856**
              
              
              647**Long-term
                  Debt, Net**
              
              **2,931**
              
              
              2,698**Deferred
                  Credits and Other Liabilities:**Accumulated
                  deferred income taxes, net
              
              **1,285**
              
              
              1,277Accumulated
                  deferred investment tax credits
              
              **94**
              
              
              96Regulatory
                  liabilities
              
              **807**
              
              
              802Asset
                  retirement obligations
              
              **471**
              
              
              466Accrued
                  pension and other postretirement benefits
              
              **222**
              
              
              203Other
                  deferred credits and liabilities
              
              **59**
              
              
              72Total
                  deferred credits and other liabilities
              
              **2,938**
              
              
              2,916**Commitments
                  and Contingencies (Notes 2, 8 and 9)****Stockholders'
                  Equity:**Common
                  stock, $5 par value, 150.0 shares authorized – 102.1 shares
                  outstanding
              
              **511**
              
              
              511Preferred
                  stock not subject to mandatory redemption
              
              **113**
              
              
              113Other
                  paid-in capital, principally premium on common stock
              
              **734**
              
              
              733Retained
                  earnings
              
              **1,697**
              
              
              1,689Accumulated
                  other comprehensive loss
              
              **(33**
              **)**
              
              (30
              )Total
                  stockholders' equity
              
              **3,022**
              
              
              3,016**TOTAL
                  LIABILITIES AND STOCKHOLDERS' EQUITY**
              **$**
              **9,747**
              
              $
              9,277


The accompanying notes as they relate to UE are an integral
      part of these consolidated financial statements.




12




**UNION
                  ELECTRIC COMPANY****CONSOLIDATED
                  STATEMENT OF CASH FLOWS****(Unaudited)
                  (In millions)****Three
                  Months Ended****March
                  31,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **51**
              
              $
              57Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **80**
              
              
              76Amortization
                  of nuclear fuel
              
              **9**
              
              
              8Amortization
                  of debt issuance costs and premium/discounts
              
              **1**
              
              
              2Deferred
                  income taxes and investment tax credits, net
              
              **11**
              
              
              (13
              )Other
              
              **(1**
              **)**
              
              2Changes
                  in assets and liabilities:Receivables,
                  net
              
              **55**
              
              
              26Materials
                  and supplies
              
              **11**
              
              
              17Accounts
                  and wages payable
              
              **(202**
              **)**
              
              (153
              )Taxes
                  accrued
              
              **17**
              
              
              57Assets,
                  other
              
              **10**
              
              
              9Liabilities,
                  other
              
              **(1**
              **)**
              
              (1
              )Pension
                  and other postretirement obligations, net
              
              **19**
              
              
              20Net
                  cash provided by operating activities
              
              **60**
              
              
              107**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(88**
              **)**
              
              (117
              )CT
                  acquisitions
              
              **(292**
              **)**
              
              -Nuclear
                  fuel expenditures
              
              **(24**
              **)**
              
              (3
              )Changes
                  in money pool advances
              
              **-**
              
              
              (64
              )Other
              
              **1**
              
              
              (1
              )Net
                  cash used in investing activities
              
              **(403**
              **)**
              
              (185
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **(42**
              **)**
              
              (60
              )Dividends
                  on preferred stock
              
              **(1**
              **)**
              
              (1
              )Capital
                  issuance costs
              
              **-**
              
              
              (1
              )Changes
                  in short-term debt, net
              
              **365**
              
              
              9Changes
                  in money pool borrowings
              
              **1**
              
              
              -Issuance
                  of long-term debt
              
              **-**
              
              
              85Capital
                  contribution from parent
              
              **1**
              
              
              -Net
                  cash provided by financing activities
              
              **324**
              
              
              32Net
                  change in cash and cash equivalents
              
              **(19**
              **)**
              
              (46
              )Cash
                  and cash equivalents at beginning of year
              
              **20**
              
              
              48Cash
                  and cash equivalents at end of period
              **$**
              **1**
              
              $
              2


The accompanying notes as they relate to UE are an integral
      part of these consolidated financial statements.


13




**CENTRAL
                  ILLINOIS PUBLIC SERVICE COMPANY****STATEMENT
                  OF INCOME****(Unaudited)
                  (In millions)****Three
                  Months Ended****March
                  31,****2006**
              
              **2005****Operating
                  Revenues:**Electric
              **$**
              **160**
              
              $
              128Gas
              
              **97**
              
              
              84Total
                  operating revenues
              
              **257**
              
              
              212**Operating
                  Expenses:**Purchased
                  power
              
              **117**
              
              
              86Gas
                  purchased for resale
              
              **72**
              
              
              59Other
                  operations and maintenance
              
              **38**
              
              
              33Depreciation
                  and amortization
              
              **16**
              
              
              13Taxes
                  other than income taxes
              
              **12**
              
              
              8Total
                  operating expenses
              
              **255**
              
              
              199**Operating
                  Income**
              
              **2**
              
              
              13**Other
                  Income and Expenses:**Miscellaneous
                  income
              
              **5**
              
              
              5Miscellaneous
                  expense
              
              **(1**
              **)**
              
              -Total
                  other income
              
              **4**
              
              
              5**Interest
                  Charges**
              
              **7**
              
              
              7**Income
                  (Loss) Before Income Taxes**
              
              **(1**
              **)**
              
              11**Income
                  Taxes**
              
              **-**
              
              
              3**Net
                  Income (Loss)**
              
              **(1**
              **)**
              
              8**Preferred
                  Stock Dividends**
              
              **1**
              
              
              1**Net
                  Income (Loss) Available to Common Stockholder**
              **$**
              **(2**
              **)**
              $
              7


The accompanying notes as they relate to CIPS are an integral
      part of these financial statements.




14




**CENTRAL
                  ILLINOIS PUBLIC SERVICE COMPANY****BALANCE
                  SHEET****(Unaudited)
                  (In millions)****March
                  31,**
              
              **December
                  31,****2006**
              
              **2005****ASSETS****Current
                  Assets:**Accounts
                  receivable – trade (less allowance for doubtfulaccounts
                  of $6 and $4, respectively)
              $
              **75**
              
              $
              70Unbilled
                  revenue
              
              **52**
              
              
              71Accounts
                  receivable – affiliates
              
              **9**
              
              
              18Current
                  portion of intercompany note receivable – Genco
              
              **34**
              
              
              34Current
                  portion of intercompany tax receivable – Genco
              
              **10**
              
              
              10Advances
                  to money pool
              
              **47**
              
              
              -Materials
                  and supplies
              
              **39**
              
              
              75Other
                  current assets
              
              **15**
              
              
              28Total
                  current assets
              
              **281**
              
              
              306**Property
                  and Plant, Net**
              
              **1,133**
              
              
              1,130**Investments
                  and Other Assets:**Intercompany
                  note receivable – Genco
              
              **163**
              
              
              163Intercompany
                  tax receivable – Genco
              
              **122**
              
              
              125Other
                  assets
              
              **16**
              
              
              24Regulatory
                  assets
              
              **36**
              
              
              36Total
                  investments and other assets
              
              **337**
              
              
              348**TOTAL
                  ASSETS**
              **$**
              **1,751**
              
              $
              1,784**LIABILITIES
                  AND STOCKHOLDERS' EQUITY****Current
                  Liabilities:**Current
                  maturities of long-term debt
              **$**
              **20**
              
              $
              20Accounts
                  and wages payable
              
              **28**
              
              
              36Accounts
                  and wages payable – affiliates
              
              **51**
              
              
              65Borrowings
                  from money pool
              
              **-**
              
              
              2Current
                  portion of intercompany note payable – UE
              
              **6**
              
              
              6Taxes
                  accrued
              
              **16**
              
              
              26Other
                  current liabilities
              
              **42**
              
              
              43Total
                  current liabilities
              
              **163**
              
              
              198**Long-term
                  Debt, Net**
              
              **410**
              
              
              410**Deferred
                  Credits and Other Liabilities:**Accumulated
                  deferred income taxes and investment tax credits, net
              
              **309**
              
              
              302Intercompany
                  note payable – UE
              
              **61**
              
              
              61Regulatory
                  liabilities
              
              **205**
              
              
              208Other
                  deferred credits and liabilities
              
              **40**
              
              
              36Total
                  deferred credits and other liabilities
              
              **615**
              
              
              607**Commitments
                  and Contingencies (Notes 2 and 8)****Stockholders'
                  Equity:**Common
                  stock, no par value, 45.0 shares authorized – 25.5 shares
                  outstanding
              
              **-**
              
              
              -Other
                  paid-in capital
              
              **189**
              
              
              189Preferred
                  stock not subject to mandatory redemption
              
              **50**
              
              
              50Retained
                  earnings
              
              **327**
              
              
              329Accumulated
                  other comprehensive income (loss)
              
              **(3**
              **)**
              
              1Total
                  stockholders' equity
              
              **563**
              
              
              569**TOTAL
                  LIABILITIES AND STOCKHOLDERS' EQUITY**
              **$**
              **1,751**
              
              $
              1,784


The
      accompanying notes as they relate to CIPS are an integral part of these
      financial statements.




15




**CENTRAL
                  ILLINOIS PUBLIC SERVICE COMPANY****STATEMENT
                  OF CASH FLOWS****(Unaudited)
                  (In millions)****Three
                  Months Ended****March
                  31,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income (loss)
              **$**
              **(1**
              **)**
              $
              8Adjustments
                  to reconcile net income (loss) to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **16**
              
              
              13Deferred
                  income taxes and investment tax credits, net
              
              **(2**
              **)**
              
              (2
              )Other
              
              **(1**
              **)**
              
              4Changes
                  in assets and liabilities:Receivables,
                  net
              
              **26**
              
              
              5Materials
                  and supplies
              
              **36**
              
              
              31Accounts
                  and wages payable
              
              **(21**
              **)**
              
              (9
              )Taxes
                  accrued
              
              **(10**
              **)**
              
              7Assets,
                  other
              
              **22**
              
              
              9Liabilities,
                  other
              
              **2**
              
              
              -Net
                  cash provided by operating activities
              
              **67**
              
              
              66**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(17**
              **)**
              
              (10
              )Changes
                  in money pool advances
              
              **(47**
              **)**
              
              -Net
                  cash used in investing activities
              
              **(64**
              **)**
              
              (10
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on preferred stock
              
              **(1**
              **)**
              
              (1
              )Changes
                  in money pool borrowings
              
              **(2**
              **)**
              
              (55
              )Net
                  cash used in financing activities
              
              **(3**
              **)**
              
              (56
              )Net
                  change in cash and cash equivalents
              
              **-**
              
              
              -Cash
                  and cash equivalents at beginning of year
              
              **-**
              
              
              2Cash
                  and cash equivalents at end of period
              **$**
              **-**
              
              $
              2


The accompanying notes as they relate to CIPS are an integral
      part of these financial statements.




16




**AMEREN
                    ENERGY GENERATING COMPANY****CONSOLIDATED
                    STATEMENT OF INCOME****(Unaudited)
                    (In millions)****Three
                    Months Ended**
                  **March
                    31,****2006**
                
                
                **2005****Operating
                    Revenues:**Electric
                **$**
                **247**
                
                $
                225Total
                    operating revenues
                
                **247**
                
                
                225**Operating
                    Expenses:**Fuel
                    and purchased power
                
                **165**
                
                
                99Other
                    operations and maintenance
                
                **32**
                
                
                38Depreciation
                    and amortization
                
                **18**
                
                
                19Taxes
                    other than income taxes
                
                **6**
                
                
                (2
                )Total
                    operating expenses
                
                **221**
                
                
                154**Operating
                    Income**
                
                **26**
                
                
                71**Interest
                    Charges**
                
                **15**
                
                
                21**Income
                    Before Income Taxes**
                
                **11**
                
                
                50**Income
                    Taxes**
                
                **5**
                
                
                19**Net
                    Income**
                **$**
                **6**
                
                $
                31


The accompanying notes as they relate to GENCO are an integral
      part of these consolidated financial statements.




17




**AMEREN
                  ENERGY GENERATING COMPANY****CONSOLIDATED
                  BALANCE SHEET****(Unaudited)
                  (In millions, except shares)****March
                  31,**
              
              
              **December
                  31,****2006**
              
              
              **2005****ASSETS****Current
                  Assets:**Accounts
                  receivable – affiliates
              **$**
              **88**
              
              $
              102Accounts
                  receivable
              
              **15**
              
              
              29Materials
                  and supplies
              
              **85**
              
              
              73Other
                  current assets
              
              **1**
              
              
              1Total
                  current assets
              
              **189**
              
              
              205**Property
                  and Plant, Net**
              
              **1,500**
              
              
              1,514**Intangible
                  Assets**
              
              **96**
              
              
              79**Other
                  Assets**
              
              **13**
              
              
              13**TOTAL
                  ASSETS**
              **$**
              **1,798**
              
              $
              1,811**LIABILITIES
                  AND STOCKHOLDER'S EQUITY****Current
                  Liabilities:**Current
                  portion of intercompany notes payable – CIPS
              **$**
              **34**
              
              $
              34Borrowings
                  from money pool
              
              **195**
              
              
              203Accounts
                  and wages payable
              
              **23**
              
              
              41Accounts
                  and wages payable – affiliates
              
              **84**
              
              
              60Current
                  portion of intercompany tax payable – CIPS
              
              **10**
              
              
              10Taxes
                  accrued
              
              **34**
              
              
              37Other
                  current liabilities
              
              **23**
              
              
              16Total
                  current liabilities
              
              **403**
              
              
              401**Long-term
                  Debt, Net**
              
              **474**
              
              
              474**Intercompany
                  Notes Payable – CIPS**
              
              **163**
              
              
              163**Deferred
                  Credits and Other Liabilities:**Accumulated
                  deferred income taxes, net
              
              **156**
              
              
              156Accumulated
                  deferred investment tax credits
              
              **10**
              
              
              10Intercompany
                  tax payable – CIPS
              
              **122**
              
              
              125Asset
                  retirement obligations
              
              **29**
              
              
              29Accrued
                  pension and other postretirement benefits
              
              **10**
              
              
              8Other
                  deferred credits and liabilities
              
              **2**
              
              
              1Total
                  deferred credits and other liabilities
              
              **329**
              
              
              329**Commitments
                  and Contingencies (Notes 2 and 8)****Stockholder's
                  Equity:**Common
                  stock, no par value, 10,000 shares authorized – 2,000 shares
                  outstanding
              
              **-**
              
              
              -Other
                  paid-in capital
              
              **228**
              
              
              228Retained
                  earnings
              
              **204**
              
              
              220Accumulated
                  other comprehensive loss
              
              **(3**
              **)**
              
              (4
              )Total
                  stockholder's equity
              
              **429**
              
              
              444**TOTAL
                  LIABILITIES AND STOCKHOLDER'S EQUITY**
              **$**
              **1,798**
              
              $
              1,811


The accompanying notes as they relate to GENCO are an integral
      part of these consolidated financial statements.




18


**AMEREN
                  ENERGY GENERATING COMPANY****CONSOLIDATED
                  STATEMENT OF CASH FLOWS****(Unaudited)
                  (In millions)****Three
                  Months Ended****March
                  31,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **6**
              
              $
              31Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **18**
              
              
              19Deferred
                  income taxes and investment tax credits, net
              
              **(1**
              **)**
              
              6Other
              
              **1**
              
              
              (1
              )Changes
                  in assets and liabilities:Accounts
                  receivable
              
              **28**
              
              
              (13
              )Materials
                  and supplies
              
              **(12**
              **)**
              
              (51
              )Accounts
                  and wages payable
              
              **11**
              
              
              28Taxes
                  accrued, net
              
              **(3**
              **)**
              
              (1
              )Assets,
                  other
              
              **(16**
              **)**
              
              6Liabilities,
                  other
              
              **6**
              
              
              12Pension
                  and other postretirement obligations, net
              
              **2**
              
              
              2Net
                  cash provided by operating activities
              
              **40**
              
              
              38**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(10**
              **)**
              
              (24
              )Net
                  cash used in investing activities
              
              **(10**
              **)**
              
              (24
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **(22**
              **)**
              
              (14
              )Changes
                  in money pool borrowings
              
              **(8**
              **)**
              
              (1
              )Net
                  cash used in financing activities
              
              **(30**
              **)**
              
              (15
              )Net
                  change in cash and cash equivalents
              
              **-**
              
              
              (1
              )Cash
                  and cash equivalents at beginning of year
              
              **-**
              
              
              1Cash
                  and cash equivalents at end of period
              **$**
              **-**
              
              $
              -


The accompanying notes as they relate to GENCO are an
        integral
        part of these consolidated financial statements.
  19




**CILCORP
                  INC.****CONSOLIDATED
                  STATEMENT OF INCOME****(Unaudited)
                  (In millions)****Three
                  Months Ended****March
                  31,****2006**
              
              **2005****Operating
                  Revenues:**Electric
              **$**
              **92**
              
              $
              93Gas
              
              **150**
              
              
              128Other
              
              **-**
              
              
              1Total
                  operating revenues
              
              **242**
              
              
              222**Operating
                  Expenses:**Fuel
                  and purchased power
              
              **26**
              
              
              33Gas
                  purchased for resale
              
              **119**
              
              
              94Other
                  operations and maintenance
              
              **41**
              
              
              42Depreciation
                  and amortization
              
              **22**
              
              
              18Taxes
                  other than income taxes
              
              **9**
              
              
              7Total
                  operating expenses
              
              **217**
              
              
              194**Operating
                  Income**
              
              **25**
              
              
              28**Other Expenses:**Miscellaneous
                  expense
              
              **(1**
              **)**
              
              (2
              )Total
                  other expenses
              
              **(1**
              **)**
              
              (2
              )**Interest
                  Charges**
              
              **12**
              
              
              12**Income
                  Before Income Taxes & Preferred Dividends of****Subsidiaries**
              
              **12**
              
              
              14**Income
                  Taxes**
              
              **3**
              
              
              4**Income
                  Before Preferred Dividends of Subsidiaries**
              
              **9**
              
              
              10**Preferred
                  Dividends of Subsidiaries**
              
              **1**
              
              
              1**Net
                  Income**
              **$**
              **8**
              
              $
              9


The accompanying notes as they relate to CILCORP are an
      integral part of these consolidated financial statements.




20




**CILCORP
                  INC.****CONSOLIDATED
                  BALANCE SHEET****(Unaudited)
                  (In millions, except shares)****March
                  31,**
              
              **December
                  31,****2006**
              
              **2005****ASSETS****Current
                  Assets:**Cash
                  and cash equivalents
              **$**
              **3**
              
              $
              3Accounts
                  receivable – trade (less allowance for doubtfulaccounts
                  of $7 and $5, respectively)
              
              **75**
              
              
              61Unbilled
                  revenue
              
              **46**
              
              
              59Accounts
                  receivables – affiliates
              
              **12**
              
              
              18Note
                  receivable – Resources Company
              
              **42**
              
              
              42Materials
                  and supplies
              
              **39**
              
              
              85Other
                  current assets
              
              **23**
              
              
              50Total
                  current assets
              
              **240**
              
              
              318**Property
                  and Plant, Net**
              
              **1,206**
              
              
              1,212**Investments
                  and Other Assets:**Investments
                  in leveraged leases
              
              **21**
              
              
              21Goodwill
              
              **575**
              
              
              575Intangible
                  assets
              
              **64**
              
              
              62Other
                  assets
              
              **18**
              
              
              35Regulatory
                  assets
              
              **11**
              
              
              11Total
                  investments and other assets
              
              **689**
              
              
              704**TOTAL
                  ASSETS**
              **$**
              **2,135**
              
              $
              2,234**LIABILITIES
                  AND STOCKHOLDER'S EQUITY****Current
                  Liabilities:**Current
                  maturities of long-term debt
              **$**
              **50**
              
              $
              -Borrowings
                  from money pool
              
              **160**
              
              
              154Intercompany
                  note payable – Ameren
              
              **191**
              
              
              186Accounts
                  and wages payable
              
              **35**
              
              
              81Accounts
                  and wages payable – affiliates
              
              **19**
              
              
              28Other
                  current liabilities
              
              **66**
              
              
              55Total
                  current liabilities
              
              **521**
              
              
              504**Long-term
                  Debt, Net**
              
              **479**
              
              
              534**Preferred
                  Stock of Subsidiary Subject to Mandatory
                  Redemption**
              
              **19**
              
              
              19**Deferred
                  Credits and Other Liabilities:**Accumulated
                  deferred income taxes, net
              
              **157**
              
              
              163Accumulated
                  deferred investment tax credits
              
              **8**
              
              
              9Regulatory
                  liabilities
              
              **43**
              
              
              41Accrued
                  pension and other postretirement benefits
              
              **254**
              
              
              251Other
                  deferred credits and liabilities
              
              **26**
              
              
              31Total
                  deferred credits and other liabilities
              
              **488**
              
              
              495**Preferred
                  Stock of Subsidiary Not Subject to Mandatory
                  Redemption**
              
              **19**
              
              
              19**Commitments
                  and Contingencies (Notes 2 and 8)****Stockholder's
                  Equity:**Common
                  stock, no par value, 10,000 shares authorized – 1,000 shares
                  outstanding
              
              **-**
              
              
              -Other
                  paid-in capital
              
              **598**
              
              
              640Retained
                  earnings
              
              **-**
              
              
              -Accumulated
                  other comprehensive income
              
              **11**
              
              
              23Total
                  stockholder's equity
              
              **609**
              
              
              663**TOTAL
                  LIABILITIES AND STOCKHOLDER'S EQUITY**
              **$**
              **2,135**
              
              $
              2,234


The
      accompanying notes as they relate to CILCORP are an integral part of these
      consolidated financial statements.




21




**CILCORP
                  INC.****CONSOLIDATED
                  STATEMENT OF CASH FLOWS****(Unaudited)
                  (In millions)****Three
                  Months Ended****March
                  31,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **8**
              
              $
              9Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **20**
              
              
              18Deferred
                  income taxes and investment tax credits
              
              **(2**
              **)**
              
              (8
              )Other
              
              **2**
              
              
              8Changes
                  in assets and liabilities:Receivables,
                  net
              
              **5**
              
              
              4Materials
                  and supplies
              
              **46**
              
              
              14Accounts
                  and wages payable
              
              **(49**
              **)**
              
              (24
              )Taxes
                  accrued
              
              **13**
              
              
              (9
              )Assets,
                  other
              
              **13**
              
              
              13Liabilities,
                  other
              
              **2**
              
              
              11Pension
                  and postretirement benefit obligations, net
              
              **3**
              
              
              5Net
                  cash provided by operating activities
              
              **61**
              
              
              41**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(19**
              **)**
              
              (19
              )Changes
                  in money pool advances
              
              **-**
              
              
              4Other
              
              **-**
              
              
              2Net
                  cash used in investing activities
              
              **(19**
              **)**
              
              (13
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **(50**
              **)**
              
              (30
              )Changes
                  in money pool borrowings
              
              **6**
              
              
              (5
              )Redemptions,
                  repurchases, and maturities:Long-term
                  debt
              
              **(3**
              **)**
              
              -Issuances:Intercompany
                  note payable – Ameren
              
              **5**
              
              
              4Net
                  cash used in financing activities
              
              **(42**
              **)**
              
              (31
              )Net
                  change in cash and cash equivalents
              
              **-**
              
              
              (3
              )Cash
                  and cash equivalents at beginning of year
              
              **3**
              
              
              7Cash
                  and cash equivalents at end of period
              **$**
              **3**
              
              $
              4


The accompanying notes as they relate to CILCORP are an
      integral part of these consolidated financial statements.




22




**CENTRAL
                  ILLINOIS LIGHT COMPANY****CONSOLIDATED
                  STATEMENT OF INCOME****(Unaudited)
                  (In millions)****Three
                  Months Ended,****March
                  31****2006**
              
              **2005****Operating
                  Revenues:**Electric
              **$**
              **92**
              
              $
              93Gas
              
              **150**
              
              
              125Total
                  operating revenues
              
              **242**
              
              
              218**Operating
                  Expenses:**Fuel
                  and purchased power
              
              **25**
              
              
              31Gas
                  purchased for resale
              
              **119**
              
              
              91Other
                  operations and maintenance
              
              **41**
              
              
              44Depreciation
                  and amortization
              
              **17**
              
              
              17Taxes
                  other than income taxes
              
              **9**
              
              
              6Total
                  operating expenses
              
              **211**
              
              
              189**Operating
                  Income**
              
              **31**
              
              
              29**Other
                  Expenses:**Miscellaneous
                  expense
              
              **(1**
              **)**
              
              (1
              )Total
                  other expenses
              
              **(1**
              **)**
              
              (1
              )**Interest
                  Charges**
              
              **4**
              
              
              4**Income
                  Before Income Taxes**
              
              **26**
              
              
              24**Income
                  Taxes**
              
              **9**
              
              
              8**Net
                  Income**
              
              **17**
              
              
              16**Preferred
                  Stock Dividends**
              
              **-**
              
              
              1**Net
                  Income Available to Common Stockholder**
              **$**
              **17**
              
              **$**
              **15**


The accompanying notes as they relate to CILCO are an integral
      part of these consolidated financial statements.




23




**CENTRAL
                  ILLINOIS LIGHT COMPANY****CONSOLIDATED
                  BALANCE SHEET****(Unaudited)
                  (In millions)****March
                  31,**
              
              **December
                  31,****2006**
              
              **2005****ASSETS****Current
                  Assets:**Cash
                  and cash equivalents
              **$**
              **1**
              
              $
              2Accounts
                  receivable – trade (less allowance for doubtfulaccounts
                  of $7 and $5, respectively)
              
              **75**
              
              
              61Unbilled
                  revenue
              
              **46**
              
              
              59Accounts
                  receivable – affiliates
              
              **4**
              
              
              14Materials
                  and supplies
              
              **39**
              
              
              87Other
                  current assets
              
              **28**
              
              
              43Total
                  current assets
              
              **193**
              
              
              266**Property
                  and Plant, Net**
              
              **1,211**
              
              
              1,214**Investments
                  in Leveraged Leases**
              
              **21**
              
              
              21**Intangible
                  Assets**
              
              **10**
              
              
              4**Other
                  Assets**
              
              **28**
              
              
              41**Regulatory
                  Assets**
              
              **11**
              
              
              11**TOTAL
                  ASSETS**
              **$**
              **1,474**
              
              $
              1,557**LIABILITIES
                  AND STOCKHOLDERS' EQUITY****Current
                  Liabilities:**Current
                  maturities of long-term debt
              **$**
              **50**
              
              $
              -Borrowings
                  from money pool
              
              **168**
              
              
              161Accounts
                  and wages payable
              
              **34**
              
              
              81Accounts
                  and wages payable – affiliates
              
              **18**
              
              
              26Other
                  current liabilities
              
              **61**
              
              
              48Total
                  current liabilities
              
              **331**
              
              
              316**Long-term
                  Debt, Net**
              
              **72**
              
              
              122**Preferred
                  Stock Subject to Mandatory Redemption**
              
              **19**
              
              
              19**Deferred
                  Credits and Other Liabilities:**Accumulated
                  deferred income taxes, net
              
              **159**
              
              
              167Accumulated
                  deferred investment tax credits
              
              **8**
              
              
              8Regulatory
                  liabilities
              
              **189**
              
              
              187Accrued
                  pension and other postretirement benefits
              
              **152**
              
              
              146Other
                  deferred credits and liabilities
              
              **26**
              
              
              30Total
                  deferred credits and other liabilities
              
              **534**
              
              
              538**Commitments
                  and Contingencies (Notes 2 and 8)****Stockholders'
                  Equity:**Common
                  stock, no par value, 20.0 shares authorized – 13.6 shares
                  outstanding
              
              **-**
              
              
              -Preferred
                  stock not subject to mandatory redemption
              
              **19**
              
              
              19Other
                  paid-in capital
              
              **415**
              
              
              415Retained
                  earnings
              
              **86**
              
              
              119Accumulated
                  other comprehensive income (loss)
              
              **(2**
              **)**
              
              9Total
                  stockholders' equity
              
              **518**
              
              
              562**TOTAL
                  LIABILITIES AND STOCKHOLDERS' EQUITY**
              **$**
              **1,474**
              
              $
              1,557


The accompanying notes as they relate to CILCO are an integral
      part of these consolidated financial statements.




24




**CENTRAL
                  ILLINOIS LIGHT COMPANY****CONSOLIDATED
                  STATEMENT OF CASH FLOWS****(Unaudited)
                  (In millions)****Three
                  Months Ended****March
                  31,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **17**
              
              $
              16Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **17**
              
              
              17Deferred
                  income taxes and investment tax credits
              
              **(3**
              **)**
              
              (4
              )Other
              
              **1**
              
              
              2Changes
                  in assets and liabilities:Receivables,
                  net
              
              **9**
              
              
              3Materials
                  and supplies
              
              **48**
              
              
              13Accounts
                  and wages payable
              
              **(49**
              **)**
              
              (21
              )Taxes
                  accrued
              
              **12**
              
              
              9Assets,
                  other
              
              **(7**
              **)**
              
              1Liabilities,
                  other
              
              **10**
              
              
              -Pension
                  and postretirement benefit obligations, net
              
              **6**
              
              
              9Net
                  cash provided by operating activities
              
              **61**
              
              
              45**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(19**
              **)**
              
              (19
              )Net
                  cash used in investing activities
              
              **(19**
              **)**
              
              (19
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **(50**
              **)**
              
              (20
              )Dividends
                  on preferred stock
              
              **-**
              
              
              (1
              )Changes
                  in money pool borrowings
              
              **7**
              
              
              (6
              )Net
                  cash used in financing activities
              
              **(43**
              **)**
              
              (27
              )Net
                  change in cash and cash equivalents
              
              **(1**
              **)**
              
              (1
              )Cash
                  and cash equivalents at beginning of year
              
              **2**
              
              
              2Cash
                  and cash equivalents at end of period
              **$**
              **1**
              
              $
              1


The accompanying notes as they relate to CILCO are an integral
      part of these consolidated financial statements.




