**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 September 30, 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 require-ments
          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
          November 1, 2006, was as follows:
 
 Ameren
                    Corporation
                Common
                    stock, $.01 par value per share - 206,262,150Union
                    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
                57Item
                    3.Quantitative
                    and Qualitative Disclosures About Market Risk
                82Item
                    4.Controls
                    and Procedures
                85**PART
                    II****Other
                    Information**Item
                    1.Legal
                    Proceedings
                85Item
                    1A.Risk
                    Factors
                86Item
                    2.Unregistered
                    Sales of Equity Securities and Use of Proceeds
                90Item
                    6.Exhibits
                90Signatures
                92
 
 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 is a power marketing
          and
          risk management agent for affiliated companies. Beginning in 2007, Ameren
          Energy
          will only serve UE.
 ***Ameren
          Illinois utilities*** - CIPS,
          CILCO and IP.
 ***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.
 ***Cooling
          degree-days*** - The
          summation of positive differences between the mean daily temperature and
          a 65-degree
          Fahrenheit base. The statistic is useful as an indicator of demand for
          electricity for summer space cooling for residential and commercial
          customers.
 ***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 and
          Marketing Company parent.
 ***DOE*** -
          Department of Energy, a U.S. government agency.
 ***DRPlus*** -
          Ameren
          Corporation’s dividend reinvestment and direct stock purchase plan.
 ***Dynegy*** -
          Dynegy
          Inc.
 ***DYPM*** -
          Dynegy
          Power Marketing, Inc., a Dynegy subsidiary.
 ***EEI*** -
          Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary (40%
          owned by
          UE and 40% owned by Development Company) that operates non-rate-regulated
          electric generation and electric 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.
 ***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. A FIN statement is an explanation intended to clarify accounting
          pronouncements previously issued by the FASB.
 ***Fitch*** - Fitch
          Ratings, a credit rating agency.
 ***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.
 ***Illinois
          Regulated*** - A
          financial reporting segment consisting of the regulated electric and gas
          transmission and distribution businesses of CIPS, CILCO and IP.
   5
 ***IP*** - ****** Illinois
          Power Company, an Ameren Corporation subsidiary that was acquired from
          Dynegy 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 Liability Company to issue Transitional
          Funding Trust Notes 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.
 ***JDA*** - The
          joint dispatch agreement among UE, CIPS, and Genco under which UE and Genco
          jointly dispatch electric generation. This agreement will terminate on
          December
          31, 2006.
 ***Kilowatthour*** - ****** A
          measure
          of electricity consumption equivalent to the use of 1,000 watts of power
          over a
          period of one hour.
 ***Marketing
          Company*** - ****** Ameren
          Energy Marketing Company, a Development Company subsidiary that markets
          power
          for Genco, AERG and EEI primarily for periods over one year.
 ***Medina
          Valley*** -
          AmerenEnergy ****** Medina
          Valley Cogen (No. 4) LLC and its subsidiaries, which are all Development
          Company
          subsidiaries and 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.
 ***Missouri
          Regulated*** - A
          financial reporting segment consisting of all the operations of UE’s business
          except for UE’s 40% interest in EEI and other non-rate-regulated
          activities.
 ***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.
 ***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.
 ***Non-rate-regulated
          Generation*** - A
          financial reporting segment consisting of the operations or activities
          of Genco,
          CILCORP holding company, AERG, EEI and Marketing Company.
 ***NO*** ***x*** ****** - ****** Nitrogen
          oxide.
 ***Noranda*** -
          Noranda Aluminum, Inc.
 ***NYMEX*** -
          New
          York Mercantile Exchange.
 ***OCI*** - ****** Other
          comprehensive income (loss) as defined by GAAP.
 ***PUHCA
          1935*** -
          The
          Public Utility Holding Company Act of 1935, which was repealed, effective
          February 8, 2006, by the Energy Policy Act of 2005 that was enacted on
          August 8,
          2005.
 ***PUHCA
          2005*** - The
          Public Utility Holding Company Act of 2005, that was 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.
 ***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” provisions 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
                    or legislative actions, including changes in regulatory policies
                    and
                    ratemaking determinations, such




6


as
      the outcome of UE, CIPS, CILCO and IP rate proceedings or the
      enactment of an extension of an electric rate freeze or similar action that
      impairs the full and timely recovery


of
      costs in Illinois;


·
            the
                impact of the termination of the
                JDA;


·
            changes
                in laws and other governmental actions, including monetary and fiscal
                policies;


·
            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;


·
            the
                impact of system outages caused by severe weather conditions or other
                events;


·
            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 and affiliates 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**
                **September
                  30,**
              
              **Nine
                  Months Ended**
                **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005****Operating
                  Revenues:**Electric
              **$**
              **1,767**
              
              $
              1,732
              
              **$**
              **4,356**
              
              $
              4,257Gas
              
              **143**
              
              
              149
              
              
              **904**
              
              
              819Other
              
              **-**
              
              
              -
              
              
              **-**
              
              
              3Total
                  operating revenues
              
              **1,910**
              
              
              1,881
              
              
              **5,260**
              
              
              5,079**Operating
                  Expenses:**Fuel
                  and purchased power
              
              **623**
              
              
              634
              
              
              **1,672**
              
              
              1,524Gas
                  purchased for resale
              
              **84**
              
              
              90
              
              
              **641**
              
              
              550Other
                  operations and maintenance
              
              **395**
              
              
              392
              
              
              **1,137**
              
              
              1,112Depreciation
                  and amortization
              
              **162**
              
              
              158
              
              
              **489**
              
              
              472Taxes
                  other than income taxes
              
              **99**
              
              
              98
              
              
              **302**
              
              
              284Total
                  operating expenses
              
              **1,363**
              
              
              1,372
              
              
              **4,241**
              
              
              3,942**Operating
                  Income**
              
              **547**
              
              
              509
              
              
              **1,019**
              
              
              1,137**Other
                  Income and Expenses:**Miscellaneous
                  income
              
              **5**
              
              
              6
              
              
              **13**
              
              
              19Miscellaneous
                  expense
              
              **(3**
              **)**
              
              (1
              )
              
              **(4**
              **)**
              
              (7
              )Total
                  other income
              
              **2**
              
              
              5
              
              
              **9**
              
              
              12**Interest
                  Charges**
              
              **82**
              
              
              70
              
              
              **238**
              
              
              221**Income
                  Before Income Taxes, Minority Interest****and
                  Preferred Dividends of Subsidiaries**
              
              **467**
              
              
              444
              
              
              **790**
              
              
              928**Income
                  Taxes**
              
              **161**
              
              
              159
              
              
              **273**
              
              
              330**Income
                  Before Minority Interest and Preferred****Dividends
                  of Subsidiaries**
              
              **306**
              
              
              285
              
              
              **517**
              
              
              598**Minority
                  Interest and Preferred Dividends****of
                  Subsidiaries**
              
              **(13**
              **)**
              
              (5
              )
              
              **(31**
              **)**
              
              (12
              )**Net
                  Income**
              **$**
              **293**
              
              $
              280
              
              **$**
              **486**
              
              $
              586**Earnings
                  per Common Share – Basic and Diluted**
              **$**
              **1.42**
              
              $
              1.37
              
              **$**
              **2.37**
              
              $
              2.94**Dividends
                  per Common Share**
              **$**
              **0.635**
              
              $
              0.635
              
              **$**
              **1.905**
              
              $
              1.905**Average
                  Common Shares Outstanding**
              
              **205.9**
              
              
              203.8
              
              
              **205.4**
              
              
              199.6




**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)****September
                      30,**
                  
                  **December
                      31,****2006**
                  
                  **2005****ASSETS****Current
                      Assets:**Cash
                      and cash equivalents
                  **$**
                  **34**
                  
                  $
                  96Accounts
                      receivable – trade (less allowance for doubtfulaccounts
                      of $13 and $22, respectively)
                  
                  **463**
                  
                  
                  552Unbilled
                      revenue
                  
                  **267**
                  
                  
                  382Miscellaneous
                      accounts and notes receivable
                  
                  **116**
                  
                  
                  31Materials
                      and supplies
                  
                  **710**
                  
                  
                  572Other
                      current assets
                  
                  **147**
                  
                  
                  185Total
                      current assets
                  
                  **1,737**
                  
                  
                  1,818**Property
                      and Plant, Net**
                  
                  **14,028**
                  
                  
                  13,572**Investments
                      and Other Assets:**Investments
                      in leveraged leases
                  
                  **31**
                  
                  
                  50Nuclear
                      decommissioning trust fund
                  
                  **271**
                  
                  
                  250Goodwill
                  
                  **976**
                  
                  
                  976Intangible
                      assets
                  
                  **228**
                  
                  
                  246Other
                      assets
                  
                  **753**
                  
                  
                  419Regulatory
                      assets
                  
                  **806**
                  
                  
                  831Total
                      investments and other assets
                  
                  **3,065**
                  
                  
                  2,772**TOTAL
                      ASSETS**
                  **$**
                  **18,830**
                  
                  $
                  18,162**LIABILITIES
                      AND STOCKHOLDERS' EQUITY****Current
                      Liabilities:**Current
                      maturities of long-term debt
                  **$**
                  **465**
                  
                  $
                  96Short-term
                      debt
                  
                  **311**
                  
                  
                  193Accounts
                      and wages payable
                  
                  **382**
                  
                  
                  706Taxes
                      accrued
                  
                  **249**
                  
                  
                  131Other
                      current liabilities
                  
                  **433**
                  
                  
                  361Total
                      current liabilities
                  
                  **1,840**
                  
                  
                  1,487**Long-term
                      Debt, Net**
                  
                  **5,349**
                  
                  
                  5,354**Preferred
                      Stock of Subsidiary Subject to Mandatory
                      Redemption**
                  
                  **18**
                  
                  
                  19**Deferred
                      Credits and Other Liabilities:**Accumulated
                      deferred income taxes, net
                  
                  **2,013**
                  
                  
                  1,969Accumulated
                      deferred investment tax credits
                  
                  **121**
                  
                  
                  129Regulatory
                      liabilities
                  
                  **1,205**
                  
                  
                  1,132Asset
                      retirement obligations
                  
                  **538**
                  
                  
                  518Accrued
                      pension and other postretirement benefits
                  
                  **840**
                  
                  
                  760Other
                      deferred credits and liabilities
                  
                  **144**
                  
                  
                  218Total
                      deferred credits and other liabilities
                  
                  **4,861**
                  
                  
                  4,726**Preferred
                      Stock of Subsidiaries Not Subject to Mandatory
                      Redemption**
                  
                  **195**
                  
                  
                  195**Minority
                      Interest in Consolidated Subsidiaries**
                  
                  **19**
                  
                  
                  17**Commitments
                      and Contingencies (Notes 2, 8 and 9)****Stockholders'
                      Equity:**Common
                      stock, $.01 par value, 400.0 shares authorized,206.2
                      and 204.7 shares outstanding, respectively
                  
                  **2**
                  
                  
                  2Other
                      paid-in capital, principally premium on common stock
                  
                  **4,478**
                  
                  
                  4,399Retained
                      earnings
                  
                  **2,094**
                  
                  
                  1,999Accumulated
                      other comprehensive loss
                  
                  **(23**
                  **)**
                  
                  (24
                  )Other
                  
                  **(3**
                  **)**
                  
                  (12
                  )Total
                      stockholders’ equity
                  
                  **6,548**
                  
                  
                  6,364**TOTAL
                      LIABILITIES AND STOCKHOLDERS' EQUITY**
                  **$**
                  **18,830**
                  
                  $
                  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)****Nine
                  Months Ended****September
                  30,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **486**
              
              $
              586Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **507**
              
              
              499Amortization
                  of nuclear fuel
              
              **26**
              
              
              25Amortization
                  of debt issuance costs and premium/discounts
              
              **12**
              
              
              11Deferred
                  income taxes and investment tax credits, net
              
              **7**
              
              
              83Loss
                  on sale of leveraged leases
              
              **4**
              
              
              -Gain
                  on sales of emission allowances
              
              **(25**
              **)**
              
              (4
              )Minority
                  interest
              
              **23**
              
              
              1Other
              
              **17**
              
              
              3Changes
                  in assets and liabilities, excluding the effects of
                  acquisitions:Receivables,
                  net
              
              **157**
              
              
              (1
              )Materials
                  and supplies
              
              **(136**
              **)**
              
              (94
              )Accounts
                  and wages payable
              
              **(289**
              **)**
              
              (72
              )Taxes
                  accrued
              
              **148**
              
              
              172Assets,
                  other
              
              **(97**
              **)**
              
              (28
              )Liabilities,
                  other
              
              **101**
              
              
              (11
              )Pension
                  and other postretirement benefit obligations, net
              
              **89**
              
              
              7Net
                  cash provided by operating activities
              
              **1,030**
              
              
              1,177**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(666**
              **)**
              
              (660
              )Acquisitions,
                  net of cash acquired
              
              **-**
              
              
              12CT
                  acquisitions
              
              **(292**
              **)**
              
              -Nuclear
                  fuel expenditures
              
              **(37**
              **)**
              
              (16
              )Proceeds
                  from sale of leveraged leases
              
              **11**
              
              
              -Purchases
                  of emission allowances
              
              **(38**
              **)**
              
              (92
              )Sales
                  of emission allowances
              
              **12**
              
              
              4Other
              
              **5**
              
              
              16Net
                  cash used in investing activities
              
              **(1,005**
              **)**
              
              (736
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **(391**
              **)**
              
              (383
              )Capital
                  issuance costs
              
              **(4**
              **)**
              
              (4
              )Short-term
                  debt, net
              
              **118**
              
              
              (394
              )Borrowings
                  from credit facility
              
              **40**
              
              
              -Dividends
                  paid to minority interest
              
              **(21**
              **)**
              
              -Redemptions,
                  repurchases, and maturities:Long-term
                  debt
              
              **(138**
              **)**
              
              (262
              )Preferred
                  stock
              
              **(1**
              **)**
              
              (1
              )Issuances:Common
                  stock
              
              **78**
              
              
              430Long-term
                  debt
              
              **232**
              
              
              382Net
                  cash used in financing activities
              
              **(87**
              **)**
              
              (232
              )Net
                  change in cash and cash equivalents
              
              **(62**
              **)**
              
              209Cash
                  and cash equivalents at beginning of year
              
              **96**
              
              
              69Cash
                  and cash equivalents at end of period
              **$**
              **34**
              
              $
              278




**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**
                **September
                  30,**
              
              **Nine
                  Months Ended**
                **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005****Operating
                  Revenues:**Electric
              **$**
              **836**
              
              $
              876
              
              **$**
              **2,090**
              
              $
              2,134Gas
              
              **20**
              
              
              19
              
              
              **111**
              
              
              120Other
              
              **1**
              
              
              -
              
              
              **2**
              
              
              -Total
                  operating revenues
              
              **857**
              
              
              895
              
              
              **2,203**
              
              
              2,254**Operating
                  Expenses:**Fuel
                  and purchased power
              
              **214**
              
              
              261
              
              
              **598**
              
              
              586Gas
                  purchased for resale
              
              **10**
              
              
              8
              
              
              **66**
              
              
              66Other
                  operations and maintenance
              
              **214**
              
              
              199
              
              
              **581**
              
              
              573Depreciation
                  and amortization
              
              **82**
              
              
              79
              
              
              **243**
              
              
              231Taxes
                  other than income taxes
              
              **66**
              
              
              66
              
              
              **184**
              
              
              180Total
                  operating expenses
              
              **586**
              
              
              613
              
              
              **1,672**
              
              
              1,636**Operating
                  Income**
              
              **271**
              
              
              282
              
              
              **531**
              
              
              618**Other
                  Income and Expenses:**Miscellaneous
                  income
              
              **2**
              
              
              3
              
              
              **6**
              
              
              12Miscellaneous
                  expense
              
              **(3**
              **)**
              
              (2
              )
              
              **(7**
              **)**
              
              (6
              )Total
                  other income (expense)
              
              **(1**
              **)**
              
              1
              
              
              **(1**
              **)**
              
              6**Interest
                  Charges**
              
              **35**
              
              
              29
              
              
              **107**
              
              
              81**Income
                  Before Income Taxes and Equity****in
                  Income of Unconsolidated Investment**
              
              **235**
              
              
              254
              
              
              **423**
              
              
              543**Income
                  Taxes**
              
              **92**
              
              
              91
              
              
              **161**
              
              
              193**Income
                  Before Equity in Income****of
                  Unconsolidated Investment**
              
              **143**
              
              
              163
              
              
              **262**
              
              
              350**Equity
                  in Income of Unconsolidated Investment**
              
              **23**
              
              
              1
              
              
              **47**
              
              
              3**Net
                  Income**
              
              **166**
              
              
              164
              
              
              **309**
              
              
              353**Preferred
                  Stock Dividends**
              
              **1**
              
              
              1
              
              
              **4**
              
              
              4**Net
                  Income Available to Common Stockholder**
              **$**
              **165**
              
              $
              163
              
              **$**
              **305**
              
              $
              349




**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)****September
                  30,**
              
              **December
                  31,****2006**
              
              **2005****ASSETS****Current
                  Assets:**Cash
                  and cash equivalents
              **$**
              **2**
              
              $
              20Accounts
                  receivable – trade (less allowance for doubtfulaccounts
                  of $5 and $6, respectively)
              
              **196**
              
              
              190Unbilled
                  revenue
              
              **105**
              
              
              133Miscellaneous
                  accounts and notes receivable
              
              **84**
              
              
              7Accounts
                  receivable – affiliates
              
              **35**
              
              
              53Current
                  portion of intercompany note receivable – CIPS
              
              **-**
              
              
              6Materials
                  and supplies
              
              **236**
              
              
              199Other
                  current assets
              
              **59**
              
              
              57Total
                  current assets
              
              **717**
              
              
              665**Property
                  and Plant, Net**
              
              **7,756**
              
              
              7,379**Investments
                  and Other Assets:**Nuclear
                  decommissioning trust fund
              
              **271**
              
              
              250Intercompany
                  note receivable – CIPS
              
              **-**
              
              
              61Intangible
                  assets
              
              **63**
              
              
              63Other
                  assets
              
              **565**
              
              
              269Regulatory
                  assets
              
              **562**
              
              
              590Total
                  investments and other assets
              
              **1,461**
              
              
              1,233**TOTAL
                  ASSETS**
              **$**
              **9,934**
              
              $
              9,277**LIABILITIES
                  AND STOCKHOLDERS' EQUITY****Current
                  Liabilities:**Current
                  maturities of long-term debt
              **$**
              **10**
              
              $
              4Short-term
                  debt
              
              **208**
              
              
              80Accounts
                  and wages payable
              
              **119**
              
              
              274Accounts
                  payable – affiliates
              
              **141**
              
              
              134Taxes
                  accrued
              
              **214**
              
              
              59Other
                  current liabilities
              
              **176**
              
              
              96Total
                  current liabilities
              
              **868**
              
              
              647**Long-term
                  Debt, Net**
              
              **2,932**
              
              
              2,698**Deferred
                  Credits and Other Liabilities:**Accumulated
                  deferred income taxes, net
              
              **1,286**
              
              
              1,277Accumulated
                  deferred investment tax credits
              
              **91**
              
              
              96Regulatory
                  liabilities
              
              **815**
              
              
              802Asset
                  retirement obligations
              
              **484**
              
              
              466Accrued
                  pension and other postretirement benefits
              
              **238**
              
              
              203Other
                  deferred credits and liabilities
              
              **51**
              
              
              72Total
                  deferred credits and other liabilities
              
              **2,965**
              
              
              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
              
              **736**
              
              
              733Retained
                  earnings
              
              **1,839**
              
              
              1,689Accumulated
                  other comprehensive loss
              
              **(30**
              **)**
              
              (30
              )Total
                  stockholders' equity
              
              **3,169**
              
              
              3,016**TOTAL
                  LIABILITIES AND STOCKHOLDERS' EQUITY**
              **$**
              **9,934**
              
              $
              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)****Nine
                  Months Ended**
                **September
                  30,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **309**
              
              $
              353Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **243**
              
              
              231Amortization
                  of nuclear fuel
              
              **26**
              
              
              25Amortization
                  of debt issuance costs and premium/discounts
              
              **4**
              
              
              3Deferred
                  income taxes and investment tax credits, net
              
              **(10**
              **)**
              
              27Gain
                  on sales of emission allowances
              
              **(2**
              **)**
              
              (2
              )Other
              
              **-**
              
              
              12Changes
                  in assets and liabilities:Receivables,
                  net
              
              **(34**
              **)**
              
              (96
              )Materials
                  and supplies
              
              **(35**
              **)**
              
              2Accounts
                  and wages payable
              
              **(127**
              **)**
              
              44Taxes
                  accrued
              
              **174**
              
              
              130Assets,
                  other
              
              **(52**
              )
              
              (14
              )Liabilities,
                  other
              
              **62**
              
              
              (2
              )Pension
                  and other postretirement benefit obligations, net
              
              **35**
              
              
              (1
              )Net
                  cash provided by operating activities
              
              **593**
              
              
              712**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(325**
              **)**
              
              (388
              )CT
                  acquisitions from nonaffiliates
              
              **(292**
              **)**
              
              -CT
                  acquisitions from Genco
              
              **-**
              
              
              (241
              )Nuclear
                  fuel expenditures
              
              **(37**
              **)**
              
              (16
              )Changes
                  in money pool advances
              
              **-**
              
              
              -Proceeds
                  from intercompany note receivable - CIPS
              
              **67**
              
              
              -Sales
                  of emission allowances
              
              **2**
              
              
              2Other
              
              **1**
              
              
              10Net
                  cash used in investing activities
              
              **(584**
              **)**
              
              (633
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **(154**
              **)**
              
              (209
              )Dividends
                  on preferred stock
              
              **(4**
              **)**
              
              (4
              )Capital
                  issuance costs
              
              **-**
              
              
              (3
              )Changes
                  in short-term debt, net
              
              **128**
              
              
              (375
              )Changes
                  in money pool borrowings
              
              **-**
              
              
              79Issuance
                  of long-term debt
              
              **-**
              
              
              382Capital
                  contribution from parent
              
              **3**
              
              
              4Net
                  cash used in financing activities
              
              **(27**
              **)**
              
              (126
              )Net
                  change in cash and cash equivalents
              
              **(18**
              **)**
              
              (47
              )Cash
                  and cash equivalents at beginning of year
              
              **20**
              
              
              48Cash
                  and cash equivalents at end of period
              **$**
              **2**
              
              $
              1


**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**
                **September
                  30,**
              
              **Nine
                  Months Ended**
                **September
                  30,****2006**
              
              
              **2005**
              
              
              **2006**
              
              
              2005**Operating
                  Revenues:**Electric
              **$**
              **228**
              
              $
              244
              
              **$**
              **569**
              
              $
              542Gas
              
              **23**
              
              
              22
              
              
              **150**
              
              
              133Other
              
              **3**
              
              
              1
              
              
              **4**
              
              
              2Total
                  operating revenues
              
              **254**
              
              
              267
              
              
              **723**
              
              
              677**Operating
                  Expenses:**Purchased
                  power
              
              **125**
              
              
              140
              
              
              **355**
              
              
              331Gas
                  purchased for resale
              
              **11**
              
              
              12
              
              
              **99**
              
              
              86Other
                  operations and maintenance
              
              **41**
              
              
              39
              
              
              **117**
              
              
              109Depreciation
                  and amortization
              
              **16**
              
              
              17
              
              
              **47**
              
              
              45Taxes
                  other than income taxes
              
              **9**
              
              
              9
              
              
              **30**
              
              
              24Total
                  operating expenses
              
              **202**
              
              
              217
              
              
              **648**
              
              
              595**Operating
                  Income**
              
              **52**
              
              
              50
              
              
              **75**
              
              
              82**Other
                  Income and Expenses:**Miscellaneous
                  income
              
              **4**
              
              
              4
              
              
              **13**
              
              
              13Miscellaneous
                  expense
              
              **-**
              
              
              (1
              )
              
              **(1**
              **)**
              
              (5
              )Total
                  other income
              
              **4**
              
              
              3
              
              
              **12**
              
              
              8**Interest
                  Charges**
              
              **8**
              
              
              7
              
              
              **23**
              
              
              22**Income
                  Before Income Taxes**
              
              **48**
              
              
              46
              
              
              **64**
              
              
              68**Income
                  Taxes**
              
              **19**
              
              
              15
              
              
              **21**
              
              
              22**Net
                  Income**
              
              **29**
              
              
              31
              
              
              **43**
              
              
              46**Preferred
                  Stock Dividends**
              
              **1**
              
              
              1
              
              
              **2**
              
              
              2**Net
                  Income Available to Common Stockholder**
              **$**
              **28**
              
              $
              30
              
              **$**
              **41**
              
              $
              44




**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)****September
                  30,**
              
              **December
                  31,****2006**
              
              **2005****ASSETS****Current
                  Assets:**Cash
                  and cash equivalents
              **$**
              **-**
              
              $
              -Accounts
                  receivable – trade (less allowance for doubtfulaccounts
                  of $2 and $4, respectively)
              
              **58**
              
              
              70Unbilled
                  revenue
              
              **44**
              
              
              71Accounts
                  receivable – affiliates
              
              **4**
              
              
              18Current
                  portion of intercompany note receivable – Genco
              
              **37**
              
              
              34Current
                  portion of intercompany tax receivable – Genco
              
              **10**
              
              
              10Advances
                  to money pool
              
              **18**
              
              
              -Materials
                  and supplies
              
              **82**
              
              
              75Other
                  current assets
              
              **22**
              
              
              28Total
                  current assets
              
              **275**
              
              
              306**Property
                  and Plant, Net**
              
              **1,150**
              
              
              1,130**Investments
                  and Other Assets:**Intercompany
                  note receivable – Genco
              
              **126**
              
              
              163Intercompany
                  tax receivable – Genco
              
              **118**
              
              
              125Other
                  assets
              
              **31**
              
              
              24Regulatory
                  assets
              
              **35**
              
              
              36Total
                  investments and other assets
              
              **310**
              
              
              348**TOTAL
                  ASSETS**
              **$**
              **1,735**
              
              $
              1,784**LIABILITIES
                  AND STOCKHOLDERS' EQUITY****Current
                  Liabilities:**Current
                  maturities of long-term debt
              **$**
              **-**
              
              $
              20Accounts
                  and wages payable
              
              **31**
              
              
              36Accounts
                  payable – affiliates
              
              **65**
              
              
              65Borrowings
                  from money pool
              
              **-**
              
              
              2Current
                  portion of intercompany note payable – UE
              
              **-**
              
              
              6Taxes
                  accrued
              
              **28**
              
              
              26Other
                  current liabilities
              
              **43**
              
              
              43Total
                  current liabilities
              
              **167**
              
              
              198**Long-term
                  Debt, Net**
              
              **471**
              
              
              410**Deferred
                  Credits and Other Liabilities:**Accumulated
                  deferred income taxes and investment tax credits, net
              
              **289**
              
              
              302Intercompany
                  note payable – UE
              
              **-**
              
              
              61Regulatory
                  liabilities
              
              **218**
              
              
              208Accrued
                  pension and other postretirement benefits
              
              **13**
              
              
              7Other
                  deferred credits and liabilities
              
              **21**
              
              
              29Total
                  deferred credits and other liabilities
              
              **541**
              
              
              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
              
              **190**
              
              
              189Preferred
                  stock not subject to mandatory redemption
              
              **50**
              
              
              50Retained
                  earnings
              
              **321**
              
              
              329Accumulated
                  other comprehensive income (loss)
              
              **(5**
              **)**
              
              1Total
                  stockholders' equity
              
              **556**
              
              
              569**TOTAL
                  LIABILITIES AND STOCKHOLDERS' EQUITY**
              **$**
              **1,735**
              
              $
              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)****Nine
                  Months Ended**
                **September
                  30,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **43**
              
              $
              46Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **47**
              
              
              45Amortization
                  of debt issuance costs and premium/discounts
              
              **1**
              
              
              1Deferred
                  income taxes and investment tax credits, net
              
              **(27**
              **)**
              
              (5
              )Other
              
              **1**
              
              
              1Changes
                  in assets and liabilities:Receivables,
                  net
              
              **60**
              
              
              21Materials
                  and supplies
              
              **(7**
              **)**
              
              (25
              )Accounts
                  and wages payable
              
              **(5**
              **)**
              
              39Taxes
                  accrued
              
              **8**
              
              
              16Assets,
                  other
              
              **-**
              
              
              (32
              )Liabilities,
                  other
              
              **-**
              
              
              41Pension
                  and other postretirement obligations, net
              
              **6**
              
              
              -Net
                  cash provided by operating activities
              
              **127**
              
              
              148**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(63**
              **)**
              
              (41
              )Proceeds
                  from intercompany note receivable – Genco
              
              **34**
              
              
              52Changes
                  in money pool advances
              
              **(18**
              **)**
              
              (51
              )Net
                  cash used in investing activities
              
              **(47**
              **)**
              
              (40
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **(50**
              **)**
              
              (21
              )Dividends
                  on preferred stock
              
              **(2**
              **)**
              
              (2
              )Capital
                  issuance costs
              
              **(1**
              **)**
              
              -Changes
                  in money pool borrowings
              
              **(2**
              **)**
              
              (68
              )Redemptions,
                  repurchases, and maturities:Long-term
                  debt
              
              **(20**
              **)**
              
              (20
              )Intercompany
                  note payable - UE
              
              **(67**
              **)**
              
              -Issuance
                  of long-term debt
              
              **61**
              
              
              -Capital
                  contribution from parent
              
              **1**
              
              
              1Net
                  cash used in financing activities
              
              **(80**
              **)**
              
              (110
              )Net
                  change in cash and cash equivalents
              
              **-**
              
              
              (2
              )Cash
                  and cash equivalents at beginning of year
              
              **-**
              
              
              2Cash
                  and cash equivalents at end of period
              **$**
              **-**
              
              $
              -




**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**
                **September
                  30,**
              
              **Nine
                  Months Ended**
                **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005****Operating
                  Revenues:**Electric
              **$**
              **259**
              
              $
              287
              
              **$**
              **744**
              
              $
              777Other
              
              **-**
              
              
              2
              
              
              **-**
              
              
              2Total
                  operating revenues
              
              **259**
              
              
              289
              
              
              **744**
              
              
              779**Operating
                  Expenses:**Fuel
                  and purchased power
              
              **170**
              
              
              162
              
              
              **485**
              
              
              398Other
                  operations and maintenance
              
              **34**
              
              
              32
              
              
              **113**
              
              
              108Depreciation
                  and amortization
              
              **18**
              
              
              18
              
              
              **53**
              
              
              55Taxes
                  other than income taxes
              
              **3**
              
              
              4
              
              
              **14**
              
              
              7Total
                  operating expenses
              
              **225**
              
              
              216
              
              
              **665**
              
              
              568**Operating
                  Income**
              
              **34**
              
              
              73
              
              
              **79**
              
              
              211**Other
                  Income:**Miscellaneous
                  income
              
              **-**
              
              
              -
              
              
              **-**
              
              
              1Total
                  other income
              
              **-**
              
              
              -
              
              
              **-**
              
              
              1**Interest
                  Charges**
              
              **15**
              
              
              17
              
              
              **45**
              
              
              57**Income
                  Before Income Taxes**
              
              **19**
              
              
              56
              
              
              **34**
              
              
              155**Income
                  Taxes**
              
              **-**
              
              
              24
              
              
              **7**
              
              
              61**Net
                  Income**
              **$**
              **19**
              
              $
              32
              
              **$**
              **27**
              
              $
              94




**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)****September
                  30,**
              
              **December
                  31,****2006**
              
              **2005****ASSETS****Current
                  Assets:**Cash
                  and cash equivalents
              **$**
              **2**
              
              $
              -Accounts
                  receivable – affiliates
              
              **143**
              
              
              102Accounts
                  receivable – trade
              
              **18**
              
              
              29Materials
                  and supplies
              
              **103**
              
              
              73Other
                  current assets
              
              **4**
              
              
              1Total
                  current assets
              
              **270**
              
              
              205**Property
                  and Plant, Net**
              
              **1,512**
              
              
              1,514**Intangible
                  Assets**
              
              **81**
              
              
              79**Other
                  Assets**
              
              **27**
              
              
              13**TOTAL
                  ASSETS**
              **$**
              **1,890**
              
              $
              1,811**LIABILITIES
                  AND STOCKHOLDER'S EQUITY****Current
                  Liabilities:**Current
                  portion of intercompany note payable – CIPS
              **$**
              **37**
              
              $
              34Borrowings
                  from money pool
              
              **216**
              
              
              203Accounts
                  and wages payable
              
              **25**
              
              
              41Accounts
                  payable – affiliates
              
              **84**
              
              
              60Current
                  portion of intercompany tax payable – CIPS
              
              **10**
              
              
              10Taxes
                  accrued
              
              **24**
              
              
              37Other
                  current liabilities
              
              **32**
              
              
              16Total
                  current liabilities
              
              **428**
              
              
              401**Long-term
                  Debt, Net**
              
              **474**
              
              
              474**Intercompany
                  Note Payable – CIPS**
              
              **126**
              
              
              163**Deferred
                  Credits and Other Liabilities:**Accumulated
                  deferred income taxes, net
              
              **161**
              
              
              156Accumulated
                  deferred investment tax credits
              
              **9**
              
              
              10Intercompany
                  tax payable – CIPS
              
              **118**
              
              
              125Asset
                  retirement obligations
              
              **30**
              
              
              29Accrued
                  pension and other postretirement benefits
              
              **12**
              
              
              8Other
                  deferred credits and liabilities
              
              **2**
              
              
              1Total
                  deferred credits and other liabilities
              
              **332**
              
              
              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
              
              **378**
              
              
              228Retained
                  earnings
              
              **154**
              
              
              220Accumulated
                  other comprehensive loss
              
              **(2**
              **)**
              
              (4
              )Total
                  stockholder's equity
              
              **530**
              
              
              444**TOTAL
                  LIABILITIES AND STOCKHOLDER'S EQUITY**
              **$**
              **1,890**
              
              $
              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)****Nine
                  Months Ended**
                **September
                  30,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **27**
              
              $
              94Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **78**
              
              
              78Amortization
                  of debt issuance costs and discounts
              
              **-**
              
              
              1Deferred
                  income taxes and investment tax credits, net
              
              **7**
              
              
              35Gain
                  on sales of emission allowances
              
              **(1**
              **)**
              
              (1
              )Other
              
              **1**
              
              
              (21
              )Changes
                  in assets and liabilities:Accounts
                  receivable
              
              **(30**
              **)**
              
              (10
              )Materials
                  and supplies
              
              **(30**
              **)**
              
              (8
              )Accounts
                  and wages payable
              
              **13**
              
              
              59Taxes
                  accrued, net
              
              **(9**
              **)**
              
              (35
              )Assets,
                  other
              
              **(16**
              **)**
              
              6Liabilities,
                  other
              
              **2**
              
              
              7Pension
                  and other postretirement benefit obligations, net
              
              **4**
              
              
              **-**Net
                  cash provided by operating activities
              
              **46**
              
              
              205**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(55**
              **)**
              
              (52
              )Proceeds
                  from asset sale to UE
              
              **-**
              
              
              241Changes
                  in money pool advances
              
              **-**
              
              
              (65
              )Purchases
                  of emission allowances
              
              **(26**
              **)**
              
              (71
              )Sales
                  of emission allowances
              
              **1**
              
              
              1Net
                  cash provided by (used in) investing activities
              
              **(80**
              **)**
              
              54**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **(93**
              **)**
              