25




**ILLINOIS
                  POWER COMPANY****CONSOLIDATED
                  STATEMENT OF INCOME****(Unaudited)
                  (In millions)****Three
                  Months Ended****March
                  31,****2006**
              
              **2005****Operating
                  Revenues:**Electric
              **$**
              **242**
              
              $
              235Gas
              
              **255**
              
              
              197Total
                  operating revenues
              
              **497**
              
              
              432**Operating
                  Expenses:**Purchased
                  power
              
              **177**
              
              
              157Gas
                  purchased for resale
              
              **201**
              
              
              146Other
                  operations and maintenance
              
              **59**
              
              
              42Depreciation
                  and amortization
              
              **19**
              
              
              21Taxes
                  other than income taxes
              
              **22**
              
              
              22Total
                  operating expenses
              
              **478**
              
              
              388**Operating
                  Income**
              
              **19**
              
              
              44**Other
                  Income and Expenses:**Miscellaneous
                  income
              
              **1**
              
              
              2Miscellaneous
                  expense
              
              **(1**
              **)**
              
              -Total
                  other income
              
              **-**
              
              
              2**Interest
                  Charges**
              
              **12**
              
              
              10**Income
                  Before Income Taxes**
              
              **7**
              
              
              36**Income
                  Taxes**
              
              **3**
              
              
              14**Net
                  Income**
              
              **4**
              
              
              22**Preferred
                  Stock Dividends**
              
              **1**
              
              
              1**Net
                  Income Available to Common Stockholder**
              **$**
              **3**
              
              $
              21


The accompanying notes as they relate to IP are an integral
      part of these consolidated financial statements.




26




**ILLINOIS
                  POWER COMPANY****CONSOLIDATED
                  BALANCE SHEET****(Unaudited)
                  (In millions)****March
                  31,**
              
              **December
                  31,****2006**
              
              **2005****ASSETS****Current
                  Assets:**Cash
                  and cash equivalents
              **$**
              **1**
              
              $
              -Accounts
                  receivable (less allowance for doubtfulaccounts
                  of $11 and $8, respectively)
              
              **170**
              
              
              155Unbilled
                  revenue
              
              **84**
              
              
              118Miscellaneous
                  accounts and notes receivable
              
              **3**
              
              
              5Materials
                  and supplies
              
              **47**
              
              
              122Other
                  current assets
              
              **17**
              
              
              31Total
                  current assets
              
              **322**
              
              
              431**Property
                  and Plant, Net**
              
              **2,052**
              
              
              2,035**Investments
                  and Other Assets:**Investment
                  in IP SPT
              
              **7**
              
              
              7Goodwill
              
              **326**
              
              
              326Other
                  assets
              
              **47**
              
              
              44Regulatory
                  assets
              
              **195**
              
              
              194Accumulated
                  deferred income taxes
              
              **6**
              
              
              19Total
                  investments and other assets
              
              **581**
              
              
              590**TOTAL
                  ASSETS**
              **$**
              **2,955**
              
              $
              3,056**LIABILITIES
                  AND STOCKHOLDERS’ EQUITY****Current
                  Liabilities**:Current
                  maturities of long-term debt to IP SPT
              **$**
              **67**
              
              $
              72Borrowings
                  from money pool
              
              **78**
              
              
              75Accounts
                  and wages payable
              
              **88**
              
              
              145Accounts
                  and wages payable – affiliates
              
              **37**
              
              
              29Taxes
                  accrued
              
              **-**
              
              
              15Other
                  current liabilities
              
              **119**
              
              
              135Total
                  current liabilities
              
              **389**
              
              
              471**Long-term
                  Debt, Net**
              
              **702**
              
              
              704**Long-term
                  Debt to IP SPT**
              
              **161**
              
              
              184**Deferred
                  Credits and Other Liabilities:**Regulatory
                  liabilities
              
              **97**
              
              
              80Accrued
                  pension and other postretirement liabilities
              
              **259**
              
              
              255Other
                  deferred credits and other noncurrent liabilities
              
              **57**
              
              
              75Total
                  deferred credits and other liabilities
              
              **413**
              
              
              410**Commitments
                  and Contingencies (Notes 2 and 8)****Stockholders’
                  Equity:**Common
                  stock, no par value, 100.0 shares authorized – 23.0 shares outstanding
              
              **-**
              
              
              -Other
                  paid-in-capital
              
              **1,196**
              
              
              1,196Preferred
                  stock not subject to mandatory redemption
              
              **46**
              
              
              46Retained
                  earnings
              
              **49**
              
              
              46Accumulated
                  other comprehensive loss
              
              **(1**
              **)**
              
              (1
              )Total
                  stockholders’ equity
              
              **1,290**
              
              
              1,287**TOTAL
                  LIABILITIES AND STOCKHOLDERS’ EQUITY**
              **$**
              **2,955**
              
              $
              3,056


The accompanying notes as they relate to IP are an integral
      part of these consolidated financial statements.




27




**ILLINOIS
                  POWER COMPANY****CONSOLIDATED
                  STATEMENT OF CASH FLOWS****(Unaudited)
                  (In millions)****Three
                  Months Ended****March
                  31,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **4**
              
              $
              22Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **7**
              
              
              5Amortization
                  of debt issuance costs and premium/discounts
              
              **1**
              
              
              2Deferred
                  income taxes
              
              **7**
              
              
              7Other
              
              **-**
              
              
              1Changes
                  in assets and liabilities:Receivables,
                  net
              
              **21**
              
              
              (10
              )Materials
                  and supplies
              
              **75**
              
              
              52Accounts
                  and wages payable
              
              **(47**
              **)**
              
              (9
              )Assets,
                  other
              
              **15**
              
              
              11Liabilities,
                  other
              
              **(23**
              **)**
              
              29Pension
                  and other postretirement benefit obligations, net
              
              **4**
              
              
              3Net
                  cash provided by operating activities
              
              **64**
              
              
              113**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(37**
              **)**
              
              (31
              )Changes
                  in money pool advances
              
              **-**
              
              
              35Other
              
              **-**
              
              
              (3
              )Net
                  cash provided by (used in) investing activities
              
              **(37**
              **)**
              
              1**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **-**
              
              
              (20
              )Dividends
                  on preferred stock
              
              **(1**
              **)**
              
              (1
              )Borrowings
                  from money pool, net
              
              **3**
              
              
              -Redemptions
                  and repurchases of long-term debt
              
              **(23**
              **)**
              
              (92
              )Transitional
                  funding trust notes overfunding
              
              **(5**
              **)**
              
              (1
              )Net
                  cash used in financing activities
              
              **(26**
              **)**
              
              (114
              )Net
                  change in cash and cash equivalents
              
              **1**
              
              
              -Cash
                  and cash equivalents at beginning of year
              
              -
              
              
              5Cash
                  and cash equivalents at end of period
              **$**
              **1**
              
              $
              5


The accompanying notes as they relate to IP are an integral
      part of these consolidated financial statements.




28




**AMEREN
      CORPORATION** **(Consolidated)**


**UNION
      ELECTRIC COMPANY** **(Consolidated)**


**CENTRAL
      ILLINOIS PUBLIC SERVICE COMPANY**


**AMEREN
      ENERGY GENERATING COMPANY** **(Consolidated)**


**CILCORP
      INC.** **(Consolidated)**


**CENTRAL
      ILLINOIS LIGHT COMPANY** **(Consolidated)**


**ILLINOIS
      POWER COMPANY** **(Consolidated)**





**COMBINED
      NOTES TO FINANCIAL STATEMENTS**


**(Unaudited)**


**March
      31, 2006**





**NOTE
      1 -** **SUMMARY
      OF SIGNIFICANT ACCOUNTING POLICIES** ****





**General**





Ameren,
      headquartered in St. Louis, Missouri, is a public utility holding company under
      PUHCA 2005 administered by FERC. Ameren was registered with the SEC as a public
      utility holding company under PUHCA 1935 until that act was repealed effective
      February 8, 2006. Ameren’s primary asset is the common stock of its
      subsidiaries. Ameren’s subsidiaries, which are separate, independent legal
      entities with separate businesses, assets and liabilities, operate
      rate-regulated electric generation, transmission and distribution businesses,
      rate-regulated natural gas transmission and distribution businesses and
      non-rate-regulated electric generation businesses in Missouri and Illinois,
      as
      discussed below. Dividends on Ameren’s common stock depend on distributions made
      to it by its subsidiaries. Ameren’s principal subsidiaries are listed below.
      Also see the Glossary of Terms and Abbreviations at the front of this
      report.





·
            UE,
                or Union Electric Company, also known as AmerenUE, operates a
                rate-regulated electric generation, transmission and distribution
                business, and a rate-regulated natural gas transmission and distribution
                business in Missouri.


·
            CIPS,
                or Central Illinois Public Service Company, also known as AmerenCIPS,
                operates a rate-regulated electric and natural gas transmission and
                distribution business in Illinois.


·
            Genco,
                or Ameren Energy Generating Company, operates a non-rate-regulated
                electric generation business in Illinois and Missouri.


·
            CILCO,
                or Central Illinois Light Company, also known as AmerenCILCO, is
                a
                subsidiary of CILCORP (a holding company). It operates a rate-regulated
                electric transmission and distribution business, a primarily
                non-rate-regulated electric generation business (through its subsidiary
                AERG), and a rate-regulated natural gas transmission and distribution
                business in Illinois.


·
            IP,
                or Illinois Power Company, also known as AmerenIP, operates a
                rate-regulated electric and natural gas transmission and distribution
                business in Illinois.




Ameren
      has various other subsidiaries responsible for the short- and long-term
      marketing of power, procurement of fuel, management of commodity risks, and
      provision of other shared services. Ameren has an 80% ownership interest in
      EEI
      through UE and Development Company, which each own 40% of EEI. Ameren
      consolidates EEI for financial reporting purposes, while UE reports EEI under
      the equity method. EEI is a significant equity investment of UE, as determined
      by SEC rules. The following table presents summarized financial information
      of
      EEI (in millions) for the three months ended March 31, 2006 and
      2005:





**Three
                Months****2006**
            
            
            **2005**Operating
                revenues
            **$**
            **97**
            
            $
            42Operating
                income
            
            **35**
            
            
            3Net
                income
            
            **35**
            
            
            3





The
      financial statements of the Ameren Companies (except CIPS) are prepared on
      a
      consolidated basis and therefore include the accounts of their majority-owned
      subsidiaries, as applicable. All significant intercompany transactions have
      been
      eliminated. All tabular dollar amounts are in millions, unless otherwise
      indicated.





Our
      accounting policies conform to GAAP. Our financial statements reflect all
      adjustments (which include normal, recurring adjustments) necessary, in our
      opinion, for a fair presentation of our results. The preparation of financial
      statements in conformity with GAAP requires management to make certain estimates
      and assumptions. Such estimates and assumptions affect reported amounts of
      assets and liabilities, the disclosure of contingent assets and liabilities
      at
      the dates of financial statements, and the reported amounts of revenues and
      expenses during the reported periods. Actual results could differ from those
      estimates. The results of operations of an interim period may not give a true
      indication of results for a full year. Certain reclassifications have been
      made
      to make prior period financial statements conform to 2006 reporting. These
      financial statements should be read in conjunction with the financial statements
      and the notes thereto included in the Ameren Companies’ combined Annual Report
      on Form 10-K for the fiscal year ended December 31, 2005.





**Earnings
      Per Share**





There
      were no material differences between Ameren’s basic and diluted earnings per
      share amounts for the three months ended March 31, 2006 and 2005, due to an
      immaterial number of stock options, restricted stock units and performance
      share
      units outstanding.





**Accounting
      Changes and Other Matters**





***SFAS
      No. 123 (revised 2004)*** **** ***“Share
      Based Payment”***





Effective
      January 1, 2003, Ameren adopted the fair value recognition provisions of SFAS
      No. 123, “Accounting for




29




Stock-based
      Compensation” (SFAS 123), by using the prospective method of adoption under SFAS
      No. 148, “Accounting for Stock-based Compensation - Transition and Disclosure,”
for all employee awards granted or with terms modified on or after January
      1,
      2003.





Effective
      January 1, 2006, Ameren adopted SFAS No. 123 (revised 2004) “Share Based
      Payment” (SFAS 123R), which revises SFAS 123 and supersedes APB Opinion No. 25,
“Accounting for Stock Issued to Employees.” SFAS 123R requires companies to
      measure the cost of employee services received in exchange for an award of
      equity instruments by the grant-date fair value of the award.


Ameren
      adopted SFAS 123R utilizing the modified prospective application. Under the
      modified prospective approach, SFAS 123R applies to all awards granted or
      modified after the effective date.




**Long-term
      Incentive Plan of 1998 and 2006 Incentive Compensation
      Plan**





A
      summary
      of nonvested shares as of March 31, 2006, and changes during the quarter ended
      March 31, 2006, under Ameren’s Long-term Incentive Plan of 1998, as amended
      (“1998 Plan”) is presented below:





**Performance
                Share Units**
            
            **Restricted
                Shares****Shares**
            
            **Weighted-average
                Fair Value**
            
            **Shares**
            
            **Weighted-average
                Fair Value**Nonvested
                at January 1, 2006
            
            -
            
            $
            -
            
            
            575,469
            
            $
            44.91Granted
            
            220,434
            
            
            56.07
            
            
            -
            
            
            -Dividends
                on restricted shares
            
            -
            
            
            -
            
            
            2,122
            
            
            43.75Vested(a)
            
            (1,319
            )
            
            56.07
            
            
            (213,198
            )
            
            43.38Nonvested
                at March 31, 2006
            
            219,115
            
            $
            56.07
            
            
            364,393
            
            $
            45.79


(a)
            Units
                vested due to employee death and attainment of retirement eligibility
                by
                certain employees. Actual shares issued for retirement eligible employees
                will vary depending on actual performance over the three-year measurement
                period.





A
      performance share unit will vest and entitle an employee to receive shares
      of
      Ameren common stock (plus accumulated dividends) if, at the end of the
      three-year performance period, Ameren has achieved certain performance goals
      and
      the individual remains employed by Ameren. The exact number of shares issued
      pursuant to a performance share unit will vary from 0% to 200% of the target
      award depending on actual company performance relative to the performance goals.
      If a performance share unit vests, Ameren will issue the related shares to
      the
      employee two years after vesting, but dividends on the shares will be paid
      to
      the employee at the same time paid to other shareholders.





The
      fair
      value of the performance share unit awards granted in the first quarter of
      2006
      was determined to be $56.07 based on Ameren’s closing common share price of
      $50.69 at the grant date and lattice simulations utilized to estimate expected
      share payout based on Ameren’s attainment of certain financial measures relative
      to the designated peer group. The significant assumptions utilized to calculate
      fair value also included a three-year risk-free rate of 4.65%, dividend yields
      ranging from 2.3% to 4.6% for the peer group, volatility ranging from 13.87%
      to
      22.45% for the peer group, and Ameren’s maintenance of its $2.54 annual dividend
      over the performance period.




Ameren
      recorded compensation expense of $2 million for each of the quarters ended
      March
      31, 2006 and 2005, and a related tax benefit of less than $1 million for the
      quarter ended March 31, 2006. As of March 31, 2006, total compensation cost
      of
      $21 million related to nonvested awards not yet recognized is expected to be
      recognized over a weighted-average period of 3 years.





In
      the
      first quarter of 2006, Ameren’s Board of Directors approved the 2006 Omnibus
      Incentive Compensation Plan (“2006 Plan”), subject to shareholders’ approval,
      which was obtained on May 2, 2006. The 2006 Plan prospectively replaces the
      1998
      Plan, effective May 2, 2006. The 2006 Plan provides for a maximum number of
      4,000,000 common shares available for grant to eligible employees and directors.
      No new awards may be granted under the 1998 Plan; however, previously granted
      awards continue to vest or be exercisable in accordance with their original
      terms and conditions. The 2006 Plan awards may be stock options, stock
      appreciation rights, restricted stock, restricted stock units, performance
      shares, performance units, cash-based awards, and other stock-based
      awards.





In
      the
      first quarter of 2006, Ameren awarded 130,206 performance share units under
      the
      2006 Plan, to executive officers of Ameren and certain of its subsidiaries
      subject to shareholder approval, which was obtained on May 2, 2006. These share
      units were not considered as granted until approved by shareholders.
      Accordingly, compensation expense for these awards to executive officers was
      not
      recognized in the first quarter of 2006.


Ameren
        has not granted any stock options subsequent to its adoption of SFAS 123,
        and
        the options granted prior to the SFAS 123 adoption were fully expensed during
        2005. Therefore, there is no expense for the three months ended March 31,
        2006,
        and the pro forma expense for the year-ago period would have been less than
        $1
        million.  See Note 1 -


30


Summary
        of Significant Accounting Policies and Note 12 - Stock-based Compensation
        in the
        Ameren Companies' combined Annual Report on Form 10-K for the fiscal year
        ended
        December 31, 2005, for additional information.


**Proposed
      SFAS on Employer’s Accounting for Defined Benefit Pension and Other
      Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and
      132(R)**





Issued
      in
      March 2006, this proposed SFAS would require employers to recognize the
      overfunded or underfunded positions of defined benefit postretirement plans,
      including pension plans, in their balance sheets. Existing unrecognized net
      gains and losses and unrecognized prior-service costs and credits, as well
      as
      any new gains and losses and new prior-service costs and credits, would be
      recognized as part of the balance sheet net pension asset or liability, with
      a
      corresponding credit or charge to OCI. Existing unrecognized net transition
      assets or obligations would also be recognized as part of the balance sheet
      pension and other postretirement benefit asset or liability, but the
      corresponding adjustment upon adoption would be to retained earnings. If
      approved, the new standard would require Ameren to recognize additional pension
      and other postretirement benefit obligations of approximately $234 million
      and
      $308 million, respectively, and write-off a $79 million pension-related
      intangible asset, based on the funded status of Ameren’s defined benefit
      postretirement plans as of December 31, 2005. Ameren would also be required
      to
      record a deferred tax benefit associated with the temporary differences between
      the liabilities recognized for book and tax purposes. In addition, to the extent
      Ameren determines that it is probable that the additional liabilities will
      be
      recoverable through rates charged by Ameren’s rate-regulated businesses (UE,
      CIPS, CILCO and IP), a regulatory asset may be recorded. If approved in its
      current format, the provisions of this proposed SFAS would be applied
      retrospectively for the year ending December 31, 2006. There would be no
      material impact of adopting this proposed standard on Ameren’s net
      income.





**Revenue**





***Interchange
      Revenues***





The
      following table presents the interchange revenues included in Operating Revenues
      - Electric for the three months ended March 31, 2006 and 2005. See Note 7 -
      Related Party Transactions for further information on affiliate interchange
      revenues transactions.





**Three
                Months****2006**
            
            **2005**Ameren(a)
            **$**
            **192**
            
            $
            113UE
            
            **138**
            
            
            97CIPS
            
            **1**
            
            
            9Genco
            
            **49**
            
            
            42CILCORP
            
            **10**
            
            
            15CILCO
            
            **10**
            
            
            15IP
            
            **-**
            
            
            (b
            )


(a)
            Includes
                amounts for Ameren registrant and nonregistrant subsidiaries and
                intercompany eliminations. Includes interchange revenues at Marketing
                Company and EEI of $89 million for the three months ended March 31,
                2006
                (2005 - $7 million).


(b)
            Less
                than $1 million.





**Purchased
      Power**





The
      following table presents the purchased power expenses included in Operating
      Expenses - Fuel and Purchased Power for the three months ended March 31, 2006
      and 2005. See Note 7 - Related Party Transactions for further information on
      affiliate purchased power transactions.





**Three
                Months****2006**
            
            **2005**Ameren(a)
            **$**
            **273**
            
            $
            205UE
            
            **67**
            
            
            38CIPS
            
            **117**
            
            
            86Genco
            
            **96**
            
            
            49CILCORP
            
            **2**
            
            
            9CILCO
            
            **2**
            
            
            9IP
            
            **177**
            
            
            157


(a)
            Includes
                amounts for Ameren registrant and nonregistrant subsidiaries and
                intercompany eliminations. Includes purchased power for EEI of $1
                million
                for the three months ended March 31, 2006 (2005 - less than $1 million).





31




**Excise
        Taxes**





Excise
      taxes reflected on Missouri electric, Missouri gas, and Illinois gas customer
      bills are imposed on us. They are recorded gross in Operating Revenues and
      Taxes
      Other than Income Taxes on each company’s statement of income. Excise taxes
      reflected on Illinois electric customer bills are imposed on the consumer.
      They
      are recorded as tax collections payable and included in Other Current
      Liabilities. The following table presents excise taxes recorded in Operating
      Revenues and Taxes Other than Income Taxes for the three months ended March
      31,
      2006 and 2005:







**Three
                    Months****2006**
                
                **2005**Ameren
                **$**
                **47**
                
                $
                40UE
                
                **25**
                
                
                22CIPS
                
                **6**
                
                
                4CILCORP
                
                **5**
                
                
                3CILCO
                
                **5**
                
                
                3IP
                
                **11**
                
                
                11




**Asset
      Retirement Obligations**





AROs
      at
      Ameren and UE increased compared to December 31, 2005 to reflect the accretion
      of obligations to their fair values.





**NOTE
      2 -** **RATE
      AND REGULATORY MATTERS** ****





Below
      is
      a summary of significant regulatory proceedings. We are unable to predict
      the ultimate outcome of these regulatory proceedings, the timing of the
      final decisions of the various agencies, or the impact on our results of
      operations, financial position, or liquidity.





**CT
      Facilities Purchases**





In
      March
      2006, following the receipt of all required regulatory approvals, UE completed
      the purchase of a 640-megawatt CT facility located in Audrain County, Missouri,
      at a price of $115 million from NRG Audrain Holding, LLC, and NRG Audrain
      Generating LLC, affiliates of NRG Energy, Inc. (collectively “NRG”). As a part
      of this transaction, UE was assigned the rights of NRG as lessee of the CT
      facility under a long-term lease with Audrain County and assumed NRG’s
      obligations under the lease. This lease was entered into pursuant to Missouri
      economic development statutes to provide a development incentive property tax
      savings to the lessee for locating the CT facility in Audrain County. The lease
      term will expire December 1, 2023. It is a net lease, with UE as the lessee
      being responsible for rental payments under the lease in an amount sufficient
      to
      pay the debt service of a taxable industrial development revenue bond (principal
      amount of $240 million currently outstanding) issued to NRG by Audrain County
      in
      exchange for title to the NRG CT facility. As part of this acquisition, UE
      acquired the bond from NRG. Because rental payments are equal to debt service
      on
      the bond, there is no net cash expense relating to this lease. No capital was
      initially raised in the leasing transaction, and no capital was raised as a
      result of UE’s assumption of NRG’s lease obligations. Audrain County will retain
      title to the CT facility during the term of the bond and the lease, and
      therefore the facility will be exempt from ad valorem taxation. The title to
      the
      facility will be transferred to UE at the expiration of the lease. UE has all
      operation and maintenance responsibilities for the CT facility.





Also
      in
      March 2006, following the receipt of all required regulatory approvals, UE
      completed the purchase of the 510-megawatt Goose Creek CT facility in Piatt
      County, Illinois, at a price of $106 million and the 340-megawatt Raccoon Creek
      CT facility located in Clay County, Illinois, at a price of $71 million from
      subsidiaries of Aquila, Inc.





These
      CT
      facility purchases are designed to help meet UE’s increased generating capacity
      needs as well as to provide UE with additional flexibility in determining future
      baseload generating capacity additions. These purchases were accounted for
      as
      asset purchases.





**Missouri**





***Electric***





In
      August
      2002, a stipulation and agreement resolved an excess-earnings complaint brought
      against UE by the MoPSC staff following the expiration of UE’s experimental
      alternative regulation plan. The resolution became effective following agreement
      by all parties to the case and approval by the MoPSC. The stipulation and
      agreement included, among other things, the following features:





·
            A
                rate moratorium providing for no changes in rates before July 1,
                2006.


·
            A
                commitment to make $2.25 billion to $2.75 billion in critical energy
                infrastructure investments from January 1, 2002 through June 30,
                2006,
                including, among other things, the addition of more than 700 megawatts
                of
                new generation capacity and the replacement of steam generators at
                UE’s
                Callaway nuclear plant. The 700 megawatts of new generation was satisfied
                by UE’s addition of 240 megawatts in 2002 and the transfer at net book
                value to UE of 550 megawatts of generation assets from Genco in 2005.
                The
                replacement of the steam generators at UE’s Callaway plant was completed
                in November 2005.


·
            An
                electric cost-of-service study to be submitted to the MoPSC staff
                and
                other parties to the 2002 stipulation and agreement by January 1,
                2006. In
                late December 2005, UE submitted a confidential cost-of-service study
                based on a test year of the twelve months ending June 30, 2005. This
                submission did not constitute an electric rate adjustment request,
                but UE
                expects to file to adjust




32






electric
      rates in Missouri in 2006. In an early May 2006 meeting before the MoPSC,
      UE committed to file to adjust rates in Missouri by July 10, 2006, if the
      MoPSC staff continued


to
      support a
      test
      year ending June 30, 2006, with updates through January 1, 2007, including
      known and measureable fuel and purchased power costs. Another meeting
      before


the MoPSC
      is
      expected later in May to further discuss the timing of potential rate actions
      related to UE. The MoPSC staff and other stakeholders will review any UE
      rate


adjustment request
      and, after their analyses, may also make recommendations as to electric rate
      adjustments. Generally, a proceeding to change rates in Missouri could take
      up
      to


11
      months.


***MoPSC
      Rulemaking Proceeding***





In
      July
      2005, a new law was enacted that enables the MoPSC to put in place fuel,
      purchased power, and environmental cost recovery mechanisms for Missouri’s
      utilities. The law also includes rate case filing requirements, a 2.5% annual
      rate increase cap for the environmental recovery mechanism and prudency reviews,
      among other things. Detailed rules for these mechanisms are expected to be
      effective in the second half of 2006.





**Illinois**





***Electric***





By
      2002,
      the power market for Illinois residential, commercial and industrial customers
      of UE (whose Illinois utility business was transferred to CIPS in 2005), CIPS,
      CILCO and IP was opened to alternative electric suppliers under the Illinois
      Customer Choice Law. Under
      the
      Illinois Customer Choice Law, UE, CIPS, CILCO and IP rates initially were frozen
      through January 1, 2005. An
      amendment to the Illinois Customer Choice Law extended the rate freeze through
      January 1, 2007. As a result of this extension, and pursuant to ICC orders,
      CIPS
      and Marketing Company extended their power supply agreements through December
      31, 2006, as did CILCO and AERG. See Note
      7 - Related Party Transactions for a discussion of the affiliate power supply
      agreements.





During
      2004, the ICC conducted workshops to seek input from interested parties on
      the
      framework for retail electric rate determination and power procurement after
      the
      current Illinois electric rate freeze expires on January 1, 2007, and supply
      contracts expire on December 31, 2006.





In
      February 2005, CIPS, CILCO and IP filed with the ICC a proposed process for
      power procurement through an ICC-monitored auction, including, among other
      things, a rate mechanism to pass power supply costs directly through to
      customers. The form of power supply would meet the full requirements of each
      utility, and the risk of fluctuations in power supply requirements would be
      borne by the supplier. On January 24, 2006, the ICC issued an order which
      unanimously approved the Ameren Illinois utilities’ proposed power procurement
      auction and the related tariffs, including the retail rates by which power
      supply costs would be passed through to customers. The order includes the
      following key findings and provisions:





·
            The
                auction proposal is reasonably designed to enable CIPS, CILCO and
                IP to
                procure power supply in a competitive and least-cost
                manner.


·
            The
                first auction is to take place in the first 10 days of September
                2006.


·
            There
                is a limitation of 35% on the amount of power any single supplier
                can
                provide the Ameren Illinois utilities’ expected annual load. Genco and
                AERG will probably participate in the power procurement auction through
                Marketing Company, subject to this limit. Genco, AERG and EEI would
                be
                considered one supplier.


·
            Requires
                a portfolio of one-, two-, and three-year supply
                contracts.


·
            Allows
                full cost recovery through a rate
                mechanism.


·
            Requires
                an annual, postauction prudence review by the
                ICC.





On
      January 26, 2006, CIPS, CILCO and IP filed with the ICC a request for rehearing
      with regard to the provision of the January 2006 order, which requires an
      annual, postauction prudence review to be performed by the ICC. CIPS, CILCO
      and
      IP asserted in their request that there is no basis for such a prudence review.
      In February 2006, the ICC denied this request for rehearing, and CIPS, CILCO
      and
      IP filed an appeal in the appellate court for the Fourth District in Illinois
      on
      February 9, 2006.





Certain
      Illinois legislators, the Illinois attorney general, the Illinois governor
      and
      other parties have sought and continue to seek to block the power procurement
      auction and/or the recovery of related costs for power supply resulting from
      the
      auction through rates to customers. In May 2005, the Illinois attorney general,
      the CUB and the ELPC filed a motion to dismiss the Ameren Illinois utilities’
proposed power procurement auction with the ICC on the basis that the ICC did
      not have authority to approve market-based rates for electric service that
      have
      not been “declared competitive” pursuant to Section 16-113 of the Illinois
      Public Utilities Act (PUA). This motion and a subsequent appeal were denied
      by
      the administrative law judge in the case and by the ICC,
      respectively.




In
        September 2005, Illinois Governor Rod Blagojevich sent a letter to the ICC
        expressing his opposition to CIPS’, CILCO’s and IP’s proposed power procurement
        auction process and requesting dismissal of the pending proceeding for approval
        of such process. CIPS, CILCO and IP responded to the governor's letter citing
        legal deficiencies in his position
  33
  and
        the
        potential adverse consequences that could result if his position is ultimately
        sustained. Copies of the governor’s letter and the Ameren Illinois utilities’
response letter appear as Exhibits 99.1 and 99.2, respectively, to the Current
        Report on Form 8-K dated September 15, 2005. Also in September 2005, the
        Illinois attorney general, the Cook County state’s attorney, the CUB, and the
        ELPC filed a complaint in the Circuit Court of Cook County, Illinois, against
        the ICC and the individual ICC commissioners making claims similar to those
        included in their motion to dismiss that was denied. The complaint asked
        the
        court to determine that the ICC lacks authority to approve the auction proposal.
        It sought injunctive relief prohibiting the ICC from approving the proposals
        by
        CIPS, CILCO and IP. On January 20, 2006, the Circuit Court of Cook County,
        Illinois, entered an order dismissing the complaint with prejudice.





Both
      the
      Illinois governor's letter and the attorney general's lawsuit discussed in
      the
      previous paragraph assert that the energy component of CIPS’, CILCO’s and IP’s
      retail rates for electricity should not be based on the costs to procure energy
      and capacity in the wholesale market. Although CIPS, CILCO and IP have received
      favorable rulings from the ICC and the Circuit Court of Cook County with respect
      to their proposals, we anticipate that certain Illinois legislators, the
      Illinois attorney general, the Illinois governor, and others will persist in
      their efforts to block the power procurement auction and the recovery of related
      costs through rates to customers. In February 2006, the Illinois attorney
      general, CUB, and ELPC filed with the ICC requests for a rehearing of the ICC’s
      January 24, 2006 order approving the Ameren Illinois utilities power procurement
      auction and related tariffs. Their arguments for a rehearing are generally
      similar to those that they have previously raised as discussed above. In March
      2006, the ICC denied these requests for rehearing. In March and April 2006,
      these parties filed appeals in the appellate court for the First District in
      Illinois. We are unable to predict whether such efforts will ultimately be
      successful. However, any decision or action that impairs the ability of CIPS,
      CILCO and IP to fully recover purchased power or distribution costs from their
      electric customers in a timely manner could result in material adverse
      consequences to the Ameren Illinois utilities. As noted in their response letter
      to the Illinois governor, these consequences could include a significant drop
      in
      credit ratings (possibly to below investment-grade status), a loss of access
      to
      the capital markets, higher borrowing costs, higher power supply costs, an
      inability to make timely energy infrastructure investments, impaired customer
      service, job losses, and financial insolvency.





With
      regard to the delivery service component of customer rates, CIPS, CILCO and
      IP
      filed rate cases with the ICC in December 2005 to modify their electric delivery
      service rates effective January 2, 2007. CIPS, CILCO and IP requested to
      increase their annual revenues for electric delivery service by $14 million,
      $43
      million, and $145 million, respectively. To mitigate the impact of these
      requested increases on residential customers, CILCO and IP proposed a two-year
      phase-in with increases for average residential delivery rates capped in the
      first year. The phase-in would decrease requested rate increases by $10 million
      and $36 million for CILCO and IP, respectively, in the first year. In April
      2006, the ICC staff recommended increases in revenues for electric delivery
      services for the Ameren Illinois utilities aggregating $71 million (CIPS -
      $8
      million decrease, CILCO - $17 million increase and IP - $62 million increase)
      and the Illinois attorney general and CUB recommended increases in revenues
      for
      electric delivery services aggregating $72 million for the Ameren Illinois
      utilities (CIPS - $7 million decrease, CILCO - $19 million increase and IP
      - $59
      million increase). Other parties also made recommendations in the case. The
      ICC
      has until November 2006 to render a decision in these rate cases.





The
      Illinois legislature held hearings in 2005 and 2006 regarding the framework
      for
      retail rate determination and power procurement. In February 2006, legislation
      was introduced in the Illinois House of Representatives that would extend the
      electric rate freeze in Illinois through 2010.  CIPS, CILCO and IP strongly
      believe that an extension of the electric rate freeze in Illinois would not
      be
      in the best interests of any of the Ameren Illinois utilities or their
      customers, and have been working with key stakeholders in Illinois to develop
      a
      constructive rate increase phase-in plan for residential customers to address
      the potential significant increases in customer rates for the Ameren Illinois
      utilities beginning in 2007.  We believe that a rate increase phase-in plan
      would need to allow for deferral of a portion of the power procurement costs,
      with provision for full and timely recovery of all deferred costs in a manner
      that would not result in further reductions in credit ratings from December
      31,
      2005 levels. We believe a rate increase phase-in plan, providing for
      deferral of costs with certainty of full and timely recovery of any deferred
      costs, would require legislation in Illinois. In March 2006, legislation was
      introduced in the Illinois House of Representatives that would allow the
      deferral of a portion of the power procurement costs and would authorize the
      ICC
      to permit a utility with fewer than one million retail customers to form special
      purpose finance vehicles to issue securitization bonds to recover the deferred
      costs, with interest.  CIPS, CILCO and IP each have less than one million
      retail customers.  Securitization would allow these special purpose
      vehicles to issue debt securities and use the proceeds to pay the utilities
      immediately upon issuance of the bonds for the deferred power costs for which
      the utilities did not receive reimbursement from customers during a phase-in
      deferral period.  Customers would fund, through dedicated charges included
      on their electric bills, a future payment stream that would be used to service
      the securitized debt.  In effect, through these charges utility customers
      would pay in the future for power used, but not paid for, during a phase-in
      deferral period.  This approach has the effect of spreading




34




over
      the
      life of the bonds, a period of up to 10 years, the potentially significant
      initial electric rate increase for residential customers that would otherwise
      be
      necessary to pay the power procurement costs on a current basis. If passed,
      this
      legislation would assist our Ameren Illinois utilities in maintaining their
      financial integrity while allowing them to recover costs from customers over
      a
      longer term. We cannot predict what actions, if any, the Illinois
      legislature may ultimately take. Any decision or action that impairs CIPS’,
      CILCO’s and IP’s ability to fully recover purchased power costs from their
      electric customers in a timely manner could result in material adverse
      consequences for these companies and for Ameren.




Ameren,
      CIPS, CILCO and IP will continue to explore a number of legal and regulatory
      actions, strategies and alternatives to address these Illinois electric issues.
      There can be no assurance that Ameren and the Ameren Illinois utilities will
      prevail over the stated opposition by certain Illinois legislators, the Illinois
      attorney general, the Illinois governor, and other stakeholders, or that the
      legal and regulatory actions, strategies and alternatives that Ameren and the
      Ameren Illinois utilities are considering will be successful.





**Federal**





***Regional
      Transmission Organization***





Pursuant
      to a series of FERC orders, FERC put into effect on December 1, 2004, Seams
      Elimination Cost Adjustment (SECA) charges, subject to refund and hearing
      procedures, which were filed in late November 2004 by UE, CIPS, CILCO and IP.
      The SECA charges were a transition mechanism that was in place for the period
      December 1, 2004 to March 31, 2006, to compensate transmission owners in MISO
      and PJM for revenues lost when FERC eliminated regional through-and-out rates,
      previously applicable to transactions crossing the border between the MISO
      and
      PJM. The SECA charge was a nonbypassable surcharge payable by load-serving
      entities in proportion to the benefit they realized from the elimination of
      the
      regional through-and-out rates. For the quarter ended March 31, 2006, Ameren
      and
      IP received net revenues from the SECA charges of $2 million and $1 million,
      respectively. UE’s, CIPS’ and CILCO’s net revenues from SECA charges were
      individually less than $1 million each during this period. Until the SECA charge
      filings have been approved by FERC, we cannot predict the ultimate impact that
      such rate structure will have on UE’s, CIPS’, CILCO’s and IP’s operating costs
      and revenues.





***Hydroelectric
      License Renewal***





In
      May
      2005, UE, the U.S. Department of the Interior and various state agencies reached
      a settlement agreement that is expected to lead to FERC’s relicensing of UE’s
      Osage hydroelectric plant for another 40 years. The settlement must be approved
      by FERC. Approval and relicensure are expected in 2006. The current FERC license
      expired on February 28, 2006. Operations are permitted to continue under the
      expired license until the license renewal is approved.





***Joint
      Dispatch Agreement***





As
      a
      result of the February 2005 MoPSC order approving the transfer of UE’s Illinois
      service territory to CIPS that was completed on May 2, 2005, the provision
      in
      the joint dispatch agreement which determines the allocation between UE and
      Genco of margins or profits from short-term sales of excess generation to third
      parties had to be modified. Specifically, the MoPSC order required an amendment
      so that margins on third-party short-term power sales of excess generation
      would
      be allocated between UE and Genco based on generation output, not on load
      requirements, as the agreement had provided. In compliance with the MoPSC order,
      UE, CIPS and Genco, on January 9, 2006, filed this amendment to the joint
      dispatch agreement with FERC for its approval.





The
      Missouri OPC intervened in the FERC proceeding and requested that the joint
      dispatch agreement be further amended to price all transfers of power between
      Genco and UE at market prices rather than incremental cost, which could transfer
      additional electric margins from Genco to UE. In March 2006, FERC denied the
      Missouri OPC request and approved the amendment filed by UE, CIPS and Genco
      effective January 10, 2006. This change in the allocation methodology resulted
      in a $9 million transfer of electric margins from Genco to UE during the first
      quarter of 2006.





Should
      the joint dispatch agreement be modified to price transfers at market prices
      as
      a result of some future regulatory proceeding (for example, by the MoPSC in
      a
      ratemaking proceeding), or otherwise, an evaluation of the continued benefits
      of
      the joint dispatch agreement would have to be made by UE, CIPS and Genco.
      Depending on the outcome of the evaluations, one or more of these companies
      may
      decide to terminate the agreement. UE, CIPS and Genco have the right to
      terminate this agreement with one year’s notice, unless terminated earlier by
      mutual consent. Ameren, UE, CIPS and Genco cannot predict whether any additional
      actions may be taken by regulatory agencies on this matter in the
      future.





For
      the
      full year 2005, Genco received net transfers of 8.7 million megawatthours of
      power from UE.  Genco sold 2.9 million megawatthours of power to UE,
      generating revenue of $74 million, and purchased 11.6 million megawatthours
      from
      UE at a cost of $230 million. While it cannot be predicted what level of power
      purchases and sales will occur between the two companies in the future, UE
      and
      Genco believe that under normal operating conditions, the level of net transfers
      under the joint dispatch agreement from UE to Genco will decline in 2006 from
      2005 levels, which was a historical high, due to less




35


excess
        generation being available at UE. This is expected to result from greater
        native
        load demand in 2006 at UE, resulting from the addition of Noranda as a customer
        in June 2005, continued organic growth, and the expiration of a cost-based
        EEI
        power supply contract with UE, among other things. A cost-based EEI power
        supply
        contract with CIPS (which had been assigned to Genco through Marketing Company)
        also expired on December 31, 2005. CIPS load previously served by EEI and
        additional CIPS load created by the transfer of UE’s Illinois service territory
        to CIPS in May 2005 is being served by other available Genco resources,
        including generation available pursuant to the joint dispatch agreement,
        beginning January 1, 2006.





By
      the
      end of 2006, Genco’s electric power supply agreements with its primary customer,
      CIPS (through Marketing Company), and most of its wholesale and retail customers
      will expire. Strategies for participation in the expected CIPS, CILCO and IP
      September 2006 power procurement auction, and for sales to other customers
      for
      2006 and beyond, are currently being developed and implemented. In the event
      the
      joint dispatch agreement is terminated or amended to price all transfers at
      market prices, the amount of generation available to Genco from its own power
      plants will determine the amount of power it will offer into the power
      procurement auction and to wholesale, retail and interchange customers. As
      a
      result, we would expect future sales volumes from Genco to be lower than prior
      years, and related fuel and purchased power costs to increase. However, Genco
      believes that future sales may be contracted at higher prices since the power
      supply agreement between CIPS and Genco and substantially all of the other
      wholesale and retail contracts that expire in 2006 are below market prices
      for
      similar contracts in early 2006. Due to all of these factors, the ultimate
      impact of the potential changes to Genco’s results of operations, financial
      position, or liquidity are unable to be determined at this time; however, the
      impact could be material.





If
      the
      joint dispatch agreement did not exist or was amended to price all transfers
      at
      market prices, UE may be able to retain the net transfers of power that are
      currently going to Genco under the joint dispatch agreement and could sell
      this
      power in the interchange market at market prices, instead of incremental cost.
      At certain times, UE may also be required to use power from its own higher-cost
      power plants or purchase power to meet its load requirements. The margin impact
      to UE of the potential termination of the joint dispatch agreement or amendment
      to price all transfers at market prices has not been quantified, but UE believes
      it would significantly increase its electric margins. Any increase in UE’s
      electric margins as a result of actual or imputed changes to the joint dispatch
      agreement would likely result in a decrease in UE’s revenue requirements in its
      next rate adjustment proceeding. The ultimate ratemaking treatment for the
      joint
      dispatch agreement will be determined in a future rate proceeding.




See
      Note
      7 - Related Party Transactions for a further discussion of the joint dispatch
      agreement.




**NOTE
      3 - SHORT-TERM BORROWINGS AND LIQUIDITY**




Short-term
      borrowings typically consist of commercial paper issuances and drawings under
      committed bank credit facilities with maturities generally within 1 to 45 days.


The
        following table summarizes the short-term borrowing activity and relevant
        interest rates as of March 31, 2006 and December 31, 2005,
        respectively:
 
 **Ameren**
              **UE****March
                  31, 2006:**Average
                  daily borrowings outstanding during 2006
              **$**
              **153**
              
              **$**
              **130**Weighted-average
                  interest rate during 2006
              
              **4.49**
              **%**
              
              **4.46**
              **%**Peak
                  short-term borrowings during 2006
              
              **562**
              
              
              **445**Peak
                  interest rate during 2006
              
              **5.03**
              **%**
              
              **5.00**
              **%****December
                  31, 2005:**Average
                  daily borrowings outstanding during 2005
              $
              162
              
              $
              135Weighted-average
                  interest rate during 2005
              
              3.02
              %
              
              2.87
              %Peak
                  short-term borrowings during 2005
              
              578
              
              
              424Peak
                  interest rate during 2005
              
              4.71
              %
              
              4.52
              %


At
          March
          31, 2006, Ameren had $1.5 billion of committed credit facilities, consisting
          of
          two facilities each maturing in July 2010, in the amounts of $1.15 billion
          and
          $350 million, of which $1.0 billion was available for use. The entire amount
          of
          the $1.15 billion facility is available to Ameren; UE may directly borrow
          under
          this facility up to $500 million on a 364-day basis; and CIPS, Genco, CILCO
          and
          IP may also each directly borrow under this facility up to $150 million,
          also on
          a 364-day basis. Ameren is the sole borrower under the $350 million credit
          facility. These credit facilities are available for use subject to applicable
          regulatory short-term borrowing authorizations, by UE, CIPS, CILCO, IP
          and
          Ameren Services
  36
 
 through
          a
          utility money pool arrangement. These facilities are also available for
          use by
          Ameren directly, by CILCORP and EEI through direct short-term borrowings
          from
          Ameren, and by most of Ameren’s non-rate-regulated subsidiaries including, but
          not limited to, Ameren Services, Resources Company, Genco, Marketing Company,
          AFS, AERG and Ameren Energy, through a non-state-regulated subsidiary money
          pool
          agreement. The committed bank credit facilities are used to support our
          commercial paper programs that include all outstanding external short-term
          debt
          of Ameren and UE as of March 31, 2006 and December 31, 2005. Access to
          these
          credit facilities for the Ameren Companies is subject to reduction as they
          are
          used by affiliates.
 
 In
          April
          2006, EEI’s $20 million bank credit facility expired and was not
          renewed.
 
 **Money
          Pools**
 
 Ameren
          has money pool agreements with and among its subsidiaries to coordinate
          and
          provide for certain short-term cash and working capital requirements. Separate
          money pools are maintained for utility and non-state-regulated entities.
 
 Through
          the utility money pool, the pool participants can access committed credit
          facilities at Ameren. The availability of funds is determined by funding
          requirement limits established by regulatory authorizations. The average
          interest rate for borrowing under the utility money pool for the three
          months
          ended March 31, 2006 was 4.5% (2005 - 2.5%). While UE is a party to the
          utility
          money pool agreement, it is not currently borrowing or lending under the
          agreement.
 
 Non-state-regulated
          Ameren subsidiaries, including Genco and AERG, have the ability to access
          funding from Ameren’s credit facilities through a non-state-regulated subsidiary
          money pool agreement subject to applicable regulatory short-term borrowing
          authorizations. The
          average interest rate for borrowing under the non-state-regulated subsidiary
          money pool for the three months ended March 31, 2006 was 4.4% (2005 -
          8.2%).
  The
            total
            amount available to the money pool participants at any time is reduced
            by the
            amount of borrowings by their affiliates and is increased to the extent
            that
            other pool participants advance surplus funds to a money pool.
  See
          Note
          7 - Related Party Transactions for the amount of interest income and expense
          from the money pool arrangements recorded by the Ameren Companies for the
          three
          months ended March 31, 2006 and 2005.
 **Indebtedness
            Provisions and Other Covenants**
 
 Ameren’s
            bank credit agreements contain provisions which, among other things,
            place
            restrictions on the ability to incur liens, sell assets, and merge with
            other
            entities. The $1.15 billion revolving credit agreement also contains
            a provision
            that limits Ameren’s, UE’s, CIPS’, Genco’s and IP’s total indebtedness to 65% of
            total capitalization and CILCO’s total indebtedness to 60% of total
            capitalization pursuant to a calculation defined in the agreement. The
            $350
            million credit agreement contains a similar provision with respect to
            Ameren
            only. Exceeding these debt levels would result in a default under the
            credit
            arrangements. As of March 31, 2006, the ratio of total indebtedness to
            total
            capitalization (calculated in accordance with this provision) for Ameren,
            UE,
            CIPS, Genco, CILCO, and IP was 49%, 52%, 42%, 52%, 36% and 44%, respectively
            (2005: Ameren - 50%, UE - 45%, CIPS - 50%, CILCO - 42%, IP - 45%, covenant
            not
            in effect for Genco). These credit agreements also require us to meet
            minimum
            ERISA funding rules. In addition, these credit agreements contain cross-default
            provisions that could trigger a default under the facilities if Ameren
            or
            Ameren’s subsidiaries (subject to the definition in the underlying credit
            agreements), other than certain project finance subsidiaries, default
            in
            indebtedness of $50 million or greater, fail to pay the amounts drawn
            (as a
            direct borrower) under an Ameren credit facility, or enter bankruptcy
            proceedings. A CILCO bankruptcy would also cause a default under CILCORP’s debt
            agreements. In addition, a default in indebtedness of $50 million or
            greater or
            a bankruptcy would cause a default under the International Swap and Derivatives
            Association agreements supporting $100 million of Ameren LIBOR swaps.
 
 None
            of
            Ameren’s revolving short-term credit agreements or financing arrangements
            contain credit rating triggers. At March 31, 2006, the Ameren Companies
            and EEI
            were in compliance with their credit agreement provisions and
            covenants *.*
 
 **NOTE
            4 -** **LONG-TERM
            DEBT AND EQUITY FINANCINGS**
 
 **Ameren**
 
 Under
            DRPlus, pursuant to an effective SEC Form S-3 registration statement,
            and under
            our 401(k) plans, pursuant to effective SEC Form S-8 registration statements,
            Ameren issued a total of 0.5 million new shares of common stock in the
            first
            three months of 2006 valued at $27 million.
 
 **UE**
 
 UE’s
            debt
            increased $240 million in the first quarter of 2006 as a result of the
            capital
            lease transaction associated with the acquisition of a CT discussed in
            Note 2 -
            Rate and Regulatory Matters.
 **CILCORP**
 
 In
              March
              2006, CILCORP repurchased $2 million in principal amount of its 9.375%
              senior
              notes due 2029 for
  37
 $3
              million, and in April 2006, CILCORP repurchased an additional $7 million
              in
              principal amount of these bonds for $9 million.
 
 In
              conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was
              recorded at fair value. Amortization related to these fair value adjustments
              was
              $1 million for the three months ended March 31, 2006 (2005 - $2 million)
              and was
              included in interest expense in the Consolidated Statements of Income
              of Ameren
              and CILCORP.
  **IP**
  In
              conjunction with Ameren’s acquisition of IP, IP’s long-term debt was recorded at
              fair value. Amortization related to these fair value adjustments was
              $3 million
              for the three months ended March 31, 2006 (2005 - $5 million), and
              was included
              in interest expense in the Consolidated Statements of Income of Ameren
              and
              IP.
 **Indenture
          Provisions and Other Covenants**
 
 The
          information below presents a summary of the Ameren Companies’ compliance with
          indenture provisions and other covenants. See Note 6 - Long-term Debt and
          Equity
          Financings in the Ameren Companies’ combined Annual Report on Form 10-K for the
          fiscal year ended December 31, 2005, for a detailed description of those
          provisions.
 
 UE’s,
          CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation
          include covenants and provisions related to the issuances of first mortgage
          bonds and preferred stock. The following table includes the required and
          actual
          earnings coverage ratios for interest charges and preferred dividends and
          bonds
          and preferred stock issuable for the 12 months ended March 31, 2006, at
          an
          assumed interest and dividend rate of 7%.
  **Required
                      Interest Coverage Ratio****(a)**
                  **Actual
                      Interest**
                    **Coverage
                      Ratio**
                  
                  **Bonds**
                    **Issuable****(b)**
                  
                  **Required
                      Dividend**
                    **Coverage
                      Ratio****(c)**
                  
                  **Actual
                      Dividend Coverage Ratio**
                  
                  **Preferred
                      Stock Issuable**UE
                  
                  2.0
                  
                  5.0
                  
                  $
                  2,681
                  
                  
                  2.5
                  
                  
                  53.1
                  
                  $
                  1,718CIPS
                  
                  2.0(d)
                  
                  4.1
                  
                  
                  243
                  
                  
                  1.5
                  
                  
                  2.2
                  
                  
                  196CILCO
                  
                  2.0(d)(e)
                  
                  10.5
                  
                  
                  615
                  
                  
                  2.5
                  
                  
                  13.6
                  
                  
                  126IP
                  
                  2.0
                  
                  4.3
                  
                  
                  383(f)
                  
                  
                  1.5
                  
                  
                  2.7
                  
                  
                  504
 (a)Coverage
                        required on the annual interest charges on first mortgage
                        bonds
                        outstanding and to be issued.(b)Amount
                        of bonds issuable based on meeting required coverage
                        ratios.(c)Coverage
                        required on the annual interest charges on all long-term
                        debt (CIPS only)
                        and the annual dividend on preferred stock outstanding and
                        to be issued,
                        as required in the
                      respective company’s articles of incorporation. For CILCO, this ratio must
                        be met for a period of 12 consecutive calendar months within
                        the 15 months
                        immediately preceding
                      the issuance.(d)Coverage
                        is not required in certain cases when additional first mortgage
                        bonds are
                        issued on the basis of retired bonds.(e)In
                        lieu of meeting the interest coverage ratio requirement,
                        CILCO may attempt
                        to meet an earnings requirement of at least 12% of the principal
                        amount of
                        all mortgage
                      bonds outstanding and to be issued. For the three months
                        ended March 31, 2006, CILCO had earnings equivalent to at
                        least 72% of the
                        principal amount of all mortgage bonds
                      outstanding.(f)In
                        addition to the coverage test based on property additions,
                        IP has the
                        ability to issue bonds based upon retired bond capacity,
                        for which no
                        earnings coverage test is
                        required.
  In
          addition, UE’s mortgage indenture contains certain provisions that restrict the
          amount of common dividends that can be paid by UE. Under this mortgage
          indenture, $31 million of retained earnings was restricted against payment
          of
          common dividends, except those dividends payable in common stock, which
          left
          $1.7 billion of free and unrestricted retained earnings at March 31,
          2006.
 
 The
          ICC
          order approving Ameren’s acquisition of IP contains a provision that gives IP
          the ability to declare and pay $80
          million of dividends on its common stock in 2005 and $160 million of dividends
          on its common stock cumulatively through 2006, provided IP has achieved
          an
          investment-grade credit rating from S&P or Moody’s. If, however, IP’s $550
          million principal amount of 11.50% Series mortgage bonds due 2010 are not
          eliminated by December 31, 2006, IP may not thereafter declare or pay common
          dividends without seeking authority from the ICC. As of March 31, 2006, $33,000
          of the 11.50% Series mortgage bonds due 2010 were outstanding. The bonds
          are
          callable at the end of 2006.
  38
  Genco’s
          and CILCORP’s indentures include provisions that require the companies to
          maintain certain debt service coverage and debt-to-capital ratios in order
          for
          the companies to pay dividends, make certain principal or interest payments,
          make certain loans to affiliates, or incur additional indebtedness. The
          following table summarizes these ratios for the 12 months ended March 31,
          2006:
 
 **Required**
                  **Interest**
                  **Coverage**
                  **Ratio**
                
                **Actual**
                  **Interest**
                  **Coverage**
                  **Ratio**
                
                **Required**
                  **Debt
                    to**
                  **Capital**
                  **Ratio**
                
                **Actual**
                  **Debt
                    to**
                  **Capital**
                  **Ratio**Genco(a)
                
                ≥1.75(c)
                
                
                5.3
                
                
                ≤60
                %
                
                52
                %CILCORP(b)
                
                ≥2.2
                
                
                2.5
                
                
                ≤67
                %
                
                32
                %
 (a)
              Interest
                  coverage ratio relates to covenants regarding certain dividend,
                  principal
                  and interest payments on certain subordinated intercompany borrowings.
                  The
                  debt-to-capital ratio relates to a debt incurrence covenant, which
                  also
                  requires an interest coverage ratio of 2.5 for the most recently
                  ended
                  four fiscal quarters. (b)
              CILCORP
                  must maintain the required interest coverage ratio and debt-to-capital
                  ratio in order to make any payment of dividends or intercompany
                  loans to
                  affiliates other than to its direct or indirect
                  subsidiaries. (c)
              Ratio
                  excludes amounts payable under Genco’s intercompany note to CIPS and must
                  be met for both the prior four fiscal quarters and for the four
                  succeeding
                  six-month periods. 
 In
          order
          for the Ameren Companies to issue securities in the future, they will have
          to
          comply with any applicable tests in effect at the time of any such
          issuances.
 
 **Off-Balance-Sheet
          Arrangements**
 
 At
          March
          31, 2006, none of the Ameren Companies had any off-balance-sheet financing
          arrangements, other than operating leases entered into in the ordinary
          course of
          business. None of the Ameren Companies expect to engage in any significant
          off-balance-sheet financing arrangements in the near future.
 **NOTE
            5** **-
            OTHER INCOME AND EXPENSES**
 The
              following table presents Other Income and Expenses for each of the
              Ameren
              Companies for the three months ended March 31, 2006 and 2005:
 
 **Three
                        Months****2006**
                    
                    **2005****Ameren:****(a)**Miscellaneous
                        income:Interest
                        and dividend income
                    **$**
                    **1**
                    
                    $
                    1Allowance
                        for equity funds used during construction
                    
                    **1**
                    
                    
                    4Other
                    
                    **2**
                    
                    
                    2Total
                        miscellaneous income
                    **$**
                    **4**
                    
                    $
                    7**UE:**Miscellaneous
                        income:Interest
                        and dividend income
                    **$**
                    **1**
                    
                    $
                    -Allowance
                        for equity funds used during construction
                    
                    **1**
                    
                    
                    5Other
                    
                    **1**
                    
                    
                    2Total
                        miscellaneous income
                    **$**
                    **3**
                    
                    $
                    7Miscellaneous
                        expense:Other
                    **$**
                    **(2**
                    **)**
                    $
                    (2
                    )Total
                        miscellaneous expense
                    **$**
                    **(2**
                    **)**
                    $
                    (2
                    )**CIPS:**Miscellaneous
                        income:Interest
                        and dividend income
                    **$**
                    **4**
                    
                    $
                    5Other
                    
                    **1**
                    
                    
                    -Total
                        miscellaneous income
                    **$**
                    **5**
                    
                    $
                    5Miscellaneous
                        expense:Other
                    **$**
                    **(1**
                    **)**
                    $
                    -Total
                        miscellaneous expense
                    **$**
                    **(1**
                    **)**
                    $
                    -**CILCORP:**Miscellaneous
                        expense:Other
                    **$**
                    **(1**
                    **)**
                    $
                    (2
                    )Total
                        miscellaneous expense
                    **$**
                    **(1**
                    **)**
                    $
                    (2
                    )**CILCO:**Miscellaneous
                        expense:Other
                    **$**
                    **(1**
                    **)**
                    $
                    (1
                    )Total
                        miscellaneous expense
                    **$**
                    **(1**
                    **)**
                    $
                    (1
                    )
  39
 
 **Three
                        Months****2006**
                    
                    
                    **2005****IP:**Miscellaneous
                        income:Interest
                        and dividend income
                    **$**
                    **-**
                    
                    $
                    1Other
                    
                    **1**
                    
                    
                    1Total
                        miscellaneous income
                    **$**
                    **1**
                    
                    $
                    2Miscellaneous
                        expense:Other
                    **$**
                    **(1**
                    **)**
                    $
                    -Total
                        miscellaneous expense
                    **$**
                    **(1**
                    **)**
                    $
                    -
 (a)
                    Includes
                        amounts for Ameren registrant and nonregistrant subsidiaries
                        and
                        intercompany eliminations.
  **NOTE
              6 - DERIVATIVE FINANCIAL INSTRUMENTS**
 
 The
              pretax net gain or loss on power forward hedges is included in Operating
              Revenues - Electric, and the pretax net gain or loss on hedges related
              to
              SO 2 emission  allowances,
              fuel or power supply, and natural gas are included in Operating Expenses
              - Fuel
              and Purchased Power. This pretax net gain or loss represents the impact
              of
              discontinued cash flow hedges, the ineffective portion of cash flow
              hedges, and
              the reversal of amounts previously recorded in OCI due to transactions
              going to
              delivery or settlement, resulting in a $3 million
              loss for Ameren, a $1 million loss for Genco, and a $2 million loss
              for IP for
              the quarter ended March 31, 2006 (2005 - $2 million gain for
              Ameren).
 The
                following table presents the carrying value of all derivative instruments
                and
                the amount of pretax net gains (losses) on derivative instruments
                in Accumulated
                OCI for cash flow hedges as of March 31, 2006:
 
 **Ameren**(a)
                      
                      **UE**
                      
                      **CIPS**
                      
                      **Genco**
                      
                      **CILCORP/**
                        **CILCO**
                      
                      **IP**Derivative
                          instruments carrying value:Other
                          assets
                      **$**
                      **45**
                      
                      **$**
                      **5**
                      
                      **$**
                      **7**
                      
                      **$**
                      **-**
                      
                      **$**
                      **24**
                      
                      **$**
                      **6**Other
                          deferred credits and liabilities
                      
                      **15**
                      
                      
                      **8**
                      
                      
                      **1**
                      
                      
                      **-**
                      
                      
                      **-**
                      
                      
                      **4**Gains
                          (losses) deferred in Accumulated OCI:Power
                          forwards and swaps(b)
                      
                      **(1**
                      **)**
                      
                      **-**
                      
                      
                      **-**
                      
                      
                      **1**
                      
                      
                      **-**
                      
                      
                      **(2**
                      **)**Interest
                          rate swaps(c)
                      
                      **4**
                      
                      
                      **-**
                      
                      
                      **-**
                      
                      
                      **4**
                      
                      
                      **-**
                      
                      
                      **-**Gas
                          swaps and futures contracts(d)
                      
                      **31**
                      
                      
                      **4**
                      
                      
                      **6**
                      
                      
                      **-**
                      
                      
                      **23**
                      
                      
                      **-**
 (a)
                    Includes
                        amounts for Ameren registrant and nonregistrant subsidiaries
                        and
                        intercompany eliminations. (b)
                    Represents
                        the mark-to-market value for the hedged portion of electricity
                        price
                        exposure for periods generally less than one year. (c)
                    Represents
                        a gain associated with interest rate swaps at Genco that
                        were a partial
                        hedge of the interest rate on debt issued in June 2002. The
                        swaps cover
                        the first 10 years of debt that has a 30-year maturity and
                        the gain in OCI
                        is amortized over a 10-year period that began in June
                        2002. (d)
                    Represents
                        gains associated with natural gas swaps and futures contracts.
                        The swaps
                        are a partial hedge of our natural gas requirements through
                        March 2008.  **Other
                  Derivatives**
 
 The
                  following table presents the net change in market value as of March
                  31, 2006 and
                  2005, of option and swap transactions used to manage our positions
                  in
                  SO 2 allowances. Certain of these transactions are treated as nonhedge
                  transactions
                  under SFAS No. 133, “Accounting for Derivative Instruments and Hedging
                  Activities.” The net change in the market value of power options is recorded
                  in
                  Operating Revenues - Electric, while the net change in the market
                  value of coal,
                  heating oil and SO 2 options
                  and swaps is recorded as Operating Expenses - Fuel and Purchased
                  Power.
 