              (59
              )Changes
                  in money pool borrowings
              
              **13**
              
              
              (116
              )Repayment
                  of intercompany notes payable – CIPS and Ameren
              
              **(34**
              **)**
              
              (86
              )Capital
                  contribution from parent
              
              **150**
              
              
              1Net
                  cash provided by (used in) financing activities
              
              **36**
              
              
              (260
              )Net
                  change in cash and cash equivalents
              
              **2**
              
              
              (1
              )Cash
                  and cash equivalents at beginning of year
              
              **-**
              
              
              1Cash
                  and cash equivalents at end of period
              **$**
              **2**
              
              $
              -




**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**
                **September
                  30,**
              
              **Nine
                  Months Ended**
                **September
                  30,****2006**
              
              
              **2005**
              
              
              **2006**
              
              
              **2005****Operating
                  Revenues:**Electric
              **$**
              **119**
              
              $
              116
              
              **$**
              **309**
              
              $
              309Gas
              
              **38**
              
              
              41
              
              
              **236**
              
              
              215Other
              
              **1**
              
              
              2
              
              
              **1**
              
              
              4Total
                  operating revenues
              
              **158**
              
              
              159
              
              
              **546**
              
              
              528**Operating
                  Expenses:**Fuel
                  and purchased power
              
              **43**
              
              
              54
              
              
              **104**
              
              
              126Gas
                  purchased for resale
              
              **24**
              
              
              27
              
              
              **175**
              
              
              150Other
                  operations and maintenance
              
              **41**
              
              
              41
              
              
              **130**
              
              
              122Depreciation
                  and amortization
              
              **18**
              
              
              18
              
              
              **59**
              
              
              54Taxes
                  other than income taxes
              
              **5**
              
              
              4
              
              
              **18**
              
              
              15Total
                  operating expenses
              
              **131**
              
              
              144
              
              
              **486**
              
              
              467**Operating
                  Income**
              
              **27**
              
              
              15
              
              
              **60**
              
              
              61**Other
                  Income and Expenses:**Miscellaneous
                  income
              
              **-**
              
              
              -
              
              
              **1**
              
              
              -Miscellaneous
                  expense
              
              **(2**
              **)**
              
              (2
              )
              
              **(4**
              **)**
              
              (7
              )Total
                  other expenses
              
              **(2**
              **)**
              
              (2
              )
              
              **(3**
              **)**
              
              (7
              )**Interest
                  Charges**
              
              **13**
              
              
              12
              
              
              **38**
              
              
              37**Income
                  Before Income Taxes & Preferred****Dividends
                  of Subsidiaries**
              
              **12**
              
              
              1
              
              
              **19**
              
              
              17**Income
                  Tax Benefit**
              
              **(1**
              **)**
              
              (5
              )
              
              **(4**
              **)**
              
              (1
              )**Income
                  Before Preferred Dividends of Subsidiaries**
              
              **13**
              
              
              6
              
              
              **23**
              
              
              18**Preferred
                  Dividends of Subsidiaries**
              
              **-**
              
              
              1
              
              
              **1**
              
              
              2**Net
                  Income**
              **$**
              **13**
              
              $
              5
              
              **$**
              **22**
              
              $
              16




**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)****September
                  30,**
              
              **December
                  31,****2006**
              
              **2005****ASSETS****Current
                  Assets:**Cash
                  and cash equivalents
              **$**
              **3**
              
              $
              3Accounts
                  receivable – trade (less allowance for doubtfulaccounts
                  of $3 and $5, respectively)
              
              **35**
              
              
              61Unbilled
                  revenue
              
              **33**
              
              
              59Accounts
                  receivables – affiliates
              
              **21**
              
              
              18Note
                  receivable – Resources Company
              
              **-**
              
              
              42Materials
                  and supplies
              
              **107**
              
              
              85Other
                  current assets
              
              **34**
              
              
              50Total
                  current assets
              
              **233**
              
              
              318**Property
                  and Plant, Net**
              
              **1,218**
              
              
              1,212**Investments
                  and Other Assets:**Investments
                  in leveraged leases
              
              **-**
              
              
              21Goodwill
              
              **575**
              
              
              575Intangible
                  assets
              
              **50**
              
              
              62Other
                  assets
              
              **16**
              
              
              35Regulatory
                  assets
              
              **12**
              
              
              11Total
                  investments and other assets
              
              **653**
              
              
              704**TOTAL
                  ASSETS**
              **$**
              **2,104**
              
              $
              2,234**LIABILITIES
                  AND STOCKHOLDER'S EQUITY****Current
                  Liabilities:**Current
                  maturities of long-term debt
              **$**
              **50**
              
              $
              -Borrowings
                  from money pool
              
              **62**
              
              
              154Intercompany
                  note payable – Ameren
              
              **156**
              
              
              186Accounts
                  and wages payable
              
              **35**
              
              
              81Accounts
                  payable – affiliates
              
              **16**
              
              
              28Other
                  current liabilities
              
              **61**
              
              
              55Total
                  current liabilities
              
              **380**
              
              
              504**Long-term
                  Debt, Net**
              
              **584**
              
              
              534**Preferred
                  Stock of Subsidiary Subject to Mandatory
                  Redemption**
              
              **18**
              
              
              19**Deferred
                  Credits and Other Liabilities:**Accumulated
                  deferred income taxes, net
              
              **159**
              
              
              163Accumulated
                  deferred investment tax credits
              
              **8**
              
              
              9Regulatory
                  liabilities
              
              **50**
              
              
              41Accrued
                  pension and other postretirement benefits
              
              **253**
              
              
              251Other
                  deferred credits and liabilities
              
              **17**
              
              
              31Total
                  deferred credits and other liabilities
              
              **487**
              
              
              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
              
              **15**
              
              
              -Accumulated
                  other comprehensive income
              
              **3**
              
              
              23Total
                  stockholder's equity
              
              **616**
              
              
              663**TOTAL
                  LIABILITIES AND STOCKHOLDER'S EQUITY**
              **$**
              **2,104**
              
              $
              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)****Nine
                  Months Ended****September
                  30,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **22**
              
              $
              16Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **74**
              
              
              74Deferred
                  income taxes and investment tax credits
              
              **8**
              
              
              (19
              )Loss
                  on sale of leveraged lease investments
              
              **4**
              
              
              -Gain
                  on sales of emission allowances
              
              **-**
              
              
              (1
              )Other
              
              **1**
              
              
              1Changes
                  in assets and liabilities:Receivables,
                  net
              
              **49**
              
              
              20Materials
                  and supplies
              
              **(22**
              **)**
              
              (17
              )Accounts
                  and wages payable
              
              **(52**
              **)**
              
              (9
              )Taxes
                  accrued
              
              **(9**
              **)**
              
              (8
              )Assets,
                  other
              
              **24**
              
              
              9Liabilities,
                  other
              
              **(4**
              **)**
              
              9Pension
                  and postretirement benefit obligations, net
              
              **4**
              
              
              2Net
                  cash provided by operating activities
              
              **99**
              
              
              77**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(70**
              **)**
              
              (71
              )Proceeds
                  from note receivable - Resources Company
              
              **42**
              
              
              -Proceeds
                  from sale of leveraged leases
              
              **11**
              
              
              -Purchases
                  of emissions allowances
              
              **(12**
              **)**
              
              (21
              )Sales
                  of emission allowances
              
              **1**
              
              
              1Other
              
              **-**
              
              
              4Net
                  cash used in investing activities
              
              **(28**
              **)**
              
              (87
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **(50**
              **)**
              
              (30
              )Capital
                  issuance costs
              
              **(2**
              **)**
              
              -Changes
                  in money pool borrowings
              
              **(92**
              **)**
              
              (85
              )Proceeds
                  (repayment) - intercompany note payable - Ameren
              
              **(30**
              **)**
              
              28Borrowings
                  from credit facility
              
              **40**
              
              
              -Redemptions,
                  repurchases, and maturities:Long-term
                  debt
              
              **(32**
              **)**
              
              (6
              )Preferred
                  stock
              
              **(1**
              **)**
              
              (1
              )Issuance
                  of long-term debt
              
              **96**
              
              
              -Capital
                  contribution from parent
              
              **-**
              
              
              101Net
                  cash provided by (used in) financing activities
              
              **(71**
              **)**
              
              7Net
                  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**
                **September
                  30,**
              
              **Nine
                  Months Ended**
                **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005****Operating
                  Revenues:**Electric
              **$**
              **119**
              
              $
              117
              
              **$**
              **309**
              
              $
              309Gas
              
              **38**
              
              
              41
              
              
              **236**
              
              
              212Other
              
              **-**
              
              
              1
              
              
              **1**
              
              
              1Total
                  operating revenues
              
              **157**
              
              
              159
              
              
              **546**
              
              
              522**Operating
                  Expenses:**Fuel
                  and purchased power
              
              **39**
              
              
              49
              
              
              **95**
              
              
              117Gas
                  purchased for resale
              
              **24**
              
              
              27
              
              
              **175**
              
              
              146Other
                  operations and maintenance
              
              **41**
              
              
              44
              
              
              **134**
              
              
              128Depreciation
                  and amortization
              
              **18**
              
              
              17
              
              
              **52**
              
              
              50Taxes
                  other than income taxes
              
              **4**
              
              
              4
              
              
              **17**
              
              
              14Total
                  operating expenses
              
              **126**
              
              
              141
              
              
              **473**
              
              
              455**Operating
                  Income**
              
              **31**
              
              
              18
              
              
              **73**
              
              
              67**Other
                  Expenses:**Miscellaneous
                  expense
              
              **(2**
              **)**
              
              (2
              )
              
              **(4**
              **)**
              
              (5
              )Total
                  other expenses
              
              **(2**
              **)**
              
              (2
              )
              
              **(4**
              **)**
              
              (5
              )**Interest
                  Charges**
              
              **4**
              
              
              3
              
              
              **13**
              
              
              10**Income
                  Before Income Taxes**
              
              **25**
              
              
              13
              
              
              **56**
              
              
              52**Income
                  Taxes**
              
              **6**
              
              
              2
              
              
              **12**
              
              
              15**Net
                  Income**
              
              **19**
              
              
              11
              
              
              **44**
              
              
              37**Preferred
                  Stock Dividends**
              
              **-**
              
              
              1
              
              
              **1**
              
              
              2**Net
                  Income Available to Common Stockholder**
              **$**
              **19**
              
              $
              10
              
              **$**
              **43**
              
              $
              35




**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)****September
                  30,**
              
              **December
                  31,****2006**
              
              **2005****ASSETS****Current
                  Assets:**Cash
                  and cash equivalents
              **$**
              **2**
              
              $
              2Accounts
                  receivable – trade (less allowance for doubtfulaccounts
                  of $3 and $5, respectively)
              
              **35**
              
              
              61Unbilled
                  revenue
              
              **33**
              
              
              59Accounts
                  receivable – affiliates
              
              **15**
              
              
              14Materials
                  and supplies
              
              **107**
              
              
              87Other
                  current assets
              
              **36**
              
              
              43Total
                  current assets
              
              **228**
              
              
              266**Property
                  and Plant, Net**
              
              **1,232**
              
              
              1,214**Investments
                  in Leveraged Leases**
              
              **-**
              
              
              21**Intangible
                  Assets**
              
              **4**
              
              
              4**Other
                  Assets**
              
              **22**
              
              
              41**Regulatory
                  Assets**
              
              **12**
              
              
              11**TOTAL
                  ASSETS**
              **$**
              **1,498**
              
              $
              1,557**LIABILITIES
                  AND STOCKHOLDERS' EQUITY****Current
                  Liabilities:**Current
                  maturities of long-term debt
              **$**
              **50**
              
              $
              -Borrowings
                  from money pool
              
              **62**
              
              
              161Accounts
                  and wages payable
              
              **35**
              
              
              81Accounts
                  payable – affiliates
              
              **31**
              
              
              26Other
                  current liabilities
              
              **46**
              
              
              48Total
                  current liabilities
              
              **224**
              
              
              316**Long-term
                  Debt, Net**
              
              **188**
              
              
              122**Preferred
                  Stock Subject to Mandatory Redemption**
              
              **18**
              
              
              19**Deferred
                  Credits and Other Liabilities:**Accumulated
                  deferred income taxes, net
              
              **166**
              
              
              167Accumulated
                  deferred investment tax credits
              
              **8**
              
              
              8Regulatory
                  liabilities
              
              **201**
              
              
              187Accrued
                  pension and other postretirement benefits
              
              **155**
              
              
              146Other
                  deferred credits and liabilities
              
              **18**
              
              
              30Total
                  deferred credits and other liabilities
              
              **548**
              
              
              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
              
              **414**
              
              
              415Retained
                  earnings
              
              **97**
              
              
              119Accumulated
                  other comprehensive income (loss)
              
              **(10**
              **)**
              
              9Total
                  stockholders' equity
              
              **520**
              
              
              562**TOTAL
                  LIABILITIES AND STOCKHOLDERS' EQUITY**
              **$**
              **1,498**
              
              $
              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)****Nine
                  Months Ended****September
                  30,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **44**
              
              $
              37Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **61**
              
              
              64Deferred
                  income taxes and investment tax credits
              
              **15**
              
              
              (5
              )Loss
                  on sale of leveraged leases
              
              **6**
              
              
              -Gain
                  on sales of emission allowances
              
              **-**
              
              
              (1
              )Other
              
              **-**
              
              
              6Changes
                  in assets and liabilities:Receivables,
                  net
              
              **51**
              
              
              30Materials
                  and supplies
              
              **(20**
              **)**
              
              (15
              )Accounts
                  and wages payable
              
              **(35**
              **)**
              
              -Taxes
                  accrued
              
              **(17**
              **)**
              
              (17
              )Assets,
                  other
              
              **14**
              
              
              -Liabilities,
                  other
              
              **(6**
              **)**
              
              (9
              )Pension
                  and postretirement benefit obligations, net
              
              **9**
              
              
              11Net
                  cash provided by operating activities
              
              **122**
              
              
              101**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(70**
              **)**
              
              (71
              )Proceeds
                  from sale of leveraged leases
              
              **11**
              
              
              -Purchases
                  of emission allowances
              
              **(12**
              **)**
              
              (21
              )Sales
                  of emission allowances
              
              **1**
              
              
              1Net
                  cash used in investing activities
              
              **(70**
              **)**
              
              (91
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **(65**
              **)**
              
              (20
              )Dividends
                  on preferred stock
              
              **(1**
              **)**
              
              (2
              )Capital
                  issuance costs
              
              **(2**
              **)**
              
              -Changes
                  in money pool borrowings
              
              **(99**
              **)**
              
              (88
              )Borrowings
                  from credit facility
              
              **40**
              
              
              -Redemptions,
                  repurchases, and maturities:Long-term
                  debt
              
              **(20**
              **)**
              
              -Preferred
                  stock
              
              **(1**
              **)**
              
              (1
              )Issuance
                  of long-term debt
              
              **96**
              
              
              -Capital
                  contribution from parent
              
              **-**
              
              
              101Net
                  cash used in financing activities
              
              **(52**
              **)**
              
              (10
              )Net
                  change in cash and cash equivalents
              
              **-**
              
              
              -Cash
                  and cash equivalents at beginning of year
              
              **2**
              
              
              2Cash
                  and cash equivalents at end of period
              **$**
              **2**
              
              $
              2




**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**
                **September
                  30,**
              
              **Nine
                  Months Ended**
                **September
                  30,****2006**
              
              **2005**
              
              **2006**
              
              **2005****Operating
                  Revenues:**Electric
              **$**
              **375**
              
              $
              358
              
              **$**
              **888**
              
              $
              861Gas
              
              **59**
              
              
              61
              
              
              **381**
              
              
              331Other
              
              **1**
              
              
              1
              
              
              **2**
              
              
              1Total
                  operating revenues
              
              **435**
              
              
              420
              
              
              **1,271**
              
              
              1,193**Operating
                  Expenses:**Purchased
                  power
              
              **213**
              
              
              187
              
              
              **561**
              
              
              509Gas
                  purchased for resale
              
              **35**
              
              
              37
              
              
              **272**
              
              
              227Other
                  operations and maintenance
              
              **68**
              
              
              64
              
              
              **188**
              
              
              166Depreciation
                  and amortization
              
              **20**
              
              
              19
              
              
              **57**
              
              
              59Taxes
                  other than income taxes
              
              **14**
              
              
              14
              
              
              **52**
              
              
              54Total
                  operating expenses
              
              **350**
              
              
              321
              
              
              **1,130**
              
              
              1,015**Operating
                  Income**
              
              **85**
              
              
              99
              
              
              **141**
              
              
              178**Other
                  Income and Expenses:**Miscellaneous
                  income
              
              **2**
              
              
              2
              
              
              **4**
              
              
              6Miscellaneous
                  expense
              
              **(1**
              **)**
              
              -
              
              
              **(3**
              **)**
              
              (1
              )Total
                  other income
              
              **1**
              
              
              2
              
              
              **1**
              
              
              5**Interest
                  Charges**
              
              **13**
              
              
              11
              
              
              **37**
              
              
              32**Income
                  Before Income Taxes**
              
              **73**
              
              
              90
              
              
              **105**
              
              
              151**Income
                  Taxes**
              
              **30**
              
              
              36
              
              
              **42**
              
              
              60**Net
                  Income**
              
              **43**
              
              
              54
              
              
              **63**
              
              
              91**Preferred
                  Stock Dividends**
              
              **1**
              
              
              1
              
              
              **2**
              
              
              2**Net
                  Income Available to Common Stockholder**
              **$**
              **42**
              
              $
              53
              
              **$**
              **61**
              
              $
              89


**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)****September
                  30,**
              
              **December
                  31,****2006**
              
              **2005****ASSETS****Current
                  Assets:**Cash
                  and cash equivalents
              **$**
              **-**
              
              $
              -Accounts
                  receivable - trade (less allowance for doubtfulaccounts
                  of $3 and $8, respectively)
              
              **111**
              
              
              155Unbilled
                  revenue
              
              **82**
              
              
              118Accounts
                  receivable – affiliates
              
              **25**
              
              
              5Materials
                  and supplies
              
              **156**
              
              
              122Other
                  current assets
              
              **13**
              
              
              31Total
                  current assets
              
              **387**
              
              
              431**Property
                  and Plant, Net**
              
              **2,098**
              
              
              2,035**Investments
                  and Other Assets:**Investment
                  in IP SPT
              
              **8**
              
              
              7Goodwill
              
              **326**
              
              
              326Other
                  assets
              
              **64**
              
              
              44Regulatory
                  assets
              
              **197**
              
              
              194Accumulated
                  deferred income taxes
              
              **-**
              
              
              19Total
                  investments and other assets
              
              **595**
              
              
              590**TOTAL
                  ASSETS**
              **$**
              **3,080**
              
              $
              3,056**LIABILITIES
                  AND STOCKHOLDERS’ EQUITY****Current
                  Liabilities**:Current
                  maturities of long-term debt to IP SPT
              **$**
              **55**
              
              $
              72Borrowings
                  from money pool
              
              **110**
              
              
              75Accounts
                  and wages payable
              
              **95**
              
              
              145Accounts
                  payable – affiliates
              
              **14**
              
              
              29Taxes
                  accrued
              
              **13**
              
              
              15Other
                  current liabilities
              
              **97**
              
              
              135Total
                  current liabilities
              
              **384**
              
              
              471**Long-term
                  Debt, Net**
              
              **773**
              
              
              704**Long-term
                  Debt to IP SPT**
              
              **115**
              
              
              184**Deferred
                  Credits and Other Liabilities:**Regulatory
                  liabilities
              
              **121**
              
              
              80Accrued
                  pension and other postretirement benefits
              
              **259**
              
              
              255Other
                  deferred credits and other noncurrent liabilities
              
              **81**
              
              
              75Total
                  deferred credits and other liabilities
              
              **461**
              
              
              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
              
              **1,194**
              
              
              1,196Preferred
                  stock not subject to mandatory redemption
              
              **46**
              
              
              46Retained
                  earnings
              
              **108**
              
              
              46Accumulated
                  other comprehensive loss
              
              **(1**
              **)**
              
              (1
              )Total
                  stockholders’ equity
              
              **1,347**
              
              
              1,287**TOTAL
                  LIABILITIES AND STOCKHOLDERS’ EQUITY**
              **$**
              **3,080**
              
              $
              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)****Nine
                  Months Ended****September
                  30,****2006**
              
              **2005****Cash
                  Flows From Operating Activities:**Net
                  income
              **$**
              **63**
              
              $
              91Adjustments
                  to reconcile net income to net cashprovided
                  by operating activities:Depreciation
                  and amortization
              
              **18**
              
              
              31Amortization
                  of debt issuance costs and premium/discounts
              
              **3**
              
              
              2Deferred
                  income taxes
              
              **58**
              
              
              39Changes
                  in assets and liabilities:Receivables,
                  net
              
              **60**
              
              
              11Materials
                  and supplies
              
              **(34**
              **)**
              
              (45
              )Accounts
                  and wages payable
              
              **(64**
              **)**
              
              34Assets,
                  other
              
              **(1**
              **)**
              
              25Liabilities,
                  other
              
              **(5**
              **)**
              
              15Pension
                  and other postretirement benefit obligations, net
              
              **8**
              
              
              4Net
                  cash provided by operating activities
              
              **106**
              
              
              207**Cash
                  Flows From Investing Activities:**Capital
                  expenditures
              
              **(126**
              **)**
              
              (95
              )Changes
                  in money pool advances
              
              **-**
              
              
              90Other
              
              **(1**
              **)**
              
              1Net
                  cash used in investing activities
              
              **(127**
              **)**
              
              (4
              )**Cash
                  Flows From Financing Activities:**Dividends
                  on common stock
              
              **-**
              
              
              (60
              )Dividends
                  on preferred stock
              
              **(2**
              **)**
              
              (2
              )Capital
                  issuance costs
              
              **(1**
              **)**
              
              -Changes
                  in money pool borrowings, net
              
              **35**
              
              
              -Redemptions
                  and repurchases of long-term debt
              
              **(69**
              **)**
              
              (135
              )Issuances
                  of long-term debt
              
              **75**
              
              
              -Transitional
                  funding trust notes overfunding
              
              **(17**
              **)**
              
              (6
              )Net
                  cash provided by (used in) financing activities
              
              **21**
              
              
              (203
              )Net
                  change in cash and cash equivalents
              
              **-**
              
              
              -Cash
                  and cash equivalents at beginning of year
              
              **-**
              
              
              5Cash
                  and cash equivalents at end of period
              **$**
              **-**
              
              $
              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)**


**September
      30, 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. The following table presents summarized financial information
      of EEI (in millions) for the three months and nine months ended September 30,
      2006 and 2005.





**Three
                Months**
            
            **Nine
                Months****2006**
            
            
            **2005**
            
            
            **2006**
            
            
            **2005**Operating
                revenues
            **$**
            **105**
            
            $
            43
            
            **$**
            **290**
            
            $
            127Operating
                income
            
            **93**
            
            
            4
            
            
            **191**
            
            
            15Net
                income
            
            **56**
            
            
            3
            
            
            **117**
            
            
            8





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, including
      the reclassification of emission allowance purchases and sales from Operating
      Activities to Investing Activities on the Statements of Cash Flows for Ameren,
      UE, Genco, CILCORP and CILCO. 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. In the third quarter of 2006, Ameren, UE, CILCORP and CILCO
      changed their reportable segments. See further discussion in Note 12 - Segment
      Information.





**Earnings
      Per Share**





There
      were no material differences between Ameren’s basic and diluted earnings per
      share amounts for the three months and nine months ended September 30, 2006
      and
      2005, due to an immaterial number of stock options, restricted stock units
      and
      performance share units outstanding.





29


**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 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 Omnibus Incentive Compensation
      Plan**





In
      the
      first quarter of 2006, Ameren’s Board of Directors approved the 2006 Omnibus
      Incentive Compensation Plan (2006 Plan), subject to shareholder approval, which
      was obtained on May 2, 2006. The 2006 Plan prospectively replaced the Long-term
      Incentive Plan of 1998, as amended (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 share units, cash-based
      awards, and other stock-based awards.





A
      summary
      of nonvested shares as of September 30, 2006, and changes during the nine-month
      period ended September 30, 2006, under the 1998 Plan and the 2006 Plan is
      presented below:





**Performance
                Share Units**
            
            **Restricted
                Shares****Shares**
            
            **Weighted-average
                Fair Value Per Unit**
            
            **Shares**
            
            **Weighted-average
                Fair Value Per Share**Nonvested
                at January 1, 2006
            
            -
            
            $
            -
            
            
            575,469
            
            $
            44.91Granted(a)
            
            350,640
            
            
            56.07
            
            
            -
            
            
            -Dividends
            
            -
            
            
            -
            
            
            13,538
            
            
            51.29Forfeitures
            
            (881
            )
            
            56.07
            
            
            (2,436
            )
            
            47.58Vested(b)
            
            (4,785
            )
            
            56.07
            
            
            (213,198
            )
            
            43.38Nonvested
                at September 30, 2006
            
            344,974
            
            $
            56.07
            
            
            373,373
            
            $
            45.79


(a)
            Includes
                220,434 performance share units (share units) granted to certain
                executive
                and non-executive officers and other eligible employees in February
                2006
                under the 1998 Plan and 130,206 share units granted in February 2006
                under
                the 2006 Plan to certain executive officers subject to shareholder
                approval, which was obtained on May 2, 2006. The share units granted
                under
                the 2006 Plan were not considered as granted until approved by
                shareholders. Accordingly, compensation expense recognition for these
                awards commenced in May 2006.


(b)
            Share
                units issued under the 1998 Plan vested due to the death of an employee
                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
      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 share unit
      will vary from 0% to 200% of the target award depending on actual company
      performance relative to the performance goals. If a 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 they
      are
      paid to other shareholders.





The
      fair
      value of each share unit awarded in February 2006 under the 1998 Plan was
      determined to be $56.07 based on Ameren’s closing common share price of $50.69
      per share 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. The fair value of each share unit
      granted in May 2006 under the 2006 Plan was determined to be $56.07 based on
      assumptions similar to the February 2006 grant.




Ameren
      recorded compensation expense of $3 million and $1 million for the quarters
      ended September 30, 2006 and 2005, respectively, and a related tax benefit
      of
      less than $1 million for the quarters ended September 30, 2006 and 2005. Ameren
      recorded compensation expense of $8 million and $5 million for each of the
      nine-month periods ended September 30, 2006 and 2005, respectively, and a
      related tax




30




benefit
      of $1 million and $2 million for the nine-month periods ended September 30,
      2006
      and 2005, respectively. As of September 30, 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.




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
      2004. Therefore, there is no expense from stock options for the three- and
      nine-month periods ended September 30, 2006, and there is no pro forma expense
      for the year-ago periods. See Note 1 - 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.





**FASB
      Interpretation No. 48,** ***Accounting
      for Uncertainty in Income Taxes*** **(FIN
      48)**





FIN
      48
      establishes that the financial statement effects of a tax position taken or
      expected to be taken in a tax return are to be recognized in the financial
      statements when it is more likely than not, based on the technical merits,
      that
      the position will be sustained upon examination. In addition, FIN 48 requires
      expanded disclosure with respect to the uncertainty in income taxes and is
      effective as of the beginning of our 2007 fiscal year. We are still in the
      process of determining the impact the adoption of FIN 48 will have on our
      results of operations, financial position and liquidity; however, at this time,
      we do not expect the impact of adoption to be material.





**SFAS
      No. 157,** ***Fair
      Value Measurements***





In
      September 2006, the FASB issued SFAS No. 157, which defines fair value,
      establishes a framework for measuring fair value, and expands disclosures about
      fair value measurements. SFAS No. 157 clarifies that fair value is a
      market-based measurement that should be determined based on the assumptions
      that
      market participants would use in pricing an asset or liability. This standard
      is
      effective for Ameren as of the beginning of our 2008 fiscal year. We are still
      in the process of determining the impact the adoption of SFAS No. 157 will
      have
      on our results of operations, financial position and liquidity, if any; however,
      at this time, we do not expect the impact of adoption to be
      material.





**SFAS
      No. 158,** ***Employers’
      Accounting for Defined Benefit Pension and Other Postretirement Plans, an
      amendment of FASB Statements No. 87, 88, 106 and
      132(R)***




In
      September 2006, the FASB issued SFAS No. 158 requiring employers to recognize
      the overfunded or underfunded positions of defined benefit postretirement plans,
      including pension plans, as an asset or liability in their balance sheets and
      to
      recognize as a component of OCI, net of tax, the gains or losses and prior
      service costs or credits that arise during the period but are not recognized
      as
      components of net periodic benefit cost. SFAS No. 158 also requires additional
      disclosures in the notes to the financial statements. The recognition and
      disclosure provisions of SFAS No. 158 are effective for Ameren as of December
      31, 2006.





We
      are in
      the process of determining the impact the adoption of SFAS No. 158 will have
      on
      our financial position. However, based on the funded status of Ameren’s defined
      benefit postretirement plans as of December 31, 2005, the Ameren Companies
      would
      be required to recognize additional pension and other postretirement benefit
      obligations and write-off a pension-related intangible asset resulting in a
      charge to OCI. The following table presents the amounts that would have been
      recognized by the Ameren Companies as of December 31, 2005.





**Pension**
              **Benefit**
              **Obligations**
            
            **Postretirement**
              **Benefit**
              **Obligations**
            
            **Intangible**
              **Asset**Ameren
            $
            234
            
            $
            308
            
            $
            (79
            )UE
            
            150
            
            
            197
            
            
            (51
            )CIPS
            
            23
            
            
            31
            
            
            (8
            )Genco
            
            23
            
            
            31
            
            
            (8
            )CILCORP
            
            21
            
            
            28
            
            
            (7
            )CILCO
            
            21
            
            
            28
            
            
            (7
            )IP
            
            17
            
            
            21
            
            
            (5
            )





The
      Ameren Companies will 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 some of 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. The net result of increases and decreases
      to
      pension and other postretirement liabilities and assets, and the recognition
      of
      related deferred tax and regulatory assets will result in a charge to OCI and
      a
      decrease to common equity. The ultimate amounts recorded are highly dependent
      on
      a number of assumptions, including the discount rates in effect at December
      31,
      2006, the actual rate of return on our pension assets for 2006 and the tax
      effects of the adjustment. Changes in these assumptions since our last
      measurement date could increase or decrease the expected impact of implementing
      SFAS No. 158 in our consolidated financial statements at December 31,
      2006.





**Staff
      Accounting Bulletin No. 108,** ***Considering
      the Effects of Prior Year Misstatements When Quantifying Misstatements in
      Current Year Financial Statements*** **(SAB 108)**





In
      September 2006, the SEC staff issued SAB 108 requiring public companies to
      utilize a dual approach to assess the quantitative effects of financial
      misstatements. The dual approach includes both an income statement-focused




31


assessment
      and a balance sheet-focused assessment. SAB 108 is effective as of December
      31,
      2006, for errors that were not previously deemed material but are material
      under
      the guidance in SAB 108. While we are still in the process of determining the
      impact the adoption of SAB 108 will have on our results of operations, financial
      position and liquidity, we expect UE will make a pretax adjustment to increase
      its beginning retained earnings balance by $12 million and CIPS will make an
      adjustment to decrease its beginning retained earnings balance by $12 million.
      The adoption of SAB 108 will not have an impact on Ameren and we do not expect
      the adoption to have a material impact on the results of operations, financial
      position and liquidity of any of the Ameren Companies.





**Revenue**





***Interchange
      Revenues***





The
      following table presents the interchange revenues included in Operating Revenues
      - Electric for the three months and nine months ended September 30, 2006 and
      2005. See Note 7 - Related Party Transactions for further information on
      affiliate interchange revenues.





**Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005**Ameren(a)
            **$**
            **183**
            
            $
            105
            
            **$**
            **533**
            
            $
            359UE
            
            **90**
            
            
            110
            
            
            **331**
            
            
            336CIPS
            
            **-**
            
            
            9
            
            
            **2**
            
            
            26Genco
            
            **39**
            
            
            56
            
            
            **129**
            
            
            165CILCORP
            
            **4**
            
            
            -
            
            
            **23**
            
            
            26CILCO
            
            **4**
            
            
            -
            
            
            **23**
            
            
            26IP
            
            **-**
            
            
            -
            
            
            **-**
            
            
            (b
            )


(a)
            Includes
                amounts for Ameren registrant and nonregistrant subsidiaries and
                intercompany eliminations. Includes interchange revenues at Marketing
                Company and EEI of $103 million and $277 million for the three months
                and
                nine months ended September 30, 2006, respectively (2005 - $9 million
                and
                $24 million, respectively).


(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 and nine months ended
      September 30, 2006 and 2005. See Note 7 - Related Party Transactions for further
      information on affiliate purchased power transactions.





**Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005**Ameren(a)
            **$**
            **346**
            
            $
            340
            
            **$**
            **896**
            
            $
            782UE
            
            **64**
            
            
            102
            
            
            **199**
            
            
            206CIPS
            
            **125**
            
            
            140
            
            
            **355**
            
            
            331Genco
            
            **84**
            
            
            89
            
            
            **269**
            
            
            206CILCORP
            
            **17**
            
            
            24
            
            
            **25**
            
            
            46CILCO
            
            **17**
            
            
            24
            
            
            **25**
            
            
            46IP
            
            **213**
            
            
            187
            
            
            **561**
            
            
            509


(a)
            Includes
                amounts for Ameren registrant and nonregistrant subsidiaries and
                intercompany eliminations. Includes purchased power for EEI of $1
                million
                and $4 million for the three months and nine months ended September
                30,
                2006, respectively (2005 - nil and $1 million, respectively).




**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 and
      are therefore not included in our revenues and expenses. 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 and nine months ended September 30, 2006
      and
      2005:





**Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005**Ameren
            **$**
            **43**
            
            $
            44
            
            **$**
            **129**
            
            $
            125UE
            
            **35**
            
            
            35
            
            
            **87**
            
            
            84CIPS
            
            **2**
            
            
            3
            
            
            **11**
            
            
            10CILCORP
            
            **2**
            
            
            1
            
            
            **8**
            
            
            7CILCO
            
            **2**
            
            
            1
            
            
            **8**
            
            
            7IP
            
            **4**
            
            
            5
            
            
            **23**
            
            
            24




**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.





**Missouri**





***Electric***





With
      the
      expiration of an electric rate moratorium that provided for no changes in UE’s
      electric rates before July 1, 2006, UE filed in July 2006 a request with the
      MoPSC for an increase in base rates for electric service. UE’s filing included a
      proposed average increase in electric rates of 17.7%, or $361 million. UE is
      proposing to limit the increase on residential rates to 10%, allocating
      requested revenue amounts above that level to other customer classes. This
      rate
      increase filing was based on a test year ended June 30, 2006, and included
      known
      and measurable items through January 1, 2007. Since UE’s last electric rate case
      in 2002, UE has invested approximately $2.5 billion in its electric operations.
      Those investments included more than $700 million for 2,600 megawatts of new
      generation to meet growing customer power demands. UE’s electric rate request
      includes, among other items, the following features:


32




·
            a
                requested return on equity of 12%, and a rate base of $5.8 billion
                with a
                capital structure including about 52% common
                equity;


·
            a
                request for fuel, purchased power, and environmental cost recovery
                mechanisms under the provisions of a Missouri state law enacted in
                2005
                (See MoPSC Rulemaking Proceeding below in this Note for additional
                information);


·
            a
                proposed alternative mechanism for the MoPSC’s consideration to share
                off-system sales margins with
                ratepayers;


·
            an
                increase in depreciation rates;


·
            renewable
                energy proposals, including the addition of 100 megawatts of renewable
                energy by 2010;


·
            commitments
                to offer low income energy assistance and energy conservation programs;
                and


·
            costs
                incurred related to the December 2005 failure of UE’s Taum Sauk
                pumped-storage hydroelectric plant for the clean-up of a nearby park,
                reimbursement of state costs and resolution of individuals’ claims were
                excluded from the revenue increase
                request.