 **Three
                            Months****Gains
                            (Losses)**
                        **2006**
                        
                        **2005****SO****2****options and swaps:**Ameren
                        **$**
                        **(1**
                        **)**
                        $
                        (6
                        )UE
                        
                        **3**
                        
                        
                        (1
                        )Genco
                        
                        **(3**
                        **)**
                        
                        (5
                        )
  **NOTE
                  7 -** **RELATED
                  PARTY TRANSACTIONS**
 
 The
                  Ameren Companies have engaged in, and may in the future engage
                  in, affiliate
                  transactions in the normal course of business. These transactions
                  primarily
                  consist of gas and power purchases and sales, services received
                  or rendered, and
                  borrowings and lendings. Transactions between affiliates are reported
                  as
                  intercompany transactions on their financial statements, but are
                  eliminated in
                  consolidation for Ameren’s financial statements. For a discussion of our material related
                  party agreements,
                  see Note 14 - Related Party Transactions under Part II, Item 8
                  of the Ameren
                  Companies’ combined Annual Report on Form 10-K for the fiscal year ended
                  December 31, 2005. Below are updates to several of these related
                  party
                  agreements.
 40


**Electric
          Power Supply Agreements**
 
 The
          following table presents the amount of gigawatthour sales under related
          party
          electric power supply agreements for the three months ended March 31, 2006
          and
          2005:
 
 **Three
                    Months****2006**
                
                **2005**Genco
                    sales toMarketing
                    Company
                
                **5,591**
                
                
                4,900Marketing
                    Companysales
                    to CIPS
                
                **3,079**
                
                
                2,055EEI
                    sales to UE
                
                **-**
                
                
                697EEI
                    sales to CIPS
                
                **-**
                
                
                572EEI
                    sales to IP
                
                **-**
                
                
                413
 
 The
          EEI
          agreement that supplied power to UE, CIPS, and IP expired on December 31,
          2005.
          EEI billed residual amounts under this contract in the first quarter of
          2006 of
          $3 million, $2 million and $1 million to UE, CIPS and IP, respectively.
          EEI
          entered into a new agreement to sell 100% of its capacity and energy to
          Marketing Company through December 31, 2015.
 
 **Joint
          Dispatch Agreement**
 
 UE
          and
          Genco jointly dispatch electric generation under a joint dispatch agreement
          among UE, CIPS and Genco. UE and Genco have the option to serve their load
          requirements from their own generation first, and then each may give its
          affiliates access to any available generation at incremental cost. Any
          excess
          generation not used by UE or Genco to serve load requirements is sold to
          third
          parties on a short-term basis through Ameren Energy, which serves as each
          affiliate’s agent. To allocate power costs between UE and Genco, an intercompany
          sale is recorded by the company sourcing the power to the other company.
          Ameren
          Energy also acts as an agent on behalf of UE and Genco to purchase power
          when
          they require it. The joint dispatch agreement can be terminated by UE,
          CIPS or
          Genco upon one year’s notice, unless terminated earlier by mutual consent.
 
 As
          further discussed in Note 2 - Rate and Regulatory Matters, in March 2006
          FERC
          approved an amendment to the joint dispatch agreement effective January
          10,
          2006, to modify the allocation methodology for profits on short-term sales
          of
          excess generation to third parties between UE and Genco.
  The
          following table presents the amount of gigawatthour sales under the joint
          dispatch agreement for the three months ended March 31, 2006 and
          2005:
 
 **Three
                    Months****2006**
                
                **2005**UE
                    sales to Genco
                
                **2,795**
                
                
                2,948Genco
                    sales to UE
                
                **606**
                
                
                597
  The
          following table presents the short-term power sales margins under the joint
          dispatch agreement for UE and Genco for the three months ended March 31,
          2006
          and 2005:
 
 **Three
                    Months****2006**
                
                
                **2005**UE
                **$**
                **33**
                
                $
                36Genco
                
                **12**
                
                
                20Total
                **$**
                **45**
                
                $
                56
 
 **Money
          Pools**
 
 See
          Note
          3 - Short-term Borrowings and Liquidity for discussion of affiliate borrowing
          arrangements.
 
 **Intercompany
          Promissory Notes**
 
 Genco’s
          subordinated note payable to CIPS associated with the transfer of CIPS’ electric
          generating assets and related liabilities to Genco matures on May 1, 2010.
          Interest income and expense for this note recorded by CIPS and Genco,
          respectively, was $4 million for both the three months ended March 31,
          2006 and
          2005.
 
 UE
          and
          CIPS recorded interest income and expense, respectively, of $1 million
          for the
          three months ended March 31, 2006, related to the $67 million subordinated
          promissory note that CIPS issued to UE in May 2005 as consideration for
          50% of
          UE’s Illinois-based utility assets transferred to CIPS.
 
 The
          average interest rate on CILCORP’s note payable to Ameren was 4.4% for the three
          months ended March 31, 2006 (2005 - 8.2%). CILCORP recorded interest expense
          of
          $2 million for these borrowings for both the three months ended March 31,
          2006
          and 2005.
  41
  The
            following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO,
            and IP
            of related party transactions for the three months ended March 31, 2006
            and
            2005. It is based primarily on the agreements discussed above and in
            Note 14 -
            Related Party Transactions under Part II, Item 8 of the Ameren Companies’
combined Annual Report on Form 10-K for the fiscal year ended December
            31, 2005,
            and the money pool arrangements discussed in Note 3 - Short-term Borrowings
            and
            Liquidity.
 **Agreement**
                    **Financial
                        Statement Line Item**
                    
                    
                    **UE**
                    **CIPS**
                    **Genco**
                    **CILCORP****(a)**
                    **IP****Operating
                        Revenues:**Power
                        supply agreement with Marketing
                    Operating
                        Revenues
                    
                    **2006**
                    
                    **$**
                    **(b**
                    **)**
                    **$**
                    **2**
                    
                    **$**
                    **195**
                    
                    **$**
                    **4**
                    
                    **$**
                    **(b**
                    **)**Company
                    
                    
                    2005
                    
                    
                    (b
                    )
                    
                    9
                    
                    
                    179
                    
                    
                    15
                    
                    
                    (b
                    )Power
                        supply agreement with EEI
                    Operating
                        Revenues
                    
                    2005
                    
                    
                    (c
                    )
                    
                    (b
                    )
                    
                    (c
                    )
                    
                    (b
                    )
                    
                    (b
                    )UE
                        and Genco gas transportation
                    Operating
                        Revenues
                    
                    **2006**
                    
                    
                    **(c**
                    **)**
                    
                    **(b**
                    **)**
                    
                    **(b**
                    **)**
                    
                    **(b**
                    **)**
                    
                    **(b**
                    **)**agreement
                    
                    
                    2005
                    
                    
                    (c
                    )
                    
                    (b
                    )
                    
                    (b
                    )
                    
                    (b
                    )
                    
                    (b
                    )Joint
                        dispatch agreement
                    Operating
                        Revenues
                    
                    **2006**
                    
                    
                    **72**
                    
                    
                    **(b**
                    **)**
                    
                    **19**
                    
                    
                    **(b**
                    **)**
                    
                    **(b**
                    **)**2005
                    
                    
                    41
                    
                    
                    (b
                    )
                    
                    11
                    
                    
                    (b
                    )
                    
                    (b
                    )**Total
                        Operating Revenues**
                    
                    
                    **2006**
                    
                    **$**
                    **72**
                    
                    **$**
                    **2**
                    
                    **$**
                    **214**
                    
                    **$**
                    **4**
                    
                    **$**
                    **(b**
                    **)**2005
                    
                    
                    41
                    
                    
                    9
                    
                    
                    190
                    
                    
                    15
                    
                    
                    (b
                    )**Fuel
                        and Purchased Power:**Joint
                        dispatch agreement
                    Fuel
                        and Purchased
                    
                    **2006**
                    
                    **$**
                    **19**
                    
                    **$**
                    **(b**
                    **)**
                    **$**
                    **72**
                    
                    **$**
                    **(b**
                    **)**
                    **$**
                    **(b**
                    **)**Power
                    
                    2005
                    
                    
                    11
                    
                    
                    (b
                    )
                    
                    41
                    
                    
                    (b
                    )
                    
                    (b
                    )Power
                        supply agreement with Marketing
                    Fuel
                        and Purchased
                    
                    **2006**
                    
                    
                    **(b**
                    **)**
                    
                    **108**
                    
                    
                    **(b**
                    **)**
                    
                    **(c**
                    **)**
                    
                    **(b**
                    **)**Company
                    Power
                    
                    2005
                    
                    
                    2
                    
                    
                    76
                    
                    
                    2
                    
                    
                    3
                    
                    
                    (b
                    )Power
                        supply agreement with EEI
                    Fuel
                        and Purchased Power
                    
                    2005
                    
                    
                    14
                    
                    
                    9
                    
                    
                    (b
                    )
                    
                    (b
                    )
                    
                    7Executory
                        tolling agreement with Medina
                    Fuel
                        and Purchased
                    
                    **2006**
                    
                    
                    **(b**
                    **)**
                    
                    **(b**
                    **)**
                    
                    **(b**
                    **)**
                    
                    **13**
                    
                    
                    **(b**
                    **)**Valley
                    Power
                    
                    2005
                    
                    
                    (b
                    )
                    
                    (b
                    )
                    
                    (b
                    )
                    
                    10
                    
                    
                    (b
                    )UE
                        and Genco gas transportation
                    Fuel
                        and Purchased
                    
                    **2006**
                    
                    
                    **(b**
                    **)**
                    
                    **(b**
                    **)**
                    
                    **(c**
                    **)**
                    
                    **(b**
                    **)**
                    
                    **(b**
                    **)**agreement
                    Power
                    
                    2005
                    
                    
                    (b
                    )
                    
                    (b
                    )
                    
                    (c
                    )
                    
                    (b
                    )
                    
                    (b
                    )**Total
                        Fuel and Purchased Power**
                    
                    
                    **2006**
                    
                    **$**
                    **19**
                    
                    **$**
                    **108**
                    
                    **$**
                    **72**
                    
                    **$**
                    **13**
                    
                    **$**
                    **(b**
                    **)**2005
                    
                    
                    27
                    
                    
                    85
                    
                    
                    43
                    
                    
                    13
                    
                    
                    7**Other
                        Operating Expenses:**Ameren
                        Services support services
                    Other
                        Operating
                    
                    **2006**
                    
                    **$**
                    **33**
                    
                    **$**
                    **11**
                    
                    **$**
                    **5**
                    
                    **$**
                    **12**
                    
                    **$**
                    **17**agreement
                    Expenses
                    
                    2005
                    
                    
                    41
                    
                    
                    11
                    
                    
                    5
                    
                    
                    12
                    
                    
                    (b
                    )Ameren
                        Energy support services agreement
                    Other
                        Operating
                    
                    **2006**
                    
                    
                    **2**
                    
                    
                    **(b**
                    **)**
                    
                    **1**
                    
                    
                    **(b**
                    **)**
                    
                    **(b**
                    **)**Expenses
                    
                    2005
                    
                    
                    1
                    
                    
                    (b
                    )
                    
                    1
                    
                    
                    (b
                    )
                    
                    (b
                    )AFS
                        support services agreement
                    Other
                        Operating
                    
                    **2006**
                    
                    
                    **1**
                    
                    
                    **(c**
                    **)**
                    
                    **1**
                    
                    
                    **(c**
                    **)**
                    
                    **1**Expenses
                    
                    2005
                    
                    
                    1
                    
                    
                    (c
                    )
                    
                    1
                    
                    
                    1
                    
                    
                    (b
                    )**Total
                        Other Operating Expenses**
                    
                    
                    **2006**
                    
                    **$**
                    **36**
                    
                    **$**
                    **11**
                    
                    **$**
                    **7**
                    
                    **$**
                    **12**
                    
                    **$**
                    **18**2005
                    
                    
                    43
                    
                    
                    11
                    
                    
                    7
                    
                    
                    13
                    
                    
                    (b
                    )Money
                        pool borrowings (advances)
                    Interest
                        Income
                    
                    **2006**
                    
                    **$**
                    **-**
                    
                    **$**
                    **(c**
                    **)**
                    **$**
                    **2**
                    
                    **$**
                    **2**
                    
                    **$**
                    **1**(Expenses)
                    
                    2005
                    
                    
                    (c
                    )
                    
                    (c
                    )
                    
                    2
                    
                    
                    1
                    
                    
                    (1
                    )
 (a)
              Amounts
                  represent CILCORP and CILCO
                  activity.
 (b)
              Not
                  applicable.
 (c)
              Amount
                  less than $1 million.
 
 **NOTE
        8 -** **COMMITMENTS
        AND CONTINGENCIES**
  As
          a
          result of issues generated in the course of daily business, we are involved
          in
          legal, tax and regulatory proceedings before various courts, regulatory
          commissions, and governmental agencies, some of which involve substantial
          amounts of money. We believe that the final disposition of these proceedings,
          except as otherwise disclosed in these notes to our financial statements,
          will
          not have an adverse material effect on our results of operations, financial
          position, or liquidity.
 
 Reference
          is made to Note 1 - Summary of Significant Accounting Policies, Note 3
          - Rate
          and Regulatory Matters, Note 14 - Related Party Transactions, and Note
          15 -
          Commitments and Contingencies under Part II, Item 8 of the Ameren Companies’
combined Annual Report on Form 10-K for the fiscal year ended December
          31,
          2005.
  42
 **Callaway
        Nuclear Plant**
 
 The
        following table presents insurance coverage at UE’s Callaway nuclear plant at
        March 31, 2006:
 
 **Type
                  and Source of Coverage**
              **Maximum
                  Coverages**
              **Maximum
                  Assessments for Single Incidents**Public
                  liability:American
                  Nuclear Insurers
              $300
              $-Pool
                  participation
              10,461
              101(a)$10,761(b)
              $101Nuclear
                  worker liability:American
                  Nuclear Insurers
              $300(c)
              $                                                              
                  4Property
                  damage:Nuclear
                  Electric Insurance Ltd.
              2,750(d)
              21Replacement
                  power:Nuclear
                  Electric Insurance Ltd.
              490(e)
              7
 (a)
              Retrospective
                  premium under the Price-Anderson liability provisions of the Atomic
                  Energy
                  Act of 1954, as amended. Thisis
                  subject to retrospective assessment with respect to a covered loss
                  in
                  excess of $300 million from an incident at any licensed U.S. commercial
                  reactor, payable at $15 million per year. Renewal of Price-Anderson
                  was
                  part of the Energy Policy Act of 2005.
 (b)
              Limit
                  of liability for each incident under
                  Price-Anderson.
 (c)
              Industry
                  limit for potential liability from workers claiming exposure to
                  the
                  hazards of nuclear radiation.
 (d)
              Includes
                  premature decommissioning costs.
 (e)
              Weekly
                  indemnity of $4.5 million for 52 weeks, which commences after the
                  first
                  eight weeks of an outage, plus $3.6 million per week for 71.1 weeks
                  thereafter.
  Price-Anderson
          limits the liability for claims from an incident involving any licensed
          United
          States nuclear facility. The limit is based on the number of licensed reactors
          and is adjusted at least every five years to reflect changes in the  Consumer
          Price Index. Utilities owning a nuclear reactor cover this exposure through
          a
          combination of private insurance and mandatory participation in a financial
          protection pool, as established by Price-Anderson.
 
 If
          losses
          from a nuclear incident at the Callaway nuclear plant exceed the limits
          of, or
          are not subject to, insurance, or if coverage is unavailable, UE is at
          risk for
          any uninsured losses. If a serious nuclear incident occurred, it could
          have a
          material but indeterminable adverse effect on our results of operations,
          financial position, or liquidity.
 **Operating
          Leases**
 
 As
        of
        March 31, 2006, certain operating lease obligations have increased from amounts
        previously disclosed as of December 31, 2005. The following table presents
        our
        operating lease obligations at March 31, 2006:
 
 **Total**
              
              **Less
                  than 1 Year**
              
              **1
                  - 3 Years**
              
              **3
                  - 5 Years**
              
              **After
                  5 Years**Ameren(a)(b)
              $
              446
              
              $
              40
              
              $
              70
              
              $
              56
              
              $
              280UE(b)
              
              207
              
              
              14
              
              
              28
              
              
              27
              
              
              138CIPS(b)
              
              2
              
              
              -
              
              
              1
              
              
              1
              
              
              -Genco(b)
              
              169
              
              
              8
              
              
              17
              
              
              17
              
              
              127CILCORP/CILCO(b)
              
              21
              
              
              1
              
              
              3
              
              
              2
              
              
              15IP
              
              18
              
              
              5
              
              
              7
              
              
              6
              
              
              -
 (a)
              Includes
                  amounts for Ameren registrant and nonregistrant subsidiaries and
                  intercompany eliminations.
 (b)
              Amounts
                  related to certain real estate leases and railroad licenses have
                  indefinite payment periods. The amounts for these items are included
                  in
                  the Less than 1 Year, 1 - 3 Years, and 3 - 5 Years columns, but
                  are not
                  included in the After 5 Years or Total columns because of the indefinite
                  lease terms. The estimated annual obligation for these
                  indefinite-term
                  leases for Ameren and UE is $2 million and $1 million, respectively,
                  and
                  less than $1 millionindividuallyfor CIPS, CILCORP and CILCO.
 
 **Other
        Obligations**
 
 To
        supply
        a portion of the fuel requirements of our generating plants, we have entered
        into various long-term commitments for the procurement of coal, natural gas
        and
        nuclear fuel. In addition, we have entered into various long-term commitments
        for the purchase of electricity and natural gas for distribution. For a complete
        listing of our obligations and commitments, see Contractual Obligations under
        Part II, Item 7 and Note 15 - Commitments and Contingencies under Part II,
        Item
        8 of the Ameren Companies’ combined Annual Report on Form 10-K for the fiscal
        year ended December 31, 2005.
  43
  As
        of
        March 31, 2006, the commitments for the procurement of coal have changed
        from
        amounts previously disclosed as of December 31, 2005. The following table
        presents the total estimated coal purchase commitments at March 31, 2006:
 
 **2006**
                
                **2007**
                
                **2008**
                
                **2009**
                
                **2010**
                
                **Thereafter****(a)**Ameren(b)
                **$**
                **598**
                
                $
                493
                
                $
                499
                
                $
                381
                
                $
                215
                
                $
                77UE
                
                **339**
                
                
                285
                
                
                250
                
                
                201
                
                
                147
                
                
                77Genco
                
                **125**
                
                
                94
                
                
                148
                
                
                130
                
                
                36
                
                
                -CILCORP/CILCO
                
                **60**
                
                
                40
                
                
                34
                
                
                24
                
                
                15
                
                
                -
 (a)
                Commitments
                    for coal are until 2011.
 (b)
                Includes
                    amounts for Ameren registrant and nonregistrant subsidiaries
                    and
                    intercompany eliminations.
 
 As
          of
          March 31, 2006, the commitments for the procurement of natural gas have
          changed
          from amounts previously disclosed as of December 31, 2005. The following
          table
          presents the total estimated natural gas purchase commitments at March
          31, 2006:
 
 **2006**
                
                **2007**
                
                **2008**
                
                **2009**
                
                **2010**
                
                **Thereafter****(a)**Ameren(b)
                **$**
                **524**
                
                $
                511
                
                $
                361
                
                $
                209
                
                $
                123
                
                $
                212UE
                
                **77**
                
                
                53
                
                
                43
                
                
                34
                
                
                27
                
                
                35CIPS
                
                **91**
                
                
                116
                
                
                87
                
                
                58
                
                
                39
                
                
                107Genco
                
                **16**
                
                
                25
                
                
                20
                
                
                8
                
                
                8
                
                
                12CILCORP/CILCO
                
                **137**
                
                
                150
                
                
                97
                
                
                51
                
                
                19
                
                
                33IP
                
                **184**
                
                
                158
                
                
                112
                
                
                57
                
                
                28
                
                
                25
 (a)
                Commitments
                    for natural gas are until 2016.
 (b)
                Includes
                    amounts for Ameren registrant and nonregistrant subsidiaries
                    and
                    intercompany eliminations.
  **Environmental
          Matters**
 
 We
          are
          subject to various environmental laws and regulations by federal, state
          and
          local authorities. From the beginning phases of siting and development
          to the
          ongoing operation of existing or new electric generating, transmission
          and
          distribution facilities, and natural gas storage plants, transmission and
          distribution facilities, our activities involve compliance with diverse
          laws and
          regulations. These laws and regulations address noise, emissions, and impacts
          to
          air and water, protected and cultural resources (such as wetlands, endangered
          species, and archeological and historical resources), and chemical and
          waste
          handling. Our activities often require complex and lengthy processes as
          we
          obtain approvals, permits or licenses for new, existing or modified facilities.
          Additionally, the use and handling of various chemicals or hazardous materials
          (including wastes) requires preparation of release prevention plans and
          emergency response procedures. As new laws or regulations are promulgated,
          we
          assess their applicability and implement the necessary modifications to
          our
          facilities or our operations, as required. The more significant matters
          are
          discussed below.
 
 ***Clean
          Air Act***
  In
          May
          2005, the EPA issued final regulations with respect to SO 2 and
          NO x emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean
          Air
          Mercury Rule) from coal-fired power plants. The new rules will require
          significant reductions in these emissions from UE, Genco, CILCO and EEI
          power
          plants in phases, beginning in 2009. States are required to finalize rules
          to
          implement the federal Clean Air Interstate Rule and Clean Air Mercury Rule
          by
          September and November 2006, respectively. While the federal
          rules mandate a specific emissions cap for SO 2 ,
          NO x ,
          and
          mercury emissions by state from utility boilers, the states have considerable
          flexibility in allocating emission allowances to individual utility boilers.
          In
          addition, a state may choose to hold back certain emission allowances for
          growth
          or other reasons, and it may implement a more stringent program than the
          federal
          program. Illinois and Missouri are developing proposed rules that will
          be
          subjected to public review and comment. We do not expect the state regulations
          to be finalized until late 2006. In January 2006, the Illinois governor
          recommended that the Illinois EPA adopt rules for mercury significantly
          stricter
          than the federal rules. The process by which state rules will be drafted
          and
          determined is still in its early stages, but should stricter rules be adopted,
          they would change the overall environmental compliance strategy for UE’s,
          Genco’s, CILCO’s and EEI’s coal-fired power plants and increase or accelerate
          related costs from previous estimates. An implementation plan from Missouri
          regulators is still under review and consideration. The table below presents
          preliminary estimated capital costs based on current technology to comply
          with
          the federal Clean Air Interstate Rule and Clean Air Mercury  Rule.
          The
          timing of estimated capital costs between periods at UE will be influenced
          by
          whether excess emission credits are used to comply with the proposed rules,
          thereby deferring capital investment.
 
 **2006**
                
                **2007
                    - 2010**
                
                **2011
                    - 2016**
                
                **Total**Ameren(a)
                **$**
                **75**
                
                $
                1,020 -1,405
                
                $
                1,015
                    -1,400
                
                $
                2,110 -2,880UE
                
                **60**
                
                
                365 -   505
                
                
                750 -1,040
                
                
                1,175 -1,605Genco
                
                **10**
                
                
                430 -595
                
                
                10 -20
                
                
                450 -625CILCO
                
                **5**
                
                
                175
                    -245
                
                
                145
                    -200
                
                
                325 -450EEI
                
                **5**
                
                
                55 -75
                
                
                130 -180
                
                
                190 -260
 (a)
                Includes
                    80% of EEI.
 
  44
  The
              costs
              reflected in the table assume that each Ameren generating unit will
              be allocated
              allowances based on the model “cap and trade” rule guidelines issued by the EPA.
              Should either Missouri or Illinois develop alternative allowance allocations
              for
              utility units, the cost impact could be material. At this time, we
              are unable to
              determine the impact such a state action would have on our results
              of
              operations, financial position, or liquidity.
 
 ***Emission
          Credits***
 
 Both
          federal and state laws require significant reductions in SO 2 and
          NO x emissions that result from burning fossil fuels. The Clean Air Act and
          NO x Budget
          Trading Program created marketable commodities called allowances. Currently
          each
          allowance gives the owner the right to emit one ton of SO 2 or
          NO x .
          All
          existing generating facilities have been allocated allowances that are
          based on
          past production and the statutory emission reduction goals. If additional
          allowances are needed for new generating facilities, they can be purchased
          from
          facilities that have excess allowances or from allowance banks. Our generating
          facilities comply with the SO 2 limits
          through the use and purchase of allowances, through the use of low-sulfur
          fuels,
          and through the application of pollution control technology. The NO x Budget
          Trading Program limits emissions of NO x during
          the ozone season (May through September). The NO x Budget
          Trading Program has applied to all electric generating units in Illinois
          since
          the beginning of 2004; it will apply to the eastern third of Missouri,
          where
          UE’s coal-fired power plants are located, beginning in 2007. Our generating
          facilities are expected to comply with the NO x limits
          through the use and purchase of allowances or through the application of
          pollution control technology, including low-NO x burners,
          over-fire air systems, combustion optimization, rich reagent injection,
          selective noncatalytic reduction and selective catalytic reduction
          systems.
 
 As
          of
          March 31, 2006, UE, Genco, CILCO and EEI held 1.89 million, 0.70 million,
          0.34
          million and 0.36 million, respectively, of SO 2 emission
          allowances, with vintages from 2006 to 2016. Each company possesses additional
          allowances for use in periods beyond 2016. As of March 31, 2006, UE, Genco,
          CILCO, and EEI Illinois facilities held 249, 11,975, 2,178, and 2,859,
          respectively, of NO X emission
          allowances, with vintages from 2006 to 2008. As of March 31, 2006, the
          SO 2 and
          NO x emission
          allowances for UE, Genco, CILCO and EEI were carried as intangible assets
          at a
          book value of $63 million, $96 million, $64 million and $41 million,
          respectively. The Illinois EPA has not yet issued any NO x emission
          allowance allocations for 2007 and 2008. UE, Genco, CILCO and EEI expect
          to use
          a substantial portion of the SO 2 and
          NO x allowances for ongoing operations. Allocations of NO x allowances for Missouri facilities will be 10,178 per season in 2007 and
          2008 according to rules finalized in May 2005. New environmental regulations,
          including the Clean Air Interstate Rule, the timing of the installation
          of
          pollution control equipment and the level of operations will have a significant
          impact on the amount of allowances actually required for ongoing operations.
          The
          Clean Air Interstate Rule requires a reduction in SO 2 emissions by requiring a change in the way Acid Rain Program allowances
          are
          surrendered. The current Acid Rain Program requires the surrender of one
          SO 2 allowance for every ton of SO 2 that is
          emitted. The Clean Air Interstate Rule program will require that SO 2 allowances be surrendered at a ratio of two allowances for every ton of
          emission
          in 2010 through 2014. Beginning in 2015, the Clean Air Interstate Rule
          program
          will require SO 2 allowances to be surrendered at a ratio of 2.86 allowances for every ton
          of
          emission.
  ***New
          Source Review***
  The
          EPA
          has been conducting an enforcement initiative in an effort to determine
          whether
          modifications at a number of coal-fired power plants owned by electric
          utilities
          in the United States are subject to New Source Review requirements or New
          Source
          Performance Standards under the Clean Air Act. The EPA’s inquiries focus on
          whether the best available emission control technology was or should have
          been
          used at such power plants when major maintenance or capital improvements
          were
          performed.
  In
          April
          2005, Genco received a request from the EPA for information pursuant to
          Section
          114(a) of the Clean Air Act seeking detailed operating and maintenance
          history
          data with respect to its Meredosia, Hutsonville, Coffeen, and Newton facilities,
          EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. All of
          these facilities are coal-fired power plants. The information request required
          Genco to provide responses to specific EPA questions regarding certain
          projects
          and maintenance activities to determine compliance with certain Illinois
          air
          pollution and emissions rules and with the New Source Performance Standard
          requirements of the Clean Air Act. This information request is being complied
          with, but we cannot predict the outcome of this matter.
 
 ***Remediation***
 
 We
          are
          involved in a number of remediation actions to clean up hazardous waste
          sites as
          required by federal and state law. Such statutes require that responsible
          parties fund remediation actions regardless of degree of fault, legality
          of
          original disposal, or ownership of a disposal site. UE, CIPS, CILCO and
          IP have
          each been identified by the federal or state governments as a potentially
          responsible party at several contaminated sites. Several of these sites
          involve
          facilities that were transferred by CIPS to Genco in May 2000 and facilities
          transferred by CILCO to AERG in October 2003. As part of each transfer,
          CIPS or
          CILCO has contractually agreed to indemnify Genco or AERG for remediation
          costs
          associated with preexisting environmental contamination at the transferred
          sites.
  45
 As
              of
              March 31, 2006, CIPS, CILCO and IP owned or were otherwise responsible
              for 14,
              four and 25 former MGP sites, respectively, in Illinois. All of these
              sites are
              in various stages of investigation, evaluation and remediation. Under
              its
              current schedule, Ameren anticipates that remediation at these sites
              should be
              completed by 2015. The ICC permits each company to recover remediation
              and
              litigation costs associated with their former MGP sites in Illinois
              from their
              Illinois electric and natural gas utility customers through environmental
              adjustment rate riders. To be recoverable, such costs must be prudently
              and
              properly incurred, and costs are subject to annual reconciliation review
              by the
              ICC. As of March 31, 2006, CIPS, CILCO and IP had recorded liabilities
              of $25
              million, $3 million and $62 million, respectively, to represent estimated
              minimum obligations.
 