The
      MoPSC
      staff and other stakeholders will review UE’s rate adjustment request and, after
      their analyses, may also make recommendations as to electric rate adjustments.
      A
      decision from the MoPSC is expected no later than June 2007.





***Gas***





In
      July
      2006, UE filed a request with the MoPSC for an $11 million increase in natural
      gas delivery rates, based on an 11.5% return on equity, and a rate base of
      $200
      million with a capital structure including about 52% common equity. The MoPSC
      staff and other stakeholders will review UE’s rate adjustment request and, after
      their analyses, may also make recommendations as to gas rate adjustments. A
      decision from the MoPSC is expected no later than June 2007.





***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 cost recovery mechanism and prudency
      reviews, among other things. Rules for the fuel and purchased power cost
      recovery mechanism were approved by the MoPSC on September 21, 2006, and are
      expected to be effective by the end of the year. We are unable to predict when
      rules implementing the environmental cost recovery mechanism will be formally
      proposed and adopted. UE requested fuel, purchased power and environmental
      cost
      recovery mechanisms in its electric rate case filed with the MoPSC in July
      2006.
      UE’s requests are subject to approval by the MoPSC.





**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, with the consent of the Illinois utilities. 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. As part
      of Ameren’s acquisition of IP, IP entered into a power supply agreement with
      DYPM to supply about 70% of its electric customer requirements through the
      end
      of 2006. The remaining 30% of IP’s power needs are being supplied by other
      companies through contracts and open market purchases. See Note 7 - Related
      Party Transactions for a discussion of the affiliate power supply agreements.
      The following is a discussion of the current status of significant matters
      affecting our Illinois electric operations post-2006.




Illinois
      Power Procurement





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
      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 that
      unanimously approved the Ameren Illinois utilities’ proposed power procurement
      auction and the related tariffs for the period commencing January 2, 2007,
      including the retail rates by which power supply costs would be passed through
      to customers. The order included 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;






33




·
            there
                is a limitation of 35% on the amount of power any single supplier
                can
                provide the Ameren Illinois utilities’ expected annual load.
                Ameren-affiliated companies are considered one supplier for purposes
                of
                this limitation;


·
            requires
                a portfolio of one-, two-, and three-year supply
                contracts;


·
            allows
                full cost recovery through a rate mechanism;
                and


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





In
      accordance with the January 2006 ICC order, the power procurement auction was
      held at the beginning of September 2006. On September 14, 2006, the ICC
      determined that it would not investigate the results of the auction to procure
      power for fixed-price customers, which include the vast majority of electric
      customers of CIPS, CILCO and IP. On September 15, 2006, the independent auction
      manager (NERA Economic Consulting) declared a successful result in the auction
      for fixed-price customers. The auction clearing price was approximately $65
      per
      megawatthour for the fixed-price residential and small commercial product and
      approximately $85 per megawatthour for large commercial and industrial
      customers. Marketing Company was awarded sales in the auction. As a result
      of
      the large commercial and industrial customers’ auction price, it is expected
      that nearly all of these customers will choose a different
      supplier.





Certain
      Illinois legislators, the Illinois attorney general, the Illinois governor
      and
      other parties sought to block the power procurement auction and continue to
      challenge the auction and/or the recovery of costs for power supply resulting
      from the auction through rates to customers. Opponents of the power procurement
      auction and related tariffs claim 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.
      Opponents have claimed 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. CIPS, CILCO and IP have received favorable
      rulings from the ICC and the Circuit Court of Cook County, Illinois on
      opposition claims filed by the Illinois attorney general, CUB and
      ELPC.





Various
      parties, including CIPS, CILCO, IP, the Illinois attorney general, CUB and
      ELPC,
      have filed appeals with Illinois district appellate courts of the ICC’s denial
      of rehearing requests with respect to its January 2006 order. While CIPS, CILCO
      and IP are generally supportive of the ICC order, they filed a request for
      rehearing with regard to the provision of the January 2006 order requiring
      an
      annual, postauction prudence review to be performed by the ICC and in February
      2006 appealed the ICC’s denial of the request to the appellate court for the
      Fourth District in Illinois. CIPS, CILCO and IP asserted in their request for
      rehearing that there is no basis for such a prudence review. In their requests
      for rehearing of the January 2006 ICC order and their appeals of the ICC’s
      denial of their requests filed with the First District Illinois appellate court
      in March and April 2006, the Illinois attorney general, CUB and ELPC assert
      that
      the Ameren Illinois utilities power procurement auction should be dismissed
      on
      the basis of arguments generally similar to those that they previously raised
      as
      discussed above. In June 2006, the Illinois attorney general filed a petition
      with the Supreme Court of Illinois seeking a direct and expedited review of
      appeals filed with Illinois district courts by various parties of the ICC’s
      January 2006 order approving the Illinois power procurement auction and a stay
      on implementation of the order. In this petition, the Illinois attorney general
      raised similar arguments to those previously raised as discussed above. In
      August 2006, the Supreme Court of Illinois denied the Illinois attorney
      general’s petition and ordered that the appeals be consolidated in the appellate
      court for the Second District in Illinois. These appeals are
      pending.





Delivery
      Service Rate Cases




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
        $202 million in the aggregate (CIPS - $14 million, CILCO - $43 million and
        IP -
        $145 million). Since most customers are currently taking service
        under a frozen bundled electric rate, which includes the cost of power, any
        delivery service revenue change may not directly correspond to a change in
        CIPS’, CILCO’s or IP’s revenues or earnings when all customers transition to an
        electric delivery service rate effective January 2, 2007. 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
        June 2006, the ICC staff filed rebuttal testimony recommending increases
        in
        revenues for electric delivery services for the Ameren Illinois utilities
        aggregating $120 million (CIPS - $1 million, CILCO - $30 million and IP -
        $89
        million). In testimony, the Illinois attorney general accepted certain of
        the
        Ameren Illinois utilities’ positions, increasing its estimated aggregate
        recommended revenue increase from $70 million to approximately $110
        million (CIPS
        - $3
        milliondecrease, CILCO - $29 million increase and IP - $84 million
        increase). Other parties also made recommendations in the cases. In October
        2006, the administrative law judges issued a proposed order, which included
        a
        recommended revenue increase for electric delivery service of $147 million
        in
        the aggregate (CIPS - $8 million, CILCO - $29 million and
 IP
        - $110
        million). The ICC has until November 25, 2006, to render a decision in these
        cases.




34


Rate
      Freeze Extension Proposal





In
      February 2006, legislation was introduced in the Illinois House of
      Representatives that would extend the electric rate freeze in Illinois through
      2010. On October 2, 2006, Speaker of the Illinois House of Representatives,
      Michael Madigan, sent a letter to Illinois Governor Rod Blagojevich asking
      the
      Illinois governor to call a special session of the Illinois General Assembly
      for
      the purpose of considering this rate freeze legislation. In response, the
      Illinois governor sent a letter indicating that once the votes to pass the
      legislation were in place he would immediately call for a special session of
      the
      legislature. The governor’s letter further provided that in the event a
      consensus among members of the General Assembly is not reached in the near
      future, he would call a special session in that event as well. The governor’s
      letter stated he continued to support legislation extending a rate freeze and
      would like to sign it into law as soon as possible. Copies of the speaker’s and
      governor’s letters appear as Exhibits 99.1 and 99.2, respectively, to the
      Current Report on Form 8-K dated October 4, 2006. On October 9, 2006, the
      Electric Utility Oversight Committee of the Illinois House of Representatives
      voted in favor of extending the electric rate freeze through 2010. The measure
      will need to be approved by the full Illinois House of Representatives and
      Illinois Senate, and signed by the Illinois governor before it could become
      law.





CIPS,
      CILCORP, CILCO and IP believe the proposed electric rate freeze legislation,
      if
      enacted, would have a material adverse effect on their results of operations,
      financial position and liquidity, including the financial insolvency of CIPS,
      CILCORP, CILCO and IP, as well as result in significant job losses and, without
      governmental intervention, significant disruptions in electric and gas service.
      Since Ameren’s Illinois utilities own almost no generation, the companies must
      purchase power from the competitive market to provide customers’ energy needs.
      If the rate freeze were extended, the Ameren Illinois utilities estimate they
      would spend in the aggregate approximately $1 billion annually more for power
      than they could charge their customers (CIPS - $415 million, CILCO - $175
      million, IP - $410 million). It is likely that the Ameren Illinois utilities’
credit ratings would be downgraded to deep junk status if rate freeze
      legislation was enacted.  Moody's has also indicated that upon rate freeze
      legislation, or similar legislation that restricts the recovery of costs in
      a
      timely manner, passing the Illinois House of Representatives (even if prior
      to
      passage in the Illinois Senate or enactment into law), it may consider
      additional credit ratings downgrades with regard to one or more of the Ameren
      Companies.  With such credit ratings, we believe CIPS, CILCORP, CILCO and
      IP would be faced with potential collateral and prepayment requirements for
      products and services, such as power and natural gas, and would quickly run
      out
      of cash and available credit and be unable to borrow. We believe this would
      lead
      to the Ameren Illinois utilities and CILCORP being financially insolvent by
      February 2007, or sooner. In reaction to intensified political discussion in
      Illinois regarding electric rate freeze extension legislation, in October 2006
      S&P downgraded the short- and long-term credit ratings of the Ameren
      Companies and kept the Ameren Companies on credit watch with negative
      implications; Moody’s placed the long-term debt credit ratings of the Ameren
      Companies under review for possible downgrade; and Fitch placed the ratings
      of
      Ameren, CIPS, CILCORP, CILCO and IP on rating watch negative.





Electric
      Rate Increase Phase-in Plans





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
      and small to mid-size commercial customers to address the significant increases
      in customer rates for the Ameren Illinois utilities beginning in 2007. The
      Ameren Illinois utilities believe that a rate increase phase-in plan would
      need
      to allow for full and timely recovery of all deferred costs in a manner that
      supports investment-grade credit ratings for CIPS, CILCO and IP.





CIPS,
      CILCO and IP filed two proposed plans with the ICC to mitigate the impact of
      expected higher electric rates for residential customers. The Customer Elect
      Payment Plan (the Opt-In Plan), which these Ameren Illinois utilities filed
      with
      the ICC in October 2006, would allow residential customers the choice on an
      individual basis to either pay the full amount of higher electricity costs
      in
      2007 or to phase in increases over a period of years. Under this plan, increases
      would be phased in at an annual maximum increase of 15 percent over three years
      or until the full amount of the rate increase is reached, whichever is earlier.
      At the end of the phase-in period, customers would have three years to repay
      the
      deferred costs at a carrying charge interest rate of 6.5 percent. As part of
      this filing, CIPS, CILCO and IP have proposed to make an additional contribution
      of $5 million to their Dollar More and Warm Neighbors programs, which provide
      bill paying assistance, energy conservation materials and rebates for energy
      efficient equipment if this plan is approved.





Earlier
      in 2006, the Ameren Illinois utilities filed with the ICC a rate increase
      phase-in and revenue securitization plan for residential customers for the
      deferral of power supply costs for 2007 and 2008. Unlike the Opt-In Plan,
      legislation would be needed for this plan to become effective, and the plan
      would apply to all residential customers (i.e. participation would not be
      voluntary). In July 2006, the Illinois attorney general filed a motion with
      the
      ICC to dismiss this plan. In July 2006, the administrative law judge denied
      the
      Illinois attorney general’s motion. In March 2006, legislation was introduced in
      the Illinois House of Representatives that would allow the




35




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. This approach has the effect of spreading over the life of
      the
      bonds, a period of up to 10 years, the significant initial electric rate
      increase for residential customers that would otherwise be necessary to pay
      the
      power supply costs on a current basis. This legislation was not adopted during
      the spring session.




Summary





We
      are
      unable to predict the results of the court appeals of the January 2006 ICC
      order
      approving CIPS’, CILCO’s and IP’s power procurement auction and the related
      tariffs, nor can we predict the actions the Illinois General Assembly and
      governor may take which may impact electric rates or the power procurement
      process for CIPS, CILCO and IP after the expiration of the current Illinois
      electric rate freeze on January 1, 2007, and power supply contracts on December
      31, 2006. 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 would result in material adverse consequences
      to
      Ameren, CIPS, CILCORP, CILCO and IP. These consequences could include a
      significant drop in credit ratings to deep junk status, a loss of access to
      the
      capital markets, higher borrowing costs, higher power supply costs, an inability
      to make timely energy infrastructure investments, significant risk of disruption
      in electric and gas service, significant job losses, and financial insolvency.
      In addition, Ameren, CILCORP and IP could be required to record a one-time
      charge for goodwill impairment related to goodwill that was recorded when Ameren
      acquired these companies. As of September 30, 2006, Ameren, CILCORP and IP
      had
      $976 million, $575 million and $326 million, respectively, of goodwill recorded
      on their balance sheets. Furthermore, if the Ameren Illinois utilities are
      unable to recover their costs from customers, the utilities could be required
      to
      cease applying SFAS No. 71, “Accounting for the Effects of Certain Types of
      Regulation”, which allows CIPS, CILCO and IP to defer certain costs pursuant to
      actions of rate regulators. This
      would result in the elimination of all regulatory assets recorded by CIPS,
      CILCORP, CILCO and IP on their balance sheets and a one-time extraordinary
      charge on their statements of income that could be material. As of September
      30,
      2006, CIPS, CILCORP, CILCO and IP had $35 million, $12 million, $12 million
      and
      $197 million, respectively, recorded as regulatory assets on their balance
      sheets.





Ameren,
      CIPS, CILCORP, CILCO and IP continue to explore a number of legal and regulatory
      actions, strategies and alternatives to address these Illinois electric issues.
      CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to
      protect their financial interests, including seeking the protection of the
      bankruptcy courts. There can be no assurance that Ameren, CIPS, CILCORP, CILCO
      and IP 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,
      CIPS, CILCORP, CILCO and IP are considering will be successful.





**Federal**





***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 by the end of 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***





See
      Note
      7 - Related Party Transactions for a description of the JDA among UE, CIPS
      and
      Genco.





*January
      2006 JDA Amendment*





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 JDA that determines the allocation between UE and Genco of margins 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 March 2006, FERC approved the amendment filed
      by
      UE, CIPS and Genco, effective January 10, 2006. This change in the allocation
      methodology resulted in a $3 million and $17 million transfer of electric
      margins from Genco to UE during the three months and nine months ended September
      30, 2006, respectively.





*Termination
      of JDA*





On
      July
      7, 2006, UE, CIPS and Genco mutually consented to waive a one-year termination
      notice requirement of the JDA and agreed to terminate it on December 31, 2006.
      This action with respect to the JDA was accepted by the FERC in September
      2006.









36




The
      benefits of the JDA to UE and Genco have changed recently due to the emergence
      of transparent wholesale markets, the dispatching of generation being conducted
      by MISO, and changes to the Illinois regulatory framework, among other things.
      As a result, UE believes the benefit it will receive from retaining the power
      it
      was transferring under the JDA to Genco at incremental cost will exceed the
      benefit it would have received from being able to call upon Genco's generation
      under the JDA at incremental cost. Since UE was prepared to immediately provide
      Genco with one-year notice of termination in June 2006, Genco believes the
      potential benefit it could receive from being able to call upon UE's generation
      through June 2007 is outweighed by, among other things, the negative
      consequences associated with the continued existence of the JDA past December
      31, 2006. In particular, Genco believes that the JDA is no longer necessary
      or
      effective in dispatching Genco's generation jointly with that of UE due to
      changes in the marketplace for the sale of electricity, including the MISO
      Day
      Two Energy Market, and the centralized dispatching of generation by MISO.
      Additionally, the JDA is based on a combined control area for the UE and CIPS
      transmission facilities located in Missouri and Illinois,
      respectively. This combined control area creates operational inefficiencies
      for Genco to effectively participate through Marketing Company in the Illinois
      power procurement auction to supply power beginning January 1, 2007. In
      conjunction with terminating the JDA, Ameren's transmission-owning entities
      intend to restructure their control areas so as to have one control area in
      Missouri for UE's transmission facilities and one in Illinois for the
      transmission facilities of CIPS, CILCO and IP.





As
      a
      result of the termination of the JDA on December 31, 2006, UE and Genco will
      no
      longer have the obligation to provide power to each other. In 2005, Genco
      received from UE under the JDA net transfers of 8.7 million megawatthours of
      power at an average price of $18 per megawatthour and generated 14.2 million
      megawatthours of power from its plants at an average cost of approximately
      $18
      per megawatthour. This power, along with 2.0 million megawatthours purchased
      from EEI, was used in 2005 to supply CIPS' load and other wholesale and retail
      customers at an average selling price of $35 per megawatthour. In 2005, Genco
      also sold 3.3 million net megawatthours of power in the interchange market
      at an
      average price of $47 per megawatthour. Upon termination of the JDA, Genco will
      no longer receive the margins on sales that were supplied with power from UE.




Ameren's
      and UE’s earnings will be affected by the termination of the JDA when UE's rates
      are adjusted by the MoPSC. As discussed under Missouri Electric in this Note,
      UE
      filed a request in July 2006 with the MoPSC to increase its electric rates
      by
      $361 million. UE's requested increase is net of the decrease in its revenue
      requirement resulting from increased margins expected to result from the
      termination of the JDA.





The
      ultimate impact of the termination of the JDA and the MoPSC’s treatment of the
      effects of such termination in UE’s current rate case proceeding on the Ameren
      Companies’ results of operations, financial position, or liquidity cannot be
      predicted at this time.





***Leveraged
      Leases***





Ameren
      owns interests in certain assets that were acquired through the acquisition
      of
      CILCORP and financed as leveraged leases. By an order dated April 15, 2004,
      issued pursuant to PUHCA 1935, the SEC determined that certain nonutility
      interests and investments of CILCORP and its subsidiaries, including investments
      in several leveraged leases, are not retainable by Ameren. The April 2004 SEC
      order required that Ameren cause its subsidiaries to sell or otherwise dispose
      of the nonretainable interests. The nonretainable interests primarily consist
      of
      lease interests in commercial real estate properties and equipment. The SEC
      approved the divestiture transaction structure proposed by Ameren in December
      2005.





Ameren,
      CILCORP and CILCO recognized net after-tax losses of $4 million, $4 million
      and
      $6 million, respectively, from the sale of two leveraged leases in the second
      quarter of 2006.





Ameren
      and several of its registrant and nonregistrant subsidiaries are pursuing the
      sale of their interests in four remaining leveraged lease assets.




**NOTE
      3 - CREDIT FACILITIES AND LIQUIDITY**





The
      liquidity needs of the Ameren Companies are typically supported through the
      use
      of available cash, commercial paper issuances and drawings under committed
      bank
      credit facilities. The following table summarizes the short-term borrowing
      activity and relevant interest rates as of September 30, 2006, and December
      31,
      2005, respectively:





**Ameren**
            
            **UE****September
                30, 2006:**Average
                daily borrowings outstanding during 2006
            **$**
            **276**
            
            **$**
            **246**Weighted-average
                interest rate during 2006
            
            **5.06**
            **%**
            
            **5.05**
            **%**Peak
                short-term borrowings during 2006
            **$**
            **602**
            
            **$**
            **470**Peak
                interest rate during 2006
            
            **5.55**
            **%**
            
            **5.55**
            **%**






37





**Ameren**
            
            
            **UE****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
        September 30, 2006, Ameren and certain of its subsidiaries had $1.65 billion
        of
        committed credit facilities, consisting of two facilities as described below,
        each maturing in July 2010, in the amounts of $1.15 billion and $500 million.





Ameren
      could directly borrow under the $1.15 billion facility up to the entire amount
      of the facility; UE could directly borrow under this facility up to $500 million
      on a 364-day basis; Genco could directly borrow under this facility up to $150
      million on a 364-day basis; and until July 13, 2006, CIPS, CILCO and IP could
      also each directly borrow under this facility up to $150 million, on a 364-day
      basis. On July 14, 2006, the $1.15 billion credit facility was amended. The
      amended facility will terminate on July 14, 2010, with respect to Ameren. UE
      and
      Genco will continue to have the option to seek an annual renewal on a 364-day
      basis after their current termination dates. Effective July 13, 2006, the
      termination date for UE and Genco was extended to July 12, 2007. CIPS, CILCO
      and
      IP no longer had borrowing authority under this facility effective July 13,
      2006, but remained parties to the agreement until September 8, 2006 as discussed
      in the Indebtedness Provisions and Other Covenants section below. Under the
      amended facility, Ameren will continue to have $1.15 billion of borrowing
      availability. UE and Genco will continue to have $500 million and $150 million,
      respectively, of borrowing availability.





Under
      the
      amended $1.15 billion credit facility, the principal amount of each revolving
      loan will be due and payable no later than the final maturity of the facility
      in
      the case of Ameren and the last day of the then applicable 364-day
      period in the case of UE and Genco. The principal amount of each loan will
      be
      due and payable at the end of the interest period applicable to it, which shall
      not be later than the final maturity date of the facility. Swingline loans
      will
      be made on same-day notice and will mature five business days after they are
      made.




Ameren,
      UE and Genco will use the proceeds of any borrowings under the amended facility
      for general corporate purposes, including for working capital, commercial paper
      liquidity support and to fund loans under the Ameren money pool arrangements.
      See Exhibit 10.1 to the Current Report on Form 8-K, dated July 18, 2006, for
      a
      copy of the amended facility.





On
      July
      14, 2006, CIPS, CILCORP, CILCO, IP and AERG entered into a new $500 million
      multiyear, senior secured credit facility. Borrowing authority under this
      facility was effective immediately for AERG and CILCORP and effective September
      8, 2006, for CIPS, CILCO and IP upon the receipt of regulatory approvals and
      the
      issuance by CIPS, CILCO and IP of mortgage bonds as security as described below.
      Once CIPS, CILCO and IP were authorized to borrow under this new facility,
      they
      were removed as parties to the $1.15 billion credit facility.




The
      obligations of each borrower under the new $500 million facility are several
      and
      not joint, and are not guaranteed by Ameren or any other subsidiary of Ameren.
      The maximum amount available to each borrower, including for issuance of letters
      of credit on its behalf, is limited as follows: CIPS - $135 million, CILCORP
      -
      $50 million, CILCO - $150 million,


IP
      - $150
      million and AERG - $200 million. In September 2006, AERG drew a $40 million
      Eurodollar loan under this credit facility at an interest rate of 6.7%. The
      borrowing companies will use the proceeds of any borrowings for working capital
      and other general corporate purposes; however, a portion of the borrowings
      by
      AERG may be limited to financing or refinancing the development, management
      and
      operation of any of its projects or assets. The new facility will terminate
      on
      January 14, 2010.





The
      obligations of CIPS, CILCO and IP under the new facility are secured by the
      issuance on September 8, 2006, of mortgage bonds by each such utility under
      its
      respective mortgage indenture in the amounts of $135 million, $150 million
      and
      $150 million, respectively. The obligations of CILCORP under the facility are
      secured by a pledge of the common stock of CILCO. The obligations of AERG are
      secured by a mortgage and security interest in its E.D. Edwards and Duck Creek
      power plants and related licenses, permits and similar rights. See Exhibit
      10.2
      to the Current Report on Form 8-K, dated July 18, 2006, for a copy of the new
      facility.





As
      a
      condition to the amendment of the $1.15 billion credit facility and the closing
      of the new $500 million credit facility, effective July 14, 2006, Ameren
      terminated its $350 million credit facility. Ameren was the only borrower under
      this agreement, and there was no early termination penalty.




The
      $1.15
      billion credit facility, and the $350 million credit facility prior to its
      termination, were used to support our commercial paper programs that include
      all
      outstanding external short-term debt of Ameren and UE as of September 30, 2006,
      and December 31, 2005. The $1.15 billion amended facility will continue to
      support Ameren’s and UE’s commercial paper programs. Access to


38


the
        $1.15
        billion credit facility and the $500 million credit facility for the Ameren
        Companies are 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 may access the committed credit
      facilities. CIPS, CILCO and IP borrow from each other through the utility money
      pool agreement subject to applicable regulatory short-term borrowing
      authorizations. While UE and Ameren Services are parties to the utility money
      pool agreement, they are not currently borrowing or lending under the agreement.
      Ameren Services administers the utility money pool and tracks internal and
      external funds separately. Ameren and AERG may participate in the utility money
      pool only as lenders. The availability of funds is effectively determined by
      funding requirement limits established by regulatory authorizations. The average
      interest rate for borrowing under the utility money pool for the three months
      and nine months ended September 30, 2006, was 5.4% and 5.0%, respectively (2005
      - 3.5% and 3.0%, respectively).





Non-state-regulated
      Ameren subsidiaries, including Genco and AERG, have the ability, subject to
      Ameren authorization, to access funding from Ameren’s $1.15 billion credit
      facility 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 and nine months ended September 30, 2006, was
      4.8% and 4.6%, respectively (2005 - 4.1% and 5.9%, respectively).





The
      total
      amount available to the money pool participants at any time is reduced by the
      amount of borrowings by their affiliates under existing agreements and is
      increased to the extent that other pool participants advance surplus funds
      to
      the 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 and nine months ended September 30, 2006 and 2005.





**Indebtedness
      Provisions and Other Covenants**





The
      bank
      credit facilities described above contain provisions which, among other things,
      place restrictions on the ability to incur liens, sell assets, and merge with
      other entities. As discussed above, the $1.15 billion credit facility was
      amended effective July 14, 2006. The provisions in the amended facility are
      similar to those in the prior facility, including the covenant that limits
      total
      indebtedness of Ameren, UE and Genco to 65% of total capitalization pursuant
      to
      a calculation defined in the facility. Exceeding these debt levels would result
      in a default under the credit arrangements.





The
      amended $1.15 billion credit facility also contains default provisions similar
      to those in the prior facility, including cross defaults, with respect to a
      borrower under the facility, that can result from the occurrence of an event
      of
      default under any other facility covering indebtedness of that borrower or
      certain of its subsidiaries in excess of $50 million in the aggregate. The
      obligations of Ameren, UE and Genco under the amended facility remain several
      and not joint, and except under limited circumstances, the obligations of UE
      and
      Genco are not guaranteed by Ameren or any other subsidiary. With the termination
      of CIPS, CILCO and IP as parties to this agreement on September 8, 2006, they
      are no longer considered subsidiaries for purposes of the cross-default
      provisions nor are CILCORP or AERG.





Under
      the
      amended $1.15 billion credit facility, restrictions apply limiting investments
      in and other transfers to CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries
      by Ameren and certain subsidiaries. Additionally, CIPS, CILCORP, CILCO, IP,
      AERG
      and their subsidiaries are excluded for purposes of determining compliance
      with
      the 65% total consolidated indebtedness to total consolidated capitalization
      financial covenant that remains in the amended facility.





The
      new
      $500 million credit facility entered into by CIPS, CILCORP, CILCO, IP and AERG,
      discussed above, limits the indebtedness of each borrower to 65% of consolidated
      total capitalization pursuant to a calculation set forth in the facility. Events
      of default under this facility apply separately to each borrower (and, except
      in
      the case of CILCORP, their subsidiaries), and an event of default under this
      facility does not constitute an event of default under the amended $1.15 billion
      credit facility and vice versa. In addition, if CIPS’, CILCO’s or IP’s senior
      secured long-term debt securities or first mortgage bonds, or CILCORP’s senior
      unsecured long-term debt securities, have received a below investment-grade
      credit rating by either Moody’s or S&P, then such borrower will be limited
      to capital stock dividend payments of $10 million per year each, while such
      below investment-grade credit rating is in effect. On July 26, 2006, Moody’s
      downgraded CILCORP’s senior unsecured long-term debt credit rating to below
      investment-grade causing it to be subject to this


39




dividend
      payment limitation. A similar restriction
      applies to AERG if its debt-to-operating cash flow ratio, as set forth in the
      facility, is below a specified ratio. As of September 30, 2006, AERG failed
      to
      meet the debt-to-operating cash flow ratio test in the facility and, therefore,
      is currently limited in its ability to pay dividends. CIPS, CILCO and IP are
      not
      currently limited in their dividend payments by this provision of the $500
      million credit facility. 
 This
        new
        facility also limits the amount of other secured indebtedness issuable by
        each
        borrower as follows: for CIPS, CILCO and IP, other secured debt is limited
        to
        that permitted under their respective mortgage indentures. For CILCORP, other
        secured debt is limited to $550 million secured by the pledge of CILCO stock,
        and for AERG, other secured debt is limited to $200 million secured on an
        equal
        basis with its obligations under the new facility. The new facility provides that
        CIPS, CILCO and IP will agree to reserve future bonding capacity under their
        respective mortgage indentures (that is, agree to forego the issuance of
        additional mortgage bonds otherwise permitted under the terms of each mortgage
        indenture) in the following amounts: CIPS, prior to December 31, 2007 - $50
        million, on and after December 31, 2007, but prior to December 31, 2008 -
        $100
        million, on and after December 31, 2008 - $150 million; CILCO - $25 million;
        and
        IP - $100 million. In addition, the new credit facility prohibits CILCO from
        issuing any preferred stock if after giving effect to such issuance the
        aggregate liquidation value of all CILCO preferred stock issued after July
        14,
        2006, would exceed $50 million.





As
      of
      September 30, 2006, the ratio of total indebtedness to total capitalization,
      calculated in accordance with the provisions of the $1.15 billion credit
      facility for Ameren, UE and Genco was 50%, 47% and 51%, respectively. The ratio
      for CIPS, CILCORP, CILCO, IP and AERG, calculated in accordance with the
      provisions of the $500 million credit facility, were 47%, 55%, 37%, 44% and
      25%,
      respectively.





None
      of
      Ameren’s credit facilities or financing arrangements contain credit rating
      triggers that would cause an event of default or acceleration of repayment
      of
      outstanding balances. At September 30, 2006, the Ameren Companies were in
      compliance with their credit facility 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 0.4 million new shares of common stock valued at $21
      million and 1.5 million new shares valued at $78 million in the three months
      and
      nine months ended September 30, 2006, respectively.





**UE**





UE’s
      debt
      increased $240 million in the first quarter of 2006 as a result of the capital
      lease assigned to it in connection with the acquisition from affiliates of
      NRG
      Energy, Inc. of a 640-megawatt CT facility located in Audrain County, Missouri.
      No capital was raised as a result of UE’s assumption of the lease
      obligations.





**CIPS**





In
      June
      2006, CIPS issued and sold, pursuant to an effective SEC Form S-3 registration
      statement, $61 million of 6.70% senior secured notes due June 15, 2036, with
      interest payable semi-annually on June 15 and December 15 of each year,
      beginning in December 2006. These notes are secured by first mortgage bonds,
      which are subject to fallaway provisions, as defined in the related financing
      agreements. CIPS received net proceeds of $60 million, which were used, among
      other funds, to repay in full CIPS’ intercompany note payable to
      UE.





Also
      in
      June 2006, $20 million of CIPS’ 7.05% first mortgage bonds matured and were
      retired.





See
      Note
      3 - Credit Facilities and Liquidity regarding first mortgage bonds issued by
      CIPS in September 2006 as security for its obligations under the $500 million
      credit facility.





**CILCORP**





In
      March
      2006, CILCORP repurchased $2 million in principal amount of its 9.375% senior
      bonds due 2029, and in April 2006, CILCORP repurchased an additional $7 million
      in principal amount of these bonds.





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 (2005 - $2 million) and $4 million (2005 - $6 million) for the three
      months and nine months ended September 30, 2006, respectively, and was included
      as a reduction to interest expense in the Consolidated Statements of Income
      of
      Ameren and CILCORP. See Note 3 - Credit Facilities and Liquidity regarding
      CILCORP’s pledge of the common stock of CILCO as security for CILCORP’s
      obligations under the $500 million credit facility.





**CILCO**





In
      June
      2006, CILCO issued and sold, with registration rights in a private placement,
      $54 million of 6.20% senior secured notes due June 15, 2016, and $42 million
      of
      6.70%


40


senior
      secured notes due June 15, 2036, both with
      interest payable semi-annually on June 15 and December 15 of each year,
      beginning in December 2006. These notes are secured by first mortgage bonds,
      which are subject to fallaway provisions as defined in the related financing
      agreements. CILCO received total net proceeds of $95 million which were used
      to
      reduce short-term money pool borrowings and, in July 2006, to redeem CILCO’s $20
      million 7.73% secured medium-term notes due 2025. CILCO
      commenced the offer to exchange registered secured notes for the outstanding
      unregistered senior secured notes under the related registration rights
      agreement on October 18, 2006. Unless extended, the exchange offer will expire
      on November 16, 2006. 
 In
        July
        2006, CILCO redeemed 11,000 shares of its 5.85% Class A preferred stock at
        a
        redemption price of $100
        per
        share plus accrued and unpaid dividends. The redemption satisfied CILCO’s
        mandatory sinking fund redemption requirement for this series of preferred
        stock
        for 2006.





See
      Note
      3 - Credit Facilities and Liquidity regarding first mortgage bonds issued by
      CILCO and the mortgage and security interest in its power plants issued by
      AERG
      in September 2006 as security for their respective obligations under the $500
      million credit facility.





**IP**





In
      June
      2006, IP issued and sold, with registration rights in a private placement,
      $75
      million of 6.25% senior secured notes due June 15, 2016, with interest payable
      semi-annually on June 15 and December 15 of each year, beginning in December
      2006. These notes are secured by mortgage bonds, which are subject to fallaway
      provisions as defined in the related financing agreements. IP received net
      proceeds of $74 million, which were used to reduce short-term money pool
      borrowings. IP commenced the offer to exchange registered secured notes for
      the
      outstanding unregistered senior secured notes under the related registration
      rights agreement on October 18, 2006. Unless extended, the exchange offer will
      expire on November 16, 2006.




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 (2005 - $3 million and $10 million (2005
      -
      $12 million) for the three months and nine months ended September 30, 2006,
      respectively, and was included as a reduction to interest expense in the
      Consolidated Statements of Income of Ameren and IP.





See
      Note
      3 - Credit Facilities and Liquidity regarding mortgage bonds issued by IP in
      September 2006 as security for its obligations under the $500 million credit
      facility.





**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 along
      with
      bonds and preferred stock issuable based on the 12 months ended September 30,
      2006, at an assumed interest and dividend rate of 7%.





**Required
                Interest Coverage Ratio****(a)(b)**
            
            **Actual
                Interest**
              **Coverage
                Ratio**
            
            **Bonds**
              **Issuable****(c)(d)**
            
            **Required
                Dividend Coverage Ratio****(e)**
            
            **Actua****l**
              **Dividend**
              **Coverage
                Ratio**
            
            **Preferred**
              **Stock**
              **Issuable**UE
            
            2.0
            
            
            4.4
            
            
            2,150
            
            
            2.5
            
            
            41.4
            
            
            1,319CIPS
            
            2.0
            
            
            4.0
            
            
            149
            
            
            1.5
            
            
            2.2
            
            
            210CILCO
            
            2.0(f
            )
            
            9.1
            
            
            200
            
            
            2.5
            
            
            17.4
            
            
            166(g
            )IP
            
            2.0
            
            
            5.7
            
            
            620
            
            
            1.5
            
            
            2.5
            
            
            420


(a)Coverage
      required on the annual interest charges on first mortgage bonds outstanding
      and
      to be issued.