 In
              addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri
              and
              one in Iowa. UE does not currently have a rate rider mechanism in effect
              in
              Missouri that permits remediation costs associated with MGP sites to
              be
              recovered from utility customers. See Note 2 - Rate and Regulatory
              Matters for
              information on a recently enacted law in Missouri enabling the MoPSC
              to put in
              place environmental cost recovery mechanisms for Missouri utilities.
              UE does not
              have any retail utility operations in Iowa which would provide a source
              of
              recovery of these remediation costs. Because of the unknown and unique
              characteristics of each site (such as amount and type of residues present,
              physical characteristics of the site, and the environmental risk) and
              uncertain
              regulatory requirements, we are not able to determine the maximum liability
              for
              the remediation of these sites. As of March 31, 2006, UE had recorded
              $10
              million to represent its estimated minimum obligation for MGP sites.
              UE also is
              responsible for four electric sites in Missouri that have corporate
              cleanup
              liability, most as a result of federal agency mandates. As of March
              31, 2006, UE
              had recorded $5 million to represent its estimated minimum obligation
              for these
              sites. At this time, we are unable to determine what portion of these
              costs, if
              any, will be eligible for recovery from insurance carriers.
 In
          June
          2000, the EPA notified UE and numerous other companies that former landfills
          and
          lagoons in Sauget, Illinois, may contain soil and groundwater contamination.
          These sites are known as Sauget Area 2. From approximately 1926 until 1976,
          UE
          operated a power generating facility adjacent to Sauget Area 2. UE currently
          owns a parcel of property that was used as a landfill. Under the terms
          of an
          Administrative Order and Consent, UE has joined with other potentially
          responsible parties to evaluate the extent of potential contamination with
          respect to Sauget Area 2.
 
 In
          October 2002, UE was included in a Unilateral Administrative Order issued
          by the
          EPA listing potentially liable parties for groundwater contamination for
          a
          portion of the Sauget Area 2 site. The Unilateral Administrative Order
          encompasses the groundwater contamination releasing to the Mississippi
          River
          adjacent to Solutia’s former chemical waste landfill and the resulting impact
          area in the Mississippi River. UE was asked to participate in response
          to
          activities that involve the installation of a barrier wall around a chemical
          waste site and three recovery wells to divert groundwater flow. The projected
          cost for this remedy method ranges from $25 million to $30 million. In
          November
          2002, UE sent a letter to the EPA asserting its defenses to the Unilateral
          Administrative Order and requesting its removal from the list of potentially
          responsible parties under the Unilateral Administrative Order. Solutia
          agreed to
          comply with the Unilateral Administrative Order. However, in December 2003,
          Solutia filed for bankruptcy protection and it is now seeking to discharge
          its
          environmental liabilities. In March 2004, Pharmacia Corporation, the former
          parent company of Solutia, confirmed its intent to comply with the EPA’s
          Unilateral Administrative Order.
 
 The
          status of future remediation at Sauget Area 2 and compliance with the Unilateral
          Administrative Order is uncertain, so we are unable to predict the ultimate
          impact of the Sauget Area 2 site on our results of operations, financial
          position, or liquidity. In December 2004, the U.S. Supreme Court, in Cooper
          Industries, Inc., vs. Aviall Services, Inc., limited the circumstances
          under
          which potentially responsible parties could assert cost-recovery claims
          against
          other potentially responsible parties. As a result of this ruling, it is
          possible that UE may not be able to recover from other potentially responsible
          parties the costs it incurs in complying with EPA orders. Any liability
          or
          responsibility that may be imposed on UE as a result of this Sauget, Illinois,
          environmental matter was not transferred to CIPS as a part of UE’s May 2005
          Illinois utility service territory transfer to CIPS.
 
 In
          December 2004, AERG submitted a comprehensive package to the Illinois EPA
          to
          address groundwater and surface water issues associated with the recycle
          pond,
          ash ponds, and reservoir at the Duck Creek power plant facility. Information
          submitted by AERG is currently under review by the Illinois EPA. CILCORP
          and
          CILCO both have a liability of $3 million at March 31, 2006, included on
          their
          Consolidated Balance Sheets for the estimated cost of the remediation effort,
          which involves treating and discharging recycle-system water in order to
          address
          these groundwater and surface water issues.
 
 In
          addition, our operations, or those of our predecessor companies, involve
          the
          use, disposal and, in appropriate circumstances, the cleanup of substances
          regulated under environmental protection laws. We are unable to determine
          the
          impact these activities may have on our results of operations, financial
          position, or liquidity.
  46
  ***Pumped-storage
          Hydroelectric Facility Breach***
  In
          December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk
          pumped-storage hydroelectric facility. This resulted in significant flooding
          in
          the local area, which damaged a state park. The incident is being investigated
          by FERC and state authorities. UE expects the results of these reviews
          later in
          2006. Preliminary reports issued by outside experts hired by UE to review
          the
          cause of the incident and by FERC staff, indicate design, construction
          and human
          error as causes of the breach. In their report, UE’s outside experts concluded
          that restoration of the upper reservoir, if undertaken, will require a
          complete
          rebuild of the entire dam with a completely different design concept, not
          simply
          a repair of the breached area. We expect that these reports will be considered
          in the final report issued by FERC. The facility will remain out of service
          until reviews by FERC and state authorities are concluded, further analyses
          are
          completed, and input is received from key stakeholders as to how and whether
          to
          rebuild the facility. Should the decision be made to rebuild the Taum Sauk
          plant, UE would expect it to be out of service through most, if not all,
          of
          2008.
 
 UE has accepted responsibility for the effects of the incident. At this
          time, UE
          believes that substantially all of the damage and liabilities caused by
          the
          breach will be covered by insurance. UE expects the total cost for damage
          and
          liabilities resulting from the Taum Sauk incident to range from $53 million
          to
          $73 million. As of March 31, 2006, UE had paid $18 million and accrued
          a $35
          million liability, while expensing $1 million for the insurance deductible
          and
          recording a $52 million receivable due from insurance companies. No amounts
          have
          been recognized in the financial statements relating to estimated costs
          to
          repair or rebuild the facility. Under UE’s insurance policies, all claims by or
          against UE are subject to review by its insurance carriers.
  As
          a
          result of this breach, UE may be subject to litigation by private parties
          or by
          state or federal authorities. Until the reviews conducted by state and
          federal
          authorities have concluded, the insurance review is completed, a decision
          whether the plant will be rebuilt is made and future regulatory treatment
          for
          the plant is determined, among other things, we are unable to determine
          the
          impact the breach may have on Ameren’s and UE’s results of operations, financial
          position, or liquidity beyond those amounts already accrued.
 
 **Asbestos-related
          Litigation**
  Ameren,
          UE, CIPS, Genco, CILCO and IP have been named, along with numerous other
          parties, in a number of lawsuits filed by plaintiffs claiming varying degrees
          of
          injury from asbestos exposure. Most have been filed in the Circuit Court
          of
          Madison County, Illinois. The total number of defendants named in each
          case is
          significant; as many as 129 parties are named in some pending cases and
          as few
          as six in others. However, in the cases that were pending as of March 31,
          2006,
          the average number of parties is 65.
 
 The
          claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury
          from
          asbestos exposure during the plaintiffs’ activities at our present or former
          electric generating plants. Former CIPS plants are now owned by Genco,
          and most
          former CILCO plants are now owned by AERG. Most of IP’s plants were transferred
          to a Dynegy subsidiary prior to Ameren’s acquisition of IP. As a part of the
          transfer of ownership of the CIPS and CILCO generating plants, CIPS or
          CILCO has
          contractually agreed to indemnify Genco or AERG for liabilities associated
          with
          asbestos-related claims arising from activities prior to the transfer.
          Each
          lawsuit seeks unspecified damages in excess of $50,000, which, if proved,
          typically would be shared among the named defendants.
  From
          January 1, 2006, through March 31, 2006, seven additional asbestos-related
          lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the Circuit
          Court
          of Madison County, Illinois. Three lawsuits were dismissed and three were
          settled. The following table presents the status as of March 31, 2006,
          of the
          asbestos-related lawsuits that have been filed against the Ameren
          Companies:
 
 
 **Specifically
                    Named as Defendant****Total****(a)**
                
                **Ameren**
                
                **UE**
                
                **CIPS**
                
                **Genco**
                
                **CILCO**
                
                **IP**Filed
                
                303
                
                
                30
                
                
                161
                
                
                121
                
                
                2
                
                
                32
                
                
                141Settled
                
                93
                
                
                -
                
                
                48
                
                
                38
                
                
                -
                
                
                9
                
                
                47Dismissed
                
                140
                
                
                22
                
                
                91
                
                
                46
                
                
                2
                
                
                4
                
                
                62Pending
                
                70
                
                
                8
                
                
                22
                
                
                37
                
                
                -
                
                
                19
                
                
                32
 (a)
                Addition
                    of the numbers in the individual columns does not equal the total
                    column
                    because some of the lawsuits name multiple Ameren entities as
                    defendants.
 
 As
          of
          March 31, 2006, five asbestos-related lawsuits were pending against EEI.
          The
          general liability insurance maintained by EEI provides coverage with respect
          to
          liabilities arising from asbestos-related claims.
 
 The
          ICC
          order approving Ameren’s acquisition of IP effective September 30, 2004, also
          approved a tariff rider to recover the costs of IP’s asbestos-related litigation
          claims, subject to the following terms. Beginning in 2007, 90% of cash
          expenditures in excess of the amount included in base electric rates will
          be
          recovered by IP from a $20 million trust fund established by IP and
  47
  financed
            with contributions of $10 million each by Ameren and Dynegy. If cash
            expenditures are less than the amount in base rates, IP will contribute
            90% of
            the difference to the fund. Once the trust fund is depleted, 90% of allowed
            cash
            expenditures in excess of base rates will be recovered through charges
            assessed
            to customers under the tariff rider.
 
 The
          Ameren Companies believe that the final disposition of these proceedings
          will
          not have a material adverse effect on their results of operations, financial
          position, or liquidity.
 
 **NOTE
          9 - CALLAWAY NUCLEAR PLANT**
 
 Under
          the
          Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent
          storage and disposal of spent nuclear fuel. The DOE currently charges one
          mill,
          or 1 / 10 of one
          cent, per nuclear-generated kilowatthour sold for future disposal of spent
          fuel.
          Pursuant to this act, UE collects one mill from its electric customers
          for each
          kilowatthour of electricity that it generates and sells from its Callaway
          nuclear plant. Electric utility rates charged to customers provide for
          recovery
          of such costs. The DOE is not expected to have its permanent storage facility
          for spent fuel available until at least 2015. UE has sufficient installed
          storage capacity at its Callaway nuclear plant until 2020. It has the capability
          for additional storage capacity through the licensed life of the plant.
          The
          delayed availability of the DOE’s disposal facility is not expected to adversely
          affect the continued operation of the Callaway nuclear plant through its
          currently licensed life.
 
 Electric
          utility rates charged to customers provide for the recovery of the Callaway
          nuclear plant’s decommissioning costs, which include decontamination,
          dismantling, and site restoration costs, over an assumed 40-year life of
          the
          plant, ending with the expiration of the plant’s operating license in 2024. It
          is assumed that the Callaway nuclear plant site will be decommissioned
          based on
          immediate dismantlement method and removal from service. Ameren and UE
          have
          recorded an ARO for the Callaway nuclear plant decommissioning costs at
          fair
          value, which represents the present value of estimated future cash outflows.
          Decommissioning costs are charged to the costs of service used to establish
          electric rates for UE’s customers. These costs amounted to $7 million in each of
          the years 2005, 2004 and 2003. Every three years, the MoPSC requires UE
          to file
          an updated cost study for decommissioning its Callaway nuclear plant. Electric
          rates may be adjusted at such times to reflect changed estimates. The latest
          study was filed in 2005. Costs collected from customers are deposited in
          an
          external trust fund to provide for the Callaway nuclear plant’s decommissioning.
          If the assumed return on trust assets is not earned, we believe that it
          is
          probable that any such earnings deficiency will be recovered in rates.
          The fair
          value of the nuclear decommissioning trust fund for UE’s Callaway nuclear plant
          is reported in Nuclear Decommissioning Trust Fund in Ameren’s and UE’s
          Consolidated Balance Sheets. This amount is legally restricted. It may
          be used
          only to fund the costs of nuclear decommissioning. Changes in the fair
          value of
          the trust fund are recorded as an increase or decrease to the nuclear
          decommissioning trust fund and to a regulatory asset.
  **NOTE
          10** **-** **** **OTHER
          COMPREHENSIVE INCOME**
 
 Comprehensive
          income includes net income as reported on the statements of income and
          all other
          changes in common stockholders’ equity, except those resulting from transactions
          with common shareholders. A reconciliation of net income to comprehensive
          income
          for the three months ended March 31, 2006 and 2005, is shown below for
          the
          Ameren Companies:
 
 **2006**
                
                **2005****Ameren:****(a)**Net
                    income
                **$**
                **70**
                
                $
                121Unrealized
                    gain (loss) on derivative hedging instruments, net of taxes (benefit)
                    of
                    $(10) and $15, respectively
                
                **(15**
                **)**
                
                17Reclassification
                    adjustments for (gains) included in net income, net of taxes
                    of $3 and $-,
                    respectively
                
                **(5**
                **)**
                
                -Total
                    comprehensive income, net of taxes
                **$**
                **50**
                
                $
                138**UE:**Net
                    income
                **$**
                **51**
                
                $
                57Unrealized
                    gain (loss) on derivative hedging instruments, net of taxes (benefit)
                    of
                    $(1) and $2, respectively
                
                **(2**
                **)**
                
                3Reclassification
                    adjustments for (gains) included in net income, net of taxes
                    of $1 and $-,
                  respectively
                
                **(1**
                **)**
                
                -Total
                    comprehensive income, net of taxes
                **$**
                **48**
                
                $
                60**CIPS:**Net
                    income (loss)
                **$**
                **(1**
                **)**
                $
                8Unrealized
                    gain (loss) on derivative hedging instruments, net of taxes (benefit)
                    of
                    $(2) and $3,
                  respectively
                
                **(2**
                **)**
                
                6Reclassification
                    adjustments for (gains) included in net income, net of taxes
                    of $1 and $
                    -, respectively
                
                **(2**
                **)**
                
                -Total
                    comprehensive income, net of taxes
                **$**
                **(5**
                **)**
                $
                14
  48
 
 **2006**
                
                
                **2005****Genco:**Net
                    income
                **$**
                **6**
                
                $
                31Unrealized
                    (loss) on derivative hedging instruments, net of taxes of $-
                    and $ -,
                    respectively
                
                **-**
                
                
                (1
                )Reclassification
                    adjustments for losses included in net income, net of taxes of
                    $- and $-,
                    respectively
                
                **1**
                
                
                -Total
                    comprehensive income, net of taxes
                **$**
                **7**
                
                $
                30**CILCORP:**Net
                    income
                **$**
                **8**
                
                $
                9Unrealized
                    gain (loss) on derivative hedging instruments, net of taxes (benefit)
                    of
                    $(5) and $8,
                  respectively
                
                **(7**
                **)**
                
                15Reclassification
                    adjustments for (gains) included in net income, net of taxes
                    of $3 and $-,
                    respectively
                
                **(4**
                **)**
                
                -Total
                    comprehensive income, net of taxes
                **$**
                **(3**
                **)**
                $
                24**CILCO:**Net
                    income
                **$**
                **17**
                
                $
                16Unrealized
                    gain (loss) on derivative hedging instruments, net of taxes (benefit)
                    of
                    $(5) and $8, respectively
                
                **(7**
                **)**
                
                13Reclassification
                    adjustments for (gains) included in net income, net of taxes
                    of $3 and $-,
                  respectively
                
                **(4**
                **)**
                
                -Total
                    comprehensive income, net of taxes
                **$**
                **6**
                
                $
                29**IP:**Net
                    income
                **$**
                **4**
                
                $
                22Unrealized
                    (loss) on derivative hedging instruments, net of taxes (benefit)
                    of $(1)
                    and $ -,
                  respectively
                
                **(1**
                **)**
                
                -Reclassification
                    adjustments for losses included in net income, net of taxes (benefit)
                    of
                    $(1) and $-,
                  respectively
                
                **1**
                
                
                -Total
                    comprehensive income, net of taxes
                **$**
                **4**
                
                $
                22
 (a)
                Includes
                    amounts for Ameren registrant and nonregistrant subsidiaries
                    and
                    intercompany eliminations.
  **NOTE
          11** **-
          RETIREMENT BENEFITS**
  Ameren’s
          pension plans are funded in compliance with income tax regulations and
          federal
          funding requirements. Based on our assumptions at December 31, 2005, and
          assuming continuation of the recently expired federal interest rate relief
          beyond 2006, in order to maintain minimum funding levels for Ameren’s pension
          plans, we do not expect future contributions to be required until 2011
          at which
          time we would expect a required contribution of $100 million to $150 million.
          If
          federal interest rate relief is not continued in its most recent form,
          $200
          million to $300 million may need to be funded in 2009 to 2010 based on
          other
          recent federal legislative proposals. These amounts are estimates. They
          may
          change with actual stock market performance, changes in interest rates,
          any
          pertinent changes in government regulations, and any voluntary
          contributions.
 
 The
          following table presents the components of the net periodic benefit cost
          for our
          pension and postretirement benefit plans for the three months ended March
          31,
          2006 and 2005:
 
 **Pension
                    Benefits****(a)**
                
                **Postretirement
                    Benefits****(a)****2006**
                
                **2005**
                
                **2006**
                
                **2005**Service
                    cost
                **$**
                **16**
                
                $
                15
                
                **$**
                **6**
                
                $
                6Interest
                    cost
                
                **43**
                
                
                42
                
                
                **18**
                
                
                19Expected
                    return on plan assets
                
                **(49**
                **)**
                
                (46
                )
                
                **(12**
                **)**
                
                (12
                )Amortization
                    of:Prior
                    service cost
                
                **2**
                
                
                2
                
                
                **(1**
                **)**
                
                (1
                )Actuarial
                    loss
                
                **11**
                
                
                10
                
                
                **10**
                
                
                10Net
                    periodic benefit cost
                **$**
                **23**
                
                $
                23
                
                **$**
                **21**
                
                $
                22
 (a)
                Includes
                    amounts for Ameren registrant and nonregistrant
                    subsidiaries.
 
 UE,
          CIPS,
          Genco, CILCORP, CILCO and IP are participants in Ameren’s plans and are
          responsible for their proportional share of the pension and postretirement
          costs. The following table presents the pension costs and the postretirement
          benefit costs incurred for the three months ended March 31, 2006 and 2005:
 
 **Pension
                    Costs**
                
                **Postretirement
                    Costs****2006**
                
                
                **2005**
                
                
                **2006**
                
                
                **2005**UE
                **$**
                **13**
                
                $
                13
                
                **$**
                **11**
                
                $
                11CIPS
                
                **3**
                
                
                3
                
                
                **3**
                
                
                3Genco
                
                **2**
                
                
                2
                
                
                **1**
                
                
                1CILCORP
                
                **2**
                
                
                3
                
                
                **3**
                
                
                4CILCO
                
                **3**
                
                
                4
                
                
                **5**
                
                
                6IP
                
                **2**
                
                
                2
                
                
                **4**
                
                
                3
  49
 **NOTE
                12 -** **SEGMENT
                INFORMATION** ****
 
 Ameren’s
                reportable segment Utility Operations comprises its electric generation
                and
                electric and gas transmission and distribution operations. It includes
                the
                operations of UE, CIPS, Genco, CILCORP, CILCO and IP. Ameren’s reportable
                segment Other consists of the parent holding company, Ameren Corporation.
 The
              accounting policies for segment data are the same as those described
              in Note 1 -
              Summary of Significant Accounting Policies. Segment data includes intersegment
              revenues, as well as a charge for allocating costs of administrative
              support
              services to each of the operating companies, which in each case is
              eliminated
              upon consolidation. Ameren Services allocates administrative support
              services
              based on various factors, such as head count, number of customers,
              and total
              assets.
  The
              following table presents information about the reported revenues and
              net income
              of Ameren for the three months ended March 31, 2006 and 2005:
 **Utility
                          Operations**
                      
                      **Other**
                      
                      **Reconciling
                          Items****(a)**
                      
                      **Total****2006:**Operating
                          revenues
                      **$**
                      **2,252**
                      
                      **$**
                      **-**
                      
                      **$**
                      **(452**
                      **)**
                      **$**
                      **1,800**Net
                          income
                      
                      **71**
                      
                      
                      **(1**
                      **)**
                      
                      **-**
                      
                      
                      **70****2005:**Operating
                          revenues
                      $
                      1,944
                      
                      $
                      -
                      
                      $
                      (318
                      )
                      $
                      1,626Net
                          income
                      
                      125
                      
                      
                      (4
                      )
                      
                      -
                      
                      
                      121
 (a)
                    Elimination
                        of intercompany revenues. 
 **ITEM
                2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
                OPERATIONS.**
 
 **OVERVIEW** **
 
 **Ameren
                Executive Summary**
 
 Despite
                solid operations, Ameren’s first quarter 2006 earnings fell short of the strong
                earnings achieved last year. Several
                factors negatively impacted Ameren’s earnings.  Temperatures during the
                2006 winter season in Ameren’s service territory were extremely mild resulting
                in lower electric and gas margins.  Electric margins were also negatively
                impacted by higher fuel and purchased power costs due primarily to
                increased
                coal and related transportation costs. In addition, Ameren incurred
                incremental
                costs of operating in the MISO Day Two Energy Market in the first
                quarter of
                2006 because MISO Day Two operations did not commence until the second
                quarter
                last year. These factors offset higher margins from organic growth
                and
                interchange sales compared to the first quarter of last year. Other
                operating
                expenses and taxes other than income taxes also rose, negatively
                affecting
                earnings for the quarter. These expenses rose primarily as a result
                of higher
                gross receipts taxes, the absence of a favorable property tax settlement,
                such
                as the one realized during the first quarter of 2005, and higher
                bad debt
                expenses.
  Ameren continues to have quite a bit of activity on the regulatory
                front. In
                delivery services rate filings made in late December 2005, CIPS,
                CILCO and IP
                requested a total combined annual electric revenue increase of approximately
                $200 million. In April 2006, the ICC staff, the Illinois attorney
                general and
                CUB recommended combined annual electric revenue increases in the
                range of $70
                million. The ICC has until November of this year to issue a final
                decision in
                these cases. As a result of the potential increases to ratepayers
                from this
                increase request and the transition to market-based power costs,
                there have been
                two pieces of legislation proposed in Illinois. One proposal includes
                a
                potential extension of the rate freeze through 2010, which we believe
                is without
                legal merit. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability
                to fully recover purchased power costs from their electric customers
                in a timely
                manner could result in material adverse consequences for these companies.
                Following the introduction of the rate freeze proposal, a second
                separate and
                constructive piece of legislation was introduced, which would authorize
                the
                issuance of securitization bonds that would effectively result in
                the deferral
                for up to 10 years of power procurement costs for residential customers.
                This
                proposed legislation would result in recovery of the deferred power
                procurement
                costs immediately upon the issuance of securitization bonds. In Missouri,
                UE
                expects to file for a rate increase later this year. The exact timing
                of the
                filing, and amount of the requested increase, is still to be determined.
                The
                MoPSC staff and others will review any filing and, based upon their
                analyses,
                will make their own rate recommendations.
  50
 
 **General**
 
 Ameren,
                      headquartered in St. Louis, Missouri, is a public utility holding
                      company under
                      PUHCA 2005 administered by FERC. Ameren was registered with
                      the SEC as a public
                      utility holding company under PUHCA 1935, until that act
                      was
 
 ·
                        UE
                            operates a rate-regulated electric generation, transmission
                            and
                            distribution business, and a rate-regulated natural gas
                            transmission and
                            distribution business in Missouri. Before May 2, 2005,
                            UE also operated
                            those businesses in Illinois. ·
                        CIPS
                            operates a rate-regulated electric and natural gas transmission
                            and
                            distribution business in Illinois. ·
                        Genco
                            operates a non-rate-regulated electric generation business
                            in Illinois and
                            Missouri. ·
                        CILCO,
                            a subsidiary of CILCORP (a holding company), operates
                            a rate-regulated
                            electric transmission and distribution business, a primarily
                            non-rate-regulated electric generation business (through
                            its subsidiary,
                            AERG), and a rate-regulated natural gas transmission
                            and distribution
                            business in Illinois. ·
                        IP
                            operates a rate-regulated electric and natural gas transmission
                            and
                            distribution business in Illinois. 
 In
                    addition to presenting results of operations and earnings amounts
                    in total, we
                    present certain information in cents per share. These amounts
                    reflect factors
                    that directly affect Ameren’s earnings. We believe this per share information
                    helps readers to understand the impact of these factors on Ameren’s earnings per
                    share. All references in this report to earnings per share are
                    based on
                    weighted-average diluted common shares outstanding during the
                    applicable period.
                    All tabular dollar amounts are in millions, unless otherwise
                    indicated.
 
 **RESULTS
                    OF OPERATIONS**
 
 **Earnings
                    Summary**
 
 Our
                    results of operations and financial position are affected by
                    many factors.
                    Weather, economic conditions, and the actions of key customers
                    or competitors
                    can significantly affect the demand for our services. Our results
                    are also
                    affected by seasonal fluctuations: winter heating and summer
                    cooling demands.
                    Approximately 85% of Ameren’s 2005 revenues were directly subject to state and
                    federal regulation. This regulation can have a material impact
                    on the price we
                    charge for our services. Our non-rate-regulated sales are subject
                    to market
                    conditions for power. We principally use coal, nuclear fuel,
                    natural gas, and
                    oil in our operations. The prices for these commodities can fluctuate
                    significantly due to the global economic and political environment,
                    weather,
                    supply and demand, and many other factors. We do not currently have
                    fuel
                    or purchased power cost recovery mechanisms in Missouri or Illinois
                    for our
                    electric utility businesses, but we do
                    have gas cost recovery mechanisms in each state for our gas delivery
                    businesses.
                    The electric and gas rates for UE in Missouri are set through
                    June 2006 and for
                    CIPS, CILCO and IP in Illinois through January 1, 2007; therefore,
                    cost
                    decreases or increases will not be immediately reflected in rates.
                    Fluctuations
                    in interest rates affect our cost of borrowing and our pension
                    and
                    postretirement benefits costs. We employ various risk management
                    strategies to
                    reduce our exposure to commodity risks and other risks inherent
                    in our
                    businesses. The reliability of our power plants and transmission
                    and
                    distribution systems, the level of purchased power costs, operating
                    and
                    administrative costs, and capital investment are key factors
                    that we seek to
                    control to optimize our results of operations ,
                    financial position, and liquidity .
 
 Ameren’s
                    net income decreased to $70 million, or 34 cents per share, in
                    the first quarter
                    of 2006 from $121 million, or 62 cents per share, in the first
                    quarter of 2005.
                    This decrease in net income was due to a combination of factors
                    in the first
                    quarter of the current year, including extremely mild winter
                    weather conditions,
                    higher fuel prices and transportation costs, the unavailability
                    of UE’s Taum
                    Sauk plant due to an upper reservoir breach, increased purchased
                    power costs as
                    a result of higher power prices and incremental costs of operating
                    in the MISO
                    Day Two Energy Market, and increased other operating expenses.
                    An increase in
                    the number of common shares outstanding also reduced Ameren’s earnings per share
                    in the first quarter of 2006 compared with the first quarter
                    of 2005. Increased
                    margins on interchange sales from EEI and organic growth in revenues
                    reduced the
                    impact of these items on first quarter 2006 earnings.
 51
  Because
            it is a holding company, Ameren’s net income and cash flows are primarily
            generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and
            IP. The
            following table presents the contribution by Ameren’s principal subsidiaries to
            Ameren’s consolidated net income for the three months ended March 31, 2006 and
            2005:
 
 **2006**
                
                **2005**Net
                    income (loss):UE(a)
                **$**
                **50**
                
                $
                56CIPS
                
                **(2**
                **)**
                
                7Genco(a)
                
                **6**
                
                
                31CILCORP(a)
                
                **8**
                
                
                9IP
                
                **3**
                
                
                21Other(b)
                
                **5**
                
                
                (3
                )Ameren
                    net income
                **$**
                **70**
                
                $
                121
 (a)
                Includes
                    earnings from market-based interchange power sales that provided
                    the
                    following contributions to net income:
 UE:
          2006
          - $20 million; 2005 - $22 million.
 Genco:
          2006 - $7 million; 2005 - $12 million.
 CILCORP:
          2006 - $7 million; 2005 - $5 million.
 (b)
                Includes
                    earnings from EEI, corporate general and administrative
                    expenses, other non-rate-regulated operations, and intercompany
                    eliminations.
  **Electric
          Operations**
 
 The
          following table presents the favorable (unfavorable) variations in electric
          margins, defined as electric revenues less fuel and purchased power costs,
          for
          the three months ended March 31, 2006, as compared with the year-ago period.
          We
          consider electric and interchange margins useful measures to analyze the
          change
          in profitability of our electric operations between periods. We have included
          the analysis below as a complement to the financial information we provide
          in
          accordance with GAAP. However, electric and interchange margins may not
          be a
          presentation defined under GAAP and may not be comparable to other companies’
presentations or more useful than the GAAP information we provide elsewhere
          in
          this report.
 
 **Three
                    Months**
                **Ameren****(a)**
                
                **UE**
                
                **CIPS**
                
                **Genco**
                
                **CILCORP**
                
                **CILCO**
                
                **IP**Electric
                    revenue change:Effect
                    of weather (estimate)
                $
                (11
                )
                $
                (5
                )
                $
                (5
                )
                $
                -
                
                $
                (1
                )
                $
                (1
                )
                $
                -Growth
                    and other (estimate)
                
                14
                
                
                (2
                )
                
                45
                
                
                15
                
                
                5
                
                
                5
                
                
                7Interchange
                    revenues
                
                79
                
                
                41
                
                
                (8
                )
                
                7
                
                
                (5
                )
                
                (5
                )
                
                -Total
                $
                82
                
                $
                34
                
                $
                32
                
                $
                22
                
                $
                (1
                )
                $
                (1
                )
                $
                7Fuel
                    and purchased power change:Fuel:Generation
                    and other
                $
                (15
                )
                $
                (3
                )
                $
                -
                
                $
                (9
                )
                $
                -
                
                $
                (1
                )
                $
                -Price
                
                (26
                )
                
                (16
                )
                
                -
                
                
                (10
                )
                
                -
                
                
                -
                
                
                -Purchased
                    power
                
                (68
                )
                
                (29
                )
                
                (31
                )
                
                (47
                )
                
                7
                
                
                7
                
                
                (20
                )Total
                $
                (109
                )
                $
                (48
                )
                $
                (31
                )
                $
                (66
                )
                $
                7
                
                $
                6
                
                $
                (20
                )Net
                    change in electric margins
                $
                (27
                )
                $
                (14
                )
                $
                1
                
                $
                (44
                )
                $
                6
                
                $
                5
                
                $
                (13
                )
 (a)
                Includes
                    amounts for Ameren registrant and nonregistrant subsidiaries
                    and
                    intercompany eliminations.
 