(b) Coverage
        is not required in certain cases when additional mortgage bonds are issued
        on
        the basis of retired bonds.
 (c)
            Amount
                of bonds issuable based on either meeting required coverage ratios
                or
                unfunded property additions and retired bonds, whichever is more
                restrictive. (d)
            Amounts
                are net of future bonding capacity restrictions agreed to by CIPS,
                CILCO
                and IP under the $500 million credit facility entered into by these
                companies. See Note 3 - Credit Facilities and Liquidity for further
                discussion. (e)
            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. (f)
            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
                and
                nine months ended September 30, 2006, CILCO had earnings equivalent
                to at
                least 44% of the principal amount of all mortgage bonds
                outstanding. (g)
            See
                Note 3 - Credit Facilities and Liquidity for a discussion regarding
                a
                restriction on the issuance of preferred stock by CILCO under the
                $500
                million credit facility.






41




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
        $1.8 billion of free and unrestricted retained earnings at September 30,
        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. On
        October 5, 2006, S&P downgraded IP’s credit ratings to the lowest
        investment-grade


rating
      and placed them on credit watch with negative implications. On October 10,
      2006,
      Moody’s placed IP’s long-term credit ratings under review for possible
      downgrade. If 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 September
      30, 2006, $33,000
      of the 11.50% Series mortgage bonds due 2010 were outstanding. The bonds become
      callable in December 2006.





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 September 30,
      2006:





**Required**
                **Interest**
                **Coverage**
                **Ratio**
              **Actual**
                **Interest**
                **Coverage**
                **Ratio**
              **Required**
                **Debt-to-**
                **Capital**
                **Ratio**
              **Actual**
                **Debt-to-**
                **Capital**
                **Ratio**Genco(a)
              ≥1.75(b)
              3.9
              ≤60%
              50%CILCORP(c)
              ≥2.2
              2.6
              ≤67%
              40%


(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)
            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.


(c)
            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.





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
      September 30, 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 and nine months ended September 30, 2006 and
      2005:





**Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005****Ameren:****(a)**Miscellaneous
                income:Interest
                and dividend income
            **$**
            **2**
            
            $
            3
            
            **$**
            **5**
            
            $
            5Allowance
                for equity funds used during construction
            
            **1**
            
            
            3
            
            
            **2**
            
            
            10Other
            
            **2**
            
            
            -
            
            
            **6**
            
            
            4Total
                miscellaneous income
            **$**
            **5**
            
            $
            6
            
            **$**
            **13**
            
            $
            19Miscellaneous
                expense:Other
            **$**
            **(3**
            **)**
            $
            (1
            )
            **$**
            **(4**
            **)**
            $
            (7
            )Total
                miscellaneous expense
            **$**
            **(3**
            **)**
            $
            (1
            )
            **$**
            **(4**
            **)**
            $
            (7
            )**UE:**Miscellaneous
                income:Interest
                and dividend income
            **$**
            **-**
            
            $
            -
            
            **$**
            **2**
            
            $
            -Allowance
                for equity funds used during construction
            
            **1**
            
            
            3
            
            
            **1**
            
            
            9Other
            
            **1**
            
            
            -
            
            
            **3**
            
            
            3Total
                miscellaneous income
            **$**
            **2**
            
            $
            3
            
            **$**
            **6**
            
            $
            12






42





**Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005**


Miscellaneous
                expense:Other
            **$**
            **(3**
            **)**
            $
            (2
            )
            **$**
            **(7**
            **)**
            $
            (6
            )Total
                miscellaneous expense
            **$**
            **(3**
            **)**
            $
            (2
            )
            **$**
            **(7**
            **)**
            $
            (6
            )


**CIPS:**Miscellaneous
                income:Interest
                and dividend income
            **$**
            **4**
            
            $
            4
            
            **$**
            **12**
            
            $
            13Other
            
            **-**
            
            
            -
            
            
            **1**
            
            
            -Total
                miscellaneous income
            **$**
            **4**
            
            $
            4
            
            **$**
            **13**
            
            $
            13Miscellaneous
                expense:Other
            **$**
            **-**
            
            $
            (1
            )
            **$**
            **(1**
            **)**
            $
            (5
            )Total
                miscellaneous expense
            **$**
            **-**
            
            $
            (1
            )
            **$**
            **(1**
            **)**
            $
            (5
            )**Genco:**Miscellaneous
                income:Other
            **$**
            **-**
            
            $
            -
            
            **$**
            **-**
            
            $
            1Total
                miscellaneous income
            **$**
            **-**
            
            $
            -
            
            **$**
            **-**
            
            $
            1**CILCORP:**Miscellaneous
                income:Interest
                and dividend income
            **$**
            **-**
            
            $
            -
            
            **$**
            **1**
            
            $
            -Total
                miscellaneous income
            **$**
            **-**
            
            $
            -
            
            **$**
            **1**
            
            $
            -Miscellaneous
                expense:Other
            **$**
            **(2**
            **)**
            $
            (2
            )
            **$**
            **(4**
            **)**
            $
            (7
            )Total
                miscellaneous expense
            **$**
            **(2**
            **)**
            $
            (2
            )
            **$**
            **(4**
            **)**
            $
            (7
            )**CILCO:**Miscellaneous
                expense:Other
            **$**
            **(2**
            **)**
            $
            (2
            )
            **$**
            **(4**
            **)**
            $
            (5
            )Total
                miscellaneous expense
            **$**
            **(2**
            **)**
            $
            (2
            )
            **$**
            **(4**
            **)**
            $
            (5
            )**IP:**Miscellaneous
                income:Interest
                and dividend income
            **$**
            **1**
            
            $
            1
            
            **$**
            **2**
            
            $
            3Allowance
                for equity funds used during construction
            
            **-**
            
            
            -
            
            
            **-**
            
            
            1Other
            
            **1**
            
            
            1
            
            
            **2**
            
            
            2Total
                miscellaneous income
            **$**
            **2**
            
            $
            2
            
            **$**
            **4**
            
            $
            6Miscellaneous
                expense:Other
            **$**
            **(1**
            **)**
            $
            -
            
            **$**
            **(3**
            **)**
            $
            (1
            )Total
                miscellaneous expense
            **$**
            **(1**
            **)**
            $
            -
            
            **$**
            **(3**
            **)**
            $
            (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 being
      delivered or settled, resulting in a $3
      million gain for Ameren, a $2 million gain for UE, and a $1 million gain for
      Genco for the three months ended September 30, 2006 (2005 - $1 million loss
      for
      Ameren, $1 million loss for UE, $1 million loss for Genco), and a $2 million
      gain for Ameren, a $2 million gain for UE, and a $2 million loss for IP for
      the
      nine months ended September 30, 2006 (2005 - $2 million gain for Ameren, $1
      million loss for UE).




43


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 September 30, 2006:





**Ameren**(a)
            
            **UE**
            
            **CIPS**
            
            **Genco**
            
            **CILCORP/**
              **CILCO**
            
            **IP**Derivative
                instruments carrying value:Total
                assets
            $
            79
            
            $
            11
            
            $
            2
            
            $
            3
            
            $
            9
            
            $
            5Total
                deferred credits and liabilities
            
            16
            
            
            6
            
            
            -
            
            
            1
            
            
            -
            
            
            1Gains
                (losses) deferred in Accumulated OCI:Power
                forwards and swaps(b)
            
            54
            
            
            7
            
            
            -
            
            
            3
            
            
            -
            
            
            (1
            )Interest
                rate swaps(c)
            
            3
            
            
            -
            
            
            -
            
            
            3
            
            
            -
            
            
            -Gas
                swaps and futures contracts(d)
            
            9
            
            
            1
            
            
            2
            
            
            -
            
            
            9
            
            
            -SO2futures contracts
            
            (1
            )
            
            -
            
            
            -
            
            
            (1
            )
            
            -
            
            
            -


(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 of up to four years, including $30 million over
                the
                next 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
                2011.




**Other
      Derivatives**





The
      following table presents the net change in market value for the three months
      and
      nine months ended September 30, 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**
            
            **Nine
                Months****Gains
                (Losses)**
            **2006**
            
            **2005**
            
            **2006**
            
            **2005****SO****2****options and swaps:**Ameren
            **$**
            **1**
            
            $
            (4
            )
            **$**
            **(2**
            **)**
            $
            (10
            )UE
            
            **1**
            
            
            (4
            )
            
            **3**
            
            
            (5
            )Genco
            
            **-**
            
            
            -
            
            
            **(4**
            **)**
            
            (5
            )CILCORP/CILCO
            
            **-**
            
            
            -
            
            
            **(1**
            **)**
            
            -**Coal
                Options:**Ameren
            
            **(1**
            **)**
            
            -
            
            
            **(2**
            **)**
            
            1UE
            
            **(1**
            **)**
            
            1
            
            
            **(2**
            **)**
            
            1





**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.




**Electric
      Power Supply Agreements**





The
      following table presents the amount of gigawatthour sales under related party
      electric power supply agreements for the three months and nine months ended
      September 30, 2006 and 2005:


**Three
                  Months**
              
              **Nine
                  Months****2006**
              
              **2005**
              
              **2006**
              
              **2005**Genco
                  sales toMarketing
                  Company
              
              **5,820**
              
              
              6,788
              
              
              **16,707**
              
              
              16,884Marketing
                  Companysales
                  to CIPS
              
              **3,424**
              
              
              3,565
              
              
              **9,500**
              
              
              8,118EEI
                  sales to UE
              
              **-**
              
              
              789
              
              
              **-**
              
              
              2,230EEI
                  sales to CIPS
              
              **-**
              
              
              394
              
              
              **-**
              
              
              1,337EEI
                  sales to IP
              
              **-**
              
              
              433
              
              
              **-**
              
              
              1,227




The
      agreement under which EEI supplied power to UE, CIPS (which resold its
      entitlement to Marketing Company) 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. CIPS’
obligation to pay the residual amount of $2 million was transferred to Marketing
      Company, to which CIPS had sold power supplied by EEI under the agreement.
      Beginning January 1, 2006, EEI entered into a new agreement to sell 100% of
      its
      capacity and energy to Marketing Company at market prices through December
      31,
      2015.





In
      accordance with the January 2006 ICC order discussed in Note 2 - Rate and
      Regulatory Matters, a power procurement auction was held at the beginning of
      September 2006 to procure power for CIPS, CILCO and IP after current power
      supply contracts expire on December 31, 2006. On September 15, 2006, the
      independent auction manager (NERA Economic Consulting) declared a successful
      result in the auction for fixed-price customers. In conjunction with the
      auction, there is a limitation of 35% on the amount of power any single supplier
      can provide of the Ameren Illinois utilities’ expected annual load.
      Ameren-affiliated companies are




44




considered
      one supplier for the purposes of this limitation. Marketing Company was awarded
      contracts in the auction.




**Joint
      Dispatch Agreement**





UE
      and
      Genco jointly dispatch electric generation under the JDA 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. As
      further discussed in Note 2 - Rate and Regulatory Matters, in January 2006,
      the
      allocation methodology in the JDA for margins on short-term sales of excess
      generation to third parties between UE and Genco was modified, and on July
      7,
      2006, UE, CIPS and Genco mutually consented to waive the one-year termination
      notice requirement of the JDA and agreed to terminate it on December 31, 2006.
      This action with respect to the JDA was accepted by the FERC in September
      2006.




The
      following table presents the amount of gigawatthour sales under the JDA for
      the
      three months and nine months ended September 30, 2006 and 2005:





**Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005**UE
                sales to Genco
            
            **2,073**
            
            
            2,361
            
            
            **7,507**
            
            
            8,807Genco
                sales to UE
            
            **898**
            
            
            636
            
            
            **2,615**
            
            
            2,365




The
      following table presents the short-term power sales margins under the JDA for
      UE
      and Genco for the three months and nine months ended September 30, 2006 and
      2005:





**Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005**UE
            **$**
            **15**
            
            $
            18
            
            **$**
            **73**
            
            $
            97Genco
            
            **5**
            
            
            9
            
            
            **22**
            
            
            56Total
            **$**
            **20**
            
            $
            27
            
            **$**
            **95**
            
            $
            153





**Money
      Pools**




See
      Note
      3 - Credit Facilities 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 $3 million (2005 - $4 million) and $10 million (2005 - $12
      million) for the three months and nine months ended September 30, 2006 and
      2005.





In
      June
      2006, CIPS repaid in full the remaining balance under its May 2005, $67 million
      subordinated promissory note to UE.





The
      average interest rate on CILCORP’s note payable to Ameren was 4.8% and 4.5% for
      the three months and nine months ended September 30, 2006, respectively (2005
      -
      4.1% and 6.7%, respectively). CILCORP recorded interest expense of $2 million
      (2005 - $1 million) and $6 million (2005 - $4 million) for the three months
      and
      nine months ended September 30, 2006, respectively.





The
      following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and
      IP
      of related party transactions for the three months and nine months ended
      September 30, 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 above in Note
      3 -
      Credit Facilities and Liquidity of this report.





**Three
                Months**
            
            **Nine
                Months****Agreement**
            
            **UE**
            **CIPS**
            **Genco**
            **CILCORP****(a)**
            **IP**
            
            **UE**
            
            **CIPS**
            
            **Genco**
            **CILCORP****(a)**
            **IP****Operating
                Revenues:**Power
                supply agreement
            
            **2006**
            
            **$**
            **(b**
            **)**
            **$**
            **(b**
            **)**
            **$**
            **216**
            
            **$**
            **(c**
            **)**
            **$**
            **(b**
            **)**
            **$**
            **(b**
            **)**
            **$**
            **(b**
            **)**
            **$**
            **605**
            
            **$**
            **5**
            
            **$**
            **(b**
            **)**with
                Marketing Company
            
            2005
            
            
            (b
            )
            
            8
            
            
            229
            
            
            2
            
            
            (b
            )
            
            (b
            )
            
            25
            
            
            603
            
            
            23
            
            
            (b
            )Power
                supply agreementwith
                EEI
            
            2005
            
            
            (c
            )
            
            (b
            )
            
            (c
            )
            
            (b
            )
            
            (b
            )
            
            (c
            )
            
            (b
            )
            
            (c
            )
            
            (b
            )
            
            (b
            )UE
                and Genco gas
            
            **2006**
            
            
            **(c**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(c**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**transportation
                agreement
            
            2005
            
            
            (c
            )
            
            (b
            )
            
            (b
            )
            
            (b
            )
            
            (b
            )
            
            (c
            )
            
            (b
            )
            
            (b
            )
            
            (b
            )
            
            (b
            )JDA
            
            **2006**
            
            
            **35**
            
            
            **(b**
            **)**
            
            **23**
            
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **156**
            
            
            **(b**
            **)**
            
            **69**
            
            
            **(b**
            **)**
            
            **(b**
            **)**2005
            
            
            50
            
            
            (b
            )
            
            26
            
            
            (b
            )
            
            (b
            )
            
            147
            
            
            (b
            )
            
            57
            
            
            (b
            )
            
            (b
            )**Total
                Operating**
            
            **2006**
            
            **$**
            **35**
            
            **$**
            **(b**
            **)**
            **$**
            **239**
            
            **$**
            **(c**
            **)**
            **$**
            **(b**
            **)**
            **$**
            **156**
            
            **$**
            **(b**
            **)**
            **$**
            **674**
            
            **$**
            **5**
            
            **$**
            **(b**
            **)****Revenues**
            
            2005
            
            
            50
            
            
            8
            
            
            255
            
            
            2
            
            
            (b
            )
            
            147
            
            
            25
            
            
            660
            
            
            23
            
            
            (b
            )**Fuel
                and Purchased Power:**JDA
            
            **2006**
            
            **$**
            **23**
            
            **$**
            **(b**
            **)**
            **$**
            **35**
            
            **$**
            **(b**
            **)**
            **$**
            **(b**
            **)**
            **$**
            **69**
            
            **$**
            **(b**
            **)**
            **$**
            **156**
            
            **$**
            **(b**
            **)**
            **$**
            **(b**
            **)**2005
            
            
            26
            
            
            (b
            )
            
            50
            
            
            (b
            )
            
            (b
            )
            
            57
            
            
            (b
            )
            
            147
            
            
            (b
            )
            
            (b
            )






45





**Three
                Months**
            **Nine
                Months****Agreement**
            
            
            
            **UE**
            
            **CIPS**
            
            **Genco**
            
            **CILCORP****(a****)**
            **IP**
            
            **UE**
            
            
            **CIPS**
            
            
            **Genco**
            
            **CILCORP****(a****)**
            **IP**Power
                supply agreement
            
            **2006**
            
            **$**
            **(b**
            **)**
            **$**
            **118**
            
            **$**
            **(b**
            **)**
            **$**
            **1**
            
            **$**
            **(b**
            **)**
            **$**
            **(b**
            **)**
            **$**
            **337**
            
            **$**
            **(b**
            **)**
            **$**
            **1**
            
            **$**
            **(b**
            **)**with
                Marketing Company
            
            2005
            
            
            (b
            )
            
            121
            
            
            2
            
            
            3
            
            
            (b
            )
            
            4
            
            
            291
            
            
            4
            
            
            10
            
            
            (b
            )Power
                supply agreementwith
                EEI
            
            2005
            
            
            16
            
            
            8
            
            
            (b
            )
            
            (b
            )
            
            13
            
            
            46
            
            
            25
            
            
            (b
            )
            
            (b
            )
            
            40Executory
                tolling agreement
            
            **2006**
            
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **9**
            
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **29**
            
            
            **(b**
            **)**with
                Medina Valley
            
            2005
            
            
            (b
            )
            
            (b
            )
            
            (b
            )
            
            9
            
            
            (b
            )
            
            (b
            )
            
            (b
            )
            
            (b
            )
            
            27
            
            
            (b
            )UE
                and Genco gas
            
            **2006**
            
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(c**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **(c**
            **)**
            
            **(b**
            **)**
            
            **(b**
            **)**transportation
                agreement
            
            2005
            
            
            (b
            )
            
            (b
            )
            
            (c
            )
            
            (b
            )
            
            (b
            )
            
            (b
            )
            
            (b
            )
            
            (c
            )
            
            (b
            )
            
            (b
            )**Total
                Fuel and**
            
            **2006**
            
            **$**
            **23**
            
            **$**
            **118**
            
            **$**
            **35**
            
            **$**
            **10**
            
            **$**
            **(b**
            **)**
            **$**
            **69**
            
            **$**
            **337**
            
            **$**
            **156**
            
            **$**
            **30**
            
            **$**
            **(b**
            **)****Purchased
                Power**
            
            2005
            
            
            42
            
            
            129
            
            
            52
            
            
            12
            
            
            13
            
            
            107
            
            
            316
            
            
            151
            
            
            37
            
            
            40**Other
                Operating Expenses:**Ameren
                Services support
            
            **2006**
            
            **$**
            **34**
            
            **$**
            **12**
            
            **$**
            **7**
            
            **$**
            **12**
            
            **$**
            **18**
            
            **$**
            **103**
            
            **$**
            **36**
            
            **$**
            **18**
            
            **$**
            **37**
            
            **$**
            **54**services
                agreement
            
            2005
            
            
            38
            
            
            10
            
            
            5
            
            
            9
            
            
            20
            
            
            119
            
            
            32
            
            
            15
            
            
            30
            
            
            42Ameren
                Energy support
            
            **2006**
            
            
            **2**
            
            
            **(b**
            **)**
            
            **1**
            
            
            **(b**
            **)**
            
            **(b**
            **)**
            
            **6**
            
            
            **(b**
            **)**
            
            **2**
            
            
            **(b**
            **)**
            
            **(b**
            **)**services
                agreement
            
            2005
            
            
            1
            
            
            (b
            )
            
            1
            
            
            (b
            )
            
            (b
            )
            
            3
            
            
            (b
            )
            
            2
            
            
            (b
            )
            
            (b
            )AFS
                support services
            
            **2006**
            
            
            **1**
            
            
            **(c**
            **)**
            
            **(c**
            **)**
            
            **(c**
            **)**
            
            **1**
            
            
            **3**
            
            
            **1**
            
            
            **1**
            
            
            **1**
            
            
            **2**agreement
            
            2005
            
            
            1
            
            
            (c
            )
            
            1
            
            
            1
            
            
            (c
            )
            
            3
            
            
            1
            
            
            2
            
            
            2
            
            
            1**Total
                Other**
            
            **2006**
            
            **$**
            **37**
            
            **$**
            **12**
            
            **$**
            **8**
            
            **$**
            **12**
            
            **$**
            **19**
            
            **$**
            **112**
            
            **$**
            **37**
            
            **$**
            **21**
            
            **$**
            **38**
            
            **$**
            **56****Operating
                Expenses**
            
            2005
            
            
            40
            
            
            10
            
            
            7
            
            
            10
            
            
            20
            
            
            125
            
            
            33
            
            
            19
            
            
            32
            
            
            43**Interest
                Income (Expense):**Money
                pool borrowings
            
            **2006**
            
            **$**
            **(c**
            **)**
            **$**
            **(1**
            **)**
            **$**
            **3**
            
            **$**
            **1**
            
            **$**
            **1**
            
            **$**
            **(c**
            **)**
            **$**
            **(2**
            **)**
            **$**
            **8**
            
            **$**
            **4**
            
            **$**
            **2**(advances)
            
            2005
            
            
            2
            
            
            (1
            )
            
            (1
            )
            
            1
            
            
            (1
            )
            
            4
            
            
            (1
            )
            
            2
            
            
            3
            
            
            (3
            )


(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.





**Callaway
      Nuclear Plant**





The
      following table presents insurance coverage at UE’s Callaway nuclear plant at
      September 30, 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)
            $
            24Replacement
                power:Nuclear
                Electric Insurance Ltd.
            $
            490
            (e)
            $
            9


(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.


(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.




46




Price-Anderson
      limits the liability for claims from an incident involving any licensed United
      States commercial nuclear power 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 adverse effect on Ameren and UE’s results of operations, financial
      position, or liquidity.





**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.





As
      of
      September 30, 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 September 30, 2006:





**2006**
            
            **2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **Thereafter****(a)**Ameren(b)
            **$**
            **116**
            
            $
            582
            
            $
            568
            
            $
            432
            
            $
            267
            
            $
            77UE
            
            **64**
            
            
            311
            
            
            283
            
            
            227
            
            
            174
            
            
            77Genco
            
            **22**
            
            
            145
            
            
            170
            
            
            143
            
            
            50
            
            
            -CILCORP/CILCO
            
            **18**
            
            
            49
            
            
            41
            
            
            30
            
            
            21
            
            
            -


(a)
            Commitments
                for coal are until 2011.


(b)
            Includes
                amounts for Ameren registrant and nonregistrant subsidiaries and
                intercompany eliminations.





As
      of
      September 30, 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 September
      30, 2006:





**2006**
            
            **2007**
            
            **2008**
            
            **2009**
            
            **2010**
            
            **Thereafter****(a)**Ameren(b)
            **$**
            **210**
            
            $
            587
            
            $
            427
            
            $
            290
            
            $
            182
            
            $
            248UE
            
            **20**
            
            
            67
            
            
            57
            
            
            38
            
            
            26
            
            
            75CIPS
            
            **30**
            
            
            126
            
            
            106
            
            
            71
            
            
            51
            
            
            100Genco
            
            **4**
            
            
            22
            
            
            19
            
            
            8
            
            
            8
            
            
            10CILCORP/CILCO
            
            **86**
            
            
            147
            
            
            107
            
            
            60
            
            
            32
            
            
            33IP
            
            **61**
            
            
            214
            
            
            135
            
            
            111
            
            
            65
            
            
            29


(a)
            Commitments
                for natural gas are until 2016.


(b)
            Includes
                amounts for Ameren registrant and nonregistrant subsidiaries and
                intercompany eliminations.





As
      of
      September 30, 2006, the long-term commitments for the purchase of electricity
      have increased from amounts previously disclosed as of December 31, 2005, as
      a
      result of power supply contracts obtained by CIPS, CILCO and IP in September
      2006 through the operation of the competitive power procurement auction in
      Illinois for fixed-price customers, which include the vast majority of electric
      customers of these Ameren Illinois utilities. See Note 2 - Rate and Regulatory
      Matters for information on the Illinois power procurement auction and related
      matters, including pending court appeals that challenge the auction process
      and
      the recovery by utilities through rates to customers of costs for power supply
      resulting from the auction.





CIPS,
      CILCO and IP obtained power supply contracts through the September 2006 auction
      with terms of 17 months, 29 months and 41 months to serve, commencing January
      1, 2007, the electric load requirements of fixed-price residential and small
      commercial customers with less than one megawatt of demand. CIPS, CILCO and
      IP
      obtained 17-month-term electric power supply contracts to serve the load
      requirements of commercial and industrial fixed-price customers with one
      megawatt or greater demand commencing January 1, 2007. Under these contracts,
      the electric suppliers are responsible for providing to CIPS, CILCO and IP
      energy, capacity, certain transmission, volumetric risk management and other
      services necessary for the Ameren Illinois utilities to serve the load of
      customers at an all inclusive fixed price.




47




Through
      the Illinois auction held in September 2006, CIPS, CILCO and IP contracted
      for
      their anticipated fixed-price loads for residential and small commercial
      customers (less than one megawatt of demand) as follows:





**Term
                Ending****May
                31, 2008**
            
            **May
                31, 2009**
            
            **May
                31, 2010****Term**
            **17
                Months**
            
            **29
                Months**
            
            **41
                Months**Load
                in megawatts(a)
            
            1,822
            
            
            1,874
            
            
            1,874$
                per megawatthour
            $
            64.77
            
            $
            64.75
            
            $
            66.05


(a)
            Represents
                2007 peak forecast load for CIPS, CILCO and IP in the aggregate.
                Actual
                load could be different due to customers electing not to purchase
                power
                pursuant to the power procurement auction and receive power from
                a
                different supplier, and weather, among other things.





Through
      the Illinois auction held in September 2006, CIPS, CILCO and IP contracted
      for
      their anticipated fixed-price loads for large commercial and industrial
      customers (one megawatt of demand or higher) as follows:





**Term
                  Ending****May
                  31, 2008****Term**
              **17
                  Months**Load
                  in megawatts(a)
              
              1,920$
                  per megawatthour
              $
              84.95


(a)
            Represents
                2007 peak forecast load for CIPS, CILCO and IP in the aggregate.
                Actual
                load could be different due to customers having 30 to 50 days after
                the
                date the auction was declared successful (September 15, 2006) to
                elect not
                to participate and receive power from a different supplier, and weather,
                among other things.





**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, our activities involve
      compliance with diverse laws and regulations. These laws and regulations address
      chemical and waste handling, noise, emissions, and impacts to air, water, and
      protected and cultural resources (such as wetlands, endangered species, and
      archeological and historical resources). Our activities often require complex
      and lengthy processes to obtain regulatory approvals, and 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.
      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
      subject to public review and comment. We do not expect the state regulations
      to
      be finalized until the first quarter of 2007. The Illinois EPA-proposed rules
      for mercury are significantly stricter than the federal rules. Illinois has
      also
      proposed Clean Air Interstate Rule program rules for NO x that are
      more stringent than the federal program. The Missouri Department of Natural
      Resources is expected to formally propose rules to implement the federal Clean
      Air Mercury and Clean Air Interstate Rules in November 2006. The table below
      presents preliminary estimated capital costs based on current technology to
      comply with both (1) the federal Clean Air Interstate Rule and Clean Air
      Mercury  Rule
      through 2016, and (2) Illinois’ mercury regulations as revised pursuant to an
      agreement between Genco, CILCO, EEI, and the Illinois EPA. Under the agreement,
      Illinois generators may delay the compliance date for mercury reductions in
      exchange for accelerating the installation of NO x and
      SO 2 controls. In November 2006, these mercury regulations were approved by the
      Illinois Pollution Control Board and are now pending before the Joint Committee
      on Administrative Review. The agreement with the Illinois EPA will also restrict
      purchasing SO 2 and
      NO x emission
      allowances to meet specific allowed emission rates set forth in the agreement
      and resulted in a $600 million increase in estimated expenditures for the period
      of 2006 to 2016. These estimates could change based on new technology,
      variations in costs of material or labor, alternative compliance strategies
      or
      state rulemaking to implement the federal rules, among other reasons. The timing
      of estimated capital costs may also be influenced by whether emission credits
      are used to comply with the proposed rules, thereby deferring capital
      investment.





**2006**
            
            **2007
                - 2010**
            
            **2011
                - 2016**
            
            **Total**Ameren
            **$**
            **80**
            
            $
            1,225
                - $1,615
            
            $
            1,350
                - $1,750
            
            $
            2,655
                - $3,445UE
            
            **60**
            
            
            365
                -505
            
            
            750
                -1,040
            
            
            1,175
                -1,605Genco
            
            **10**
            
            
            555
                -720
            
            
            305
                -320
            
            
            870
                -1,050CILCO
            
            **5**
            
            
            260 -330
            
            
            145
                -200
            
            
            410
                -535EEI
            
            **5**
            
            
            55
                -75
            
            
            190
                -235
            
            
            250
                -315





The
      states of Illinois and Missouri must also develop attainment plans to meet
      the
      federal 8-hour ozone ambient standard by June 2007 and the federal fine
      particulate ambient standard by April 2008. The costs reflected in the table
      assume that emission controls required for the Clean Air Interstate Rule
      regulations will be sufficient to meet this new standard in the St. Louis
      region. Should Missouri develop an




48




alternative
      plan to comply with this standard, the cost impact could be material to UE.
      Illinois is planning to impose additional requirements beyond the Clean Air
      Interstate Rule as part of the attainment plans for ozone and fine particulate.
      At this time, we are unable to determine the impact state actions 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.





The
      following table presents the tons of SO 2 and
      NO x emission
      allowances held and the related SO 2 and
      NO x book
      values that are carried as intangible assets as of September 30,
      2006.





**SO****2********(a)**
            
            **NO****x********(b)**
            
            **Book
                Value**UE
            
            1.816
            
            
            605
            
            $
            63Genco
            
            0.677
            
            
            16,227
            
            
            81CILCO
            
            0.322
            
            
            3,798
            
            
            51EEI
            
            0.300
            
            
            5,594
            
            
            33


(a)
            Vintages
                are from 2006 to 2016. Each company possesses additional allowances
                for
                use in periods beyond 2016. Units are in millions of SO2allowances (currently one allowance equals one ton
                emitted).


(b)
            Vintages
                are from 2006 to 2008. Units are in NOxallowances (one allowance equals one ton emitted).





The
      following table presents the distribution by company and year of the
      NO x emission
      allowances that were allocated by the Illinois EPA on September 12, 2006 for
      2007 and 2008.





**2007****(a)**
            
            **2008****(a)**UE
            
            156
            
            
            130Genco
            
            4,656
            
            
            4,679CILCO
            
            2,052
            
            
            2,053EEI
            
            2,746
            
            
            2,713


(a)
            These
                NOxallowances are included in the total allowances table
                above.





Allocations
      of NO x allowances for UE’s Missouri generating facilities will be 10,178 tons per
      emissions season in 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. 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. Information responsive to the EPA’s request
      has been submitted but we cannot predict the outcome of this
      matter.






49


***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
      and
      CILCO contractually agreed to indemnify Genco and AERG for remediation costs
      associated with preexisting environmental contamination at the transferred
      sites.





As
      of
      September 30, 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 September 30, 2006, CIPS, CILCO and IP had recorded liabilities
      of
      $26 million, $3 million and $65 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 law enacted in Missouri in 2005 enabling the MoPSC to put
      in
      place environmental cost recovery mechanisms for Missouri utilities. UE does
      not
      have any retail utility operations in Iowa that 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 September 30, 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 September 30,
      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




50




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 September 30, 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.





***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. 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.





The
      FERC
      investigation of the incident has been completed. In October 2006, the FERC
      approved a stipulation and consent agreement between UE and the FERC’s Office of
      Enforcement that resolves all issues arising from an investigation that the
      FERC’s Office of Enforcement conducted into alleged violations of license
      conditions and FERC regulations by UE as the licensee of the Taum Sauk
      hydroelectric facility that may have contributed to the breach of the upper
      reservoir. As part of the stipulation and consent agreement, UE agreed, among
      other things, to: (i) pay a civil penalty of $10 million; (ii) pay $5 million
      into an interest-bearing escrow account to fund project enhancements at or
      near
      the Taum Sauk facility; and (iii) implement and comply with a new dam safety
      program developed in connection with the settlement. As a result of $8 million
      having previously been accrued with respect to the FERC’s investigation in the
      second quarter of 2006, UE’s after-tax charge to earnings in the third quarter
      ended September 30, 2006, related to this stipulation and consent agreement
      was
      limited to $7 million.





Investigations
      by state authorities of the incident have not concluded. The facility will
      remain out of service until reviews by 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 at least all
      of
      2008, if not longer.




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, including rebuilding the plant, will be covered by insurance. UE expects
      the total cost for damage and liabilities, excluding costs to rebuild the
      facility, resulting from the Taum Sauk incident to range from $106 million
      to
      $126 million. As of September 30, 2006, UE had paid $38 million and accrued
      a
      $68 million liability, including costs resulting from the FERC stipulation
      and
      consent discussed above, while expensing $18 million and recording an $88
      million receivable due from insurance companies. As of September 30, 2006,
      UE
      has received $12 million from insurance companies reducing the insurance
      receivable balance to $76 million. 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 authorities. Until the reviews conducted by state 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 recognized.





**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 185 parties are named in some pending cases and as
      few
      as six in others. However, in the cases that were pending as of September 30,
      2006, the average number of parties is 67.





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 and CILCO
      contractually agreed to indemnify Genco and 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.





51





From
      July
      1, 2006, through September 30, 2006, six additional asbestos-related lawsuits
      were filed against Ameren, UE, CIPS, CILCO and IP, mostly in the Circuit Court
      of Madison County, Illinois. Two lawsuits were dismissed and five were settled.
      The following table presents the status as of September 30, 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
            
            316
            
            
            31
            
            
            170
            
            
            130
            
            
            2
            
            
            39
            
            
            150Settled
            
            100
            
            
            -
            
            
            51
            
            
            43
            
            
            -
            
            
            11
            
            
            50Dismissed
            
            145
            
            
            24
            
            
            93
            
            
            47
            
            
            2
            
            
            6
            
            
            65Pending
            
            71
            
            
            7
            
            
            26
            
            
            40
            
            
            -
            
            
            22
            
            
            35


(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
      September 30, 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
      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.




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
      paid for by IP from a $20 million trust fund established by IP and 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.




**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 2017. 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. Discovery of tritium releases in 2006 at the
      Callaway nuclear plant may result in an increased estimate for decommissioning
      when the next study is conducted. 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.