 *Ameren*
 
 Ameren’s
          electric margin decreased $27 million, or 4%, for the three months ended
          March
          31, 2006, compared with the same period in 2005. Ameren’s electric rates charged
          to its UE, CIPS, CILCO and IP regulated customers were unchanged in 2006
          from
          2005 levels. The decrease in electric margin was due to increased fuel
          and
          purchased power costs. Increases in margins on interchange sales, primarily
          from
          EEI, reduced the impact of these increased costs.
  As
          discussed above, Ameren’s electric margin decreased because of a $109 million,
          or 26%, increase in fuel and purchased power costs for the three months
          ended
          March 31, 2006, compared with the same period in 2005. Fuel and purchased
          power
          costs increased primarily because of increased coal and transportation
          prices,
          MISO Day Two Energy Market costs, and increased emission allowance utilization
          at Genco and AERG. Costs related to the MISO Day Two Energy
          Market, which commenced operations in April 2005, totaled $26 million for
          the
          three months ended
 52
  March
          31,
          2006, versus none in the prior-year period. In the first quarter of 2006,
          UE
          incurred $6 million in incremental fees levied by FERC upon completion
          of its
          cost study for generation benefits provided to UE’s Osage hydroelectric plant.
          Finally, the unavailability of UE’s Taum Sauk hydroelectric plant resulted in an
          estimated $6 million increase in fuel and purchased power costs for the
          three
          months ended March 31, 2006, compared with the same period in 2005.
 
 The
          decrease in electric margins was reduced by a $49 million, or 73%, increase
          in
          margins on interchange sales for the first three months of 2006, compared
          with
          the same period in 2005. Interchange margins increased primarily because
          of the
          increased sale of power from EEI resulting from the expiration of affiliate
          cost-based sales contracts on December 31, 2005, and because of higher
          average
          power prices. In addition, there was increased availability of low-cost
          generation resulting from reduced demand from native load customers due
          to the
          mild weather as well as improved power plant availability. Average realized
          power prices on interchange sales increased to approximately $47 per
          megawatthour in the first three months of 2006 from approximately $38 per
          megawatthour in the comparable period of 2005. Average power prices increased
          because of slightly higher market prices and increased on-peak sales from
          EEI.
          Reduced transmission losses as a result of entering the MISO Day Two Energy
          Market also contributed to an estimated $6 million increase in margins
          on
          interchange sales in the first three months of 2006 as compared to the
          year-ago
          period. Ameren’s baseload electric generating plants’ average capacity factor
          was approximately 80% in the first quarter of 2006 compared with 76% in
          the same
          period of 2005 and the equivalent availability factor was approximately
          90%, as
          compared with 84% in the prior-year period.
 
 *UE*
  UE’s
          electric margin decreased $14 million, or 4%, for the first three months
          of
          2006, compared to the same period in 2005. The decrease in margin was due
          to
          increased fuel and purchased power costs. In addition, the transfer of
          UE’s
          Illinois service territory to CIPS on May 2, 2005, resulted in lost margins
          totaling $18 million and contributed to UE’s decrease in electric margin for the
          first three months of 2006 compared to the same period in 2005. Partially
          offsetting these decreases to margin were sales to Noranda, which became
          a
          significant new industrial customer on June 1, 2005, and an increase in
          margins
          on interchange sales. The addition of Noranda added approximately $6 million
          in
          electric margin in the first three months of 2006.
  Fuel
          and
          purchased power costs increased $48 million, or 33%, for the first three
          months
          of 2006 compared to the same period in 2005 primarily because of higher
          coal and
          transportation costs. Several other factors contributed to higher fuel
          and
          purchased power costs as well. In the first quarter of 2006, UE incurred
          $6
          million in incremental fees levied by FERC upon completion of its cost
          study for
          generation benefits provided to UE’s Osage hydroelectric plant. In addition, UE
          had to supply higher-cost power to its native load customers as a cost-based
          power supply contract with EEI expired on December 31, 2005. MISO Day Two
          Energy
          Market costs, totaling $16 million, in the first three months of 2006 were
          also
          a contributing factor to UE’s increased purchased power costs over the first
          quarter of 2005.
 
 UE’s
          margins on interchange sales increased for the first three months of 2006,
          compared with the same period in 2005. Margins on interchange sales to
          affiliates increased because of the amendment of the joint dispatch agreement
          between UE and Genco and increased sales to Genco to serve a greater load
          primarily resulting from the transfer of UE’s Illinois service territory to
          CIPS. The joint dispatch agreement determines the allocation of margins
          or
          profits from short-term sales of excess generation to third parties between
          UE
          and Genco. The MoPSC-required, and FERC-approved, change in the methodology
          to
          base the allocation on generation output instead of load requirements,
          effective
          January 10, 2006, resulted in $9 million in incremental margins on interchange
          sales for UE in the first quarter of 2006 as compared to the year-ago period.
          In
          addition, margins on interchange sales with non-affiliates increased $3
          million
          in the first three months of 2006, compared with the same period in 2005,
          primarily because of higher power prices and access to the MISO Day Two
          Energy
          Market. Reduced transmission losses as a result of entering the MISO Day
          Two
          Energy Market resulted in $4 million in increased margins on interchange
          sales.
 
 *CIPS*
 
 CIPS’
          electric margin increased $1 million, or 2%, for the first three months
          of 2006,
          compared to the same period in 2005, primarily because of increased industrial
          sales as a result of the transfer to CIPS of UE’s Illinois service territory on
          May 2, 2005, and customers switching back to CIPS from Marketing Company
          because
          tariff rates were below market rates for power. The transfer of UE’s Illinois
          service territory resulted in a $12 million increase in electric margin
          in the
          first quarter of 2006 over the prior-year period. Revenues declined $5
          million
          in the first three months of 2006, compared to the same period last year
          because
          of milder weather, resulting in a decrease in electric margin of $3 million
          from
          the prior-year period as incremental energy costs under the power supply
          agreement with Marketing Company were similar to the previous-year period.
          Increased MISO Day Two Energy Market costs, totaling approximately $4 million,
          also reduced electric margins. Due to the expiration of the CIPS’ power supply
          agreement with EEI in December 2005, where CIPS sold its entitlements under
          the
          agreement with EEI to
  53
 Marketing
          Company, both interchange revenues and purchased power expenses decreased
          $8
          million.
 
 *Genco*
 
 Genco’s
          electric margin decreased $44 million, or 35%, in the first three months
          of
          2006, compared with the same period in 2005, primarily because of lower
          wholesale margins, higher coal and transportation prices, increased purchased
          power costs, higher emission allowance utilization costs, and incremental
          MISO
          Day Two Energy Market expenses. In addition, power prices under Genco’s
          principal power supply contract for CIPS (through Marketing Company) remained
          unchanged. Wholesale margins decreased because Genco purchased higher-cost
          power
          from affiliates and third parties to serve a greater load. Emission allowance
          utilization increased fuel costs by $4 million in 2006. The first quarter
          2006
          MISO Day Two Energy Market costs totaling $4 million versus none in the
          prior-year period were also a contributing factor to Genco’s increased purchased
          power costs. Power costs averaged $26 per megawatthour in the first three
          months
          of 2006 compared to approximately $14 per megawatthour in the year-ago
          period.
          The increase in revenues due to the transfer of UE’s Illinois service territory
          to CIPS in May 2005 was partially offset by lower wholesale sales as a
          result of
          the expiration of several large contracts in 2005.
 
 Genco’s
          margin on interchange sales decreased in the first three months of 2006,
          compared with the same period in 2005, primarily because a $9 million reduction
          due to the amendment of the joint dispatch agreement between UE and Genco
          discussed above. The impact of this change was reduced by the benefit of
          higher
          power prices and access to the MISO Day Two Energy Market.
 
 *CILCORP
          and CILCO*
 
 Electric
          margin increased $6 million, or 10%, and $5 million, or 8%, at CILCORP
          and
          CILCO, respectively, in the first three months of 2006 compared with the
          same
          period in 2005 primarily because of lower purchased power costs and higher
          margins on interchange sales. Purchased power costs decreased because of
          improved plant availability. No planned outages occurred in the first three
          months of 2006, compared with a planned outage that occurred at one of
          AERG’s
          power plants in the same period in 2005. Margins on interchange sales increased
          $3 million. Reducing the increase in electric margins at CILCORP and CILCO
          was
          MISO Day Two Energy Market costs totaling $1 million in the first three
          months
          of 2006 compared with none in the same period in 2005.
 
 *IP*
 
 IP’s
          electric margin decreased $13 million, or 17%, in the first three months
          of
          2006, compared to the same period in 2005, primarily because of higher
          purchased
          power costs. Purchased power costs were $20 million higher due to increased
          power prices as a result of the expiration of its cost-based power supply
          agreement with EEI on December 31, 2005, and a 12% increase in average
          purchased
          power cost per megawatthour.
 
 **Gas
          Operations**
 
 The
          following table presents the favorable (unfavorable) variations in gas
          margins,
          defined as gas revenues less gas purchased for resale, for the three months
          ended March 31, 2006, compared with the year-ago period. We consider gas
          margin
          to be a useful measure of the change in profitability of our gas utility
          operations between periods. The table below complements the financial
          information we provide in accordance with GAAP. However, gas margin may
          not be a
          presentation defined under GAAP. Our presentation may not be comparable
          to other
          companies’ presentations or more useful than the GAAP information we provide
          elsewhere in this report.
 
 **Three
                    Months**Ameren(a)
                **$**
                **(6**
                **)**UE
                
                **(5**
                **)**CIPS
                
                **-**CILCORP
                
                **(3**
                **)**CILCO
                
                **(3**
                **)**IP
                
                **3**
 (a)
                Includes
                    amounts for Ameren registrant and nonregistrant subsidiaries
                    and
                    intercompany eliminations.
 
 *Ameren*
 
 Ameren’s
          gas margin decreased by $6 million, or 4%, for the three months ended March
          31,
          2006, over the same period in 2005 primarily because of extremely mild
          weather
          conditions that reduced gas margins as heating degree-days were about 11%
          below
          a mild 2005 first quarter. Residential and commercial gas volume sales,
          which
          are correlated to heating degree-days, both decreased 12%, for the three
          months
          ended March 31, 2006, compared with the same period in 2005. Ameren’s decrease
          in gas margin in the first quarter of 2006 was reduced by, among other
          things,
          the effect of an IP rate increase effective in May 2005 that added revenues
          of
          $4 million. Other delivery services rates were flat between periods.
 
 *UE*
 
 UE’s
          gas
          margin decreased by $5 million, or 17%, for the three months ended March
          31,
          2006, compared with the same period in 2005, primarily because of the transfer
          of UE’s Illinois service territory to CIPS, which reduced gas margins by $3
          million, and extremely mild weather conditions, as evidenced by an 8% decrease
          in heating degree-days in UE’s service territory. Residential and commercial gas
          sales decreased 22% and 18%, respectively, for the three months
  54
  ended
          March 31, 2006, compared with the same period in 2005 primarily as a result
          of
          the extremely mild weather and the transfer of UE’s Illinois service territory
          to CIPS. Industrial gas sales also decreased 30% over the same period primarily
          because of the UE Illinois service territory transfer to CIPS.
  *CIPS*
 
 CIPS’
gas
          margin for the three months ended March 31, 2006, was comparable with the
          same period in 2005. The transfer to CIPS of UE’s Illinois service territory
          increased gas margin by $3 million and industrial gas sales by 25%. The
          increase
          in gas margin was offset by extremely mild weather as evidenced by a 15%
          decrease in heating degree-days.
 
 *CILCORP
          and CILCO*
  CILCORP’s
          and CILCO’s gas margins each decreased by $3 million, or 9%, for the three
          months ended March 31, 2006, over the same period in 2005, primarily as
          a result
          of extremely mild weather conditions as heating degree-days were 9% below
          the
          first quarter of 2005 in CILCO’s service territory. This resulted in a 13%
          decrease in both residential and commercial gas sales.
 
 *IP*
 
 IP’s
          gas
          margin increased $3 million, or 6%, for the three months ended March 31,
          2006,
          over the same period in 2005, primarily because of a rate increase effective
          in
          May 2005 that added revenues of $4 million. This increase was reduced by
          extremely mild weather conditions as evidenced by a 12% decrease in heating
          degree-days in 2006 as compared with the year-ago period in IP’s service
          territory. Residential and commercial gas sales decreased 12% and 15%,
          respectively, for the three months ended March 31, 2006, compared with
          the same
          period in 2005.
 
 **Operating
          Expenses and Other Statement of Income Items**
 
 ***Other
          Operations and Maintenance***
  *Ameren*
 
 Ameren’s
          other operations and maintenance expenses increased $3 million in the first
          three months of 2006, as compared with the same period in 2005, primarily
          because of higher bad debt expense. Bad debt expense increased as a result
          of
          actions by the Illinois governor to restrict customer disconnections during
          the
          first quarter of 2006 and higher gas billings resulting from increased
          gas
          prices.
 
 *UE*
 
 Other
          operations and maintenance expenses at UE decreased $10 million in the
          first
          quarter of 2006 as compared with the first quarter of 2005. The transfer
          of UE’s
          Illinois service territory to CIPS in May 2005 resulted in a decrease in
          other
          operations and maintenance expenses at UE in the first quarter of the current
          year of $6 million as compared to the same period in 2005. A reduction
          in
          injuries and damages expenses also contributed to the favorable variance.
 
 *CIPS*
 
 Other
          operations and maintenance expenses at CIPS increased $5 million in the
          first
          three months of 2006, as compared with the first three months of 2005,
          primarily
          because of the transfer of UE’s Illinois service territory to CIPS in May 2005,
          which resulted in an increase in other operations and maintenance expenses
          of $6
          million at CIPS in the current year period as compared to the same period
          in
          2005.
  *Genco*
 
 Genco’s
          other operations and maintenance expenses decreased $6 million in the first
          three months of 2006, as compared with the first three months of 2005,
          primarily
          because of lower maintenance expenses due to a major power plant outage
          in the
          first quarter of 2005.
 
 *CILCORP*
 
 Other
          operations and maintenance expenses at CILCORP were comparable for the
          three
          months ended March 31, 2006, with the same period in 2005.
 
 *CILCO*
 
 CILCO’s
          other operations and maintenance expenses decreased $3 million in the first
          quarter of 2006 from the same period in 2005 primarily because of lower
          employee
          benefit costs, partially offset by increased bad debt expense.
 
 *IP*
 
 IP’s
          other operations and maintenance expenses increased $17 million in the
          first
          quarter of 2006 over the same period in 2005 primarily because of higher
          labor
          costs and increased information technology and bad debt expenses.
 
 ***Depreciation
          and Amortization***
 
 Variations
          in depreciation and amortization expenses at the Ameren Companies between
          the
          first quarter of 2006 and the first quarter of 2005 were as
          follows:
 *Ameren* -
              Increased $8 million as a result of capital additions, primarily at
              UE, and the
              impairment of an intangible asset associated with the CILCORP
              acquisition.
  55
  *UE* -
          Increased $4 million primarily because of capital additions, a portion
          of which
          were related to new steam generators and turbine rotors installed during
          the
          refueling and maintenance outage at the Callaway nuclear plant in the prior
          year. Partially offsetting these increases was a reduction of depreciation
          due
          to the transfer of property to CIPS in the Illinois service territory
          transfer.
 
 *CIPS* -
          Increased $3 million primarily because of depreciation on property transferred
          to CIPS from UE Illinois service territory transfer along with capital
          additions.
 
 *CILCORP* -
          Increased $4 million due to the impairment of an intangible asset established
          in
          conjunction with Ameren’s acquisition of CILCORP.
 
 *Genco* , *CILCO
          and IP* -
          Depreciation and amortization expenses were comparable between
          periods.
 
 ***Taxes
          Other Than Income Taxes***
 
 Variations
          in taxes other than income taxes at the Ameren Companies between the first
          three
          months of 2006 and the first three months of 2005 were as follows:
 
 *Ameren* -
          Increased $22 million primarily as a result of higher gross receipts taxes
          and
          higher property taxes at Genco.
 
 *UE* -
          Increased $4 million primarily as a result of higher gross receipts taxes.
 
 *CIPS* -
          Increased $4 million primarily as a result of higher gross receipts and
          excise
          taxes.
  *Genco* -
          Increased $8 million because of higher property taxes due to the absence
          in 2006
          of an $8 million tax settlement that was received in the first quarter
          of 2005.
 
 *CILCORP,
          CILCO and IP* - Taxes
          other than income taxes were comparable between periods.
 
 ***Other
          Income and Expenses***
 
 Variations
          in other income and expenses at the Ameren Companies between the first
          quarter
          of 2006 and the first quarter of 2005 were as follows:
 
 *Ameren
          and UE* - Income
          decreased $3 million and $4 million at Ameren and UE, respectively, primarily
          as
          a result of a lower capitalization of funds used during
          construction.
 
 *CIPS,*  *Genco,
          CILCORP, CILCO and IP* - Other
          income and expenses were comparable between periods.
 
 ***Interest***
 
 Variations
          in interest expense at the Ameren Companies between the first three months
          of
          2006 and the first three months of 2005 were as follows:
 
 *Ameren,
          CIPS,*  *CILCORP,
          CILCO and IP* -
          Interest expense was comparable between periods. At Ameren, increased interest
          expense from the issuance of senior secured notes in 2005 at UE was offset
          by a
          decrease in interest expense resulting from the repurchase and retirement
          of
          Ameren’s $95 million of senior notes in February 2005 and the maturity of
          Genco’s senior notes in November 2005.
 
 *UE* -
          Increased $10 million primarily because of the issuances of $300 million
          of
          senior secured notes in July 2005 and $260 million of senior secured notes
          in
          December 2005.
 
 *Genco* -
          Decreased $6 million primarily because of the maturity of $225 million
          of senior
          notes in November 2005, lower average money pool borrowings, and a reduction
          in
          principal amounts outstanding on intercompany promissory notes to CIPS
          and
          Ameren. The intercompany note payable to Ameren was repaid in May 2005.
 
 ***Income
          Taxes***
 
 Income
          tax expense at Ameren, UE, CIPS, Genco and IP decreased primarily because
          of
          lower pretax income. Income tax expense at CILCORP and CILCO was comparable
          for
          the first three months of 2006 compared with the same period in
          2005.
  **LIQUIDITY
          AND CAPITAL RESOURCES**
 
 The
          tariff-based gross margins of Ameren’s rate-regulated utility operating
          companies (UE, CIPS, CILCO and IP) continue to be the principal source
          of cash
          from operating activities for Ameren and its rate-regulated subsidiaries.
          A
          diversified retail-customer mix of primarily rate-regulated residential,
          commercial and industrial classes and a commodity mix of gas and electric
          service provide a reasonably predictable source of cash flows for Ameren.
          For
          operating cash flows, Genco principally relies on sales to an affiliate
          under a
          contract expiring at the end of 2006 and sales to other wholesale and industrial
          customers under short and long-term contracts. Commencing in 2007, Genco
          intends
          to sell power previously sold under these contracts through
 56
  the
          proposed auctions for CIPS, CILCO and IP and to other wholesale and retail
          customers. In addition, each of the Ameren Companies plans to use short-term
          borrowings to support normal operations and other temporary capital
          requirements. The use of operating cash flows and short-term borrowings to
          fund capital expenditures and other investments may periodically result
          in a
          working capital deficit, as was the case at March 31, 2006, for Ameren,
          UE,
          Genco, CILCORP, CILCO and IP. Ameren will discretionarily reduce its short-term
          borrowings with cash from operations or with long-term borrowings.
  The
          following table presents net cash
          provided by (used in) operating, investing and financing activities for
          the
          three months ended March 31, 2006 and 2005:
 
 **Net
                    Cash Provided By**
                  **Operating
                    Activities**
                
                **Net
                    Cash Provided By**
                  **(Used
                    In) Investing Activities**
                
                **Net
                    Cash Provided By**
                  **(Used
                    In) Financing Activities****2006**
                
                **2005**
                
                **Variance**
                
                **2006**
                
                **2005**
                
                **Variance**
                
                **2006**
                
                **2005**
                
                **Variance**Ameren(a)
                **$**
                **287**
                
                $
                357
                
                $
                (70
                )
                **$**
                **(494**
                **)**
                $
                (202
                )
                $
                (292
                )
                **$**
                **140**
                
                $
                (194
                )
                $
                334UE
                
                **60**
                
                
                107
                
                
                (47
                )
                
                **(403**
                **)**
                
                (185
                )
                
                (218
                )
                
                **324**
                
                
                32
                
                
                292CIPS
                
                **67**
                
                
                66
                
                
                1
                
                
                **(64**
                **)**
                
                (10
                )
                
                (54
                )
                
                **(3**
                **)**
                
                (56
                )
                
                53Genco
                
                **40**
                
                
                38
                
                
                2
                
                
                **(10**
                **)**
                
                (24
                )
                
                14
                
                
                **(30**
                **)**
                
                (15
                )
                
                (15
                )CILCORP
                
                **61**
                
                
                41
                
                
                20
                
                
                **(19**
                **)**
                
                (13
                )
                
                (6
                )
                
                **(42**
                **)**
                
                (31
                )
                
                (11
                )CILCO
                
                **61**
                
                
                45
                
                
                16
                
                
                **(19**
                **)**
                
                (19
                )
                
                -
                
                
                **(43**
                **)**
                
                (27
                )
                
                (16
                )IP
                
                **64**
                
                
                113
                
                
                (49
                )
                
                **(37**
                **)**
                
                1
                
                
                (38
                )
                
                **(26**
                **)**
                
                (114
                )
                
                88
 (a)****
                Includes
                    amounts for Ameren registrant and nonregistrant subsidiaries
                    and
                    intercompany eliminations.
 **Cash
          Flows from Operating Activities**
 
 Ameren’s
          cash from operations decreased in 2006, as compared with 2005, due primarily
          to
          decreases in electric and gas margins as discussed in Results of Operations
          above. Also contributing to the decrease was cash used during the first
          quarter
          of 2006 for payment of 2005 year-end accruals including real estate and
          property
          taxes, annual incentive compensation that was more than it was a year ago
          due to
          increased 2005 earnings relative to performance targets, and trade payables
          that
          were higher than normal due to an unusually cold December 2005 and higher
          natural gas prices. Reducing this negative impact was the collection of
          higher-than-normal trade receivables caused by cold December weather, and
          the
          sale of gas inventories during the winter heating season. The cash impact
          from
          trade receivables and inventory reductions was more significant in the
          current
          period due to higher gas prices than the year-ago period.
 
 At
          UE,
          cash from operating activities decreased in 2006 due to lower electric
          and gas
          margins and cash used for working capital changes that primarily included
          increased payments of year-end accruals in the first quarter of 2006 as
          compared
          with the year-ago period as discussed above for Ameren.
 
 At
          CIPS,
          the negative cash effect of higher other operations and maintenance expenses
          and
          taxes other than income, as discussed in Results of Operations, was offset
          by a
          cash benefit from reduced working capital investment, resulting in operating
          cash flow in the first quarter of 2006 that was consistent with the 2005
          period.
          The most significant working capital cash benefit was the reduction of
          trade
          receivables that was greater than the year-ago period as a result of colder
          December weather and higher gas prices compared to the year-ago period.
          The
          acquisition of UE’s Illinois
          service territory in May 2005 also increased receivables and
          payables.
  Genco’s
          cash from operating activities in the first quarter of 2006 was comparable
          to
          the 2005 period primarily because the negative cash effect of lower operating
          margins was partially offset by an $18 million reduction in emission allowance
          purchases and lower interest payments as a result of decreased debt
          outstanding.
 
 Cash
          from
          operating activities increased for CILCORP and CILCO in the first quarter
          of
          2006 compared with the 2005 period primarily because of a $9 million decrease
          in
          emission allowance purchases in 2006 as compared with the year-ago period.
          In
          addition, gas inventories were reduced as a result of sales during the
          winter
          heating season creating a cash benefit. As discussed above, the
          period-over-period impact was greater in 2006 due to higher natural gas
          prices.
 
 IP’s
          cash
          from operations decreased in the first quarter of 2006 compared with the
          2005
          period due to lower electric margins and higher other operations and maintenance
          expenses as discussed above in Results of Operations. Also contributing
          to IP’s
          decreased operating cash flows in 2006 were income taxes paid of $16 million
          in
          the 2006 period as compared with income tax refunds of $10 million in the
          year-ago period. The 2005 period included more tax benefits from Ameren’s
          acquisition of IP and tax benefits from premiums paid for early debt redemptions
          made in 2004.
 
 **Cash
          Flows from Investing Activities**
 
 Ameren’s
          increase in cash used in investing activities was primarily because of
          UE’s
          purchases of a 640-megawatt CT facility from affiliates of NRG, and 510-megawatt
          and 340-megawatt CT facilities from subsidiaries of Aquila, Inc. for $292
          million. The CT purchases are intended to meet UE’s
 57
 increased
          generating capacity needs and provide UE with additional flexibility in
          determining future base-load generating capacity additions.
 
 Excluding
          the CT purchases, Ameren’s and UE’s capital expenditures decreased $31 million
          and $29 million, respectively, in the first quarter of 2006 as compared
          with the
          year-ago period primarily because fewer capital resources were allocated
          to
          other projects due to the planned CT acquisitions.
  CIPS’
          increase in cash used in investing activities in the first quarter of 2006
          over
          the 2005 period was due to a $7
          million increase in capital expenditures and $47 million of advances to
          the
          money pool in 2006. The increased capital expenditures resulted partly
          from
          CIPS’ expansion of its service territory because of its acquisition of UE’s
          Illinois utility operations in May 2005. CIPS’ capital expenditures were for
          projects to improve the reliability of its electric and gas transmission
          and
          distribution systems.
 
 Genco’s
          capital expenditures were lower in the first quarter of 2006 compared
          with the 2005 period because 2005 included more expenditures due to an
          extended
          planned outage at one of its power plants in 2005.
 
 CILCORP’s
          and CILCO’s cash used in investing activities were comparable in the first
          quarters of the 2006 and 2005
          periods, except for the absence in 2006 of CILCORP’s cash from repayments in
          2005 of prior period advances to the money pool.
  IP’s
          cash
          from investing activities in 2006 decreased primarily because of the absence
          in
          the first quarter of 2006 of proceeds received in the first quarter of
          2005 from
          repayments received for advances made to the money pool in prior
          periods.
 
 See
          Note
          8 - Commitments and Contingencies and Note 2 - Rate and Regulatory Matters
          to
          our financial statements under Part I, Item 1, of this report for a further
          discussion of environmental matters and the UE CT acquisitions,
          respectively.
 
 We
          continually review our generation portfolio and expected power needs. As
          a
          result, we could modify our plans for generation capacity, which could
          include
          changing the times when certain assets will be added to or removed from
          our
          portfolio, the type of generation asset technology that will be employed,
          and
          whether capacity may be purchased, among other things. Any changes that
          we may
          plan to make for future generating needs could result in significant capital
          expenditures or losses being incurred, which could be material.
  **Cash
          Flows from Financing Activities**
 
 Cash
          from
          financing activities increased for Ameren in 2006 from the
          year-ago period, primarily because of an increase in net short-term debt
          proceeds of $270 million, principally at UE, that were used to partially
          fund
          UE’s CT acquisitions. Decreased long-term debt redemptions of $158
          million also contributed to the increase in cash from financing activities
          in
          2006. These cash benefits were partially offset by an $85 million decrease
          in
          proceeds from long-term debt issuances.
  UE’s
          cash
          from financing activities increased in the first quarter of 2006, as
          compared with the 2005 period, primarily because of a $356 million increase
          in
          short-term debt proceeds related to the CT acquisitions and an $18 million
          decrease in dividend payments. These increases were reduced by an $85 million
          decrease in long-term debt proceeds.
 
 CIPS’
          cash used in financing activities decreased in the first quarter of 2006, as
          compared with the 2005 period, because of a $53 million decrease in payments
          to
          the money pool in the 2006 period.
  Genco’s
          cash used in financing activities increased in the first quarter of 2006 from the
          same period in 2005 primarily because of increased money pool payments
          and
          common stock dividend payments of $7 million and $8 million, respectively.
 
 CILCORP’s
          and CILCO’s cash used in financing activities increased primarily due to
          increases in common stock dividends of $20 million and $30 million,
          respectively, that were partially offset by net increases in cash from
          money
          pool borrowings of $11 million and $13 million at CILCORP and CILCO,
          respectively.
 
 IP’s
          cash
          used in financing activities decreased in the first quarter of 2006,
          as
          compared with the 2005
          period, primarily because of lower redemptions and repurchases of long-term
          debt
          of $69 million and the absence in 2006 of a $20 million common stock dividend
          payment made in 2005.
  ***Short-term
          Borrowings and Liquidity***
 
 For
          information on credit facilities, short-term borrowing activity, relevant
          interest rates, and borrowings under Ameren’s utility money pool arrangement and
          non-state-regulated subsidiary money pool arrangement, see Note 3 - Short-term
          Borrowings and Liquidity to our financial statements under Part I, Item
          1, of
          this report.
  58
  The
          following table presents the committed bank credit facilities of Ameren
          and EEI
          as of March 31, 2006:
 
 **Credit
                    Facility**
                **Expiration**
                
                **Amount
                    Committed**
                
                **Amount
                    Available****Ameren:****(a)**Multiyear
                    revolving(b)
                July
                    2010
                
                $
                1,150
                
                $
                686Multiyear
                    revolving
                July
                    2010
                
                
                350
                
                
                350**EEI:**Bank
                    credit facility(c)
                April
                    2006
                
                
                20
                
                
                20Total
                
                
                $
                1,520
                
                $
                1,056
 (a)
                Ameren
                    Companies may access these credit facilities through intercompany
                    borrowing arrangements.
 (b)
                UE,
                    CIPS, Genco, CILCO and IP are also direct borrowers under this
                    agreement.
 (c)
                This
                    facility expired in April 2006 and was not
                    renewed.
  In
          addition to committed credit facilities, a further source of liquidity
          for
          Ameren from time to time is available cash and cash equivalents. At March
          31,
          2006, Ameren had $29 million of cash and cash equivalents.
  With
          the
          repeal of PUHCA 1935 in February 2006, the issuance of short-term debt
          securities by Ameren’s utility subsidiaries is now subject to approval by FERC
          under the Federal Power Act. In March 2006, FERC issued an order authorizing
          these subsidiaries to issue short-term debt securities subject to the following
          limits on outstanding balances:
 UE
          - $1
          billion; CIPS - $250 million; and CILCO - $250
          million. This authorization is effective as of April 1, 2006, and terminates
          on
          March 31, 2008.
  Genco
          is
          also authorized by FERC in its March 2006 order to have up to $300 million
          of
          short-term debt outstanding at
          any
          time. IP and EEI have unlimited short-term debt authorization from
          FERC.
  With
          the
          repeal of PUHCA 1935 in February 2006, the issuance of short-term debt
          securities by Ameren and CILCORP, which was previously subject to SEC approval
          under PUHCA 1935, is no longer subject to approval by any regulatory body.
  ***Long-term
          Debt and Equity***
 
 The
          following table presents the issuances of common stock and the issuances,
          redemptions, repurchases and maturities of long-term debt and preferred
          stock
          (net of any issuance discounts and including any redemption premiums) for
          the
          three months ended March 31, 2006 and 2005, for the Ameren Companies. For
          additional information, see Note 4 - Long-term Debt and Equity Financings
          to our
          financial statements under Part I, Item 1, of this report.
 