52


**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 and nine months ended September 30, 2006 and 2005, is
      shown
      below for the Ameren Companies:





**Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005****Ameren:****(a)**Net
                income
            
            **$**
            **293**
            
            $
            280
            
            **$**
            **486**
            
            $
            586Unrealized
                gain on derivative hedging instruments, net of taxes of $12, $11,
              $9
                and $22, respectively
            
            
            **23**
            
            
            15
            
            
            **19**
            
            
            33Reclassification
                adjustments for (gains) included in net income, net of taxes of $6,
                $2,
                $11 and $3, respectively
            
            
            **(10**
            **)**
            
            (2
            )
            
            **(18**
            **)**
            
            (5
            )Total
                comprehensive income, net of taxes
            
            **$**
            **306**
            
            $
            293
            
            **$**
            **487**
            
            $
            614**UE:**Net
                income
            
            **$**
            **166**
            
            $
            164
            
            **$**
            **309**
            
            $
            353Unrealized
                gain (loss) on derivative hedging instruments, net of taxes (benefit)
                of$3,
                $(2), $2 and $ -, respectively
            
            
            **4**
            
            
            (4
            )
            
            **3**
            
            
            (1
            )Reclassification
                adjustments for (gains) included in net income, net of taxes
              of $1,$
                -, $2 and $ -, respectively
            
            
            **(1**
            **)**
            
            (1
            )
            
            **(3**
            **)**
            
            (1
            )Total
                comprehensive income, net of taxes
            
            **$**
            **169**
            
            $
            159
            
            **$**
            **309**
            
            $
            351**CIPS:**Net
                income
            
            **$**
            **29**
            
            $
            31
            
            **$**
            **43**
            
            $
            46Unrealized
                gain (loss) on derivative hedging instruments, net of taxes (benefit)
                of$
                -, $4, $(1) and $7, respectively
            
            
            **-**
            
            
            7
            
            
            **(2**
            **)**
            
            11Reclassification
                adjustments for (gains) included in net income, net of taxes
              of $1,$1,
                $3 and $1, respectively
            
            
            **(1**
            **)**
            
            (1
            )
            
            **(4**
            **)**
            
            (2
            )Total
                comprehensive income, net of taxes
            
            **$**
            **28**
            
            
            37
            
            **$**
            **37**
            
            $
            55**Genco:**Net
                income
            
            **$**
            **19**
            
            $
            32
            
            **$**
            **27**
            
            $
            94Unrealized
                gain (loss) on derivative hedging instruments, net of taxes (benefit)
                of
                $1, $(3), $1 and $(3), respectively
            
            
            **1**
            
            
            (5
            )
            
            **2**
            
            
            (6
            )Total
                comprehensive income, net of taxes
            
            **$**
            **20**
            
            $
            27
            
            **$**
            **29**
            
            $
            88**CILCORP:**Net
                income
            
            **$**
            **13**
            
            $
            5
            
            **$**
            **22**
            
            $
            16Unrealized
                gain (loss) on derivative hedging instruments, net of taxes (benefit)
                of$1,
                $13, $(6) and $19, respectively
            
            
            **2**
            
            
            19
            
            
            **(10**
            **)**
            
            31Reclassification
                adjustments for (gains) included in net income, net of taxes of $4,
                $ -,
                $7 and $ -, respectively
            
            
            **(6**
            **)**
            
            (1
            )
            
            **(10**
            **)**
            
            -Total
                comprehensive income, net of taxes
            
            **$**
            **9**
            
            $
            23
            
            **$**
            **2**
            
            $
            47**CILCO:**Net
                income
            
            **$**
            **19**
            
            $
            11
            
            **$**
            **44**
            
            $
            37Unrealized
                gain (loss) on derivative hedging instruments, net of taxes (benefit)
                of$1,
                $13, $(6), and $20, respectively
            
            
            **2**
            
            
            19
            
            
            **(9**
            **)**
            
            30Reclassification
                adjustments for (gains) included in net income, net of taxes
              of $4,$
                -, $7 and $1, respectively
            
            
            **(6**
            **)**
            
            (1
            )
            
            **(10**
            **)**
            
            (1
            )Total
                comprehensive income, net of taxes
            
            **$**
            **15**
            
            $
            29
            
            **$**
            **25**
            
            $
            66**IP:**Net
                income
            
            **$**
            **43**
            
            $
            54
            
            **$**
            **63**
            
            $
            91Unrealized
                (loss) on derivative hedging instruments, net of (benefit) of $
                -,
              $
                -, $ - and $ -, respectively
            
            
            **-**
            
            
            -
            
            
            **(1**
            **)**
            
            -Reclassification
                adjustments for losses included in net income, net of (benefit)
              of
                $ -, $ -, $(1) and $ -, respectively
            
            
            **-**
            
            
            -
            
            
            **1**
            
            
            -Total
                comprehensive income, net of taxes
            
            **$**
            **43**
            
            $
            54
            
            **$**
            **63**
            
            $
            91


(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 the new contribution requirements in the recently
      passed Pension Protection Act of 2006, in order to maintain minimum funding
      levels for Ameren’s pension plans, we do not expect future contributions to be
      required until 2009 at which time we would expect a required contribution of
      $100 million to $150 million. Required contributions of $150 million to $200
      million each year are also




53


expected
      for 2010 and 2011. These amounts are estimates and may change with actual stock
      market performance, changes in interest rates, any pertinent changes in
      government regulations, and any voluntary contributions.





The
      following tables present the components of the net periodic benefit cost for
      our
      pension and postretirement benefit plans for the three months and nine months
      ended September 30, 2006 and 2005:





**Pension
                Benefits****(a)****Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005**Service
                cost
            **$**
            **16**
            
            $
            14
            
            **$**
            **47**
            
            $
            43Interest
                cost
            
            **43**
            
            
            41
            
            
            **129**
            
            
            124Expected
                return on plan assets
            
            **(49**
            **)**
            
            (45
            )
            
            **(147**
            **)**
            
            (136
            )Amortization
                of:Prior
                service cost
            
            **3**
            
            
            3
            
            
            **8**
            
            
            8Actuarial
                loss
            
            **10**
            
            
            9
            
            
            **31**
            
            
            28Net
                periodic benefit cost
            **$**
            **23**
            
            $
            22
            
            **$**
            **68**
            
            $
            67


(a)
            Includes
                amounts for Ameren registrant and nonregistrant
                subsidiaries.








**Postretirement
                Benefits****(a)****Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005**Service
                cost
            **$**
            **5**
            
            $
            5
            
            **$**
            **16**
            
            $
            16Interest
                cost
            
            **18**
            
            
            17
            
            
            **51**
            
            
            53Expected
                return on plan assets
            
            **(12**
            **)**
            
            (11
            )
            
            **(35**
            **)**
            
            (34
            )Amortization
                of:Transition
                obligation
            
            **-**
            
            
            1
            
            
            **1**
            
            
            2Prior
                service cost
            
            **(2**
            **)**
            
            (2
            )
            
            **(5**
            **)**
            
            (4
            )Actuarial
                loss
            
            **9**
            
            
            9
            
            
            **26**
            
            
            28Net
                periodic benefit cost
            **$**
            **18**
            
            $
            19
            
            **$**
            **54**
            
            $
            61


(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 proportionate share of the pension and postretirement
      costs. The following tables present the pension costs and the postretirement
      benefit costs incurred for the three months and nine months ended September
      30,
      2006 and 2005:





**Pension
                Costs****Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005**UE
            **$**
            **13**
            
            $
            13
            
            **$**
            **39**
            
            $
            39CIPS
            
            **3**
            
            
            3
            
            
            **9**
            
            
            9Genco
            
            **2**
            
            
            2
            
            
            **6**
            
            
            6CILCORP
            
            **3**
            
            
            3
            
            
            **8**
            
            
            9CILCO
            
            **4**
            
            
            5
            
            
            **11**
            
            
            14IP
            
            **2**
            
            
            1
            
            
            **6**
            
            
            4





**Postretirement
                Costs****Three
                Months**
            
            **Nine
                Months****2006**
            
            **2005**
            
            **2006**
            
            **2005**UE
            **$**
            **9**
            
            $
            11
            
            **$**
            **28**
            
            $
            33CIPS
            
            **2**
            
            
            2
            
            
            **6**
            
            
            8Genco
            
            **1**
            
            
            1
            
            
            **3**
            
            
            3CILCORP
            
            **3**
            
            
            2
            
            
            **7**
            
            
            8CILCO
            
            **4**
            
            
            3
            
            
            **11**
            
            
            12IP
            
            **3**
            
            
            3
            
            
            **10**
            
            
            9





**NOTE
      12 -** **SEGMENT
      INFORMATION** ****





Prior
      to
      the third quarter of 2006, Ameren reported one segment, Utility Operations,
      comprising electric generation and electric and gas transmission and
      distribution operations, with Other including Ameren holding company activity.
      As a result of the following changes in circumstances, Ameren, UE, CILCORP
      and CILCO changed their segments in the third quarter of 2006:





·
            the
                Ameren Companies’ chief operating decision-making group began to
                assess performance and allocate resources based on a new segment
                structure and made




54




related
      organizational and management reporting changes
      in the third quarter of 2006;


·
            electric
                generation deregulation in Illinois, which is currently scheduled
                to
                become effective January 1, 2007;


·
            the
                expiration of affiliate power supply agreements for CIPS and CILCO,
                and
                other supply agreements for IP on December 31,
                2006;


·
            the
                July 2006 termination of the JDA among UE, Genco and CIPS effective
                December 31, 2006; and


·
            the
                September 2006 completion of a state-wide auction to procure power
                for
                CIPS, CILCO and IP for 2007 and beyond, Marketing Company's sale
                in that
                auction of power being acquired from Genco and
                AERG.





Ameren
      determined in the third quarter of 2006 that it has three reportable segments:
      Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. The
      Missouri Regulated segment for Ameren includes all the operations of UE’s
      business as described in Note 1 - Summary of Significant Accounting Policies,
      except for UE’s 40% interest in EEI and other non-rate regulated activities,
      which are included in Other. The Illinois Regulated segment for Ameren consists
      of the regulated electric and gas transmission and distribution businesses
      of
      CIPS, CILCO, and IP, as described in Note 1 - Summary of Significant Accounting
      Policies. The Non-rate-regulated Generation segment for Ameren primarily
      consists of the operations or activities of Genco, the CILCORP holding company,
      AERG, EEI, and Marketing Company. Other primarily includes Ameren holding
      company activities and the leasing activities of CILCORP, AERG, Resources
      Company, and CIPSCO Investment Company.





UE
      determined it now has one reportable segment: Missouri Regulated. The Missouri
      Regulated segment for UE includes all the operations of UE’s business as
      described in Note 1 - Summary of Significant Accounting Policies, except for
      UE’s 40% interest in EEI and other non-rate-regulated activities, which are
      included in Other.





CILCORP
      and CILCO determined they now have two reportable segments: Illinois Regulated
      and Non-rate-regulated Generation. The Illinois Regulated segment for CILCORP
      and CILCO is comprised of the regulated electric and gas transmission and
      distribution businesses of CILCO. The Non-rate-regulated Generation segment
      for
      CILCORP and CILCO consists of the generation business of AERG. Other for CILCORP
      and CILCO is comprised of leveraged lease investments, parent company activity,
      and minor activities not reported in the Illinois Regulated or
      Non-rate-regulated Generation segments for CILCORP.





Prior
      period presentation has been adjusted for comparative purposes.




The
      following table presents information about the reported revenues and net income
      of Ameren for the three months and nine months ended September 30, 2006 and
      2005, and total assets as of September 30, 2006 and December 31, 2005.


**Three
                  Months**
              **Missouri
                  Regulated**
              
              **Illinois**
                **Regulated**
              
              **Non-rate-regulated
                  Generation**
              
              **Other**
              
              **Intersegment
                  Eliminations**
              
              **Consolidated****2006:**External
                  revenues
              **$**
              **813**
              
              **$**
              **836**
              
              **$**
              **261**
              
              **$**
              **-**
              
              **$**
              **-**
              
              **$**
              **1,910**Intersegment
                  revenues
              
              **44**
              
              
              **7**
              
              
              **212**
              
              
              **-**
              
              
              **(263**
              **)**
              
              **-**Net
                  income(a)
              
              **142**
              
              
              **83**
              
              
              **61**
              
              
              **7**
              
              
              **-**
              
              
              **293****2005:**External
                  revenues
              $
              828
              
              $
              835
              
              $
              217
              
              $
              1
              
              $
              -
              
              $
              1,881Intersegment
                  revenues
              
              67
              
              
              11
              
              
              246
              
              
              -
              
              
              (324
              )
              
              -Net
                  income(a)
              
              162
              
              
              96
              
              
              27
              
              
              (5
              )
              
              -
              
              
              280**Nine
                  Months****2006:**External
                  revenues
              **$**
              **2,024**
              
              **$**
              **2,501**
              
              **$**
              **735**
              
              **$**
              **-**
              
              **$**
              **-**
              
              **$**
              **5,260**Intersegment
                  revenues
              
              **179**
              
              
              **17**
              
              
              **603**
              
              
              **-**
              
              
              **(799**
              **)**
              
              **-**Net
                  income(a)
              
              **258**
              
              
              **125**
              
              
              **100**
              
              
              **3**
              
              
              **-**
              
              
              **486****2005:**External
                  revenues
              $
              2,075
              
              $
              2,338
              
              $
              659
              
              $
              7
              
              $
              -
              
              $
              5,079Intersegment
                  revenues
              
              179
              
              
              30
              
              
              640
              
              
              -
              
              
              (849
              )
              
              -Net
                  income(a)
              
              346
              
              
              159
              
              
              89
              
              
              (8
              )
              
              -
              
              
              586**As
                  of September 30, 2006:**Total
                  assets
              **$**
              **9,910**
              
              **$**
              **5,986**
              
              **$**
              **3,650**
              
              **$**
              **1,813**
              
              **$**
              **(2,529**
              **)**
              **$**
              **18,830****As
                  of December 31, 2005:**Total
                  assets
              
              9,261
              
              
              6,073
              
              
              3,731
              
              
              1,949
              
              
              (2,852
              )
              
              18,162
 (a)
            Represents
                net income available to common shareholders; 100% of CILCO’s preferred
                stock dividends are included in the Illinois Regulated
                segment. 
 
 55
 
 The
        following table presents information about the reported revenues and net
        income
        of UE for the three months and nine months ended September 30, 2006 and 2005,
        and total assets as of September 30, 2006 and December 31, 2005.
 
 **Three
                  Months**
              **Missouri**
                **Regulated**
              
              **Other****(a)**
              
              **Consolidated**
                **UE****2006:**Revenues
              **$**
              **857**
              
              **$**
              **-**
              
              **$**
              **857**Net
                  income(b)
              
              **142**
              
              
              **23**
              
              
              **165****2005:**Revenues
              $
              895
              
              $
              -
              
              $
              895Net
                  income(b)
              
              162
              
              
              1
              
              
              163**Nine
                  Months****2006:**Revenues
              **$**
              **2,203**
              
              **$**
              **-**
              
              **$**
              **2,203**Net
                  income(b)
              
              **258**
              
              
              **47**
              
              
              **305****2005:**Revenues
              $
              2,254
              
              $
              -
              
              $
              2,254Net
                  income(b)
              
              346
              
              
              3
              
              
              349**As
                  of September 30, 2006:**Total
                  assets
              **$**
              **9,910**
              
              **$**
              **24**
              
              **$**
              **9,934****As
                  of December 31, 2005:**Total
                  assets
              
              9,261
              
              
              16
              
              
              9,277
 (a)
            Includes
                40% interest in EEI and other non-rate-regulated
                activities. (b)
            Represents
                net income available to the common shareholder
                (Ameren).  The
        following table presents information about the reported revenues and net
        income
        of CILCORP for the three months and nine months ended September 30, 2006
        and
        2005, and total assets as of September 30, 2006 and December 31,
        2005.
 
 **Three
                  Months**
              **Illinois**
                **Regulated**
              
              **Non-rate-regulated
                  Generation**
              
              **CILCORP**
                **Other**
              
              **Intersegment**
                **Eliminations**
              
              **Consolidated**
                **CILCORP****2006:**External
                  revenues
              **$**
              **154**
              
              **$**
              **3**
              
              **$**
              **1**
              
              **$**
              **-**
              
              **$**
              **158**Intersegment
                  revenues
              
              **-**
              
              
              **56**
              
              
              **-**
              
              
              **(56**
              **)**
              
              **-**Net
                  income(a)
              
              **11**
              
              
              **2**
              
              
              **-**
              
              
              **-**
              
              
              **13****2005:**External
                  revenues
              $
              159
              
              $
              -
              
              $
              -
              
              $
              -
              
              $
              159Intersegment
                  revenues
              
              -
              
              
              54
              
              
              -
              
              
              (54
              )
              
              -Net
                  income(a)
              
              12
              
              
              (8
              )
              
              1
              
              
              -
              
              
              5**Nine
                  Months****2006:**External
                  revenues
              **$**
              **523**
              
              **$**
              **23**
              
              **$**
              **-**
              
              **$**
              **-**
              
              **$**
              **546**Intersegment
                  revenues
              
              **-**
              
              
              **139**
              
              
              **-**
              
              
              **(139**
              **)**
              
              **-**Net
                  income(a)
              
              **22**
              
              
              **4**
              
              
              **(4**
              **)**
              
              **-**
              
              
              **22****2005:**External
                  revenues
              $
              498
              
              $
              24
              
              $
              6
              
              $
              -
              
              $
              528Intersegment
                  revenues
              
              -
              
              
              140
              
              
              -
              
              
              (140
              )
              
              -Net
                  income(a)
              
              26
              
              
              (12
              )
              
              2
              
              
              -
              
              
              16**As
                  of September 30, 2006:**Total
                  assets(b)
              **$**
              **1,169**
              
              **$**
              **1,157**
              
              **$**
              **4**
              
              **$**
              **(226**
              **)**
              **$**
              **2,104****As
                  of December 31, 2005:**Total
                  assets(b)
              
              1,231
              
              
              1,201
              
              
              4
              
              
              (202
              )
              
              2,234
 (a)
            Represents
                net income available to the common shareholders (Ameren); 100% of
                CILCO’s
                preferred stock dividends are included in the Illinois Regulated
                segment. (b)
            Total
                assets for Illinois Regulated include an allocation of goodwill and
                other
                purchase accounting amounts related to CILCO that are recorded at
                CILCORP
                (parent company).


56


The
      following table presents information about the reported revenues and net income
      of CILCO for the three months and nine months ended September 30, 2006 and
      2005,
      and total assets as of September 30, 2006 and December 31, 2005.





**Three
                Months**
            **Illinois**
              **Regulated**
            
            **Non-rate-regulated
                Generation**
            
            **CILCO**
              **Other**
            
            **Intersegment**
              **Eliminations**
            
            **Consolidated**
              **CILCO****2006:**External
                revenues
            **$**
            **154**
            
            **$**
            **3**
            
            **$**
            **-**
            
            **$**
            **-**
            
            **$**
            **157**Intersegment
                revenues
            
            **-**
            
            
            **56**
            
            
            **-**
            
            
            **(56**
            **)**
            
            **-**Net
                income(a)
            
            **11**
            
            
            **8**
            
            
            **-**
            
            
            **-**
            
            
            **19****2005:**External
                revenues
            $
            159
            
            $
            -
            
            $
            -
            
            $
            -
            
            $
            159Intersegment
                revenues
            
            -
            
            
            54
            
            
            -
            
            
            (54
            )
            
            -Net
                income(a)
            
            12
            
            
            (2
            )
            
            -
            
            
            -
            
            
            10**Nine
                Months****2006:**External
                revenues
            **$**
            **523**
            
            **$**
            **23**
            
            **$**
            **-**
            
            **$**
            **-**
            
            **$**
            **546**Intersegment
                revenues
            
            **-**
            
            
            **139**
            
            
            **-**
            
            
            **(139**
            **)**
            
            **-**Net
                income(a)
            
            **22**
            
            
            **24**
            
            
            **(3**
            **)**
            
            **-**
            
            
            **43****2005:**External
                revenues
            $
            498
            
            $
            24
            
            $
            -
            
            $
            -
            
            $
            522Intersegment
                revenues
            
            -
            
            
            140
            
            
            -
            
            
            (140
            )
            
            -Net
                income(a)
            
            26
            
            
            9
            
            
            -
            
            
            -
            
            
            35**As
                of September 30, 2006:**Total
                assets
            **$**
            **949**
            
            **$**
            **565**
            
            **$**
            **1**
            
            **$**
            **(17**
            **)**
            **$**
            **1,498****As
                of December 31, 2005:**Total
                assets
            
            1,008
            
            
            563
            
            
            1
            
            
            (15
            )
            
            1,557





(a)
            Represents
                net income available to the common shareholder (CILCORP); 100% of
                CILCO’s
                preferred stock dividends are included in the Illinois Regulated
                segment.




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




**OVERVIEW** **





**Ameren
      Executive Summary**





Ameren’s
      earnings in 2006 have been significantly impacted by higher
      fuel and transportation costs due primarily to increased coal and related
      transportation costs, severe storm-related customer outages, an unplanned outage
      at UE’s Callaway nuclear plant and milder winter and summer weather than 2005.
      In addition, Ameren incurred additional costs of operating in the MISO Day
      Two
      Energy Market in the first nine months of 2006 because MISO Day Two operations
      did not commence until the second quarter last year. However, the costs of
      MISO
      Day Two operations in the third quarter of 2006 were lower than the year-ago
      period. Incremental costs resulting from the December 2005 breach of the upper
      reservoir at UE’s Taum Sauk hydroelectric pumped-storage plant also negatively
      impacted earnings in the third quarter and first nine months of 2006. In the
      third quarter, UE settled issues relating to the reservoir breach with federal
      authorities, but the breach is still being investigated by state authorities.
      Increased margins from interchange sales and organic growth compared to the
      third quarter and first nine months of last year positively influenced 2006
      earnings.




In
      Illinois, there has been significant regulatory and legislative activity as
      we
      approach the scheduled end of a 10-year electric rate freeze and the expiration
      of power supply contracts. In electric delivery service rate filings made in
      December 2005, CIPS, CILCO and IP requested a total combined annual electric
      revenue increase of approximately $200 million. In early October, the
      administrative law judges in our delivery service cases recommended an aggregate
      $147 million increase in electric rates. The ICC has until late November to
      render a decision in these cases.





Since
      the
      Ameren Illinois utilities own almost no generation and their supply contracts
      expire at the end of this year, in September, an ICC-approved procurement
      auction for post-2006 power requirements for these companies was held. The
      supply contracts from this auction resulted in market prices for power which
      are
      above those prices currently reflected in customer rates. Due to potential
      Illinois rate increases of 40% to 55% there have been calls by some key
      lawmakers, including the Illinois governor, for a three-year extension of the
      rate freeze in Illinois. We believe an extension of the rate freeze is without
      legal merit, and any decision or action that impairs CIPS’, CILCO’s and IP’s
      ability to fully recover purchased power or other costs from their electric
      customers in a timely manner could result in material adverse consequences
      for
      all of the Ameren Companies. If an extension of the rate freeze were to occur,
      the Ameren Illinois utilities estimate they would spend approximately $1 billion
      more annually for power than they could charge their customers. As has been
      clearly demonstrated by recent actions and statements by the credit rating
      agencies, if the electric rate freeze in Illinois is extended, the credit
      ratings of the Ameren Illinois utilities and CILCORP will be slashed
      to


57


deep
      junk
      status. These credit ratings will immediately trigger collateral and other
      funding requirements. We believe such funding requirements, combined with the
      inability to recover costs through rates to customers, would cause the Ameren
      Illinois utilities to exhaust their available cash and credit and be unable
      to
      borrow. Ameren believes this would lead to the Ameren Illinois utilities and
      CILCORP being financially insolvent by February 2007, or sooner. Any decision
      or
      action that impairs the ability of CIPS, CILCO, and IP to fully recover costs
      from their electric customers in a timely manner would result in material
      adverse consequences for Ameren, CIPS, CILCORP, CILCO, and IP. CIPS, CILCO
      and
      IP remain steadfastly committed to working with key stakeholders to develop
      a
      constructive solution that would mitigate the impact of these rate increases
      on
      our Illinois residential customers, yet still provide for full and timely
      recovery of costs. This year the Ameren Illinois utilities filed two different
      plans with the ICC that would allow expected electric rate increases to be
      phased in over time. These utilities are hopeful that these plans will provide
      a
      constructive solution to lessen the impact of the expected rate increases on
      Illinois customers.




In
      early
      July 2006, UE filed requests with the MoPSC to increase base rates for electric
      service by $361 million and to increase base rates for gas service by $11
      million. The primary drivers of the requested electric rate increase were
      significant investments in critical energy infrastructure, as well as
      significantly higher operating expenses. In conjunction with the filing of
      the
      electric rate case in Missouri, UE, CIPS and Genco mutually agreed to terminate
      the JDA on December 31, 2006. A decision from the MoPSC on both rate case
      filings is expected no later than June 2007. The resolution of these regulatory
      matters in Illinois and Missouri will have a significant impact on earnings
      for
      the Ameren Companies in 2007 and beyond.




**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. See
      Note 1 - Summary of Significant Accounting Policies to our financial statements
      under Part I, Item 1, of this report for a detailed description of our principal
      subsidiaries.


·
            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 and natural gas transmission and distribution business and
                a
                primarily non-rate-regulated electric generation business (through
                its
                subsidiary, AERG) 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.





**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. Non-rate-regulated sales are subject to market
      conditions for power and with the expiration of Genco’s and AERG’s supply
      contracts with CIPS and CILCO at the end of 2006, these companies’ and Ameren’s
      earnings will be subject to increased volatility. 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.
      In September 2006, the MoPSC approved rules for a fuel and purchased power
      cost
      recovery mechanism, which are expected to become effective by the end of 2006.
      UE has requested approval of a fuel and purchased power cost recovery mechanism
      as a part of its


58


current
      electric rate case. Since rates for UE, CIPS, CILCO and IP are regulated, 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
      including the forward sale of power and purchase of fuel to reduce our exposure
      to the volatility of commodities 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 increased to $293 million, or $1.42 per share, in the third quarter
      of 2006 from $280 million, or $1.37 per share, in the third quarter of 2005.
      Ameren’s net income decreased to $486 million, or $2.37 per share, for the nine
      months ended September 30, 2006, from earnings of $586 million, or $2.94 per
      share, in the first nine months of 2005.





Earnings
      were negatively impacted for the three-month and nine-month periods by the
      costs
      and lost electric margins associated with outages caused by severe storms,
      lower
      prices for interchange sales, milder weather conditions, and costs associated
      with an upper reservoir breach in December 2005 at UE’s Taum Sauk plant. In the
      third quarter of 2005, we began a scheduled refueling and maintenance outage
      at
      UE’s Callaway nuclear plant and recorded an impairment of an aircraft leveraged
      lease; items that did not recur in 2006. The nine-month period was also
      unfavorably impacted by an unscheduled outage at UE’s Callaway nuclear plant in
      the second quarter of 2006 and increased fuel and purchased power costs,
      including incremental costs of operating in the MISO Day Two Energy Market.
      An
      increase in the number of common shares outstanding in the current-year periods
      further reduced Ameren’s earnings per share. Increased margins on interchange
      sales at EEI and organic growth reduced the impact of these unfavorable items
      on
      current year earnings.





Prior
      to
      the third quarter of 2006, Ameren reported one segment, Utility Operations,
      comprising electric generation and electric and gas transmission and
      distribution operations, with Other including Ameren holding company activity.
      As a result of the following changes in circumstances, Ameren, UE, CILCORP
      and
      CILCO changed their segments in the third quarter of 2006:


·
            the
                Ameren Companies’ chief operating decision-making group began to assess
                the performance and allocate resources based on a new segment structure
                and made related organizational and management reporting changes
                in the
                third quarter of 2006; ·
            electric
                generation deregulation in Illinois, which is currently scheduled
                to
                become effective January 1, 2007; ·
            the
                expiration of affiliate power supply agreements for CIPS and CILCO,
                and
                other supply agreements for IP on December 31,
                2006; ·
            the
                July 2006 termination of the JDA among UE, Genco and CIPS effective
                December 31, 2006; and ·
            the
                September 2006 completion of a state-wide auction to procure power
                for
                CIPS, CILCO and IP for 2007 and beyond, and Marketing Company's sale
                in
                that auction of power being acquired from Genco and
                AERG.




Prior
      period presentation has been adjusted for comparative purposes.





Ameren
      determined in the third quarter of 2006 that it has three reportable segments:
      Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. UE
      determined that it has one reportable segment: Missouri Regulated. CILCORP
      and
      CILCO determined that they have two reportable segments: Illinois Regulated
      and
      Non-rate-regulated Generation. A discussion of changes in components of net
      income between periods by business segment is provided below where material.
      See
      Note 12 - Segment Information to our financial statements under Part I, Item
      1,
      of this report for further discussion of Ameren’s, UE’s, CILCORP’s and CILCO’s
      business segments.


59


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 and nine months ended
      September 30, 2006 and 2005:





**Three
                Months**
            
            **Nine
                Months****2006**
            
            
            **2005**
            
            
            **2006**
            
            
            **2005**Net
                income (loss):UE(a)(b)
            **$**
            **165**
            
            $
            163
            
            **$**
            **305**
            
            $
            349CIPS
            
            **28**
            
            
            30
            
            
            **41**
            
            
            44Genco(a)
            
            **19**
            
            
            32
            
            
            **27**
            
            
            94CILCORP(a)
            
            **13**
            
            
            5
            
            
            **22**
            
            
            16IP
            
            **42**
            
            
            53
            
            
            **61**
            
            
            89Other(c)
            
            **26**
            
            
            (3
            )
            
            **30**
            
            
            (6
            )Ameren
                net income
            **$**
            **293**
            
            $
            280
            
            **$**
            **486**
            
            $
            586


(a)
            Includes
                earnings from market-based interchange power sales that provided
                the
                following contributions to net income for the three-month and nine-month
                periods, respectively:


UE:
              2006
                  - $9 million, $43 million2005
                  - $7 million, $53 millionGenco:
              2006
                  - $2 million, $13 million2005
                  - $3 million, $31 millionCILCORP:
              2006
                  - $2 million, $14 million2005
                - $2 million, $11 million
 (b)
              Includes
                  earnings from a non-rate-regulated 40% interest in
                  EEI.
 (c)
              Includes
                  earnings from non-rate-regulated operations and a 40% interest
                  in EEI held
                  by Development Company, corporate general and administrative
                  expenses,
                and
                  intercompany eliminations.





**RESULTS
      OF OPERATIONS**





**Margins**





The
      following table presents the favorable (unfavorable) variations in electric
      and
      gas margins, by registrant company, defined as electric revenues less fuel
      and
      purchased power costs, and gas revenues less gas purchased for resale, for
      the
      three months and nine months ended September 30, 2006, as compared with the
      year-ago periods. We consider electric, interchange and gas margins useful
      measures to analyze the change in profitability of our electric and gas
      operations between periods. We have included the analysis below as a complement
      to the financial information we provide in accordance with GAAP. However, these
      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)
            $
            (30
            )
            $
            (10
            )
            $
            (5
            )
            $
            -
            
            $
            (6
            )
            $
            (6
            )
            $
            (9
            )Storm-related
                outages
            
            (3
            )
            
            (2
            )
            
            (2
            )
            
            2
            
            
            -
            
            
            -
            
            
            (1
            )Wholesale
                contracts(b)
            
            (18
            )
            
            -
            
            
            -
            
            
            (18
            )
            
            -
            
            
            -
            
            
            -Interchange
                revenues(c)
            
            69
            
            
            (26
            )
            
            (9
            )
            
            (19
            )
            
            4
            
            
            4
            
            
            -Growth
                and other (estimate)
            
            17
            
            
            (2
            )
            
            -
            
            
            7
            
            
            5
            
            
            4
            
            
            27Total
            $
            35
            
            $
            (40
            )
            $
            (16
            )
            $
            (28
            )
            $
            3
            
            $
            2
            
            $
            17Fuel
                and purchased power change:Fuel:Generation
                and other
            $
            29
            
            $
            14
            
            $
            -
            
            $
            9
            
            $
            8
            
            $
            7
            
            $
            -Sales
                of emissions allowances
            
            (2
            )
            
            -
            
            
            -
            
            
            (21
            )
            
            -
            
            
            -
            
            
            -Price
            
            (8
            )
            
            (4
            )
            
            -
            
            
            -
            
            
            (4
            )
            
            (4
            )
            
            -Purchased
                power
            
            (6
            )
            
            38
            
            
            15
            
            
            5
            
            
            7
            
            
            7
            
            
            (26
            )Storm-related
                energy costs
            
            (2
            )
            
            (1
            )
            
            -
            
            
            (1
            )
            
            -
            
            
            -
            
            
            -Total
            $
            11
            
            $
            47
            
            $
            15
            
            $
            (8
            )
            $
            11
            
            $
            10
            
            $
            (26
            )**Net
                change in electric margins**
            **$**
            **46**
            
            **$**
            **7**
            
            **$**
            **(1**
            **)**
            **$**
            **(36**
            **)**
            **$**
            **14**
            
            **$**
            **12**
            
            **$**
            **(9**
            **)****Net
                change in gas margins**
            **$**
            **-**
            
            **$**
            **(1**
            **)**
            **$**
            **2**
            
            **$**
            **-**
            
            **$**
            **-**
            
            **$**
            **-**
            
            **$**
            **-****Nine
                Months**Electric
                revenue change:Effect
                of weather (estimate)
            $
            (60
            )
            $
            (24
            )
            $
            (12
            )
            $
            -
            
            $
            (9
            )
            $
            (9
            )
            $
            (15
            )Storm-related
                outages
            
            (9
            )
            
            (8
            )
            
            (2
            )
            
            2
            
            
            -
            
            
            -
            
            
            (1
            )Noranda
            
            46
            
            
            46
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Illinois
                service territory transfer
            
            3
            
            
            (38
            )
            
            41
            
            
            34
            
            
            -
            
            
            -
            
            
            -Wholesale
                contracts(b)
            
            (54
            )
            
            -
            
            
            -
            
            
            (54
            )
            
            -
            
            
            -
            
            
            -Interchange
                revenues(c)
            
            171
            
            
            (5
            )
            
            (24
            )
            
            (38
            )
            
            (3
            )
            
            (3
            )
            
            -Growth
                and other (estimate)
            
            2
            
            
            (15
            )
            
            24
            
            
            23
            
            
            12
            
            
            12
            
            
            43Total
            $
            99
            
            $
            (44
            )
            $
            27
            
            $
            (33
            )
            $
            -
            
            $
            -
            
            $
            27




60


**Nine
                Months**
            
            **Ameren****(a)**
            
            
            **UE**
            
            
            **CIPS**
            
            
            **Genco**
            
            
            **CILCORP**
            
            
            **CILCO**
            
            
            **IP**Fuel
                and purchased power change:Fuel:Generation
                and other
            $
            22
            
            $
            13
            
            $
            -
            
            $
            12
            
            $
            8
            
            $
            8
            
            $
            -Sale
                of emissions allowances
            
            (2
            )
            
            -
            
            
            -
            
            
            (21
            )
            
            -
            
            
            -
            
            
            -Price
            
            (55
            )
            
            (34
            )
            
            -
            
            
            (14
            )
            
            (7
            )
            
            (7
            )
            
            -Purchased
                power
            
            (114
            )
            
            7
            
            
            (24
            )
            
            (63
            )
            
            21
            
            
            21
            
            
            (52
            )Storm-related
                energy costs
            
            1
            
            
            2
            
            
            -
            
            
            (1
            )
            
            -
            
            
            -
            
            
            -Total
            $
            (148
            )
            $
            (12
            )
            $
            (24
            )
            $
            (87
            )
            $
            22
            
            $
            22
            
            $
            (52
            )**Net
                change in electric margins**
            **$**
            **(49**
            **)**
            **$**
            **(56**
            **)**
            **$**
            **3**
            
            **$**
            **(120**
            **)**
            **$**
            **22**
            
            **$**
            **22**
            
            **$**
            **(25**
            **)****Net
                change in gas margins**
            **$**
            **(6**
            **)**
            **$**
            **(9**
            **)**
            **$**
            **4**
            
            **$**
            **-**
            
            **$**
            **(4**
            **)**
            **$**
            **(5**
            **)**
            **$**
            **5**


(a)
            Includes
                amounts for Ameren registrant and nonregistrant subsidiaries and
                intercompany eliminations.


(b)
            Represents
                several wholesale contracts that expired in 2005 and were not
                renewed.


(c)
            Excludes
                the impact from storm-related
                outages.





The
      table
      below presents the favorable (unfavorable) variations in electric and gas
      margins and non-utility revenues by segment for Ameren for the three months
      and
      nine months ended September 30, 2006, compared with the same periods in 2005.





**Three
                Months**
            **Missouri
                Regulated**
            
            **Illinois**
              **Regulated**
            
            **Non-rate-regulated
                Generation**
            
            **Other**
            
            **Intersegment
                Eliminations**
            
            **Consolidated**Electric
                margin change
            $
            7
            
            $
            (10
            )
            $
            54
            
            $
            -
            
            $
            (5
            )
            $
            46Gas
                margin change
            
            (1
            )
            
            2
            
            
            -
            
            
            -
            
            
            (1
            )
            
            -Other
                revenues (Non-utility)
            
            1
            
            
            1
            
            
            (1
            )
            
            (3
            )
            
            2
            
            
            -Total
            $
            7
            
            $
            (7
            )
            $
            53
            
            $
            (3
            )
            $
            (4
            )
            $
            46**Nine
                Months**Electric
                margin change
            $
            (56
            )
            $
            (20
            )
            $
            40
            
            $
            -
            
            $
            (13
            )
            $
            (49
            )Gas
                margin change
            
            (9
            )
            
            4
            
            
            -
            
            
            -
            
            
            (1
            )
            
            (6
            )Other
                revenues (Non-utility)
            
            2
            
            
            3
            
            
            (5
            )
            
            (5
            )
            
            2
            
            
            (3
            )Total
            $
            (63
            )
            $
            (13
            )
            $
            35
            
            $
            (5
            )
            $
            (12
            )
            $
            (58
            )


Ameren





Ameren’s
      electric margin increased by $46 million, or 4%, for the three months and
      decreased $49 million, or 2%, for the nine months ended September 30, 2006,
      compared with the same periods in 2005. The following items had a favorable
      impact on electric margins for the third quarter and first nine months of 2006
      as compared to the year-ago periods:


·
            an
                increase in margins on interchange sales of $59 million, or 181%,
                and $121
                million, or 67%, over the prior three and nine-month periods primarily
                because of the expiration of EEI’s affiliate cost-based power supply
                contract on December 31, 2005; ·
            organic
                growth and industrial customers switching back to Illinois tariff
                rates
                because of the expiration of power contracts with
                suppliers; ·
            sales
                to Noranda, which commenced on June 1, 2005, that increased electric
                margin by approximately $20 million at UE for the first nine
                months; ·
            lower
                emissions allowance costs totaling $10 million for both the quarter
                and
                nine months ended September 30, 2006; and ·
            MISO
                Day Two Energy Market costs which were $5 million lower for the three
                months ended September 30, 2006, compared with the same period in
                2005.





The
      following items had an unfavorable impact on electric margins for the third
      quarter and first nine months of 2006 as compared to the year-ago
      periods:





·
            unfavorable
                weather conditions as evidenced by a 10% decline in cooling degree-days
                for both the three months and nine months ended September 30, 2006,
                and a
                9% decrease in heating degree-days for the nine months ended September
                30,
                2006, compared with the same period in
                2005;


·
            severe
                storm-related outages which negatively impacted electric sales and
                resulted in an estimated net reduction in overall electric margin
                of $5
                million and $8 million in the third quarter and the nine months ended
                September 30, 2006;


·
            wholesale
                margins which were approximately $8 million lower for the nine months
                ended September 30, 2006 due primarily to the expiration of several
                large
                contracts in 2005;


·
            incremental
                fees of $4 million levied by FERC for the nine months ended September
                30,
                2006, upon completion of its cost study for generation benefits provided
                to UE’s Osage hydroelectric plant;


·
            a
                7% increase in the third quarter and 11% increase for the first nine
                months of 2006 in coal and transportation prices;  61


·
            MISO
                Day Two Energy Market costs which were $16 million higher for the
                nine
                months ended September 30, 2006, compared with the same periods in
                2005 as
                this market did not begin until the second quarter of 2005;


·
            reduced
                margins because of the unavailability of UE’s Taum Sauk hydroelectric
                plant totaling an estimated $10 million and $20 million in the third
                quarter and first nine months of
                2006;


·
            reduced
                margins from UE’s other hydroelectric generation due to drought-like
                conditions across the central and southern portions of Missouri totaling
                approximately $5 million for the third quarter and $24 million for
                the
                nine months ended September 30, 2006, as compared to prior
                periods;


·
            an
                unscheduled outage in the second quarter of 2006 at UE’s Callaway nuclear
                plant, which reduced electric margins by an estimated $20 million.
                In the
                third quarter of 2005, there was a scheduled refueling and maintenance
                outage that reduced electric margins by $4 million. The lack of a
                similar
                outage in the third quarter of 2006 benefited current year electric
                margins; and


·
            reduced
                transmission service revenues primarily due to elimination of interim
                cost
                recovery mechanisms and reduced revenues associated with the MISO
                Day Two
                Energy Market.





Ameren’s
      gas margins were flat for the three months and decreased by $6 million, or
      2%,
      for the nine months ended September 30, 2006, compared with the same periods
      in
      2005, respectively.





Ameren’s
      decrease in gas margins for the nine months ended September 30, 2006, compared
      with the same period in 2005, was primarily due to mild weather conditions
      as
      evidenced by a 9% decrease in heating degree-days. Weather-sensitive residential
      and commercial gas sales volumes decreased 9% and 8%, respectively, for the
      nine
      months ended September 30, 2006, compared with the same period in 2005. The
      decrease in gas margin was reduced by, among other things, the effect of an
      IP
      rate increase effective in May 2005 that added revenues of $6 million in the
      first nine months of 2006.





*Missouri
      Regulated*





UE




UE’s
      electric margin increased by $7 million, or 1%, for three months and decreased
      by $56 million, or 4%, for the nine months ended September 30, 2006, compared
      to
      the same periods in 2005. The increase in the electric margin for the three
      months ended September 30, 2006, was primarily due to:





·
            the
                lack of a scheduled Callaway nuclear plant refueling and maintenance
                outage in 2006; and


·
            decreased
                MISO Day Two Energy Market costs totaling $6
                million.





Factors
      that reduced the increase in electric margin for the three months and
      contributed to the decrease in electric margins for the nine months ended
      September 30, 2006, as compared to the same periods in the prior year were
      as
      follows:





·
            unfavorable
                weather conditions as evidenced by a 6% decline in cooling degree-days
                for
                the three months and 8% decline for the nine months ended September
                30,
                2006;


·
            severe
                spring and summer storms in 2006 caused outages which reduced electric
                sales and resulted in an estimated net reduction in overall electric
                margin of $3 million for the third quarter and $6 million for the
                first
                nine months of 2006;


·
            the
                transfer of UE’s Illinois service territory on May 2, 2005, to CIPS, which
                resulted in lost margins compared to the prior periods, totaling
                an
                estimated $22 million for the first nine months of 2006 with no impact
                on
                the third quarter of 2006;


·
            lower
                margins on interchange sales as a result of lower power prices in
                the
                third quarter and first nine months of 2006. Average interchange
                revenue
                realization per kilowatthour was 50% and 9% lower for the third quarter
                and first nine months of 2006, respectively. However, margins on
                interchange sales benefited from the January 2006 amendment of the
                JDA.
                The MoPSC-required and FERC-approved
                change in the JDA methodology to base the allocation of third-party
                short-term power sales of excess generation on generation output
                instead
                of load requirements, effective January 10, 2006, resulted in $3
                million
                and $17 million in incremental margins on interchange sales for UE
                for the
                three months and nine months ended September 30, 2006,
                respectively;


·
            a
                4% and 11% increase in coal and related transportation prices for
                the
                third quarter and first nine months of 2006;


·
            fees
                of $4 million levied by FERC for the nine months ended September
                30, 2006,
                for generation benefits provided to UE’s Osage hydroelectric
                plant;


·
            reduced
                margins because of the unavailability of UE’s Taum Sauk hydroelectric
                plant;


·
            reduced
                electric margins from UE’s other hydroelectric generation due to
                drought-like conditions across the central and southern portions
                of
                Missouri;


·
            unscheduled
                outage at UE’s Callaway nuclear plant in the second quarter of
                2006;


·
            MISO
                Day Two Energy Market costs, which were $8 million higher for the
                first
                nine months of 2006 as this market did not begin until the second
                quarter
                of 2005;


62
 ·
            the
                expiration of a cost-based power supply contract with EEI on December
                31,
                2005; and


·
            reduced
                transmission service revenues primarily due to elimination of interim
                cost
                recovery mechanisms and reduced revenues associated with the MISO
                Day Two
                Energy Market.





The
      decrease in UE’s electric margins for the nine months ended September 30, 2006,
      compared with the same period in 2005, was reduced by increased sales to Noranda
      and the lack of a scheduled Callaway refueling and maintenance outage in
      2006.





UE’s
      gas
      margin decreased by $1 million, or 9%, for the three months and $9 million,
      or
      17%, for the nine months ended September 30, 2006, compared with the same
      periods in 2005. UE’s decrease in gas margins was due to mild winter weather
      conditions, as evidenced by a 9% decrease in heating degree-days for the nine
      months ended September 30, 2006. In addition, UE’s gas margin was negatively
      impacted by the transfer of UE’s Illinois service territory to CIPS in May 2005,
      which reduced gas margins by $3 million for the nine months ended September
      30,
      2006, compared with the same period in 2005.





*Illinois
      Regulated*





Illinois
      Regulated’s electric margin decreased by $10 million, or 3%, for the three
      months and $20 million, or 3%, for the nine months ended September 30, 2006,
      compared with the same periods in 2005.




Illinois
      Regulated’s gas margin increased by $2 million, or 4%, for the three months and
      $4 million, or 2%, for the nine months ended September 30, 2006.





CIPS





CIPS’
      electric margin decreased by $1 million, or 1%, for the three months and
      increased by $3 million, or 1%, for the nine months ended September 30, 2006,
      compared to the same periods in 2005. The increase in electric margins for
      the
      first nine months of 2006 was primarily because of:





·
            the
                transfer to CIPS of UE’s Illinois service territory on May 2, 2005, which
                generated incremental electric margins of $4 million for the first
                nine
                months of 2006, and


·
            customers
                switching back to CIPS from Marketing Company in 2006 because tariff
                rates
                were below market rates for power.





CIPS’
      increase in electric margins was reduced by the following factors for the third
      quarter and first nine months of 2006, compared to the same periods in 2005,
      as
      follows:





·
            increased
                MISO Day Two Energy Market costs, totaling $2 million for the nine
                months
                ended September 30, 2006, compared with the same period in 2005 as
                this
                market did not begin until the second quarter of
                2005;


·
            severe
                summer storms caused outages that reduced electric sales and resulted
                in
                an estimated net reduction in electric margin of $2 million for the
                three
                months and nine months ended September 30, 2006;


·
            unfavorable
                weather conditions as evidenced by a 12% and 8% decrease in cooling
                degree-days for the third quarter and first nine months of 2006;
                and


·
            reduced
                transmission service revenues primarily due to elimination of interim
                cost
                recovery mechanisms and reduced revenues associated with the MISO
                Day Two
                Energy Market.





Due
      to
      the expiration of CIPS’ cost-based power supply agreement with EEI in December
      2005, where CIPS sold its entitlements under the agreement to Marketing Company,
      both interchange revenues and purchased power expenses decreased $9 million
      and
      $24 million for the three months and nine months ended September 30,
      2006.





CIPS’
gas
      margin increased by $2 million for the three months and $4 million, or 9%,
      for
      the nine months ended September 30, 2006, as compared with the same periods
      in
      2005 primarily because of the transfer to CIPS of UE’s Illinois service
      territory in May 2005. The increase in gas margin was reduced by extremely
      mild
      winter weather as evidenced by an 11% decrease in heating degree-days for the
      nine months ended September 30, 2006, as compared with the same period in
      2005.





CILCO
      (Illinois Regulated)





The
      following table provides a reconciliation of CILCO’s change in electric margin
      by segment to CILCO’s total change in electric margin for the three months and
      nine months ended September 30, 2006, as compared with the same periods in
      2005:





**Three
                Months**
            
            **Nine
                Months**CILCO
                (Illinois Regulated)
            **$**
            **(1**
            **)**
            **$**
            **2**CILCO
                (AERG)
            
            **13**
            
            
            **20**Total
                change in electric margin
            **$**
            **12**
            
            **$**
            **22**





CILCO’s
      Illinois Regulated electric margin decreased by $1 million, or 2%, for the
      three
      months ended September 30, 2006, as compared to the year-ago period, primarily
      because of unfavorable weather conditions as evidenced by a 19% decrease in
      cooling degree-days.





CILCO’s
      Illinois Regulated electric margin increased by $2 million, or 2%, for the
      nine
      months ended September 30, 2006, compared to the same periods in 2005. The
      increase in electric margins was primarily because of:




63


·
            increased
                native load growth, primarily in the industrial sector,
                and


·
            lower
                MISO Day Two Energy Market costs.





The
      increase in CILCO’s (Illinois Regulated) electric margins for the nine months
      ended September 30, 2006, was reduced by the impact of unfavorable weather
      conditions as evidenced by the decrease in cooling degree-days and a 6% decrease
      in heating degree-days.





See
      Non-rate-regulated Generation under Results of Operations for a detailed
      explanation of CILCO’s (AERG) change in electric margin for the three months and
      nine months ended September 30, 2006, as compared with the same periods in
      2005.





CILCO’s
      (Illinois Regulated) gas margin was flat for the three months and decreased
      by
      $5 million, or 8%, for the nine months ended September 30, 2006, compared to
      the
      same periods in 2005. This decrease was primarily as a result of the mild winter
      weather conditions in CILCO’s service territory.





IP





IP’s
      electric margin decreased by $9 million, or 5%, for the three months and $25
      million, or 7%, for the nine months ended September 30, 2006, compared with
      the
      same periods in 2005 primarily because of:





·
            increased
                purchased power costs as a result of the expiration of its cost-based
                power supply agreement with EEI on December 31, 2005, and increased
                purchased power prices;


·
            reduced
                transmission service revenues primarily due to the elimination of
                interim
                cost recovery mechanisms and reduced revenues associated with the
                MISO Day
                Two Energy Market;


·
            unfavorable
                weather conditions, including a 12% and 10% decrease in cooling
                degree-days for the three months and nine months ended September
                30, 2006,
                compared with the same periods in 2006;
                and


·
            severe
                summer storms caused outages that reduced electric sales and resulted
                in
                an estimated net reduction in electric margin of $1 million for the
                three
                months and nine months ended September 30,
                2006.





The
      decrease in IP’s electric margins in the third quarter and first nine months of
      2006 was reduced by an increase in revenues as a result of customers switching
      back to IP because tariff rates were below market rates for power and lower
      transmission expenses due, in part, to a $6 million favorable settlement of
      disputed ancillary charges with MISO.





IP’s
      gas
      margin was flat for the three months and increased by $5 million, or 5%, for
      the
      nine months ended September 30, 2006, compared to the same periods in 2005.
      The
      increase in the nine months ended September 30, 2006, was primarily because
      of a
      rate increase effective in May 2005 that added revenues of $6 million in 2006.
      This increase was reduced by the extremely mild winter weather conditions as
      evidenced by a 10% decrease in heating degree-days in the first nine months
      of
      2006 as compared with the year-ago period in IP’s service
      territory.





*Non-rate-regulated
      Generation*





Non-rate-regulated
      Generation’s electric margins increased by $54 million, or 32%, for the three
      months and $40 million, or 7%, for the nine months ended September 30, 2006,
      compared with the same periods in 2005.





Genco





Genco’s
      electric margin decreased by $36 million, or 29%, and $120 million, or 32%,
      for
      the three months and nine months ended September 30, 2006, compared with the
      same periods in 2005, primarily because of:





·
            lower
                wholesale margins as Genco purchased additional power at higher costs
                due,
                in part, to the expiration of the coal-based power supply contract
                between
                EEI and its affiliates on December 31, 2005;


·
            higher
                net emission allowance costs because of a $21 million gain at Genco
                in the
                third quarter of 2005 resulting from the nonmonetary swap of certain
                earlier vintage year SO2emission allowances for later vintage year
                allowances;


·
            a
                7% and 9% increase in coal and transportation prices for the three
                months
                and nine months ended September 30, 2006, compared with the same
                periods
                in 2005;


·
            reduced
                plant availability of major coal-fired units in
                2006;


·
            lower
                margins on interchange sales for the three months and nine months
                ended
                September 30, 2006, compared with the same periods in 2005, primarily
                because of lower power prices, and a $3 million and $17 million reduction
                in 2006 due to the amendment of the JDA among UE, Genco and CIPS;
                and


·
            higher
                MISO Day Two Market costs totaling $5 million for the third quarter
                and
                $11 million for the first nine months of 2006 as this market did
                not begin
                until the second quarter of 2005.





Genco’s
      decrease in electric margins was reduced by an increase in electric margins
      due
      to the May 2005 transfer of UE’s Illinois service territory to CIPS. Genco
      supplies CIPS’ power requirements through a power supply agreement with
      Marketing Company.




64


CILCO
      (AERG)





For
      the
      three- and nine-month periods ended September 30, 2006, AERG’s electric margin
      increased by $13 million, or 97%, for the three months and $20 million, or
      29%,
      for the nine months ended September 30, 2006, compared with the same periods
      in
      2005 primarily because of:





·
            lower
                purchased power costs due to improved power plant
                availability;


·
            decreases
                in emission allowance utilization expenses of $3 million and $7 million
                for the third quarter and first nine months of 2006, respectively;
                and


·
            an
                increase in margins on interchange sales of $5 million for the first
                nine
                months of 2006, due in part to improved plant
                availability.





EEI





EEI’s
      electric margins increased by $87 million for the three months and $179 million
      for the nine months ended September 30, 2006, compared with the same periods
      in
      2005 primarily because of the increase in margins on interchange sales resulting
      from the expiration of its affiliate cost-based sales contract on December
      31,
      2005, and its replacement with a market-based sales contract.





**Operating
      Expenses and Other Statement of Income Items**





***Other
      Operations and Maintenance***





*Ameren*





Three
      months - Other operations and maintenance expenses were comparable between
      periods. We experienced the most damaging storms in the company’s history in our
      service territory this summer resulting in the loss of power to approximately
      950,000 electric customers and expenses of $23 million. In addition, incremental
      costs of $7 million as a result of the December 2005 Taum Sauk plant incident
      increased 2006 third quarter other operations and maintenance expenses. Reducing
      the impact of this unfavorable item was decreased bad debt expense and an
      impairment of $10 million recorded in the prior-year period related to an
      investment in an aircraft leveraged lease with Delta Air Lines, Inc. due to
      its
      Chapter 11 bankruptcy filing in September 2005. No such impairment occurred
      in
      the current year period.





Nine
      months - Other operations and maintenance expenses increased $25 million
      primarily because of storm expenditures in the current year as discussed above,
      $17 million of costs related to the December 2005 reservoir breach at UE’s Taum
      Sauk plant, and losses on sales of leveraged lease assets in the second quarter
      of 2006 that increased other operations and maintenance expenses by $7 million.
      Additionally, higher power plant maintenance expenses due to the timing of
      maintenance outages and an increase in legal fees for environmental issues
      and
      general litigation resulted in increased other operations and maintenance
      expenses. Reducing the impact of these items was a reduction in bad debt expense
      and injuries and damages expense along with the impairment of the Delta Air
      Lines, Inc. leveraged lease recorded in the prior year, which did not recur
      in
      the current year, as discussed above.





Variations
      in other operations and maintenance expenses at Ameren’s, CILCORP’s and CILCO’s
      business segments and for the Ameren Companies for the three months and nine
      months ended September 30, 2006, compared with the same periods in 2005 were
      as
      follows:





*Missouri
      Regulated*





UE





Three
      months - Other operations and maintenance expenses increased $15 million
      primarily because of repair expenditures related to severe storms in UE’s
      service territory this summer of $16 million. Additionally, incremental costs
      of
      $7 million were recorded related to the December 2005 Taum Sauk plant incident
      because of a settlement with FERC resolving all potential federal liability.
      Reducing the impact of these unfavorable items were lower employee benefit
      costs
      and legal fees. Additionally, in the third quarter of 2005, we began a scheduled
      refueling and maintenance outage at UE’s Callaway nuclear plant, resulting in
      maintenance expenses of $3 million, which did not recur this year.





Nine
      months - Other operations and maintenance expenses increased $8 million
      primarily because of storm repair expenditures, as noted above, and incremental
      costs associated with the Taum Sauk incident of $17 million. Reducing the impact
      of these unfavorable items were decreased other operations and maintenance
      expenses of $7 million resulting from the transfer of UE’s Illinois service
      territory to CIPS in May 2005. Additionally, lower injuries and damages
      expenses, due in part to the settlement of claims, decreased bad debt expense
      and employee benefit costs, and the lack of a scheduled Callaway refueling
      and
      maintenance outage, as noted above, resulted in a reduction in other operations
      and maintenance expenses.





*Illinois
      Regulated*





Other
      operations and maintenance expenses increased $3 million and $27 million in
      Illinois Regulated primarily at IP for the three months and nine months ended
      September 30, 2006, respectively, compared with the same periods in
      2005.





65


CIPS





Three
      months - Other operations and maintenance expenses were comparable between
      periods as storm repair expenditures in the current period were offset by a
      reduction in bad debt expense.





Nine
      months - Other operations and maintenance expenses increased $8 million
      primarily because of storm repair expenditures and the transfer of UE’s Illinois
      service territory to CIPS in May 2005, which resulted in additional other
      operations and maintenance expenses of $7 million. The negative effect of these
      items was reduced by lower bad debt expense.





CILCO
      (Illinois Regulated)





Three
      months - Other operations and maintenance expenses were comparable between
      periods.





Nine
      months - Other operations and maintenance expenses decreased $3 million
      primarily because of lower employee benefit costs, partially offset by increased
      legal fees.





IP





Three
      months - Other operations and maintenance expenses increased $4 million
      primarily because of storm repair expenditures of $4 million in the current
      period and increased injuries and damages expenses, partially offset by
      decreased labor costs.





Nine
      months - Other operations and maintenance expenses increased $22 million
      primarily because of storm repair expenditures, along with higher rental
      expenses and injuries and damages expenses. The negative effect of these items
      was reduced by lower labor costs.





*Non-rate-regulated
      Generation*





Other
      operations and maintenance expenses were comparable at Non-rate-regulated
      Generation in the third quarter of this year compared to the third quarter
      of
      the prior year. Other operations and maintenance expenses increased $11 million
      for the nine months ended September 30, 2006, compared with the same period
      in
      2005, primarily at Genco.





Genco





Three
      months - Other operations and maintenance expenses were comparable between
      periods.





Nine
      months - Other operations and maintenance expenses increased $5 million
      primarily because of higher maintenance expenses resulting from increased power
      plant maintenance outages in the current-year period.





CILCORP
      (Parent Company Only), EEI & CILCO (AERG)





Three
      months and nine months - Other operations and maintenance expenses were
      comparable between periods.





*Other*





Three
      months - In the third quarter of 2005, Ameren recorded an impairment of $10
      million at a nonregistrant subsidiary related to an investment in an aircraft
      leveraged lease to Delta Air Lines, Inc. due to its Chapter 11 bankruptcy filing
      in September 2005. No such impairment occurred in the current year period.





Nine
      months - In the second quarter of 2006, losses on sales of leveraged lease
      assets were recorded at CILCO. The leveraged lease losses in other operations
      and maintenance expenses were partially offset by a tax benefit reflected in
      income taxes. The lack of the 2005 leveraged lease impairment associated with
      Delta Air Lines, Inc. in the current year reduced the year-over-year impact
      of
      the leveraged lease losses for the first nine-months of 2006.





***Depreciation
      and Amortization***





*Ameren*





Three
      months - Depreciation and amortization expenses increased $4 million primarily
      because of capital additions.





Nine
      months - Depreciation and amortization expenses increased $17 million primarily
      as a result of capital additions and the impairment of an intangible asset
      associated with the CILCORP acquisition.





Variations
      in depreciation and amortization expenses at Ameren’s business segments for the
      three months and nine months ended September 30, 2006, compared with the same
      periods in 2005 were as follows:




*Missouri
      Regulated*





UE





Three
      months - Depreciation and amortization expenses increased $3 million primarily
      because of capital additions.





Nine
      months - Depreciation and amortization expenses increased $12 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 2005. Additionally, depreciation
      increased due to CTs transferred to UE from




66


Genco
      in
      May 2005. Reducing the impact of these increases was a reduction of depreciation
      due to the transfer of property to CIPS as part of the Illinois service
      territory transfer in May 2005.





*Illinois
      Regulated*





Depreciation
      and amortization expenses were comparable at Illinois Regulated for the three
      months and nine months ended September 30, 2006, compared with the same periods
      in 2005.





CIPS





Three
      months - Depreciation and amortization expenses were comparable between
      periods.





Nine
      months - Depreciation and amortization expenses increased $2 million primarily
      because of capital additions and depreciation on property transferred to CIPS
      from UE in the May 2005 Illinois service territory transfer.





CILCO
      (Illinois Regulated) & IP





Three
      months and nine months - Depreciation and amortization expenses were comparable
      between periods.




*Non-rate-regulated
      Generation*





Depreciation
      and amortization expenses were comparable at Non-rate-regulated Generation
      in
      the third quarter of 2006 compared to the third quarter of last year.
      Depreciation and amortization expenses increased $3 million for the nine months
      ended September 30, 2006, compared with the same period in 2005.





Genco,
      EEI & CILCO (AERG)





Three
      months and nine months - Depreciation and amortization expenses were comparable
      between periods.





CILCORP
      (Parent Company Only)





Three
      months - Depreciation and amortization expenses were comparable between
      periods.





Nine
      months - Depreciation and amortization expenses increased $4 million primarily
      because of the recording of an impairment of an intangible asset established
      in
      conjunction with Ameren’s acquisition of CILCORP.




***Taxes
      Other Than Income Taxes***





*Ameren*




Three
      months - Taxes other than income taxes were comparable between
      periods.





Nine
      months - Taxes other than income taxes increased $18 million primarily as a
      result of higher gross receipts and excise taxes and higher property taxes.




Variations
      in taxes other than income taxes at Ameren’s business segments for the three
      months and nine months ended September 30, 2006, compared with the same periods
      in 2005 were as follows:





*Missouri
      Regulated*





UE





Three
      months - Taxes other than income taxes were comparable between
      periods.





Nine
      months - Taxes other than income taxes increased $4 million primarily as a
      result of higher gross receipts taxes.





*Illinois
      Regulated*





Taxes
      other than income taxes were comparable at Illinois Regulated in the third
      quarter of this year compared to the third quarter of the prior year. Taxes
      other than income taxes increased $8 million for the nine months ended September
      30, 2006, compared with the same period in 2005.





CIPS





Three
      months - Taxes other than income taxes were comparable between
      periods.





Nine
      months - Taxes other than income taxes increased $6 million primarily as a
      result of higher excise taxes.





CILCO
      (Illinois Regulated)





Three
      months - Taxes other than income taxes were comparable between
      periods.





Nine
      months - Taxes other than income taxes increased $3 million primarily as a
      result of higher excise taxes.





IP





Three
      months and nine months - Taxes other than income taxes were comparable between
      periods.




67




*Non-rate-regulated
      Generation*





Taxes
      other than income taxes were comparable at Non-rate-regulated Generation in
      the
      third quarter of 2006 compared to the third quarter of the prior year. Taxes
      other than income taxes increased $8 million for the nine months ended September
      30, 2006, compared with the same period in 2005, primarily at
      Genco.





Genco





Three
      months - Taxes other than income taxes were comparable between
      periods.




Nine
      months - Taxes other than income taxes increased $7 million primarily because
      of
      higher property taxes due to a favorable court decision in the first quarter
      of
      2005 that did not recur in 2006.





CILCORP
      (Parent Company Only), EEI & CILCO (AERG)





Three
      months and nine months - Taxes other than income taxes were comparable between
      periods.





***Other
      Income and Expenses***





*Ameren*





Three
      months and nine months - Miscellaneous income decreased $1 million and $6
      million primarily as a result of lower capitalization of equity funds used
      during construction in the current year periods. Miscellaneous expense increased
      $2 million in the third quarter primarily because of activity related to
      investments in low income housing credits. Miscellaneous expense decreased
      $3
      million in the nine months primarily due to the write-off of unrecoverable
      natural gas costs in the prior year as noted below.





Variations
      in other income and expenses at Ameren’s, CILCORP’s and CILCO’s business
      segments for the three months and nine months ended September 30, 2006, compared
      with the same periods in 2005 were as follows:





*Missouri
      Regulated*





UE





Three
      months - Other income and expenses were comparable between periods.





Nine
      months - Miscellaneous income decreased $6 million primarily as a result of
      lower capitalization of equity funds used during construction in 2006. In the
      prior-year period, UE replaced steam generators and turbine rotors at the
      Callaway nuclear plant. Miscellaneous expense was comparable between
      periods.





*Illinois
      Regulated*





Other
      income and expenses were comparable at Illinois Regulated in the third quarter
      of 2006 compared to the third quarter of the prior year. Other income and
      expenses were favorable $3 million for the nine months ended September 30,
      2006,
      compared with the same period in 2005.





CIPS





Three
      months - Miscellaneous income and miscellaneous expense were comparable between
      periods.





Nine
      months - Miscellaneous income was comparable between periods. Miscellaneous
      expense decreased $4 million primarily as a result of the write-off in 2005
      of
      unrecoverable natural gas costs.





CILCO
      (Illinois Regulated)





Three
      months - Miscellaneous income and miscellaneous expense were comparable between
      periods.





Nine
      months - Miscellaneous income was comparable between periods. Miscellaneous
      expense decreased $3 million primarily as a result of the write-off in the
      prior
      year of unrecoverable natural gas costs.





IP





Three
      months - Miscellaneous income and miscellaneous expense were comparable between
      periods.





Nine
      months - Miscellaneous income decreased $2 million primarily because of lower
      capitalization of equity funds used during construction. Miscellaneous expenses
      increased $2 million primarily as a result of IP-related integration
      costs.





*Non-rate-regulated
      Generation*





Other
      income and expenses were comparable at Non-rate-regulated Generation for the
      three months and nine months ended September 30, 2006, compared with the same
      periods in 2005.





Genco,
      CILCORP (Parent Company Only), EEI & CILCO (AERG)





Three
      months and nine months - Other income and expenses were comparable between
      periods.




68


***Interest***





*Ameren*





Three
      months and nine months - Interest expense increased $12 million and $17 million
      primarily because of items noted below.





Variations
      in interest expense at Ameren’s, CILCORP’s and CILCO’s business segments for the
      three months and nine months ended September 30, 2006, compared with the same
      periods in 2005 were as follows:





*Missouri
      Regulated*





UE





Three
      months and nine months - Interest expense increased $6 million and $26 million,
      respectively, 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 along with increased short-term borrowings, partially resulting from the
      purchase of CTs in the first quarter of 2006.





*Illinois
      Regulated*





Interest
      expense was comparable at Illinois Regulated in the third quarter of this year
      compared to the third quarter of the prior year. Interest expense increased
      $6
      million for the nine months ended September 30, 2006, compared with the same
      period in 2005, principally at IP.





CIPS
      & CILCO (Illinois Regulated)





Three
      months and nine months - Interest expense was comparable between
      periods.





IP





Three
      months - Interest expense was comparable between periods.





Nine
      months - Interest expense increased $5 million primarily because of the issuance
      of $75 million of senior secured notes in June 2006 along with increased money
      pool borrowings.





*Non-rate-regulated
      Generation*





Interest
      expense was comparable at Non-rate-regulated Generation in the third quarter
      of
      2006 compared to the third quarter of the prior year. Interest expense decreased
      $14 million for the nine months ended September 30, 2006, compared with the
      same
      period in 2005, principally at Genco.





Genco





Three
      months - Interest expense was comparable as a reduction in interest expense
      of
      $4 million resulting from the maturity of $225 million of senior notes in
      November 2005 was offset by increased money pool borrowings.





Nine
      months - Interest expense decreased $12 million primarily because of the
      maturity of the $225 million senior notes.





CILCORP
      (Parent Company Only)





Three
      months - Interest expense was comparable between periods.





Nine
      months - Interest expense was comparable as a decrease of $3 million due to
      the
      repurchase of $85 million of 8.70% senior notes in 2005 was offset by increased
      money pool borrowings.





EEI
&
      CILCO (AERG)





Three
      months and nine months - Interest expense was comparable between
      periods.





***Income
      Taxes***





*Ameren*





Three
      months and nine months - Effective tax rate increased in the third quarter
      of
      the current year primarily because of items discussed below. Effective tax
      rate
      for the nine months was comparable to the prior-year period.





Variations
      in effective tax rates at Ameren’s, CILCORP’s and CILCO’s business segments for
      the three months and nine months ended September 30, 2006, compared with the
      same periods in 2005 were as follows:





*Missouri
      Regulated*





UE





Three
      months and nine months - Effective tax rate increased over the prior year
      primarily because of non-deductible items for tax purposes and an increase
      in
      reserves for uncertain tax positions.





*Illinois
      Regulated*





Effective
      tax rate increased at Illinois Regulated for the three months and nine months
      ended September 30, 2006, compared with the same periods in 2005.





69





CIPS




Three
      months - Effective tax rate increased primarily because of the settlement of
      uncertain tax positions in the current year.





Nine
      months - Effective tax rates were comparable between periods.





CILCO
      (Illinois Regulated)





Three
      months and nine months - Effective tax rate increased primarily because of
      a
      reduction in a permanent deduction allowed for tax purposes that was not allowed
      for book purposes.





IP





Three
      months and nine months - Effective tax rates were comparable between periods.





*Non-rate-regulated
      Generation*





Effective
      tax rate decreased at Non-rate-regulated Generation for the three months and
      nine months ended September 30, 2006, compared with the same periods in
      2005.




Genco





Three
      months and nine months - Effective tax rate decreased primarily because of
      the
      settlement of uncertain tax positions in the current year.





CILCORP
      (Parent Company Only)





Three
      months and nine months - Effective tax rates were comparable between
      periods.





CILCO
      (AERG)





Three
      months and nine months - Effective tax rate decreased primarily because of
      the
      settlement of uncertain tax positions in the current year.





EEI





Three
      months and nine months - Effective tax rates were comparable between periods.