 **Three
                    Months****Month
                    Issued, Redeemed, Repurchased or Matured**
                
                **2006**
                
                **2005****Issuances***Long-term
                    debt***UE:**5.00%
                    Senior secured notes due 2020
                January
                
                **$**
                **-**
                
                $
                85Total
                    Ameren long-term debt issuances
                
                
                **$**
                **-**
                
                $
                85*Common
                    stock***Ameren:**DRPlus
                    and 401(k)
                Various
                
                **$**
                **27**
                
                $
                30Total
                    common stock issuances
                
                
                **$**
                **27**
                
                $
                30Total
                    Ameren long-term debt and common stock issuances
                
                
                **$**
                **27**
                
                $
                115**Redemptions,
                    Repurchases and Maturities***Long-term
                    debt***Ameren:**Senior
                    notes due 2007(a)
                February
                
                **$**
                **-**
                
                $
                95**CILCORP:**9.375%
                    Senior notes due 2029
                March
                
                
                **3**
                
                
                -**IP:**6.75%
                    First mortgage bonds due 2005
                March
                
                
                **-**
                
                
                70Note
                    payable to IP SPT5.54%
                    Series due 2007
                Various
                
                
                **28**
                
                
                -5.38%
                    Series due 2005
                Various
                
                
                **-**
                
                
                22Total
                    Ameren long-term debt and preferred stock redemptions, repurchases
                    and
                    maturities
                
                
                **$**
                **31**
                
                $
                187
 (a)
                Component
                    of the adjustable conversion-rate equity security units.
  59
 The
              following table presents the authorized amounts under Form S-3 shelf
              registration statements filed and declared effective for certain Ameren
              Companies as of March 31, 2006:
 
 **Effective**
                      **Date**
                    
                    **Authorized**
                      **Amount**
                    
                    **Issued**
                    
                    **Available**Ameren
                    
                    June
                        2004
                    
                    $
                    2,000
                    
                    $
                    459
                    
                    $
                    1,541UE
                    
                    October
                        2005
                    
                    
                    1,000
                    
                    
                    260
                    
                    
                    740CIPS
                    
                    May
                        2001
                    
                    
                    250
                    
                    
                    150
                    
                    
                    100
 
 Ameren
              also has approximately 4.6 million shares of common stock available
              for issuance
              under various other SEC effective registration statements applicable
              to its
              DRPlus and 401(k) plans as of March 31, 2006.
 
 Ameren,
              UE and CIPS may sell all or a portion of the remaining securities registered
              under their effective registration statements if market conditions
              and capital
              requirements warrant such a sale. Any offer and sale will be made only
              by means
              of a prospectus meeting the requirements of the Securities Act of 1933
              and the
              rules and regulations thereunder.
  **Indebtedness
          Provisions and Other Covenants**
 
 See
          Note
          3 - Short-term Borrowings and Liquidity to our financial statements under
          Part
          I, Item 1, of this report for a discussion of the covenants and provisions
          contained in
 Ameren’s
          bank credit facilities and applicable cross-default provisions. Also see
          Note 4
          - Long-term Debt and Equity Financings to our financial statements under
          Part I,
          Item 1, of this report for a discussion of covenants and provisions contained
          in
          certain of the Ameren Companies’ indenture agreements and articles of
          incorporation.
  At
          March
          31, 2006, the Ameren Companies were in compliance with their credit agreement,
          indenture, and articles of incorporation provisions and covenants.
 
 We
          consider access to short-term and long-term capital markets a significant
          source
          of funding for capital requirements not satisfied by our operating cash
          flows.
          Our inability
          to raise capital on favorable terms, particularly during times of uncertainty
          in
          the capital markets, could negatively affect our ability to maintain and
          expand
          our businesses. After assessing our current operating performance, liquidity,
          and credit ratings (see Credit Ratings below), we believe that we will
          continue
          to have access to the capital markets. However, events beyond our control
          may
          create uncertainty in the capital markets. Such events might increase our
          cost
          of capital or adversely affect our ability to access the capital
          markets.
 
 **Dividends**
 
 Dividends
          paid by Ameren to shareholders during the first three months of 2006 totaled
          $130 million, or 63.5 cents per share (2005 - $124 million or 63.5 cents
          per
          share). On May 2, 2006, Ameren’s board of directors declared a quarterly common
          stock dividend of 63.5 cents per share payable on June 30, 2006, to shareholders
          of record on June 7, 2006.
 
 UE
          paid
          preferred stock dividends of approximately $1 million on February 15, 2006.
          CIPS
          paid preferred stock dividends of approximately $1 million on March 31,
          2006.
          CILCO paid preferred stock dividends of less than $1 million on both January
          3,
          2006 and April 3, 2006. IP paid preferred stock dividends of approximately
          $1
          million on both February 1, 2006 and May 1, 2006. The next preferred dividends
          are payable on May 15, 2006, June 30, 2006, July 3, 2006 and August 1,
          2006 for
          UE, CIPS, CILCO and IP, respectively.
  Certain
          of our financial agreements and articles of incorporation contain covenants
          and
          conditions that, among other things, would restrict the Ameren Companies’
payment of dividends in certain circumstances. At March 31, 2006, none
          of these
          circumstances existed and as a result, the Ameren Companies are allowed
          to pay
          dividends. In its approval of the acquisition of IP by Ameren, the ICC
          issued an
          order that permits IP to pay dividends on its common stock subject to certain
          conditions related to credit ratings of IP and Ameren and the elimination
          of
          IP’s 11.50% Series mortgage bonds. See Note 4 - Long-term Debt and Equity
          Financings to our financial statements under Part I, Item 1, of this
          report.
 
 The
          following table presents dividends paid by Ameren Corporation and by Ameren’s
          subsidiaries to their respective parents for the three months ended March
          31,
          2006 and 2005.
 
 **Three
                    Months****2006**
                
                **2005**UE
                **$**
                **42**
                
                $
                60Genco
                
                **22**
                
                
                14CILCORP(a)
                
                **50**
                
                
                30IP
                
                **-**
                
                
                20Nonregistrants
                
                **16**
                
                
                -Dividends
                    paid by Ameren
                **$**
                **130**
                
                $
                124
 (a)
                CILCO
                    paid dividends of $50 million and $20 million for the three months
                    ended
                    March 31, 2006 and 2005,
                    respectively.
  60
 
 **Contractual
          Obligations**
 
 For
          a
          complete listing of our obligations and commitments, see Contractual Obligations
          under Part II, Item 7 and Note 15 - Commitments and Contingencies under
          Part II,
          Item 8 of the Ameren Companies’ combined Annual Report on Form 10-K for the
          fiscal year ended December 31, 2005. See Note 11 - Retirement Benefits
          to our
          financial statements under Part I, Item 1, of this report for information
          regarding expected minimum funding levels for our pension plan.
 
 Subsequent
          to December 31, 2005, operating lease obligations increased at Ameren,
          UE, and
          Genco to $446 million, $207 million, and $169 million, respectively, as
          of March
          31, 2006. Subsequent to December 31, 2005, obligations related to the
          procurement of coal and natural gas increased at Ameren, UE, CIPS, Genco,
          CILCORP, CILCO and IP to
 $4,203
          million, $1,568 million, $498 million, $622 million, $660 million, $660
          million
          and $564 million, respectively, as of March 31, 2006. Total other obligations
          at
          March 31, 2006, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were
          $4,496
          million, $1,717 million, $620 million, $622 million, $765 million, $765
          million
          and $707 million, respectively.
 
 Ameren’s
          and UE’s long-term debt increased $240 million as a result of the first quarter
          leasing transaction related to the Audrain CT acquisition as discussed
          in Note 2
          - Rate and Regulatory Matters to our financial statements under Part I,
          Item 1,
          of this report.
  **Credit
          Ratings**
 
 There
          have been no changes to the Ameren Companies’ credit ratings since the Ameren
          Companies’ combined Annual Report on Form 10-K for the fiscal year ended
          December 31, 2005.
 
 Any
          adverse change in the Ameren Companies’ credit ratings may reduce access to
          capital. It may also increase the cost of borrowing and fuel and power supply,
          among other things, resulting in a negative impact on earnings. For example,
          if
          at March 31, 2006, the Ameren Companies had a sub-investment-grade rating
          (less
          than BBB- or Baa3), Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could
          have
          been required to post collateral for certain trade obligations amounting
          to $119
          million, $14 million, $7 million, $2 million, $16 million, $16 million,
          or $49
          million, respectively. In addition, the cost of borrowing under our credit
          facilities can increase or decrease with credit ratings. A credit rating
          is not
          a recommendation to buy, sell or hold securities. It should be evaluated
          independently of any other rating. Ratings are subject to revision or withdrawal
          at any time by the rating organization.
 
 **OUTLOOK**
  Below
          are
          some key trends that may affect the Ameren Companies’ financial condition,
          results of operations, or liquidity in 2006 and beyond:
 
 ***Revenues***
 
 ·
                By
                    the end of 2006, electric rates for Ameren’s operating subsidiaries will
                    have been fixed or declining for periods ranging from 15 years
                    to 25
                    years. In 2006, electric rate adjustment moratoriums and power
                    supply
                    contracts expire in Ameren’s regulatory jurisdictions.
 ·
                Approximately
                    11 million megawatthours supplied annually by Genco and 6 million
                    megawatthours supplied annually by AERG have been subject to
                    contracts to
                    provide CIPS and CILCO, respectively, with power. The prices
                    in these
                    power supply contracts of $34.00 per megawatthour for AERG and
                    $38.50 per
                    megawatthour for Genco were below estimated market prices for
                    similar
                    contracts in early 2006. Most of Genco’s other wholesale and retail
                    electric power supply agreements also expire during 2006 and
                    substantially
                    all of these are below market prices for similar contracts in
                    early 2006.
                    In January 2006, the ICC approved a framework for CIPS, CILCO
                    and IP to
                    procure power for use by their customers in 2007 through an auction.
                    This
                    approval is subject to court
                    appeal.
 ·
                Certain
                    Illinois legislators, the Illinois attorney general, the Illinois
                    governor, and other parties have sought and continue to seek
                    various
                    methods, including rate freeze legislation, to block the power
                    procurement
                    auction and/or the recovery of related costs for power supply
                    resulting
                    from the auction through rates to customers. Any decision or
                    action that
                    impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power
                    costs from their electric customers in a timely manner could
                    result in
                    material adverse consequences for these companies and for Ameren.
                    CIPS,
                    CILCO and IP are willing to work with stakeholders to ease the
                    burden of
                    higher energy prices on residential customers through a rate
                    increase
                    phase-in plan, as long as such plan allows for the full and timely
                    recovery of costs and does not adversely impact credit ratings.
                    In March
                    2006, legislation was introduced in the Illinois House of Representatives
                    that would allow the deferral of a portion of the power procurement
                    costs
                    and would authorize the ICC to permit a utility with fewer than
                    one
                    million retail customers to form special purpose finance vehicles
                    to issue
                    securitization bonds to recover the deferred costs, with
                    interest.
  61
  
 ·
                The
                    Ameren Illinois utilities filed proposed new tariffs with the
                    ICC in
                    December 2005 that would increase annual revenues from electric
                    delivery
                    services, effective January 2, 2007, by $156 million (CIPS -
                    $14 million,
                    CILCO - $33 million, IP - $109 million) per year commencing in
                    2007 and an
                    additional $46 million (CILCO - $10 million, IP - $36 million
                    per year)
                    per year commencing in 2008. In April 2006, the ICC staff recommended
                    increases in revenues for electric delivery services for Ameren
                    of $71
                    million (CIPS - $8 million decrease, CILCO - $17 million increase
                    and IP -
                    $62 million increase) and the Illinois attorney general and CUB
                    recommended increases in revenues for electric delivery services
                    of $72
                    million for Ameren (CIPS - $7 million decrease, CILCO - $19 million
                    increase and IP - $59 million increase). Other parties also made
                    recommendations in the case. The ICC has until November 2006
                    to render a
                    decision in these rate cases. See Note 2 - Rate and Regulatory
                    Matters to
                    our financial statements under Part I, Item 1, of this
                    report.
 ·
                In
                    accordance with an August 2002 MoPSC order, UE submitted a confidential
                    electric cost-of-service study to the MoPSC staff and others
                    in December
                    2005. The study was based on a test year of the twelve months
                    ending June
                    30, 2005. This submission did not constitute an electric rate
                    adjustment
                    request, but UE expects to file to adjust electric rates in Missouri
                    in
                    2006. In an early May 2006 meeting before the MoPSC, UE committed
                    to file
                    to adjust rates in Missouri by July 10, 2006, if the MoPSC staff
                    continued
                    to support a test year ending June 30, 2006, with updates through
                    January
                    1, 2007, including known and measureable fuel and purchased power
                    costs.
                    Another meeting before the MoPSC is expected later in May to
                    further
                    discuss the timing of potential rate actions related to UE. The
                    MoPSC
                    staff and other stakeholders will review any UE rate adjustment
                    request
                    and, after their analyses, may also make recommendations as to
                    electric
                    rate adjustments. Generally, a proceeding to change rates in
                    Missouri
                    could take up to 11 months.
 ·
                We
                    expect continued economic growth in our service territory to
                    benefit
                    energy demand in 2006 and beyond, but higher energy prices could
                    result in
                    reduced demand from consumers.
 ·
                UE,
                    Genco and CILCO are seeking to raise the equivalent availability
                    and
                    capacity factors of their power plants through a process improvement
                    program.
 ·
                Very
                    volatile power prices in the Midwest affect the amount of revenues
                    UE,
                    Genco and CILCO (through AERG) can generate by marketing power
                    into the
                    wholesale and interchange markets and influence the cost of power
                    we
                    purchase in the interchange markets.
 ·
                On
                    April 1, 2005, the MISO Day Two Energy Market began operating.
                    The MISO
                    Day Two Energy Market presents an opportunity for increased power
                    sales
                    from UE, Genco and CILCO power plants and improved access to
                    power for UE,
                    CIPS, CILCO and IP.
  ***Fuel
          and Purchased Power***
 
 **· **
                In
                    2005, 86% of Ameren’s electric generation (UE - 80%, Genco - 96%, CILCO -
                    99%) was supplied by its coal-fired power plants. About 85% of
                    the coal
                    used by these plants (UE - 96%, Genco - 62%, CILCO - 77%) was
                    delivered by railroads from the Powder River Basin in Wyoming.
                    In May
                    2005, the joint Burlington Northern-Union Pacific rail line in
                    the Powder
                    River Basin suffered two derailments due to unstable track conditions.
                    As
                    a result, the Federal Rail Administration placed slow orders,
                    or speed
                    restrictions, on sections of the line until the track could be
                    made safe.
                    Because of the railroad delivery problems, UE, Genco and CILCO
                    received
                    only about 90% to 95% of scheduled deliveries of Powder River
                    Basin coal
                    in 2005. The impact of the coal delivery issues on inventory
                    levels was
                    exacerbated by warm summer weather and high power prices, which
                    caused UE,
                    Genco and CILCO plants to run more and to burn record amounts
                    of coal.
                    Maintenance on the rail lines into the Powder River Basin is
                    expected to
                    continue in 2006, but to have less of an impact on deliveries
                    than in
                    2005. Further disruptions in coal deliveries could cause UE,
                    Genco and
                    CILCO to pursue a strategy that could include reducing sales
                    of power
                    during low-margin periods, utilizing higher-cost fuels to generate
                    required electricity and purchasing
                    power.
 ·
                Ameren’s
                    coal and related transportation costs are expected to increase
                    10% to 15%
                    in 2006 and an additional 15% to 20% in 2007.In
                    addition, power generation from higher-cost gas-fired plants
                    is expected
                    to increase in the next few years. See Item 3 - Quantitative
                    and
                    Qualitative Disclosures about Market Risk for information about
                    the
                    percentage of fuel and transportation requirements that are price-hedged
                    for 2006 through 2010.
 ·
                The
                    MISO Day Two Energy Market resulted in significantly higher MISO-related
                    costs in 2005. In part, these higher charges were due to volatile
                    summer
                    weather patterns and related loads. In addition, we attribute
                    some of
                    these higher charges to the relative infancy of the MISO Day
                    Two Energy
                    Market, suboptimal dispatching of power plants, and price volatility.
                    We
                    will continue to optimize our operations and work closely with
                    MISO to
                    ensure that the MISO Day Two Energy Market operates more efficiently
                    and
                    effectively in the future.
 ·
                In
                    July 2005, a new law was enacted that enables the MoPSC to put in
                    place fuel, purchased power, and environmental cost recovery
                    mechanisms
                    for Missouri’s utilities. The law also includes rate case filing
                    requirements, a 2.5% annual rate increase cap for the environmental
                    recovery mechanism, and prudency reviews, among other things.
                    Detailed
                    rules for these
  62
  mechanisms
          are expected to be effective in the second half of
          2006.
  ***Other
            Costs***
 
 ·
                In
                    December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk
                    pumped-storage hydroelectric facility. This resulted in significant
                    flooding in the local area, which damaged a state park. The incident
                    is
                    being investigated by FERC and state authorities. UE expects
                    the results
                    of these reviews later in 2006. The facility will remain out
                    of service
                    until reviews by FERC and state authorities are concluded, further
                    analyses are completed, and input is received from key stakeholders
                    as to
                    how and whether to rebuild the facility. Should the decision
                    be made to
                    rebuild the Taum Sauk plant, UE would expect it to be out of
                    service
                    through most, if not all, of 2008.
  UE
          has
          accepted responsibility for the effects of the incident. At this time,
          UE
          believes that substantially all of the damage and liabilities caused by
          the
          breach will be covered by insurance. UE expects the total cost for damage
          and
          liabilities resulting from the Taum Sauk incident to range from $53 million
          to
          $73 million. As of March 31, 2006, UE had paid $18 million and accrued
          a $35
          million liability, while expensing $1 million for the insurance deductible
          and
          recording a $52 million receivable due from insurance companies.  No
          amounts have been recognized in the financial statements relating to estimated
          costs to repair or rebuild the facility. Under UE’s insurance policies, all
          claims by or against UE are subject to review by its insurance
          carriers.
 
 As
          a
          result of this breach, UE may be subject to litigation by private parties
          or by
          state or federal authorities. Until the reviews conducted by state and
          federal
          authorities have concluded, the insurance review is completed, a decision
          whether the plant will be rebuilt is made and future regulatory treatment
          for
          the plant is determined, among other things, we are unable to determine
          the
          impact the breach may have on Ameren’s and UE’s results of operations, financial
          position, or liquidity beyond those amounts already accrued.
 ·
                UE’s
                    Callaway nuclear plant’s next scheduled refueling and maintenance outage
                    is in 2007. During an outage, which occurs every 18 months, maintenance
                    and purchased power costs increase, and the amount of excess
                    power
                    available for sale decreases, versus non-outage
                    years.
 ·
                Over
                    the next few years, we expect rising employee benefit costs as
                    well as
                    higher insurance and security costs associated with additional
                    measures we
                    have taken, or may need to take, at UE’s Callaway nuclear plant and our
                    other facilities. Insurance premiums may also increase as a result
                    of the
                    Taum Sauk incident.
 ·
                We
                    are currently undertaking cost reduction and control initiatives
                    associated with the strategic sourcing of purchases and streamlining
                    of
                    all aspects of our business.
 
 ***Capital
          Expenditures***
 
 ·
                The
                    EPA has issued more stringent emission limits on all coal-fired
                    power
                    plants. Between 2006 and 2016, Ameren expects that certain Ameren
                    Companies will be required to invest between $2.1 billion and
                    $2.9 billion
                    to retrofit their power plants with pollution control equipment.
                    More
                    stringent state regulations could increase these costs. These
                    investments
                    will also result in higher ongoing operating expenses. Approximately
                    55%
                    to 60% of this investment will be in Ameren’s regulated UE operations, and
                    therefore it is expected to be recoverable over time from ratepayers.
                    The
                    recoverability of amounts expended in non-rate-regulated operations
                    will
                    depend on whether market prices for power adjust as a result
                    of this
                    increased investment.
 ·
                In
                    March 2006, UE completed the purchase of three gas-fired CT facilities
                    with a capacity of nearly 1,500 megawatts in transactions valued
                    at $292
                    million. The purchase of these facilities is designed to meet
                    UE’s
                    increased generating capacity needs and to provide additional
                    flexibility
                    in determining future baseload generating capacity additions.
                    UE continues
                    to evaluate its longer-term needs for new baseload and peaking
                    electric
                    generation capacity, but at this time does not expect to require
                    new
                    baseload generation capacity until at least
                    2015.
 
 ***Affiliate
          Transactions***
 
 ·
                Due
                    to a MoPSC order issued in conjunction with the transfer of UE’s Illinois
                    service territory to CIPS, UE and Genco amended an agreement
                    to jointly
                    dispatch electric generation in January 2006. In 2005, such an
                    amendment
                    probably would have resulted in a transfer of electric margins
                    from Genco
                    to UE of $35 million to $45 million based on certain assumptions
                    and
                    historical results. Ameren’s consolidated earnings could be affected when
                    electric rates for UE are adjusted by the MoPSC to reflect the
                    change in
                    revenue. The Missouri OPC intervened in the FERC proceeding considering
                    approval of the proposed amendment and requested that the joint
                    dispatch
                    agreement be further amended to price all transfers at market
                    prices
                    rather than incremental cost, which could transfer additional
                    electric
                    margins from Genco to UE. In March 2006, FERC rejected the Missouri
                    OPC’s
                    request for further amendment. The ultimate impact of the amendment
                    will
                    be determined by whether the joint dispatch agreement continues
                    to exist,
                    future native load demand, the availability of electric generation
                    from UE
                    and Genco and market prices, among other things, but such impact
                    could be
                    material. See Risk Factors under Part II, Item 1A and Note 2
                    - Rate and
  63
  Regulatory Matters and Note 7 - Related Party
                  Transactions to our financial statements under Part I,
                  Item 1, of this report for a discussion of the modification to
                  the joint
                  dispatch agreement ordered by the MoPSC and the amendment sought
                  bytheMissouri OPC and
                  rejected in
                  the FERC proceeding.
 ·
                On
                    December 31, 2005, a power supply agreement for UE, CIPS and
                    IP with EEI
                    expired. Power supplied under the agreement by EEI to UE, CIPS
                    and IP was
                    priced at EEI’s cost. The expiration of this agreement may require UE,
                    Genco (as a result of its power supply agreement with CIPS) and
                    IP to
                    incur higher fuel or purchased power costs. Power previously
                    supplied
                    under this agreement to UE, CIPS and IP will be sold at market
                    prices.
                    Market prices in early 2006 were above EEI’s cost to produce power. See
                    Note 7 - Related Party Transactions to our financial statements
                    under Part
                    I, Item 1, of this report for a further discussion of the EEI
                    power supply
                    agreement.
 
 ***Recent
          Acquisitions***
 
 ·
                Ameren,
                    CILCORP, CILCO and IP expect to focus on realizing integration
                    synergies
                    associated with these acquisitions, including utilizing more
                    economical
                    fuels at CILCORP and CILCO and reducing administrative and operating
                    expenses at IP.
 
 ***Other***
 
 ·
                In
                    August 2005, President George W. Bush signed into law the Energy
                    Policy
                    Act of 2005. This legislation includes several provisions that affect
                    the Ameren Companies, including the repeal of PUHCA 1935 (under
                    which
                    Ameren was registered) effective in February 2006, and tax incentives
                    for
                    investments in pollution control equipment, electric transmission
                    property, clean coal facilities, and natural gas distribution
                    lines. The Energy Policy Act of 2005 also extends the Price-Anderson
                    nuclear plant liability provisions under the Atomic Energy Act
                    of
                    1954.
 
 The
          above
          items could have a material impact on our results of operations, financial
          position, or liquidity. Additionally, in the ordinary course of business,
          we
          evaluate strategies to enhance our results of operations, financial position,
          or
          liquidity. These strategies may include acquisitions, divestitures,
          opportunities to reduce costs or increase revenues, and other strategic
          initiatives to increase Ameren’s shareholder value. We are unable to predict
          which, if any, of these initiatives will be executed. The execution of
          these
          initiatives may have a material impact on our future results of operations,
          financial position, or liquidity.
  **REGULATORY
          MATTERS**
 
 See
          Note
          2 - Rate and Regulatory Matters to our financial statements under Part
          I, Item
          1, of this report.
 
 **ITEM
          3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
          RISK.**
 
 Market
          risk is the risk of changes in value of a physical asset or a financial
          instrument, derivative or non-derivative, caused by fluctuations in market
          variables such as interest rates, commodity prices and equity security
          prices.
          We handle market risks in accordance with established policies, which may
          include entering into various derivative transactions. In the normal course
          of
          business, we also face risks that are either nonfinancial or nonquantifiable.
          Such risks, principally business, legal and operational risks, are not
          part of
          the following discussion.
 
 Our
          risk
          management objective is to optimize our physical generating assets within
          prudent risk parameters. Our risk management policies are set by a Risk
          Management Steering Committee, which is comprised of senior-level Ameren
          officers.
 
 Except
          as
          discussed below, there have been no material changes to the quantitative
          and
          qualitative disclosures about market risk in the Ameren Companies’ combined
          Annual Report on Form 10-K for the fiscal year ended December 31, 2005.
          See Item
          7A under Part II of the 2005 Form 10-K for a more detailed discussion of
          our
          market risks.
 
 **Interest
          Rate Risk**
 
 We
          are
          exposed to market risk through changes in interest rates. The following
          table
          presents the estimated increase in our annual interest expense and decrease
          in
          net income if interest rates were to increase by 1% on variable-rate debt
          outstanding at March 31, 2006:
 
 **Interest
                    Expense**
                
                **Net
                    Income****(a)**Ameren
                $
                14
                
                $
                (9
                )UE
                
                9
                
                
                (5
                )CIPS
                
                (b
                )
                
                (b
                )Genco
                
                2
                
                
                (1
                )CILCORP
                
                4
                
                
                (2
                )CILCO
                
                2
                
                
                (1
                )IP
                
                4
                
                
                (3
                )
 (a)
                Calculations
                    are based on an effective tax rate of 38%.
 (b)
                Less
                    than $1 million.
  64
 The
            model
            does not consider potential reduced overall economic activity that would
            exist
            in such an environment. In the event of a significant change in interest
            rates,
            management would probably act to further mitigate our exposure to this
            market
            risk. However, due to the uncertainty of the specific actions that would
            be
            taken and their possible effects, this sensitivity analysis assumes no
            change in
            our financial structure.
 
 **Credit
          Risk**
 
 Credit
          risk represents the loss that would be recognized if counterparties fail
          to
          perform as contracted. NYMEX-traded futures contracts are supported by
          the
          financial and credit quality of the clearing members of the NYMEX and have
          nominal credit risk. On all other transactions, we are exposed to credit
          risk in
          the event of nonperformance by the counterparties to the
          transaction.
 
 Our
          physical and financial instruments are subject to credit risk consisting
          of
          trade accounts receivables, executory contracts with market risk exposures,
          and
          leveraged lease investments. The risk associated with trade receivables
          is
          mitigated by the large number of customers in a broad range of industry
          groups
          who make up our customer base. At March 31, 2006, no nonaffiliated customer
          represented greater than 10%, in the aggregate, of our accounts receivable.
          Our
          revenues are primarily derived from sales of electricity and natural gas
          to
          customers in Missouri and Illinois. UE, Genco, IP and Marketing Company
          may have
          credit exposure associated with interchange purchase and sale activity
          with
          nonaffiliated companies. At March 31, 2006, UE’s, Genco’s, IP’s and Marketing
          Company’s combined credit exposure to non-investment-grade counterparties
          related to interchange purchases and sales was $1 million, net of collateral.
          We
          establish credit limits for these counterparties and monitor the appropriateness
          of these limits on an ongoing basis through a credit risk management program
          that involves daily exposure reporting to senior management, master trading
          and
          netting agreements, and credit support, such as letters of credit and parental
          guarantees. We also analyze each counterparty’s financial condition before we
          enter into sales, forwards, swaps, futures or option contracts, and we
          monitor
          counterparty exposure associated with our leveraged leases. We estimate
          our
          credit exposure to MISO associated with the MISO Day Two Energy Market
          to be $32
          million at March 31, 2006.
 
 **Equity
          Price Risk**
 
 Our
          costs
          of providing defined benefit retirement and postretirement benefit plans
          are
          dependent on a number of factors, including the rate of return on plan
          assets.
          To the extent the value of plan assets declines, the effect could be reflected
          in net income and OCI, and in the amount of cash required to be contributed
          to
          the plans.
  **Commodity
          Price Risk**
 
 We
          are
          exposed to changes in market prices for electricity, fuel, and natural
          gas.
          UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are
          partially hedged through sales agreements to regulated and unregulated
          electric
          customers. Most of Genco’s and AERG’s electric power sales
          agreements expire during 2006. EEI’s cost-based power supply agreements for
          nearly all of its power expired at the end of 2005. EEI now has a contract
          to
          sell all its power to Marketing Company at market prices through December
          31,
          2015. EEI currently does not expect to hedge for price risk a significant
          portion of its available megawatthours.  Genco and AERG will probably
          participate jointly in the September 2006 Illinois power procurement auction
          through Marketing Company.  Genco and AERG will also seek to sell
          power forward to wholesale, municipal and industrial customers as has been
          its
          past practice. Ultimately, Genco and AERG will seek to hedge for price risk
          the majority of available megawatthours for 2007 by December 31, 2006.
          We also
          attempt to mitigate financial risks through structured risk management
          programs
          and policies, through structured forward-hedging programs, and through
          derivative financial instruments (primarily forward contracts, futures
          contracts, option contracts, and financial swap contracts). A derivative
          is a
          contract whose value is dependent on, or derived from, the value of some
          underlying asset.
  CIPS,
          CILCO and IP have electric rate freezes in Illinois through January 1,
          2007, and
          power supply contracts in place through December 31, 2006. In January 2006,
          the
          ICC approved a framework for CIPS, CILCO and IP to procure power for use
          by
          their customers in 2007 through a September 2006 auction. The approved
          framework
          also allows for full cost recovery of power through a rate mechanism. UE
          has an
          electric rate freeze in Missouri through June 30, 2006, and is also exposed
          to
          price risk on its interchange sales. See Note 2 - Rate and Regulatory Matters
          to
          our financial statements under Part I, Item 1, of this report for further
          information.
  65
  The
          following table presents the percentages of the projected required supply
          of
          coal and coal transportation for our coal-fired power plants, nuclear fuel
          for
          UE’s Callaway nuclear plant, natural gas for our CTs and retail distribution,
          as
          appropriate, and purchased power needs of CIPS, CILCO and IP, which own
          virtually no generation, that are price-hedged over the remainder of 2006
          through 2010:
 
 **2006**
                
                **2007**
                
                **2008**-**2010****Ameren:**Coal
                
                **100**
                **%**
                
                93
                %
                
                55
                %Coal
                    transportation
                
                **100**
                
                
                93
                
                
                60Nuclear
                    fuel
                
                **100**
                
                
                100
                
                
                69Natural
                    gas for generation
                
                **58**
                
                
                10
                
                
                1Natural
                    gas for distribution(a)
                
                **(a**
                **)**
                
                33
                
                
                6**UE:**Coal
                
                **100**
                **%**
                
                94
                %
                
                51
                %Coal
                    transportation
                
                **100**
                
                
                98
                
                
                79Nuclear
                    fuel
                
                **100**
                
                
                100
                
                
                69Natural
                    gas for generation
                
                **39**
                
                
                5
                
                
                1Natural
                    gas for distribution(a)
                
                **(a**
                **)**
                
                25
                
                
                5**CIPS:**Natural
                    gas for distribution(a)
                
                **(a**
                **)**
                
                41
                %
                
                13
                %Purchased
                    power(b)
                
                **100**
                
                
                -
                
                
                -**Genco:**Coal
                
                **100**
                **%**
                
                90
                %
                
                65
                %Coal
                    transportation
                
                **100**
                
                
                89
                
                
                38Natural
                    gas for generation
                
                **100**
                
                
                12
                
                
                2**CILCORP/CILCO:**Coal
                
                **100**
                **%**
                
                95
                %
                
                53
                %Coal
                    transportation
                
                **100**
                
                
                67
                
                
                44Natural
                    gas for distribution(a)
                
                **(a**
                **)**
                
                38
                
                
                5Purchased
                    power(b)
                
                **100**
                
                
                -
                
                
                -**IP:**Natural
                    gas for distribution(a)
                
                **(a**
                **)**
                
                30
                %
                
                3
                %Purchased
                    power(b)
                
                **90**
                
                
                -
                
                
                -
 (a)
                Represents
                    the percentage of natural gas price-hedged for the peak winter
                    season of
                    November through March. The year 2006 represents the period January
                    2006
                    through March 2006 and therefore is non-applicable (n/a) for
                    this report.
                    The year 2007 represents November 2006 through March 2007. This
                    continues
                    each successive year through March
                    2010.
 (b)
                Beginning
                    in 2007, CIPS, CILCO and IP are expected to purchase all electric
                    capacity
                    and energy through a power procurement auction process approved
                    by the
                    ICC. See Note 2 - Rate and Regulatory Matters to our financial
                    statements
                    under Part I, Item 1, of this report for a discussion of this
                    matter.
 
 The
          following table shows how our total fuel expense might increase and how
          our net
          income might decrease if coal and coal transportation costs were to increase
          by
          1% on any requirements not currently covered by fixed-price contracts for
          the
          remainder of 2006 through 2010:
 
 **Coal**
                
                **Transportation****Fuel**
                  **Expense**
                
                **Net**
                  **Income****(a)**
                
                **Fuel**
                  **Expense**
                
                **Net**
                  **Income****(a)**Ameren
                $
                10
                
                $
                (6
                )
                $
                10
                
                $
                (6
                )UE
                
                6
                
                
                (3
                )
                
                3
                
                
                (2
                )Genco
                
                3
                
                
                (2
                )
                
                4
                
                
                (3
                )CILCORP/CILCO
                
                1
                
                
                (1
                )
                
                2
                
                
                (1
                )
 (a)
                Calculations
                    are based on an effective tax rate of
                    38%.
 
 In
          the
          event of a significant change in coal prices, UE, Genco and CILCO would
          probably
          take actions to further mitigate
          their exposure to this market risk. However, due to the uncertainty of
          the
          specific actions that would be taken and their possible effects, this
          sensitivity analysis assumes no change in our financial structure or fuel
          sources. As discussed in Note 2 - Rate and Regulatory Matters under Part
          I, Item
          1, of this report, Missouri legislation has been approved that could mitigate
          the impact of increased fuel cost at Ameren and UE through UE’s ability to
          recover these increases in rates.
 
 See
          Note
          8 - Commitments and Contingencies to our financial statements under Part
          I, Item
          1, of this report for further information.
  66
  **Fair
          Value of Contracts**
 
 Most
          of
          our commodity contracts qualify for treatment as normal purchases and normal
          sales. We use derivatives principally to manage the risk of changes in
          market
          prices for natural gas, fuel, electricity and emission credits. The following
          table presents the favorable (unfavorable) changes in the fair value of
          all
          derivative contracts marked-to-market during the quarter ended March 31,
          2006.
          The sources used to determine the fair value of these contracts were active
          quotes, other external sources, and other modeling and valuation methods.
          All of
          these contracts have maturities of less than four years.
 
 **Ameren**(a)
                
                **UE**
                
                **CIPS**
                
                **CILCORP/**
                  **CILCO**
                
                **IP**Fair
                    value of contracts at beginning of period, net
                $
                69
                
                $
                (5
                )
                $
                12
                
                $
                50
                
                $
                (2
                )Contracts
                    realized or otherwise settled during the period
                
                (12
                )
                
                (2
                )
                
                (3
                )
                
                (4
                )
                
                (1
                )Changes
                    in fair values attributable to changes in valuation technique
                    and
                    assumptions
                
                -
                
                
                -
                
                
                -
                
                
                -
                
                
                -Fair
                    value of new contracts entered into during the period
                
                -
                
                
                1
                
                
                -
                
                
                -
                
                
                -Other
                    changes in fair value
                
                (27
                )
                
                3
                
                
                (3
                )
                
                (22
                )
                
                5Fair
                    value of contracts outstanding at end of period, net
                $
                30
                
                $
                (3
                )
                $
                6
                
                $
                24
                
                $
                2
 (a)
                Includes
                    amounts for Ameren registrant and nonregistrant subsidiaries
                    and
                    intercompany eliminations.
 
 **ITEM
          4. CONTROLS AND PROCEDURES.**
  (a)
                Evaluation
                    of Disclosure Controls and
                    Procedures
 
 As
          of
          March 31, 2006, the principal executive officer and principal financial
          officer
          of each of the Ameren Companies have evaluated the effectiveness of the
          design
          and operation of each registrant’s disclosure controls and procedures (as
          defined in Rules 13a - 15(e) and 15d - 15(e) of the Exchange Act). Upon
          making
          that evaluation, the principal executive officer and principal financial
          officer
          of each of the Ameren Companies have concluded that such disclosure controls
          and
          procedures are effective in timely alerting them to any material information
          relating to such registrant that is required in such registrant’s reports filed
          or submitted to the SEC under the Exchange Act, and are effective in ensuring
          that information required to be disclosed in reports filed under the Exchange
          Act is recorded, processed, summarized and reported within the time periods
          specified in the SEC’s rules and forms.
 
 (b)
                Change
                    in Internal Controls
 
 There
          has
          been no change in the Ameren Companies’ internal control over financial
          reporting during their most recent fiscal quarter that has materially affected,
          or is reasonably likely to materially affect, their internal control over
          financial reporting.
 
 **PART
          II. OTHER INFORMATION**
 
 **ITEM
          1. LEGAL PROCEEDINGS.**
 
 We
          are
          involved in legal and administrative proceedings before various courts
          and
          agencies with respect to matters that arise in the ordinary course of business,
          some of which involve substantial amounts of money. We believe that the
          final
          disposition of these proceedings, except as otherwise disclosed in this
          report,
          will not have a material adverse effect on our results of operations, financial
          position, or liquidity. Risk of loss is mitigated, in some cases, by insurance
          or contractual or statutory indemnification. We believe that we have established
          appropriate reserves for potential losses.
 
 Note
          2 -
          Rate and Regulatory Matters, Note 7 - Related Party Transactions and Note
          8 -
          Commitments and Contingencies to our financial statements under Part I,
          Item 1,
          of this report contain information on legal and administrative proceedings
          which
          are incorporated by reference under this item.
  **ITEM
          1A. RISK FACTORS.**
 
 The
          Ameren Companies’ combined Annual Report on Form 10-K for the fiscal year ended
          December 31, 2005, includes a detailed discussion of our risk factors.
          The
          information presented below updates and should be read in conjunction with
          the
          risk factors and information disclosed in that Form 10-K.
  67
  **The
          electric and gas rates that certain Ameren Companies are allowed to charge
          in
          Missouri and Illinois are largely set through 2006. These “rate freezes,” along
          with other actions of lawmakers and regulators that can significantly adversely
          affect our prospective earnings, liquidity, or business activities, are
          largely
          outside our control.**
 
 The
          rates
          that certain Ameren Companies are allowed to charge for their services
          are the
          single most important item influencing the results of operations, financial
          position, or liquidity of the Ameren Companies. Our industry is highly
          regulated. The regulation of the rates that we charge our customers is
          determined, in large part, by governmental entities outside of our control,
          including the MoPSC, the ICC, and FERC. Decisions made by these entities
          could
          have a material adverse impact on our businesses including our results
          of
          operations, financial position, or liquidity.
 
 As
          a part
          of the settlement of UE’s Missouri electric rate case in August 2002, UE is
          subject to a rate moratorium that prohibits changes in its electric rates
          in
          Missouri before July 1, 2006. Furthermore, as part of the settlement of
          UE’s
          Missouri gas rate case, which was approved by the MoPSC in January 2004, UE
          agreed to make no changes in its gas delivery rates prior to July 1, 2006,
          with certain exceptions. In late December 2005, UE submitted a confidential
          cost-of-service study based on a test year of the twelve months ending
          June 30,
          2005. This submission did not constitute an electric rate adjustment request,
          but UE expects to file to adjust electric rates in Missouri in 2006. In
          an early
          May 2006 meeting before the MoPSC, UE committed to file to adjust rates
          in
          Missouri by July 10, 2006, if the MoPSC staff continued to support a test
          year
          ending June 30, 2006, with updates through January 1, 2007, including known
          and
          measureable fuel and purchased power costs. Another meeting before the
          MoPSC is
          expected later in May to further discuss the timing of potential rate actions
          related to UE. The MoPSC staff and other stakeholders will review any UE
          rate
          adjustment request and, after their analyses, may also make recommendations
          as
          to electric rate adjustments. Generally, a proceeding to change rates in
          Missouri could take up to 11 months.
 
 The
          ICC
          order approving Ameren’s acquisition of IP prohibited IP from filing for any
          increase in gas delivery rates effective before January 1, 2007, beyond
          IP’s
          then-pending request for a gas delivery rate increase. In addition, a provision
          of the Illinois Customer Choice Law related to the restructuring of the
          Illinois
          electric industry put a rate freeze into effect through January 1, 2007,
          for CIPS, CILCO and IP. This Illinois legislation also requires that 50%
          of the
          earnings from each respective jurisdiction in excess of certain levels
          be
          refunded to CIPS’, CILCO’s and IP’s Illinois customers through 2006. In January
          2006, the ICC approved a framework for CIPS, CILCO and IP to procure power
          for
          use by their customers in 2007 through an auction and related tariffs.
          This
          approval is subject to a pending court appeal. In addition, certain Illinois
          legislators, the Illinois attorney general, the Illinois governor, and
          other
          parties have sought and continue to seek to block the power procurement
          auction
          and/or the recovery, through rates to customers, of related costs for power
          supply resulting from the auction. Any decision or action that impairs
          CIPS’,
          CILCO’s and IP’s ability to fully recover purchased power costs from their
          electric customers in a timely manner could result in material adverse
          consequences for these companies and for Ameren, including a significant
          drop in
          credit ratings (possibly to below investment-grade status), a loss of access
          to
          the capital markets, higher borrowing costs, higher power supply costs,
          an
          inability to make timely energy infrastructure investments, impaired customer
          service, job losses, and financial insolvency.
 
 The
          Illinois legislature held hearings in 2005 and 2006 regarding the framework
          for
          retail rate determination and power procurement. In February 2006, legislation
          was introduced in the Illinois House of Representatives that would extend
          the
          electric rate freeze in Illinois through 2010.  CIPS, CILCO and IP strongly
          believe that an extension of the electric rate freeze in Illinois would
          not be
          in the best interests of any of the Ameren Illinois utilities or their
          customers, and have been working with key stakeholders in Illinois to develop
          a
          constructive rate increase phase-in plan for residential customers to address
          the potential significant increases in customer rates for our Illinois
          utilities
          beginning in 2007.  We believe that a rate increase phase-in plan would
          need to allow for deferral of a portion of the power procurement costs,
          with
          provision for full and timely recovery of all deferred costs in a manner
          that
          would not result in further reductions in credit ratings from December
          31, 2005
          levels. We believe a rate increase phase-in plan, providing for deferral of
          costs with certainty of full and timely recovery of any deferred costs,
          would
          require legislation in Illinois. In March 2006, legislation was introduced
          in
          the Illinois House of Representatives that would allow the deferral of
          a portion
          of the power procurement costs and would authorize the ICC to permit utilities
          with fewer than one million retail customers to form special purpose finance
          vehicles to issue securitization bonds to recover the deferred costs, with
          interest.  CIPS, CILCO and IP each have less than one million retail
          customers.  Securitization would allow these special purpose vehicles to
          issue debt securities and use the proceeds to pay the utilities immediately
          upon
          issuance of the bonds for the deferred power costs for which the utilities
          did
          not receive reimbursement from customers during a phase-in deferral
          period.  Customers would fund, through dedicated charges included in
          electric bills, a future
 68
  payment
          stream that would be used to service the securitized debt.  In effect,
          through these charges utility customers would pay in the future for power
          used,
          but not paid for, during a phase-in deferral period.  This approach has the
          effect of spreading over the life of the bonds, a period of up to 10 years,
          the
          potentially significant initial electric rate increase for residential
          customers
          that would otherwise be necessary to pay the costs on a current basis,
          and we
          believe assisting our Ameren Illinois utilities in maintaining their financial
          integrity. We cannot predict what actions, if any, the Illinois legislature
          may ultimately take. Any decision or action that impairs CIPS’, CILCO’s and
          IP’s ability to fully recover purchased power costs from their electric
          customers in a timely manner could result in material adverse consequences
          for
          these companies and for Ameren.
 
 Ameren,
          CIPS, CILCO and IP will continue to explore a number of legal and regulatory
          actions, strategies and alternatives to address these Illinois electric
          issues.
          There can be no assurance that Ameren and the Ameren Illinois utilities
          will
          prevail over the stated opposition by certain Illinois legislators, the
          Illinois
          attorney general, the Illinois governor and other stakeholders, or that
          the
          legal and regulatory actions, strategies and alternatives that Ameren and
          the
          Ameren Illinois utilities are considering will be successful.
 
 In
          December 2005, the Ameren Illinois utilities filed with the ICC proposed
          new
          tariffs that would increase revenues from electric delivery services, effective
          January 2, 2007, based on a proposed residential rate phase-in plan, by
          $156
          million (CIPS - $14 million, CILCO - $33 million, IP - $109 million) per
          year
          commencing in 2007 and an additional $46 million (CILCO - $10 million,
          IP - $36
          million) per year commencing in 2008. In April 2006, the ICC staff recommended
          increases in revenues for electric delivery services for Ameren of $71
          million
          (CIPS - $8 million decrease, CILCO - $17 million increase and IP - $62
          million
          increase) and the Illinois attorney general and CUB recommended increases
          in
          revenues for electric delivery services for Ameren of $72 million (CIPS
          - $7
          million decrease, CILCO - $19 million increase and IP - $59 million increase).
          Other parties also made recommendations in the case. These proposed tariffs
          are
          subject to approval of, and reduction by, the ICC, which is expected to
          rule by
          November 2006. We cannot predict the outcome of these proceedings.
 
 As
          a part
          of the settlement of UE’s Missouri electric rate case in 2002, UE made a
          commitment to make $2.25 billion to $2.75 billion in critical energy
          infrastructure investments from January 1, 2002 through June 30, 2006.
          Ameren also committed IP to make between $275 million and $325 million in energy
          infrastructure investments over its first two years of ownership, in conjunction
          with the ICC’s approval of Ameren’s acquisition of IP. UE’s agreement to a rate
          moratorium in Missouri and CIPS’, CILCO’s and IP’s rate freezes mean that
          capital expenditures will not become recoverable in rates and will not
          earn a
          return before at least July 1, 2006, for UE and January 2, 2007, for CIPS,
          CILCO
          and IP. In the current climate of rate reductions and rate moratoriums,
          any new
          energy infrastructure and new programs could result in increased financing
          requirements for UE, CIPS, CILCO and IP. This could have a material impact
          on
          our results of operations, financial position, or liquidity.
 
 The
          Ameren Companies do not currently have, in either Missouri or Illinois,
          a rate
          adjustment clause for their electric operations that would allow them to
          recover
          the costs for purchased power or increased fuel costs from customers. Therefore,
          insofar as we have not hedged our fuel and power costs, we are exposed
          to
          changes in fuel and power prices to the extent that fuel for our electric
          generating facilities and power must be purchased on the open market.
 
 Steps
          taken and being considered at the federal and state levels continue to
          change
          the structure of the electric industry and utility regulation. At the federal
          level, FERC has been mandating changes in the regulatory framework for
          transmission-owning public utilities such as UE, CIPS, CILCO and IP.
 
 Principally
          because of rate reductions and moratoriums, and increased costs and investments
          have caused decreased returns in Ameren’s distribution utility businesses. In
          response to competitive, economic, political, legislative and regulatory
          pressures, we may be subject to further rate moratoriums, rate refunds,
          limits
          on rate increases or rate reductions, including phase-in plans. Any or
          all of
          these could have a significant adverse effect on our results of operations,
          financial position, or liquidity.
 
 **UE,
          CIPS and Genco are parties to an agreement to jointly dispatch power.
          Modification or termination of this agreement could result in the transfer
          of
          electric margins from Genco to UE and the reduction of electric margins
          at
          Ameren.**
 
 Genco
          and
          UE have an agreement to dispatch their generating facilities jointly. Recently
          completed, ongoing or future federal and state regulatory proceedings and
          policies, among other things, may evolve in ways that could affect Genco’s and
          UE’s ability to participate in this affiliate arrangement on current terms.
          For
          example, as a result of the February 2005 MoPSC order approving the transfer
          of
          UE’s Illinois service territory to CIPS in 2005, the provision in the joint
          dispatch agreement which determines the allocation between UE and Genco
          of
          margins or profits from short-term sales of excess generation to third
          parties
          had to be modified. Specifically, the MoPSC order required an amendment
          so that
          margins on third-party short-term sales of excess generation to third parties
          had to be modified. Specifically, the MoPSC order required an amendment
          so that
          margins on third-party short-term
  69
  power
          sales of excess generation would be allocated between UE and Genco based
          on
          generation output, not on load requirements, as the agreement had provided.
          In
          compliance with the MoPSC order, UE, CIPS and Genco, on January 9, 2006,
          filed
          this amendment to the joint dispatch agreement with FERC for its approval.
 
 The
          Missouri OPC intervened in the FERC proceeding and requested that the joint
          dispatch agreement be further amended to price all transfers of power between
          Genco and UE at market prices rather than incremental cost, which could
          transfer
          additional electric margins from Genco to UE. In March 2006, FERC denied
          the
          Missouri OPC request and approved the amendment filed by UE, CIPS and Genco
          effective January 10, 2006. This change in the allocation methodology resulted
          in a $9 million transfer of electric margins from Genco to UE during the
          first
          quarter of 2006.
 
 Should
          the joint dispatch agreement be modified to price transfers at market prices
          as
          a result of some future regulatory proceeding (for example, by the MoPSC
          in a
          ratemaking proceeding), or otherwise, an evaluation of the continued benefits
          of
          the joint dispatch agreement would have to be made by UE, CIPS and Genco.
          Depending on the outcome of the evaluations, one or more of these companies
          may
          decide to terminate the agreement. UE, CIPS and Genco have the right to
          terminate this agreement with one year’s notice, unless terminated earlier by
          mutual consent. Ameren, UE, CIPS and Genco cannot predict whether any additional
          actions may be taken by regulatory agencies on this matter in the
          future.
 
 For
          the
          full year 2005, Genco received net transfers of 8.7 million megawatthours
          of
          power from UE.  In 2005, Genco sold 2.9 million megawatthours of power to
          UE, generating revenue of $74 million, and purchased 11.6 million megawatthours
          from UE at a cost of $230 million. While it cannot be predicted what level
          of
          power purchases and sales will occur between the two companies in the future,
          UE
          and Genco believe that under normal operating conditions, the level of
          net
          transfers under the joint dispatch agreement from UE to Genco will decline
          in
          2006 from 2005 levels, which was a historical high, due to less excess
          generation being available at UE. This is expected to result from greater
          native
          load demand in 2006 at UE, resulting from the addition of Noranda as a
          customer
          in June 2005, continued organic growth, and the expiration of a cost-based
          EEI
          power supply contract with UE, among other things. A cost-based EEI power
          supply
          contract with CIPS (which had been assigned to Genco through Marketing
          Company)
          also expired on December 31, 2005. CIPS load previously served by EEI and
          additional CIPS load created by the transfer of UE’s Illinois service territory
          to CIPS in May 2005 is being served by other available Genco resources,
          including generation available pursuant to the joint dispatch agreement,
          beginning January 1, 2006.
  By
          the
          end of 2006, Genco’s electric power supply agreements with its primary customer,
          CIPS (through Marketing Company), and most of its wholesale and retail
          customers
          will expire. Strategies for participation in the expected CIPS, CILCO and
          IP
          September 2006 power procurement auction, and for sales to other customers
          for
          2006 and beyond, are currently being developed and implemented. In the
          event the
          joint dispatch agreement is terminated or amended to price all transfers
          at
          market prices, the amount of generation available to Genco from its own
          power
          plants will determine the amount of power it will offer into the power
          procurement auction and to wholesale, retail and interchange customers.
          As a
          result, we would expect future sales volumes from Genco to be lower than
          prior
          years, and related fuel and purchased power costs to increase. However,
          Genco
          believes that future sales may be contracted at higher prices since the
          power
          supply agreement between CIPS and Genco and substantially all of the other
          wholesale and retail contracts that expire in 2006 are below market prices
          for
          similar contracts in early 2006. Due to all of these factors, the ultimate
          impact of the potential changes to Genco’s results of operations, financial
          position, or liquidity are unable to be determined at this time; however,
          the
          impact could be material.
 
 If
          the
          joint dispatch agreement did not exist or was amended to price all transfers
          at
          market prices, UE may be able to retain the net transfers of power that
          are
          currently going to Genco under the joint dispatch agreement and could sell
          this
          power in the interchange market at market prices, instead of incremental
          cost.
          At certain times, UE may also be required to use power from its own higher-cost
          power plants or purchase power to meet its load requirements. The margin
          impact
          to UE of the potential termination of the joint dispatch agreement or an
          amendment to price all transfers at market prices has not been quantified,
          but
          UE believes it would significantly increase its electric margins. Any increase
          in UE’s electric margins as a result of actual or imputed changes to the joint
          dispatch agreement would likely result in a decrease in UE’s revenue
          requirements in its next rate adjustment proceeding. The ultimate ratemaking
          treatment for the joint dispatch agreement will be determined in a future
          rate
          proceeding.
 
 While
          UE’s and Genco’s results of operations, financial position, or liquidity could
          be materially impacted by an amendment to price all transfers at market
          prices
          or termination of the joint dispatch agreement, these changes would not
          have a
          material impact on CIPS. Further, Ameren’s earnings would be unaffected until
          electric rates for UE are adjusted by the MoPSC to reflect the impact of
          the
          proposed amendments or other changes to the joint dispatch agreement.
  70
  **ITEM
          2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF
          PROCEEDS.**
  The
          following table presents Ameren Corporation’s purchases of equity securities
          reportable under Item 703 of Regulation S-K:
 
 **Period**
                **(a)
                    Total Number**
                  **of
                    Shares**
                  **(or
                    Units)**
                  **Purchased****(a)**
                
                **(b)
                    Average Price**
                  **Paid
                    per Share**
                  **(or
                    Unit)**
                
                **(c)
                    Total Number of Shares (or**
                  **Units)
                    Purchased as Part of**
                  **Publicly
                    Announced Plans or**
                  **Programs**
                
                **(d)
                    Maximum Number (or**
                  **Approximate
                    Dollar Value) of**
                  **Shares
                    (or Units) that May Yet Be**
                  **Purchased
                    Under the Plans or**
                  **Programs**January
                    1 - January 31, 2006
                
                22,150
                
                $
                51.51
                
                
                -
                
                
                -February
                    1 - February 28, 2006
                
                1,830
                
                
                50.76
                
                
                -
                
                
                -March
                    1 - March 31, 2006
                
                79,303
                
                
                50.45
                
                
                -
                
                
                -Total
                
                103,283
                
                $
                50.68
                
                
                -
                
                
                -
 (a)
                Included
                    in January were 10,000 shares of Ameren common stock purchased
                    by Ameren
                    in open-market transactions pursuant to Ameren’s Long-term Incentive Plan
                    of 1998 in satisfaction of Ameren’s obligations for director compensation
                    awards. Included in March were 79,303 shares of Ameren common
                    stock
                    purchased by Ameren from employee participants to satisfy participants’
                    tax obligations incurred by the release of restricted shares
                    of Ameren
                    common stock under the Long-term Incentive Plan of 1998. The
                    remaining
                    shares of Ameren common stock were purchased by Ameren in open-market
                    transactions in satisfaction of Ameren’s obligation upon the exercise by
                    employees of options issued under Ameren’s Long-term Incentive Plan of
                    1998. Ameren does not have any publicly announced equity securities
                    repurchase plans or programs.
 
 None
          of
          the other registrants purchased equity securities reportable under Item
          703 of
          Regulation S-K during the January 1 to March 31, 2006, period.
 
 **ITEM
          6. EXHIBITS.**
 
 (a)  Exhibits. The documents listed below are being filed on behalf of Ameren,
          UE,
          CIPS, Genco, CILCORP, CILCO and IP as indicated.
  
 **Exhibit
                    Designation**
                **Registrant(s)**
                **Nature
                    of Exhibit****Rule
                    13a-14(a) / 15d-14(a) Certifications**31.1
                Ameren
                Rule
                    13a-14(a)/15d-14(a) Certification of Principal Executive Officer
                    of
                    Ameren31.2
                Ameren
                Rule
                    13a-14(a)/15d-14(a) Certification of Principal Financial Officer
                    of
                    Ameren31.3
                UE
                  CIPS
                  CILCORP
                  CILCO
                  IP
                Rule
                    13a-14(a)/15d-14(a) Certification of Principal Executive Officer
                    of UE,
                    CIPS, CILCORP, CILCO and IP31.4
                UE
                  CIPS
                  Genco
                  CILCORP
                  CILCO
                  IP
                Rule
                    13a-14(a)/15d-14(a) Certification of Principal Financial Officer
                    of UE,
                    CIPS, Genco, CILCORP, CILCO and IP31.5
                Genco
                Rule
                    13a-14(a)/15d-14(a) Certification of Principal Executive Officer
                    of
                    Genco**Section
                    1350 Certifications**32.1
                Ameren
                  UE
                  CIPS
                  CILCORP
                  CILCO
                  IP
                Section
                    1350 Certification of Principal Executive Officer and Principal
                    Financial
                    Officer of Ameren, UE, CIPS, CILCORP, CILCO and IP32.2
                Genco
                Section
                    1350 Certification of Principal Executive Officer and Principal
                    Financial
                    Officer of Genco
 71
 **SIGNATURES**
 
 Pursuant
                to the requirements of the Exchange Act, each registrant has duly
                caused this
                report to be signed on its behalf by the undersigned thereunto duly
                authorized.
                The signature for each undersigned company shall be deemed to relate
                only to
                matters having reference to such company or its
                subsidiaries.
 AMEREN
        CORPORATION
 (Registrant)
 
 /s/ Martin J.
        Lyons
 Martin
        J.
        Lyons
 Vice
        President and Controller   ****
 (Principal
        Accounting Officer)
 
 
 
 
 UNION
        ELECTRIC COMPANY
 (Registrant)
  /s/
        Martin J.
        Lyons
 Martin
        J.
        Lyons
 ** Vice
        President and Controller
 (Principal
        Accounting Officer)
 
 
 
 
 CENTRAL
        ILLINOIS PUBLIC SERVICE COMPANY
 (Registrant)
 
 /s/
        Martin J.
        Lyons
 Martin
        J.
        Lyons
 Vice
        President and Controller   ****
 (Principal
        Accounting Officer)
 
 
 
 AMEREN ENERGY GENERATING COMPANY
 (Registrant)
  /s/ Martin J.
        Lyons
 Martin
        J.
        Lyons
 ** Vice
        President and Controller
 (Principal
        Accounting Officer)
  72
  CILCORP INC .
 (Registrant)
  /s/
              Martin J.
              Lyons
 Martin J. Lyons
 ** Vice
              President and Controller
 (Principal
              Accounting Officer)
  
 CENTRAL
        ILLINOIS LIGHT COMPANY
 (Registrant)
 
 /s/ Martin J. Lyons
 Martin
        J.
        Lyons
 ** Vice
        President and Controller
 (Principal
        Accounting Officer)
 
 
 
 
 ILLINOIS
        POWER COMPANY
 (Registrant)
 
 /s/
        Martin J.
        Lyons
 Martin
        J.
        Lyons
 ** Vice
        President and Controller
 (Principal
        Accounting Officer)
 
 
 
 Date:
        May
        10, 2006
 
 73