**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, UE,
      CIPS, CILCO and IP. For operating cash flows, Genco principally relies on power
      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 and AERG expect to sell power previously sold under
      contracts expiring at the end of 2006 to Marketing Company, which has sold
      power
      through the Illinois power procurement auction and is selling power through
      other contracts with wholesale and retail customers. The amount of power that
      Genco, AERG, EEI, Marketing Company and their affiliates may supply to CIPS,
      CILCO and IP through the Illinois power procurement auction is limited to 35%
      of
      CIPS’, CILCO’s and IP’s annual load. In addition, each of the Ameren Companies
      plans to use available cash, commercial paper and credit facilities 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 September 30, 2006, for Ameren, UE, Genco, CILCORP, CILCO and IP. The
      Ameren Companies will reduce their short-term borrowings with cash from
      operations or discretionarily with long-term borrowings. See Note 2 - Rate
      and
      Regulatory Matters to our financial statements under Part I, Item 1 of this
      report for a discussion of an Illinois legislative proposal to freeze electric
      rates for CIPS, CILCO and IP. If such legislation is enacted, CIPS, CILCORP,
      CILCO and IP will not have enough operating cash flow to support normal
      operations.




70




The
      following table presents net cash
      provided by (used in) operating, investing and financing activities for the
      nine
      months ended September 30, 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)
            **$**
            **1,030**
            
            $
            1,177
            
            $
            (147
            )
            **$**
            **(1,005**
            **)**
            $
            (736
            )
            $
            (269
            )
            **$**
            **(87**
            **)**
            $
            (232
            )
            $
            145UE
            
            **593**
            
            
            712
            
            
            (119
            )
            
            **(584**
            **)**
            
            (633
            )
            
            49
            
            
            **(27**
            **)**
            
            (126
            )
            
            99CIPS
            
            **127**
            
            
            148
            
            
            (21
            )
            
            **(47**
            **)**
            
            (40
            )
            
            (7
            )
            
            **(80**
            **)**
            
            (110
            )
            
            30Genco
            
            **46**
            
            
            205
            
            
            (159
            )
            
            **(80**
            **)**
            
            54
            
            
            (134
            )
            
            **36**
            
            
            (260
            )
            
            296CILCORP
            
            **99**
            
            
            77
            
            
            22
            
            
            **(28**
            **)**
            
            (87
            )
            
            59
            
            
            **(71**
            **)**
            
            7
            
            
            (78
            )CILCO
            
            **122**
            
            
            101
            
            
            21
            
            
            **(70**
            **)**
            
            (91
            )
            
            21
            
            
            **(52**
            **)**
            
            (10
            )
            
            (42
            )IP
            
            **106**
            
            
            207
            
            
            (101
            )
            
            **(127**
            **)**
            
            (4
            )
            
            (123
            )
            
            **21**
            
            
            (203
            )
            
            224


(a)
            Includes
                amounts for Ameren registrant and nonregistrant subsidiaries and
                intercompany eliminations.





**Cash
      Flows from Operating Activities**





Ameren’s
      cash from operations decreased in the first nine months of 2006, as compared
      with the first nine months of 2005, due primarily to decreases in electric
      and
      gas margins, and higher other operations and maintenance expenses as discussed
      in Results of Operations, and a $133 million increase in income tax payments.
      In
      addition, there was an increase in cash used during the first nine months of
      2006 for payment of 2005 costs, including real estate and property taxes, and
      annual incentive compensation that was more than it was a year ago because
      of
      increased 2005 earnings relative to performance targets. The cash benefit from
      reduced natural gas inventories that resulted in the first quarter of 2006
      due
      to the end of the winter heating season was offset in the second and third
      quarters as a result of increased volume and per unit prices of coal inventory
      purchases because of the coal supply issues experienced in the 2005 period
      and
      higher prices for coal in the 2006 period. Reducing these negative impacts
      was
      the collection of higher-than-normal trade receivables caused by cold December
      2005 weather during the winter heating season. The cash impact from trade
      receivables was more significant in the current period due to higher gas prices
      and colder December weather in 2005 as compared with the year-ago
      period.




At
      UE,
      cash from operating activities decreased in 2006 due to lower electric and
      gas
      margins and storm costs as discussed in Results of Operations, and cash used
      for
      working capital changes that primarily included increased payments of 2005
      costs
      in the first nine months of 2006 as compared with the year-ago period as
      discussed above for Ameren. Also contributing to the decrease were operations
      and maintenance expenditures of $14 million related to severe spring and summer
      storms, increased income tax payments of $27 million compared to the year-ago
      period, increased interest payments of $37 million, and $26 million paid (net
      of
      insurance recoveries to date) as a result of the breach at the Taum Sauk
      hydroelectric facility. See Note 8 - Commitments and Contingencies -
      Pumped-storage Hydroelectric Facility Breach for more information.





At
      CIPS,
      the negative cash effect of higher other operations and maintenance expenses
      and
      taxes other than income was partially offset by higher electric and gas margins,
      as discussed in Results of Operations. Income tax payments increased $45 million
      compared to the year-ago period. Partially offsetting this use of cash was
      an
      increase in collections of trade receivables as a result of colder December 2005
      weather and higher gas prices compared to the year-ago period.





Genco’s
      cash from operating activities in the first nine months of 2006 decreased
      compared to the 2005 period primarily because of lower operating margins as
      discussed in Results of Operations. Income tax payments decreased in 2006 by
      $35
      million compared to 2005, and interest payments were lower in the 2006 period
      due to decreased debt outstanding.





Cash
      from
      operating activities increased for CILCORP and CILCO in the nine months ended
      September 30, 2006, compared with the same period of 2005 primarily because
      of
      higher electric margins as discussed in Results of Operations, and an increase
      in collections of trade receivables as a result of colder December 2005 weather
      and higher gas prices compared to the year ago periods.  In addition,
      income tax payments decreased $15 million for CILCO and $25 million for CILCORP.
      Partially offsetting these positive effects on cash were higher other operations
      and maintenance expenses as discussed in Results of Operations.





IP’s
      cash
      from operations decreased in the nine months ended September 30, 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 net income tax
      refunds of $19 million in the 2006 period as compared with $32 million in the
      year-ago period, and cash used during the first nine months of 2006 for payment
      of 2005 costs including real estate and property taxes, and annual incentive
      compensation that was




71


more
      than
      it was a year ago due to increased 2005 earnings relative to performance
      targets.




**Cash
      Flows from Investing Activities**





Ameren’s
      increase in cash used in investing activities was primarily because of UE’s 2006
      purchases of a 640-megawatt CT facility from affiliates of NRG Energy, Inc.,
      and
      510-megawatt and 340-megawatt CT facilities from subsidiaries of Aquila, Inc.
      for a total of $292 million. The CT purchases are intended to meet UE’s
      increased generating capacity needs and provide UE with additional flexibility
      in determining future base-load generating capacity additions.




Excluding
      CT purchases, Ameren’s capital expenditures were comparable in the first nine
      months of 2006 as compared with the year-ago period. Emission allowance
      purchases decreased $54 million in the first nine months of 2006 compared to
      the
      first nine months of 2005, while emission allowance sales increased $8 million.
      The sale of leveraged lease investments provided an $11 million benefit to
      Ameren’s cash from investing activities as discussed below.





UE’s
      cash
      used in investing activities decreased in the first nine months of 2006,
      compared to the same period in 2005, principally because of $67 million received
      from CIPS on an intercompany note. The cash effect of the $292 million in CT
      purchases discussed above was more than the prior year effect of the $241
      million purchase of two CTs from Genco and the purchase of CT equipment from
      Development Company for $25 million. Excluding these transactions, UE’s capital
      expenditures decreased $38 million, despite $22 million expended as a result
      of
      the severe spring and summer storms.




CIPS’
      cash used in investing activities increased for the nine months ended September
      30, 2006, compared with the 2005 period. Capital expenditures increased $22
      million. Also negatively impacting CIPS’ investing cash flow was an $18 million
      reduction in proceeds from CIPS’ note receivable from Genco in the 2006 period
      as compared with the 2005 period. The decrease in proceeds from Genco resulted
      from the May 1, 2005, amendment and restatement of the note. Reducing these
      negative effects was a $33 million reduction of advances to the money pool
      in
      2006 as compared with 2005. 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. In addition, $6 million was expended
      as
      a result of severe summer storms. CIPS’ remaining capital expenditures were for
      projects to improve the reliability of its electric and gas transmission and
      distribution systems.





Genco
      had
      a net use of cash in investing activities for the first nine months of 2006
      compared to a net source of cash during the same period in 2005. This was due
      primarily to the 2005 sale of two CTs to UE in 2005 for $241 million. Purchases
      of emission allowances were $45 million less in the first nine months of 2006
      compared to the first nine months of 2005,
      and
      changes in net money pool advances resulted in a $65 million increase in cash
      in
      the 2006 period as compared to the 2005 period.





CILCORP’s
      and CILCO’s cash used in investing activities decreased in the nine months ended
      September 30, 2006, compared with the same period in 2005. CILCORP’s cash from
      investing activities benefited from the repayment of Resources Company’s note
      payable of $42 million that originated from the 2005 transfer of leveraged
      leases from CILCORP to Resources Company. In addition, a subsidiary of CILCORP
      and CILCO generated cash from investing activities of $11 million in the nine
      months ended September 30, 2006, from the sale of its remaining leveraged lease
      investments. Emission allowance purchases were $9 million less in the first
      nine
      months of 2006 compared to the first nine months of 2005.




IP’s
      cash
      used in investing activities increased in the first nine months of 2006 compared
      to the same period in 2005, primarily because of the absence in the 2006 period
      of proceeds received in the first nine months of 2005 from repayments received
      for advances made to the money pool in prior periods. In addition, capital
      expenditures increased $31 million over the year-ago period, which includes
      $12
      million as a result of severe summer storms, and increased expenditures to
      maintain the reliability of IP’s electric and gas transmission and distribution
      systems.





See
      Note
      8 - Commitments and Contingencies to our financial statements under Part I,
      Item
      1, of this report for a further discussion of future environmental capital
      investment estimates.





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
      used
      in financing activities decreased for Ameren in the first nine months of 2006
      from the year-ago period. Positive effects on cash included a net increase
      of
      $118 million in net short-term debt proceeds in the 2006 period, compared to
      net
      repayments of $394 million of short-term debt in the 2005 period, less long-term
      debt redemptions,




72


repurchases
      and maturities of $124 million, and borrowings on its $500 million credit
      facility of $40 million in 2006. Negative effects on cash included a $150
      million reduction in long-term debt proceeds compared to the year-ago period,
      and a $352 million reduction in proceeds from the issuance of common stock.
      The
      reduction in common stock proceeds was due to the issuance of 7.4 million shares
      in the 2005 period related to the settlement of a stock purchase obligation
      in
      Ameren’s adjustable conversion-rate equity security units.




UE’s
      cash
      used in financing activities decreased for the first nine months of 2006,
      compared to the same period last year. Net changes in short-term debt resulted
      in a $128 million positive effect on cash in 2006, but a $375 million negative
      effect on cash in 2005. In addition, dividend payments decreased $55 million
      in
      the 2006 period compared to 2005. Partially offsetting these positive effects
      on
      cash were a $382 million reduction in long-term debt issuances, and a $79
      million decrease in money pool borrowings. Net cash from financing activities
      was principally used to fund the CT acquisitions.





CIPS’
      cash used in financing activities decreased for the nine months ended September
      30, 2006, as
      compared with the 2005 period. Cash was positively affected by a $66 million
      decrease in money pool repayments in the 2006 period. A $29 million increase
      in
      dividends to Ameren negatively impacted CIPS’ cash from financing activities in
      2006 as compared to the year-ago period. CIPS’ second quarter 2006 issuance of
      $61 million of long-term debt was principally used to repay CIPS’ outstanding
      balance on the intercompany note payable to UE that was originally issued with
      the transfer of UE’s Illinois service territory to CIPS in 2005.




Genco
      had
      net cash proceeds from financing activities for the first nine months of 2006,
      compared to a net use of cash for the same period last year. This is primarily
      because in 2005, Genco used the $241 million from the CT sale to UE to make
      principal payments on intercompany notes with CIPS and Ameren, and to reduce
      its
      money pool borrowings, and then make advances to the money pool. In addition,
      $150 million of capital contributions received in 2006 from Ameren benefited
      Genco’s financing cash flows. These capital contributions were made to reduce
      Genco’s short-term debt. Reducing these positive effects on cash was a $34
      million increase in dividend payments in the 2006 period as compared with the
      2005 period.




CILCORP’s
      and CILCO’s cash from financing activities benefited from CILCO’s long-term debt
      issuances that generated $96 million in the 2006 period, as compared with no
      long-term debt issuances in the 2005 period. The proceeds of this debt were
      used
      to redeem $20 million of long-term debt and to reduce money pool borrowings.
      In
      addition, CILCO’s subsidiary AERG borrowed $40 million in 2006 under the $500
      million credit facility. These benefits in the 2006 period were partially offset
      by the absence in 2006 of a $101 million capital contribution received in the
      2005 period from Ameren, which was made to reduce CILCO’s short-term debt. In
      addition, in 2006, CILCORP used cash of $32 million for redemptions, repurchases
      and maturities of long-term debt as compared with $6 million in the 2005 period.
      CILCORP’s net repayments of $30 million on its note payable to Ameren reduced
      its financing cash flow by $58 million as compared with the year-ago period
      because the 2005 period included net borrowings on this note that provided
      CILCORP with cash.




Also
      contributing to CILCORP’s and CILCO’s increase in cash used in financing
      activities for the nine months ended September 30, 2006, as compared with the
      year-ago period, were increased common stock dividends of $20 million and $45
      million at CILCORP and CILCO, respectively, in the 2006 period as compared
      with
      the 2005 period.





IP
      had a
      net source of cash from financing activities in the first nine months of 2006,
      compared to a net use of cash in the same period of the prior year. This was
      primarily because of lower redemptions and repurchases of long-term debt of
      $66
      million. More debt was repaid in 2005 to improve IP’s credit profile. Another
      positive effect on cash from financing activities was the absence in the 2006
      period of $60 million of common stock dividend payments made in the 2005 period.
      IP issued $75 million of long-term debt in 2006 as compared with no long-term
      debt proceeds in the year-ago period. The proceeds were used to reduce money
      pool borrowings.





***Short-term
      Borrowings and Liquidity***





For
      additional information on credit facilities, short-term borrowing activity,
      relevant interest rates, and borrowings under Ameren’s utility and
      non-state-regulated subsidiary money pool arrangements, see Note 3 - Credit
      Facilities and Liquidity to our financial statements under Part I, Item 1,
      of
      this report.





73


The
      following table presents the committed bank credit facilities of the Ameren
      Companies and AERG as of October 31, 2006:





**Credit
                Facility**
            **Expiration**
            
            **Amount**
              **Committed**
            
            **Amount**
              **Available****Ameren:****(a)**Multiyear
                revolving(b)(c)
            
            July
                2010
            
            $
            1,150
            
            $
            995**CIPS,
                CILCORP, CILCO, IP and AERG:**Multiyear
                revolving(d)
            
            January
                2010
            
            
            500
            
            
            215


(a)
            Ameren’s
                $350 million revolving credit facility was terminated on July 14,
                2006.
                See further discussion in Note 3 - Credit Facilities and Liquidity
                to our
                financial statements under Part I, Item 1, of this
                report.


(b)
            Ameren
                Companies may access this credit facility through intercompany borrowing
                arrangements.


(c)
            UE
                and Genco are authorized to be direct borrowers under this facility.
                CIPS,
                CILCO and IP were also authorized to be direct borrowers under this
                agreement until July 13, 2006. See Note 3 - Credit Facilities and
                Liquidity to our financial statements under Part I, Item 1, of this
                report
                for discussion of the amendment of this
                facility.


(d)
            This
                credit facility was entered into on July 14, 2006. The maximum amount
                available to each borrower, including for issuance of letters of credit,
                is limited as follows: CIPS -
              $135
                million, CILCORP - $50 million, CILCO - $150 million, IP - $150 million
                and AERG - $200 million. Effective September 8, 2006, CIPS, CILCO,
                and IP
                became authorized to borrow and obtain letters of credit for their
                benefit
                under this facility. See Note 3 - Credit Facilities and Liquidity
                to our
                financial statements under Part I, Item 1, of this report for discussion
                of this credit facility.





In
      addition to committed credit facilities, a further source of liquidity for
      Ameren from time to time is available cash and cash equivalents. At September
      30, 2006, Ameren had


$34
      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
      was
      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, AERG and EEI have unlimited
      short-term debt authorization from FERC.




With
      the
      repeal of PUHCA 1935, 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
      nine months ended September 30, 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.





**Month
                Issued, Redeemed,**
            
            **Nine
                Months****Repurchased
                or Matured**
            
            **2006**
            
            **2005****Issuances***Long-term
                debt***UE:****(a)**5.00%
                Senior secured notes due 2020
            
            January
            
            **$**
            **-**
            
            $
            855.30%
                Senior secured notes due 2037
            
            July
            
            
            **-**
            
            
            297**CIPS:****(b)**6.70%
                Senior secured notes due 2036
            
            June
            
            
            **61**
            
            
            -**CILCO:****(b)**Borrowings
                from credit facility(c)
            
            September
            
            
            **40**
            
            
            -6.20%
                Senior secured notes due 2016
            
            June
            
            
            **54**
            
            
            -6.70%
                Senior secured notes due 2036
            
            June
            
            
            **42**
            
            
            -**IP:****(b)**6.25%
                Senior secured notes due 2016
            
            June
            
            
            **75**
            
            
            -Total
                Ameren long-term debt issuances
            
            
            
            **$**
            **272**
            
            $
            382




74





**Month
                Issued, Redeemed,**
            
            **Nine
                Months****Repurchased
                or Matured**
            
            
            **2006**
            
            
            **2005***Common
                stock***Ameren:**7,402,320
                Shares at $46.61(d)
            
            May
            
            **$**
            **-**
            
            $
            345DRPlus
                and 401(k)(e)
            
            Various
            
            
            **78**
            
            
            85Total
                common stock issuances
            
            
            
            **$**
            **78**
            
            $
            430Total
                Ameren long-term debt and common stock issuances
            
            
            
            **$**
            **350**
            
            $
            812**Redemptions,
                Repurchases and Maturities***Long-term
                debt and preferred stock***Ameren:**Senior
                notes due 2007(f)
            
            February
            
            **$**
            **-**
            
            $
            95**CIPS:**7.05%
                First mortgage bonds due 2006
            
            June
            
            
            **20**
            
            
            -6.49%
                First mortgage bonds due 2005
            
            June
            
            
            **-**
            
            
            20**CILCORP:**9.375%
                Senior notes due 2029
            
            March/April
            
            
            **12**
            
            
            -8.70%
                Senior notes due 2009
            
            May
            
            
            **-**
            
            
            6**CILCO:**7.73%
                First mortgage bonds due 2025
            
            July
            
            
            **20**
            
            
            -5.85%
                Series preferred stock
            
            July
            
            
            **1**
            
            
            1**IP:**6.75%
                Mortgage bonds due 2005
            
            March
            
            
            **-**
            
            
            70Notes
                payable to IP SPT5.54%
                Series due 2007
            
            Various
            
            
            **86**
            
            
            -5.38%
                Series due 2005
            
            Various
            
            
            **-**
            
            
            71Total
              Ameren long-term debt and preferred stock redemptions, repurchases
              and
              maturities
            
            
            **$**
            **139**
            
            
            263 (a)
            Ameren’s
                and UE’s long-term debt increased $240 million as a result of the first
                quarter 2006 leasing transaction related to UE’s purchase of a
                640-megawatt CT facility located in Audrain County, Missouri. No
                capital
                was raised as a result of UE’s assumption of the lease
                obligations. (b)
            On
                September 8, 2006, CIPS, CILCO and IP issued mortgage bonds in the
                amounts
                of $135 million, $150 million and $150 million, respectively to secure
                their obligations under the $500 million credit facility. See Note
                3 -
                Credit Facilities and Liquidity to our financial statements under
                Part I,
                Item 1, of this report. (c)
            Represents
                borrowings made by AERG under the $500 million credit facility discussed
                in Note 3 - Credit Facilities and Liquidity to our financial statements
                under Part I, Item 1, of this report. (d)
            Shares
                issued upon settlement of the purchase contracts, which were a component
                of the adjustable conversion-rate equity security
                units. (e)
            Includes
                issuances of common stock of 1.5 million shares during the nine months
                ended September 30, 2006, under DRPlus and 401(k)
                plans. (f)
            Component
                of the adjustable conversion-rate equity security
                units.




The
      following table presents the authorized amounts under Form S-3 shelf
      registration statements filed and declared effective for certain Ameren
      Companies as of September 30, 2006:





**Effective**
              **Date**
            
            **Authorized**
              **Amount**
            
            **Issued**
            
            **Available**Ameren
            
            June
                2004
            
            $
            2,000
            
            $
            459
            
            $
            1,541UE
            
            October
                2005
            
            
            1,000
            
            
            260
            
            
            740CIPS
            
            May
                2001
            
            
            250
            
            
            211
            
            
            39





Ameren
      also has approximately 6.6 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 September 30, 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 - Credit Facilities and Liquidity to our financial statements under Part
      I,
      Item 1, of this report for a discussion of the covenants and provisions
      contained in our 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
      September 30, 2006, the Ameren Companies were in compliance with their credit
      facility, 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




75


will
      continue to have access to the capital markets. However, events beyond our
      control, such as the extension of the electric rate freeze in Illinois for
      CIPS,
      CILCO and IP, may create uncertainty in the capital markets. Such events would
      likely increase our cost of capital and adversely affect our ability to access
      the capital markets. See Note 2 - Rate and Regulatory Matters to our financial
      statements under Part I, Item 1, of this report.





**Dividends**





Dividends
      paid by Ameren to shareholders during the first nine months of 2006 totaled
      $391
      million, or $1.905 per share (2005 - $383 million or $1.905 per share).





CILCO
      paid preferred stock dividends of less than $1 million on October 2, 2006.
      IP
      paid preferred stock dividends of approximately $1 million on November 1, 2006.
      The next preferred dividends are payable on November 15, 2006, December 29,
      2006, January 2, 2007, and February 1, 2007, for UE, CIPS, CILCO and IP,
      respectively.





See
      Note
      3 - Credit Facilities and Liquidity and 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’ financial agreements, articles of incorporation and an ICC order that
      would restrict the Ameren Companies’ payment of dividends in certain
      circumstances. At September 30, 2006, except as discussed below with respect
      to
      the $500 million credit facility, none of these circumstances existed at the
      other Ameren Companies and as a result, they were allowed to pay dividends.





On
      July
      14, 2006, CIPS, CILCORP, CILCO, IP, and AERG entered into a new $500 million
      multiyear, senior secured credit facility. This facility limits CIPS, CILCORP,
      CILCO or IP to capital stock dividend payments of $10 million per year each
      if
      CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first
      mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have a
      below investment-grade senior unsecured credit rating as defined in the new
      $500
      million facility. With respect to AERG, which currently is not rated, the
      dividend restriction will not apply if its consolidated total debt to
      consolidated operating cash flow pursuant to a calculation defined in the
      facility is less than or equal to 3.0 to 1. On July 26, 2006, Moody’s downgraded
      CILCORP’s senior unsecured credit rating to below investment-grade causing it to
      be subject to this dividend payment limitation. As of September 30, 2006, AERG
      failed to meet the debt-to-operating cash flow ratio test in the facility and,
      therefore is limited in its ability to pay dividends to a maximum of $10 million
      per fiscal year. The other borrowers are not currently limited in their dividend
      payments by this provision of the new credit facility. See Note 3 - Credit
      Facilities and Liquidity 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 nine months ended September
      30,
      2006 and 2005.


**Nine
                Months****2006**
            
            **2005**UE
            **$**
            **154**
            
            $
            209CIPS
            
            **50**
            
            
            21Genco
            
            **93**
            
            
            59CILCORP(a)
            
            **50**
            
            
            30IP
            
            **-**
            
            
            60Nonregistrants
            
            **44**
            
            
            4Dividends
                paid by Ameren
            **$**
            **391**
            
            $
            383


(a)
            CILCO
                paid dividends of $65 million and $20 million for the nine months
                ended
                September 30, 2006 and 2005,
                respectively.





**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, and Other Obligations in Note 8 -
      Commitments and Contingencies under Part I, Item 1, of this report. 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, obligations related to the procurement of coal and natural
      gas changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $3,986 million,
      $1,419 million, $484 million, $601 million, $624 million, $624 million and
      $615
      million, respectively, as of September 30, 2006. Total other obligations at
      September 30, 2006, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were
      $4,439 million, $1,673 million, $615 million, $601 million, $736 million, $736
      million and $797 million, respectively.


76


**Credit
      Ratings**





S&P





On
      October 5, 2006, S&P, in reaction to the intensified political discussion in
      Illinois regarding electric rate freeze extension legislation, downgraded the
      principal credit ratings of the Ameren Companies as presented in the following
      table:





**From**
            **To****Ameren:**Corporate
                credit rating
            BBB+
            BBBUnsecured
                debt
            BBB
            BBB-Commercial
                paper
            A-2
            A-3**UE:**Corporate
                credit rating
            BBB+
            BBBSecured
                debt
            BBB+
            BBBUnsecured
                debt
            BBB
            BBB-Preferred
                stock
            BBB-
            BB+Commercial
                paper
            A-2
            A-3**Genco:**Corporate
                credit rating
            BBB+
            BBBUnsecured
                debt
            BBB+
            BBB**CIPS:**Corporate
                credit rating
            BBB+
            BBB-Secured
                debt
            A-
            BBBUnsecured
                debt
            BBB
            BB+Preferred
                stock
            BBB-
            BB**CILCORP:**Corporate
                credit rating
            BBB+
            BBB-Unsecured
                debt
            BBB
            BB+**CILCO:**Corporate
                credit rating
            BBB+
            BBB-Secured
                debt
            A-
            BBBPreferred
                stock
            BBB-
            BB**IP:**Corporate
                credit rating
            BBB+
            BBB-Secured
                debt
            BBB+
            BBB-Preferred
                stock
            BBB-
            BB





All
      of
      the S&P credit ratings for the Ameren Companies remain on credit watch with
      negative implications. According to S&P, it will continue to lower the
      Ameren Companies credit ratings if, in its opinion, the likelihood of Illinois
      legislation extending the electric rate freeze increases and if the legislation
      is passed, they will lower ratings on CIPS, CILCO, CILCORP and IP into the
“B”
category - a deep junk credit rating category.





Moody’s





On
      July
      26, 2006, Moody’s downgraded the principal credit ratings of certain of the
      Ameren Companies as presented in the following table:





**From**
            **To****UE:**Secured
                debt
            A1
            A2Issuer
                rating
            A2
            A3Commercial
                paper
            P-1
            P-2**CIPS:**Secured
                debt
            A3
            Baa2Unsecured
                debt and issuer rating
            Baa1
            Baa3**CILCORP:**Unsecured
                debt
            Baa3
            Ba1**CILCO:**Secured
                debt
            A3
            Baa1Issuer
                rating
            Baa1
            Baa2




According
      to Moody’s, the downgrade of CIPS, CILCORP and CILCO was principally because of
      the following factors:





·
            A
                difficult political and regulatory environment in Illinois associated
                with
                the recovery of higher purchased power costs by electric utilities
                commencing January 1, 2007.


·
            Moody’s
                expectation that the outcome in Illinois will involve a material
                regulatory deferral of recovery of higher power procurement
                costs.





Moody’s
      confirmed the credit ratings of Ameren and IP, and Genco was unaffected.
      According to Moody’s, the downgrade of UE was principally because of the
      following factors:





·
            Weaker
                financial metrics due to higher operating costs and large capital
                expenditures for environmental
                compliance.


·
            The
                likelihood that if the operating cash flow for Ameren’s Illinois utilities
                declines, Ameren may need to rely on UE and Ameren’s unregulated
                operations for a larger share of upstreamed dividends to meet parent
                company obligations.





On
      October 10, 2006, Moody’s placed the long-term credit ratings of Ameren, UE,
      CIPS, Genco, CILCORP, CILCO and IP under review for possible downgrade, and
      affirmed the commercial paper ratings of Ameren and UE. Moody’s had removed the
      review for possible downgrade as part of its July 2006 actions. According to
      Moody’s, the review for possible downgrade was reinstituted by concerns that the
      timely recovery of increased utility costs may be impaired by legislative action
      in Illinois, specifically the rate freeze legislation discussed in Note 2 -
      Rate
      and Regulatory Matters to our financial statements under Part I, Item 1, of
      this
      report. Moody’s stated that enactment of the rate freeze legislation in Illinois
      would be expected to result in a multi-notch downgrade of the ratings of CIPS,
      CILCORP, CILCO and IP to speculative (sub-investment) grade, reflecting the
      severe impact such action would have on the utilities’ cash flow and
      liquidity.  Moody's has also indicated that upon rate freeze legislation,
      or similar legislation that restricts the recovery of costs in a timely manner,
      passing the Illinois House of Representatives (even if prior to passage in
      the
      Illinois Senate or enactment into law), it may consider additional credit
      ratings downgrades with regard to one or more of the Ameren
      Companies.





Fitch





On
      October 10, 2006, Fitch placed the credit ratings of Ameren, CIPS, CILCORP,
      CILCO and IP on rating watch negative. The ratings of UE and Genco were affirmed
      and not affected by these rating actions. The negative rating watch resulted
      from the heightened political rhetoric surrounding




77




future
      utility rates in Illinois and uncertainty related to recovery of CIPS’,
      CILCORP’s, CILCO’s and IP’s purchased power costs. 
 Any
        adverse change in the Ameren Companies’ credit ratings may reduce access to
        capital. It may also increase the cost
        of
        borrowing and fuel, power and gas supply, among other things, resulting in
        a
        negative impact on earnings. For example, if at September 30, 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 or prepay for certain trade obligations amounting to $234 million,
        $21 million, $24 million, $10 million, $43 million, $43 million, or $123
        million, respectively. In addition, the cost of borrowing under our credit
        facilities can increase or decrease depending upon the credit ratings of
        the
        borrower and suppliers may request prepayment for products and services.
        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.  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 appeals. The power procurement auction
                was
                held at the beginning of September 2006. On September 14, 2006, the
                ICC
                determined that it would not investigate the results of the auction
                to
                procure power for fixed-price customers, which include the vast majority
                of electric customers of CIPS, CILCO and IP. On September 15, 2006,
                the
                independent auction manager (NERA Economic Consulting) declared a
                successful result in the auction for fixed-price customers. The auction
                clearing price was approximately $65 per megawatthour for the fixed-price
                residential and small commercial product and approximately $85 per
                megawatthour for large commercial and industrial customers. Marketing
                Company participated in the auction with power being acquired
                from Genco and AERG, subject to an auction rules limitation of
                providing no more than 35% of a utility’s load, and was awarded sales in
                the auction. As a result of the large commercial and industrial customers’
                auction price, it is expected that nearly all of these customers
                will
                choose a different supplier.


·
            Power
                supplied by Genco and AERG to CIPS and CILCO, respectively, has been
                subject to below-market-priced contracts. 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 2006. In 2005, Genco sold 3.3 million net megawatthours of power
                in the
                interchange market at an average market price of $47 per megawatthour.
                Genco currently expects to generate approximately 17.5 million
                megawatthours of power in 2007. By 2007, only 5.2 million megawatthours
                of
                Genco’s power will be covered by wholesale and retail electric power
                supply agreements that were in effect in 2005. These agreements have
                an
                average embedded selling price of $36 per megawatthour. All other
                power
                supply agreements in effect in 2005 will expire by the end of 2006
                and any
                available generation in 2007 will be sold at prevailing market prices.
                AERG currently expects to generate approximately 7.0 million megawatthours
                of power in 2007. In 2005, this power was sold principally to CILCO
                at an
                average price of $32 per megawatthour. In addition, AERG sold 1 million
                net megawatthours of power in the interchange market at an average
                price
                of $38 per megawatthour in 2005. In 2007, all of AERG’s power will be sold
                at prevailing market prices. Market prices on power supply contracts
                entered into by Marketing Company with power being acquired from
                Genco and
                AERG for sales for 2007 and beyond may vary from the Illinois auction
                price based on the contract type, when the contracts were entered
                into,
                and load shape of customers served under those contracts, among other
                things.


·
            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 $202 million in the aggregate (CIPS - $14 million,
                CILCO - $43 million and IP - $145 million). Since most customers
                are
                currently taking service under a frozen bundled electric rate,
                which includes the cost of power, any delivery service revenue change
                may
                not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or
                earnings when all customers transition to an electric delivery service
                rate effective January 2, 2007. 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 June 2006, the ICC staff filed rebuttal testimony recommending
                increases in revenues for  78


electric delivery services for the Ameren Illinois
                utilities aggregating $120 million (CIPS - $1 million, CILCO - $30
                million
                and IP - $89 million). In testimony, the Illinois attorney general
                accepted certain of the Ameren Illinois utilities’ positions increasing
                its estimated aggregate recommended revenue increase from $70 million
                to approximately $110 million (CIPS - $3 million decrease, CILCO
                - $29 million increase and IP - $84 million increase). Other parties
                also
                made recommendations in the cases. In October 2006, the administrative
                law
                judges issued a proposed order, which included a recommended revenue
                increase for electric delivery service of $147 million in the aggregate(CIPS - $8 million, CILCO - $29 million and
                IP - $110
                million). The ICC has until November 25, 2006, to render a decision
                in
                these cases. ·
            Ameren
                expects the average residential electric rates for CIPS, CILCO and
                IP to
                increase significantly following the expiration of a rate freeze
                at the
                end of 2006. Electric rates are expected to rise as a result of increased
                cost of power to be purchased on behalf of Ameren Illinois utilities’
                customers based on the results of the Illinois power procurement
                auction
                held in early September 2006 and potential increases resulting from
                delivery service cases that are currently pending before the ICC.
                CIPS and
                IP residential rates are expected to increase approximately 40 percent
                over present rates, and CILCO residential rates are expected to increase
                approximately 55 percent over present rates. The amount of the actual
                increase will depend on outcomes for CIPS’, CILCO’s and IP’s pending
                electric delivery services revenue increase requests to the ICC,
                among
                other things.


·
            Due
                to the magnitude of these increases, certain Illinois legislators,
                the
                Illinois attorney general, the Illinois governor and other parties
                sought
                to block the power procurement auction and continue to challenge
                the
                auction and/or the recovery of costs for power supply resulting from
                the
                auction through rates to customers. CIPS, CILCO and IP have received
                favorable rulings from the ICC and the Circuit Court of Cook County,
                Illinois on opposition claims filed by the Illinois attorney general,
                CUB
                and ELPC.


·
            On
                October 2, 2006, Speaker of the Illinois House of Representatives,
                Michael
                Madigan, sent a letter to Illinois Governor Rod Blagojevich asking
                the
                Illinois governor to call a special session of the Illinois General
                Assembly for the purpose of considering this rate freeze legislation.
                In
                response, the Illinois governor sent a letter indicating that once
                the
                votes to pass the legislation were in place he would immediately
                call for
                a special session of the legislature. The governor’s letter further
                provided that in the event a consensus among members of the General
                Assembly is not reached in the near future, he would call a special
                session in that event as well. The governor’s letter stated he continued
                to support legislation extending a rate freeze and would like to
                sign it
                into law as soon as possible. On October 9, 2006, the Electric Utility
                Oversight Committee of the Illinois House of Representatives voted
                in
                favor of extending the electric rate freeze through 2010. The measure
                will
                need to be approved by the full Illinois House of Representatives
                and
                Illinois Senate and signed by the Illinois governor before it can
                become
                law.


·
            CIPS,
                CILCO and IP believe the proposed electric rate freeze extension
                would
                have a material adverse effect on the results of operations, financial
                position and liquidity, including the financial insolvency of CIPS,
                CILCORP, CILCO and IP, significant job losses and, without governmental
                intervention, significant disruptions in electric and gas service.
                Since
                Ameren’s Illinois utilities own almost no generation, the companies must
                purchase power from the competitive market to provide customers’ energy
                needs. If the rate freeze were extended, the Ameren Illinois utilities
                estimate they would spend in the aggregate approximately $1 billion
                annually more for power than they could charge their customers (CIPS
                -
                $415 million, CILCO - $175 million, IP - $410 million). It is likely
                that
                the Ameren Illinois utilities’ credit ratings would be downgraded to deep
                junk status if rate freeze legislation was enacted. Moody's has also
                indicated that upon rate freeze legislation, or similar legislation
                that
                restricts the recovery of costs in a timely manner, passing the Illinois
                House of Representatives (even if prior to passage in the Illinois
                Senate
                or enactment into law), it may consider additional credit ratings
                downgrades with regard to one or more of the Ameren
                Companies.


·
            With
                such credit ratings, CIPS, CILCORP, CILCO and IP would be faced with
                potential collateral and prepayment requirements and would quickly
                run out
                of cash and available credit and be unable to borrow. We believe
                this
                would lead to the Ameren Illinois utilities being financially insolvent
                by
                February 2007, or sooner. Any decision or action that impairs the
                ability
                of CIPS, CILCO, and IP to fully recover costs from their electric
                customers in a timely manner would result in material adverse consequences
                for Ameren, CIPS, CILCORP, CILCO, and IP. CIPS, CILCORP, CILCO and
                IP
                expect to take whatever actions are necessary to protect their financial
                interests, including seeking the protection of the bankruptcy
                courts.


·
            CIPS,
                CILCORP, 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 and small to mid-size commercial customers
                to address the significant increases in customer rates for the Ameren
                Illinois utilities beginning in 2007. The Ameren Illinois utilities
                believe that a rate increase phase-in plan would need to allow for
                deferral of a portion of the power procurement






79




costs, with provision for full and timely recovery
              of all
              deferred costs in a manner that supports investment-grade credit ratings
              for CIPS, CILCO and IP. CIPS, CILCO and IP filed two proposed plans
              with
              the ICC to mitigate the impact of expected higher electric rates for
              residential customers. See Note 2 - Rate and Regulatory Matters to
              our
              financial statements under Part I, Item 1, of this report for a further
              discussion of the proposed plans. ·
            In
                July 2006, UE filed requests with the MoPSC for an increase in electric
                rates of $361 million and in natural gas delivery rates of $11 million.
                The MoPSC staff and other stakeholders will review UE’s rate adjustment
                requests and, after their analyses, may also make recommendations
                as to
                rate adjustments. Generally, a proceeding to change rates in Missouri
                could take up to 11 months. See Note 2 - Rate and Regulatory Matters
                to
                our financial statements under Part I, Item 1, of this
                report.


·
            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. These companies expect to hedge
                85%
                to 90% of estimated available 2007 generation by the end of
                2006.


·
            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 88% of the
                coal
                used by these plants (UE - 96%, Genco - 67%, CILCO - 77%) was
                delivered by railroads from the Powder River Basin in Wyoming. In
                2005,
                deliveries from the Powder River Basin were restricted due to derailments,
                and while coal inventories are currently adequate, deliveries are
                still
                below desired levels because of railroad capacity limitations. 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 andapproximately
                20% in 2007. Ameren’s nuclear fuel costs are expected to rise over the
                next few years. In 2007, nuclear fuel costs are expected to increase
                by
                13% to 18%. 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 of this
                report
                for information about the percentage of fuel and transportation
                requirements that are price-hedged for 2006 through
                2010.


·
            In
                Illinois, we will also experience higher year-over-year purchased
                power
                expenses as the amortization of certain favorable purchase accounting
                adjustments associated with the IP acquisition is
                completed.


·
            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
                cost
                recovery mechanism, and prudency reviews, among other things. Rules
                for
                the fuel and purchased power cost recovery mechanism were approved
                by the
                MoPSC on September 21, 2006, and are expected to be effective by
                the end
                of the year. We are unable to predict when rules implementing the
                environmental cost recovery mechanism will be formally proposed and
                adopted. UE requested fuel, purchased power and environmental cost
                recovery mechanisms in its electric rate case filed with the MoPSC
                in July
                2006. UE’s requests are subject to approval by the
                MoPSC.


·
            In
                the fourth quarter of 2006, Ameren expects to continue selling excess
                emission allowances, but in 2007, Ameren expects to reduce levels
                of
                emission allowance sales in order to retain remaining allowances
                for
                future compliance needs.





***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 facility
                will
                remain out of service until reviews by state authorities are concluded,
                further analyses are completed, and input  80


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 at least all of 2008,
              if not
              longer.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, including rebuilding the plant, will be covered by insurance.
              UE expects the total cost for damage and liabilities, excluding costs
              to
              rebuild the facility, resulting from the Taum Sauk incident to range
              from
              $70 million to $90 million. As of September 30, 2006, UE had
              paid $38 million and accrued a $32 million liability, while expensing
              $18
              million, and recording a $40 million receivable due from insurance
              companies. As of September 30, 2006, UE has received $12 million 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 authorities. Until
              the reviews conducted by state 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 recognized. ·
            UE’s
                Callaway nuclear plant’s next scheduled refueling and maintenance outage
                is in 2007 and is expected to last 30 to 35 days. 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, among other
                things.


·
            Bad
                debts may increase due to rising electric
                rates.


·
            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 $2.7 billion and $3.4
                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
                50%
                of this investment will be in Ameren’s regulated UE operations, and
                therefore it is expected to be recoverable 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.


·
            UE
                continues to evaluate its longer-term needs for new baseload and
                peaking
                electric generation capacity. At this time, UE does not expect to
                require
                new baseload generation capacity until at least 2018. However, due
                to the
                significant time required to plan, acquire permits for and build
                a
                baseload power plant, UE is actively studying future plant alternatives,
                including those utilizing coal or nuclear
                power.





***Affiliate
      Transactions***





·
            Due
                to a MoPSC order issued in conjunction with the transfer of UE’s Illinois
                service territory to CIPS, UE, CIPS, and Genco amended the JDA effective
                in January 2006. If such an amendment had been in effect in 2005,
                we
                believe it 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. In July 2006, UE, CIPS and Genco mutually consented
                to
                waive the one-year termination notice requirement and agreed to terminate
                the JDA on December 31, 2006. As a result of the termination of the
                JDA,
                UE and Genco will no longer have the obligation to provide power
                to each
                other. UE will retain the power it was transferring under the JDA
                to Genco
                at incremental cost and be able to sell any excess power it has at
                market
                prices, which will most likely be higher. Genco will no longer receive
                the
                margins on sales that it made, which were supplied with power from
                UE.
                Ameren’s and UE’s earnings will be affected by the termination of the JDA
                when UE’s rates are adjusted by the MoPSC. UE’s requested electric rate
                increase filed in July 2006 is net of the decrease in its revenue
                requirement resulting from increased margins expected to result from
                the
                termination of the JDA. See Note 2 - Rate and 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
                JDA
                ordered by the MoPSC and the effects of terminating the
                JDA.


·
            On
                December 31, 2005, a power supply agreement with EEI for UE, CIPS
                (which
                resold its entitlement to Marketing Company) and IP expired. Power
                supplied under the agreement by EEI to UE, Marketing Company and
                IP was
                priced at EEI’s cost-based rates. Power previously supplied under this
                agreement to UE,  81
 Marketing
              Company and IP is being sold at market prices in 2006, which are above
              EEI’s cost-based rates and will continue to be sold at market prices in
              2007. However, in 2006, UE, Genco (which supplies Marketing Company)
              and
              IP are replacing power previously received from EEI either through
              the use
              of their own higher-cost generation or higher-cost power purchases.
              In
              2005, EEI generated 7.9 million megawatthours of power. UE, CIPS (which
              resold the power to Marketing Company) and IP purchased 3.0 million,
              2.0
              million and 1.2 million megawatthours, respectively, from EEI at an
              average price of $20 per megawatthour. The remaining generation was
              sold
              to EEI’s minority owner. The expiration of this agreement and the
              resulting decrease in UE’s margins and increase in its revenue requirement
              were reflected in UE’s July 2006 request to the MoPSC to increase electric
              rates.





***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***





·
            Ameren
                expects to complete the sale of some leveraged lease investments
                in
                2006.


·
            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.
      A
      derivative is a contract whose value is dependent on, or derived from, the
      value
      of some underlying asset. 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 September 30, 2006:





**Interest
                Expense**
            
            **Net
                Income****(a)**Ameren
            $
            13
            
            $
            (8
            )UE
            
            6
            
            
            (4
            )CIPS
            
            (b
            )
            
            (b
            )Genco
            
            2
            
            
            (1
            )CILCORP
            
            3
            
            
            (2
            )CILCO
            
            1
            
            
            (1
            )IP
            
            4
            
            
            (3
            )


(a)
            Calculations
                are based on an effective tax rate of 38%.


(b)
            Less
                than $1 million.







82




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 September 30, 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, AERG, IP and Marketing Company
      may have credit exposure associated with interchange purchase and sale activity
      with nonaffiliated companies. At September 30, 2006, UE’s, Genco’s, AERG’s, IP’s
      and Marketing Company’s combined credit exposure to non-investment-grade
      counterparties related to interchange purchases and sales was less than $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 $35 million at September 30, 2006.





**Equity
      Price Risk**





Our
      costs
      of providing defined benefit retirement and postretirement 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 would 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 nonregulated 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 has an agreement to sell 100% of its
      capacity and energy to Marketing Company through December 31, 2015. EEI plans
      to
      hedge for price risk up to 80% of its available megawatthours. Genco and AERG
      participated 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 their past
      practice. By December 31, 2006, Genco and AERG will seek to hedge for price
      risk
      85% to 90% of estimated available megawatthours for 2007 by December 31, 2006.
      We also attempt to mitigate financial risks through structured risk management
      programs and policies, which include structured forward-hedging programs and
      the
      use of derivative financial instruments (primarily forward contracts, futures
      contracts, option contracts, and financial swap contracts).





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 the Ameren Illinois utilities’ proposed power procurement auction
      and the related tariffs for the period commencing January 2, 2007, including
      the
      retail rates by which power supply costs would be passed through to customers.
      The power procurement auction was held at the beginning of September 2006.
      Marketing Company was awarded sales in the auction. UE’s electric rate freeze in
      Missouri expired June 30, 2006. In July 2006, UE filed for an increase in
      electric rates, including a request for a fuel, purchased power and
      environmental cost recovery mechanism. UE 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.





83




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**
            **%**
            
            100
            %
            
            65
            %Coal
                transportation
            
            **100**
            
            
            95
            
            
            60Nuclear
                fuel
            
            **100**
            
            
            100
            
            
            70Natural
                gas for generation
            
            **100**
            
            
            26
            
            
            2Natural
                gas for distribution(a)
            
            **(a**
            **)**
            
            46
            
            
            10**UE:**Coal
            
            **100**
            **%**
            
            100
            %
            
            61
            %Coal
                transportation
            
            **100**
            
            
            99
            
            
            79Nuclear
                fuel
            
            **100**
            
            
            100
            
            
            70Natural
                gas for generation
            
            **100**
            
            
            6
            
            
            1Natural
                gas for distribution(a)
            
            **(a**
            **)**
            
            52
            
            
            9**CIPS:**Natural
                gas for distribution(a)
            
            **(a**
            **)**
            
            56
            %
            
            19
            %Purchased
                power(b)
            
            **100**
            
            
            100
            
            
            47**Genco:**Coal
            
            **100**
            **%**
            
            100
            %
            
            76
            %Coal
                transportation
            
            **100**
            
            
            95
            
            
            40Natural
                gas for generation
            
            **100**
            
            
            47
            
            
            5**CILCORP/CILCO:**Coal
            
            **100**
            **%**
            
            100
            %
            
            63
            %Coal
                transportation
            
            **100**
            
            
            69
            
            
            44Natural
                gas for distribution(a)
            
            **(a**
            **)**
            
            44
            
            
            9Purchased
                power(b)
            
            **100**
            
            
            100
            
            
            47**IP:**Natural
                gas for distribution(a)
            
            **(a**
            **)**
            
            43
            %
            
            8
            %Purchased
                power(b)
            
            **90**
            
            
            100
            
            
            47


(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 for this report.
                The
                year 2007 represents November 2006 through March 2007. This continues
                each
                successive year through March 2010.


(b)
            Represents
                the percentage of purchased power price-hedged for fixed-price residential
                and small commercial customers with less than 1 megawatt of demand
                as part
                of the Illinois power procurement auction held in early September
                2006. Excluded from the percent hedged amount is purchased power for
                fixed-price large commercial and industrial customers with 1 megawatt
                of
                demand or higher who have 30 to 50 days after the date the auction
                was
                declared successful (September 15, 2006) to elect not to receive
                power
                from CIPS, CILCO or IP. However, regardless of whether customers
                choose a third-party supplier, the purchased power needed to serve
                this
                load is 100% price-hedged through May 31, 2008 due to the Illinois
                auction. Also excluded from the percent hedged amount is purchased
                power to serve large service real-time pricing customers as the auction
                results have not been finalized for this customer class. See Note 2 -
                Rate and Regulatory Matters and Note 8 - Commitments and Contingencies
                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
            
            $
            6
            
            $
            (4
            )
            $
            11
            
            $
            (7
            )UE
            
            
            4
            
            
            (2
            )
            
            3
            
            
            (2
            )Genco
            
            
            1
            
            
            (1
            )
            
            4
            
            
            (3
            )CILCORP/CILCO
            
            
            1
            
            
            (b
            )
            
            2
            
            
            (1
            )


(a)
            Calculations
                are based on an effective tax rate of
                38%.


(b)
            Less
                than $1 million.





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 regarding the long-term commitments
      for the procurement of coal, natural gas and nuclear fuel.




84




**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 three months and nine months
      ended September 30, 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 five
      years.





**Ameren****(a)**
            
            **UE**
            
            **CIPS**
            
            **Genco**
            
            **CILCORP/**
              **CILCO**
            
            **IP****Three
                Months**Fair
                value of contracts at beginning of period, net
            
            $
            43
            
            $
            (2
            )
            $
            4
            
            $
            1
            
            $
            18
            
            $
            2Contracts
                realized or otherwise settled during the period
            
            
            (14
            )
            
            (1
            )
            
            (1
            )
            
            (1
            )
            
            (6
            )
            
            -Changes
                in fair values attributable to changes in valuation technique and
                assumptions
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Fair
                value of new contracts entered into during the period
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Other
                changes in fair value
            
            
            34
            
            
            8
            
            
            (1
            )
            
            2
            
            
            (3
            )
            
            2Fair
                value of contracts outstanding at end of period, net
            
            $
            63
            
            $
            5
            
            $
            2
            
            $
            2
            
            $
            9
            
            $
            4**Nine
                Months**Fair
                value of contracts at beginning of period, net
            
            $
            69
            
            $
            (5
            )
            $
            12
            
            $
            -
            
            $
            50
            
            $
            (2
            )Contracts
                realized or otherwise settled during the period
            
            
            (40
            )
            
            (5
            )
            
            (6
            )
            
            -
            
            
            (15
            )
            
            (2
            )Changes
                in fair values attributable to changes in valuation technique and
                assumptions
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Fair
                value of new contracts entered into during the period
            
            
            1
            
            
            1
            
            
            -
            
            
            -
            
            
            -
            
            
            -Other
                changes in fair value
            
            
            33
            
            
            14
            
            
            (4
            )
            
            2
            
            
            (26
            )
            
            8Fair
                value of contracts outstanding at end of period, net
            
            $
            63
            
            $
            5
            
            $
            2
            
            $
            2
            
            $
            9
            
            $
            4


(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
      September 30, 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 sub-stantial 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.




85




**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.





**The
      electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are
      currently the subject of rate case proceedings and potential legislative action.
      The outcome of these proceedings and potential legislative action is largely
      outside of our control. Should these events result in the inability of UE,
      CIPS,
      CILCO or IP to recover their respective costs, it could have a material adverse
      effect on our future results of operations, financial position or liquidity.
      In
      particular, we believe a proposed electric rate freeze extension in Illinois
      would lead to CIPS, CILCORP, CILCO and IP being financially insolvent by
      February 2007, or sooner.**





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 effect on our results of operations, financial position
      or liquidity.





Increased
      costs and investments, when combined with rate reductions and moratoriums,
      have
      caused decreased returns in Ameren’s utility businesses. Ameren expects many of
      its operating expenses will continue to rise and further expects to continue
      to
      make significant investment in its energy infrastructure, which are the
      principal factors underlying its pending rate increase requests with the MoPSC
      and the ICC. We cannot predict the outcome of these rate case proceedings or
      potential Illinois legislative action to extend the rate freeze. In addition,
      in
      response to competitive, economic, political, legislative and regulatory
      pressures, in connection with the resolution of our current rate case
      proceedings, or otherwise, 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 material adverse effect on our results of
      operations, financial position or liquidity.




**Illinois**





*Electric
      Delivery Rate Cases*





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. 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 $202 million in the aggregate
      (CIPS - $14 million, CILCO - $43 million and IP - $145 million). Since most
      customers are currently taking service under a frozen bundled electric
      rate, which includes the cost of power, any delivery service revenue change
      may
      not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or
      earnings when all customers transition to an electric delivery service rate
      effective January 2, 2007. 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 June 2006, the ICC staff
      filed rebuttal testimony recommending increases in revenues for electric
      delivery services for the Ameren Illinois utilities aggregating $120 million
      (CIPS - $1 million, CILCO - $30 million and IP - $89 million). In testimony,
      the
      Illinois attorney general recommended an aggregate revenue increase of
      approximately $110 million (CIPS - $3 million decrease, CILCO - $29 million
      increase and IP - $84 million increase). Other parties also made recommendations
      in the cases. In October 2006, the administrative law judges issued a proposed
      order, which included a recommended revenue increase for electric delivery
      service of $147 million in the aggregate (CIPS - $8 million, CILCO - $29 million
      and IP - $110 million). The ICC has until November 25, 2006, to render a
      decision in these cases. Without appropriate and timely rate relief, any new
      energy infrastructure investment could result in increased financing
      requirements for CIPS, CILCO and IP. The lack of full and timely recovery of
      these costs could have a material adverse effect on CIPS’, CILCORP’s, CILCO’s
      and IP’s results of operations, financial position or liquidity.





*Potential
      Extension of Illinois Electric Rate Freeze and Recovery of Post-2006 Power
      Supply Costs*





Consistent
      with the Illinois Customer Choice Law that froze electric rates for CIPS, CILCO
      and IP through January 1, 2007, these companies entered into power supply
      contracts that expire on December 31, 2006. In January 2006, the ICC approved
      a
      framework for CIPS, CILCO and IP to procure power for use by their customers




86




through
      a
      power procurement auction and the related tariffs to collect these costs from
      customers for the period commencing January 2, 2007. This approval is subject
      to
      pending court appeals. In accordance with the January 2006 ICC order, a power
      procurement auction was held in September 2006. Subsequently, the ICC determined
      that it would not investigate the results of the auction to procure power for
      fixed-price customers, and the independent auction manager declared a successful
      result in the auction for these fixed-price customers, which include the vast
      majority of electric customers of CIPS, CILCO and IP. Certain Illinois
      legislators, the Illinois attorney general, the Illinois governor, and other
      parties sought to block the power procurement auction and continue to challenge
      the auction and/or the recovery of costs for power supply resulting from the
      auction through rates to customers. In February 2006, legislation was introduced
      in the Illinois House of Representatives that would extend the electric rate
      freeze in Illinois through 2010. On October 2, 2006, Speaker of the
      Illinois House of Representatives, Michael Madigan, sent a letter to Illinois
      Governor Rod Blagojevich asking the Illinois governor to call a special session
      of the Illinois General Assembly for the purpose of considering this rate freeze
      legislation. In response, the Illinois governor sent a letter indicating that
      once the votes to pass the legislation were in place he would immediately call
      for a special session of the legislature. The governor’s letter further provided
      that in the event a consensus among members of the General Assembly is not
      reached in the near future, he would call a special session in that event as
      well. The governor’s letter stated he continued to support legislation extending
      the rate freeze and would like to sign it into law as soon as possible. On
      October 9, 2006, the Electric Utility Oversight Committee of the Illinois House
      of Representatives voted in favor of extending the electric rate freeze through
      2010. The measure will need to be approved by the full Illinois House of
      Representatives and Illinois Senate, and signed by the Illinois governor before
      it can become law.





CIPS,
      CILCORP, CILCO and IP believe the proposed electric rate freeze legislation,
      if
      enacted, would have a material adverse effect on their results of operations,
      financial position and liquidity, including the financial insolvency of CIPS,
      CILCORP, CILCO and IP, as well as result in significant job losses and, without
      governmental intervention, significant disruptions in electric and gas service.
      Since Ameren’s Illinois utilities own almost no generation, the companies must
      purchase power from the competitive market to provide customers’ energy needs.
      If the rate freeze were extended, the Ameren Illinois utilities estimate they
      would spend in the aggregate approximately $1 billion annually more for power
      than they could charge their customers (CIPS - $415 million, CILCO - $175
      million, IP - $410 million). The major credit rating agencies have stated that
      the Ameren Illinois utilities’ and CILCORP’s credit ratings would be downgraded
      to deep junk status if rate freeze extension legislation is enacted. Moody's
      has
      also indicated that upon rate freeze legislation, or similar legislation that
      restricts the recovery of costs in a timely manner, passing the Illinois House
      of Representatives (even if prior to passage in the Illinois Senate or enactment
      into law), it may consider additional credit ratings downgrades with regard
      to
      one or more of the Ameren Companies.With such credit ratings, we believe CIPS,
      CILCORP, CILCO and IP would be faced with potential collateral and prepayment
      requirements for products and services, such as power and natural gas, and
      would
      quickly run out of cash and available credit and be unable to borrow. We believe
      this would lead to the Ameren Illinois utilities and CILCORP being financially
      insolvent by February 2007, or sooner. In reaction to intensified political
      discussion in Illinois regarding electric rate freeze extension legislation,
      in
      October 2006, S&P downgraded the short- and long-term credit ratings of the
      Ameren Companies and kept the Ameren Companies on credit watch with negative
      implications; Moody’s placed the long-term debt ratings of the Ameren Companies
      under review for possible downgrade; and Fitch placed the ratings of Ameren,
      CIPS, CILCORP, CILCO and IP on rating watch negative.





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 significant increases in customer rates for the Ameren
      Illinois utilities beginning in 2007. The Ameren Illinois utilities 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 supports investment-grade credit ratings for
      CIPS, CILCO and IP. However, even a rate phase-in plan that does not allow
      for
      the full and timely recovery of our costs could have a material adverse effect
      on CIPS’, CILCORP’s, CILCO’s and IP’s results of operations, financial position
      or liquidity.





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.
      CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to
      protect their legal and financial interests, including seeking the protection
      of
      the bankruptcy courts. However, there can be no assurance that Ameren and the
      Ameren Illinois utilities will prevail over the stated opposition of certain
      Illinois legislators, the Illinois attorney general, the Illinois governor,
      and
      other stakeholders, or that the legal and regulatory actions, strategies and


87




alternatives
      that Ameren and the Ameren Illinois
      utilities are considering will be successful. 
 We
        are
        unable to predict the results of the court appeals of the ICC order approving
        CIPS’, CILCO’s and IP’s power procurement auction and the related tariffs, nor
        can we predict the actions the Illinois General Assembly and governor may
        take
        which may impact electric rates or the
        power
        procurement process for CIPS, CILCO and IP after the expiration of the current
        Illinois electric rate freeze on January 1, 2007, and power supply contracts
        on
        December 31, 2006. Any decision or action that impairs the ability of CIPS,
        CILCO and IP to fully recover purchased power costs from their electric
        customers in a timely manner would result in material adverse consequences
        to
        Ameren, CIPS, CILCORP, CILCO and IP. These consequences could include a
        significant drop in credit ratings to deep junk status, a loss of access
        to the
        capital markets, higher borrowing costs, higher power supply costs, an inability
        to make timely energy infrastructure investments, significant risk of disruption
        in electric and gas service, significant job losses, and financial insolvency.
        In addition, Ameren, CILCORP and IP could be required to record a charge
        for
        goodwill impairment related to goodwill that was recorded when Ameren acquired
        these companies. As of September 30, 2006, Ameren, CILCORP and IP had $976
        million, $575 million and $326 million, respectively, of goodwill on their
        balance sheets. Furthermore, if the Ameren Illinois utilities are unable
        to
        recover their costs from customers, the utilities could be required to cease
        applying SFAS No. 71, “Accounting for the Effects of Certain Types of
        Regulation”, which allows CIPS, CILCORP, CILCO and IP to defer certain costs
        pursuant to actions of rate regulators and to recover such costs in rates
        charged to customers. This would result in the elimination of all regulatory
        assets recorded by CIPS, CILCORP, CILCO and IP on their balance sheets and
        a
        one-time extraordinary charge on their statements of income that could be
        material. As of September 30, 2006, CIPS, CILCORP, CILCO and IP had $35 million,
        $12 million, $12 million and $197 million, respectively, recorded as regulatory
        assets on their balance sheets.





**Missouri**





With
      the
      expiration of multi-year electric and gas rate moratoriums, effective July
      1,
      2006, UE filed requests with the MoPSC in July 2006 for an increase in electric
      rates of


$361
      million and for an increase in natural gas delivery rates of $11 million. The
      MoPSC staff and other stakeholders will review UE’s rate adjustment requests
      and, after their analyses, may also make recommendations as to electric and
      gas
      rate adjustments. A decision from the MoPSC is expected no later than June
      2007.





UE
      does
      not currently have a rate adjustment clause in Missouri for its electric
      operations that would allow it to recover the costs for purchased power,
      increased fuel or infrastructure investment costs from customers. Therefore,
      insofar as UE has not hedged its fuel and power costs, UE is exposed to changes
      in fuel and power prices to the extent they exceed the costs embedded in current
      rates. In its Missouri electric rate case filed in July 2006, UE requested
      a
      fuel and purchased power cost recovery mechanism, which is still subject to
      MoPSC approval. UE also requested an environmental cost recovery mechanism
      as
      part of its current Missouri electric rate case, but rules have not been
      established for such a mechanism. Without appropriate and timely rate relief,
      any new energy infrastructure investment could result in increased financing
      requirements for UE. The lack of timely recovery of these costs could have
      a
      material adverse effect on UE’s results of operations, financial position or
      liquidity.





**If
      the Illinois electric rate freeze is extended or the ability of CIPS, CILCO
      and
      IP to recover post-2006 power supply costs or increase electric delivery service
      rates that are the subject of pending rate cases is otherwise impaired, there
      may be a material adverse effect on Ameren, UE and Genco in addition to the
      Ameren Illinois utilities and CILCORP.**





We
      believe the proposed rate freeze extension in Illinois, if enacted, would lead
      to CIPS, CILCORP, CILCO and IP being financially insolvent by February 2007,
      or
      sooner. Although the Ameren Companies are separate, independent legal entities
      with separate businesses, assets and liabilities, there is a risk that the
      financial insolvency of CIPS, CILCORP, CILCO and IP could have a materially
      adverse effect on Ameren, UE and Genco. In the event of an extension of the
      electric rate freeze in Illinois for CIPS, CILCO and IP, or subsequent financial
      insolvency of these companies, such events might increase Ameren’s, UE’s and
      Genco’s cost of capital or adversely affect the ability of these companies to
      access the capital markets, particularly during times of uncertainty in the
      capital markets, which could negatively affect their ability to maintain and
      expand their businesses. Moody’s, S&P and Fitch have each indicated that
      they would lower the credit ratings for CIPS, CILCORP, CILCO and IP to deep
      junk
      status if the electric rate freeze was extended reflecting the material impact
      such action would have on the cash flow and liquidity of these companies. It
      is
      possible that the rating agencies could decide to lower the credit ratings
      of
      Ameren, UE or Genco at the same time. Any adverse change in the ratings of
      Ameren, UE or Genco could also increase the cost of borrowing under credit
      facilities and suppliers may request prepayment for products and services (such
      as fuel, power and gas) or the posting of collateral.







88




Commitments
        or amounts due from CIPS, CILCORP, CILCO and IP to Ameren, UE, and Genco
        may be
        unfulfilled or unpaid in the event of financial insolvency of these companies.
        In connection with the recent Illinois power procurement auction, Marketing
        Company agreed to sell power to CIPS, CILCO and IP that is expected to be
        supplied under contracts from Genco and AERG. In the event of the insolvency
        of
        CIPS, CILCORP, CILCO and IP, Genco, AERG or Marketing Company may not be
        able to
        recover the cost of power delivered to CIPS, CILCO and IP but
        not
        paid for prior to insolvency. Marketing Company’s commitments to sell power to
        CIPS, CILCO, IP and other unaffiliated parties also rely, in part, on power
        supplied by AERG. In the event of financial insolvency, AERG may not be able
        to
        deliver power it has committed to sell to Marketing Company potentially
        requiring Marketing Company to acquire power to meet its commitments at a
        higher
        cost.





In
      addition, dividends on Ameren’s common stock and the payment of Ameren’s other
      obligations, including its debt, depend on distributions made to it by its
      subsidiaries. In the event that CIPS, CILCORP, CILCO and IP become
      insolvent, they will not be able to make distributions to Ameren. As a result,
      the board of directors of Ameren may decide to rely more heavily on UE and
      Ameren’s unregulated operations to support dividends on Ameren’s common stock,
      or reduce or eliminate the payment of dividends. Moreover, the absence of
      distributions from the Illinois utilities and CILCORP could force Ameren to
      use
      other available sources of liquidity to service its debt
      obligations.





We
      cannot
      determine at this time whether the proposed rate freeze extension in Illinois
      that would lead to CIPS, CILCORP, CILCO and IP being financially insolvent
      by
      February 2007, or sooner, will occur. We also cannot determine what the
      resulting effect would be on Ameren, UE and Genco. However, the financial
      insolvency of CIPS, CILCO and IP could have a material adverse effect on the
      results of operations, financial position or liquidity of Ameren, UE and
      Genco.





**Our
      counterparties may not meet their obligations to us.**





We
      are
      exposed to the risk that counterparties to various arrangements (including
      our
      affiliates) who owe us money, energy, coal or other commodities or services
      will
      not be able to perform their obligations. Should the counterparties to these
      arrangements fail to perform, we might be forced to replace or to sell the
      underlying commitment at then-current market prices. In such event, we might
      incur losses or our results of operations, financial position or liquidity
      could
      otherwise be adversely affected.





In
      connection with the expiration of existing power supply agreements at the end
      of
      2006, the ICC approved a framework for electric utilities in Illinois, including
      CIPS, CILCO and IP, to procure power for use by their customers in 2007 through
      a power procurement auction and related tariffs, including the retail rates
      by
      which power supply costs would be passed through to customers. Commencing in
      2007, Genco and AERG will be selling power previously sold under expiring
      contracts to Marketing Company, which sold power through the Illinois power
      procurement auction to CIPS, CILCO and IP and is selling power through other
      contracts with wholesale and retail customers. If the attempts by certain
      Illinois legislators, the Illinois attorney general, the Illinois governor
      and
      other parties to block the ability of CIPS, CILCO and IP to recover post-2006
      power supply costs are successful, thereby triggering the financial insolvency
      of CIPS, CIILCORP, CILCO, and IP, Genco, AERG and Marketing Company may not
      be
      able to recover payment for power delivered to CIPS, CILCO and IP pursuant
      to
      the Illinois power procurement auction. An inability to recover such payments
      could have a material adverse effect on the results of operations, financial
      position, or liquidity of Ameren, Genco, AERG, and Marketing Company. In the
      event of the subsequent termination of the power supply contracts between
      Marketing Company and CIPS, CILCO and IP, Marketing Company would need to resell
      at then-current market prices the power previously committed to CIPS, CILCO
      and
      IP. We cannot predict whether there would be buyers for Marketing Company’s
      power or what the market prices will be at the time of any such sales.




89





**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**July
                1 - July 31, 2006
            
            1,950
            
            $
            50.84
            
            
            -
            
            
            -August
                1 - August 31, 2006
            
            3,800
            
            
            52.78
            
            
            -
            
            
            -September
                1 - September 30, 2006
            
            -
            
            
            -
            
            
            -
            
            
            -Total
            
            5,750
            
            $
            52.12
            
            
            -
            
            
            -


(a)
            These
                shares of Ameren common stock were purchased 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.





The
      following table presents CILCO’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**July
                1 - July 31, 2006
            
            11,000
            
            $
            100.00
            
            
            -
            
            
            -August
                1 - August 31, 2006
            
            -
            
            
            -
            
            
            -
            
            
            -September
                1 - September 30, 2006
            
            -
            
            
            -
            
            
            -
            
            
            -Total
            
            11,000
            
            $
            100.00
            
            
            -
            
            
            -


(a)
            CILCO
                redeemed these shares of its 5.85% Class A preferred stock to satisfy
                the
                mandatory sinking fund redemption requirement for this series of
                preferred
                stock for 2006. CILCO 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 July 1 to September 30, 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****Instruments
                  Defining Rights of Security Holders***4.1
              CILCO
              Registration
                  Rights Agreement, dated as of June 14, 2006, among CILCO, Citigroup
                  Global
                  Markets, Inc. and Goldman, Sachs & Co., as representatives of the
                  Initial Purchasers (as defined therein) (incorporated by reference
                  to
                  Exhibit 4(d) to CILCO’s Form S-4, File No. 333-137449)*4.2
              IP
              Registration
                  Rights Agreement, dated as of June 14, 2006, among IP, Goldman,
                  Sachs
                  & Co. and Lehman Brothers, Inc., as representatives of the Initial
                  Purchasers (as defined therein) (incorporated by reference to Exhibit
                  4(d)
                  to IP’s Form S-4, File No. 333-137448)**Statement
                  re: Computation of Ratios**12.1
              Ameren
              Ameren’s
                  Statement of Computation of Ratio of Earnings to Fixed Charges12.2
              UE
              UE’s
                  Statement of Computation of Ratio of Earnings to Fixed Charges
                  and
                  Combined Fixed Charges and Preferred Stock Dividend
                  Requirements12.3
              CIPS
              CIPS’
                  Statement of Computation of Ratio of Earnings to Fixed Charges
                  and
                  Combined Fixed Charges and Preferred Stock Dividend
                  Requirements12.4
              Genco
              Genco’s
                  Statement of Computation of Ratio of Earnings to Fixed
                  Charges12.5
              CILCORP
              CILCORP’s
                  Statement of Computation of Ratio of Earnings to Fixed
                  Charges12.6
              CILCO
              CILCO’s
                  Statement of Computation of Ratio of Earnings to Fixed Charges
                  and
                  Combined Fixed Charges and Preferred Stock Dividend
                  Requirements
   90
  **Exhibit
                  Designation**
              **Registrant(s)**
              **Nature
                  of Exhibit**12.7
              IP
              IP’s
                Statement of Computation of Ratio of Earnings to Fixed Charges
                and
                  Combined Fixed Charges and Preferred Stock Dividend
                  Requirements**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





*
        Incorporated by reference herein as indicated.







91


**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)





92





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:
      November 9, 2006






93