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, 2008
 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(888)
      789-2477333-56594
                  Ameren
      Energy Generating Company
                  37-1395586(Illinois
      Corporation)1901
      Chouteau AvenueSt.
      Louis, Missouri 63103(314)
      621-32222-95569
                  CILCORP
      Inc.
                  37-1169387(Illinois
      Corporation)300
      Liberty StreetPeoria,
      Illinois 61602(309)
      677-52711-2732
                  Central
      Illinois Light Company
                  37-0211050(Illinois
      Corporation)300
      Liberty StreetPeoria,
      Illinois 61602(309)
      677-52711-3004
                  Illinois
      Power Company
                  37-0344645(Illinois
      Corporation)370
      South Main StreetDecatur,
      Illinois 62523(217)
      424-6600
  
  Indicate
by check mark whether the registrants: (1) have filed all reports required to be
filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required
to file such reports), and (2) have been subject to such filing
require­ments for the past 90
days.     Yes   (X)
No   (  )
 
 Indicate by check mark whether each
registrant is a large accelerated filer, an accelerated filer, a non-accelerated
filer or a smaller reporting company. See definitions of “accelerated filer,”
“large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Securities Exchange Act of 1934.
 
 Large
      Accelerated Filer
              Accelerated
                Filer
              Non-Accelerated
      Filer
              Smaller
      Reporting
                CompanyAmeren
      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 October 31, 2008, was as
follows:
 
 Ameren
      Corporation
              Common
      stock, $.01 par value per share - 211,452,854Union
      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
                Resources
      Company, LLC (parent company of the
                registrant
      and 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
 PageGLOSSARY
      OF TERMS AND
      ABBREVIATIONS..................................................................................................................................................................................................
                5Forward-looking
      Statements.......................................................................................................................................................................................................................................
                7PART
      I   Financial InformationItem
      1.     Financial Statements
      (Unaudited)Ameren
      CorporationConsolidated
      Statement of
      Income...........................................................................................................................................................................................................
                9Consolidated
      Balance
      Sheet......................................................................................................................................................................................................................
                10Consolidated
      Statement of Cash
      Flows...................................................................................................................................................................................................
                11Union
      Electric CompanyConsolidated
      Statement of
      Income...........................................................................................................................................................................................................
                12Consolidated
      Balance
      Sheet......................................................................................................................................................................................................................
                13Consolidated
      Statement of Cash
      Flows...................................................................................................................................................................................................
                14Central
      Illinois Public Service CompanyStatement
      of
      Income...................................................................................................................................................................................................................................
                15Balance
      Sheet..............................................................................................................................................................................................................................................
                16Statement
      of Cash
      Flows...........................................................................................................................................................................................................................
                17Ameren
      Energy Generating CompanyConsolidated
      Statement of
      Income..........................................................................................................................................................................................................
                18Consolidated
      Balance
      Sheet.....................................................................................................................................................................................................................
                19Consolidated
      Statement of Cash
      Flows..................................................................................................................................................................................................
                20CILCORP
      Inc.Consolidated
      Statement of
      Income..........................................................................................................................................................................................................
                21Consolidated
      Balance
      Sheet.....................................................................................................................................................................................................................
                22Consolidated
      Statement of Cash
      Flows..................................................................................................................................................................................................
                23Central
      Illinois Light CompanyConsolidated
      Statement of
      Income..........................................................................................................................................................................................................
                24Consolidated
      Balance
      Sheet.....................................................................................................................................................................................................................
                25Consolidated
      Statement of Cash
      Flows..................................................................................................................................................................................................
                26Illinois Power CompanyConsolidated
      Statement of
      Income..........................................................................................................................................................................................................
                27Consolidated
      Balance
      Sheet.....................................................................................................................................................................................................................
                28Consolidated
      Statement of Cash
      Flows..................................................................................................................................................................................................
                29Combined
      Notes to Financial
      Statements....................................................................................................................................................................................................
                30Item
      2.    Management’s Discussion and Analysis of Financial
      Condition and Results of
      Operations............................................................................................................
                65Item
      3.    Quantitative and Qualitative Disclosures About Market
      Risk.................................................................................................................................................................
                94Item
      4 andItem
      4T.  Controls and
      Procedures...............................................................................................................................................................................................................................
                99PART
      II Other InformationItem
      1.    Legal
      Proceedings...........................................................................................................................................................................................................................................
                100Item
      1A. Risk
      Factors......................................................................................................................................................................................................................................................
                100Item
      2.    Unregistered Sales of Equity Securities and Use of
      Proceeds.................................................................................................................................................................
                101Item
      6.   
      Exhibits..............................................................................................................................................................................................................................................................
                101Signatures.........................................................................................................................................................................................................................................................................
                104
 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 should be read with
the cautionary statements and important factors included on page 7 of this Form
10-Q under the heading “Forward-looking Statements.” 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.
   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 Resources 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 Illinois
Utilities - CIPS, IP and the rate-regulated electric and gas utility
operations of CILCO.
 Ameren Services-Ameren
Services Company, an Ameren Corporation subsidiary that provides support
services to Ameren and its subsidiaries.
 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 and natural gas transmission and distribution business
and a non-rate-regulated electric generation business through AERG, 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 a non-rate-regulated subsidiary.
 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.
 CO2
- Carbon dioxide.
 COLA -
Combined construction and operating license application.
 Cooling
degree-days - The summation of positive differences between the mean
daily temperature and a 65-degree Fahrenheit base. This statistic is useful for
estimating electricity demand by residential and commercial customers for summer
cooling.
 CT-
Combustion turbine electric generation equipment used primarily for peaking
capacity.
 Development
Company- Ameren Energy Development Company, which was an Ameren Energy
Resources Company subsidiary, and parent of Genco, Marketing Company, AFS, and
Medina Valley. It was eliminated in an internal reorganization in February
2008.
 DOE-
Department of Energy, a U.S. government agency.
 DRPlus-
Ameren Corporation’s dividend reinvestment and direct stock purchase
plan.
 Dynegy-
Dynegy Inc.
 EEI-
Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary that operates
non-rate-regulated electric generation facilities and FERC-regulated
transmission facilities in Illinois. Prior to February 29, 2008, EEI was 40%
owned by UE and 40% owned by Development Company. On February 29, 2008, UE’s 40%
ownership interest and Development Company’s 40% ownership interest were
transferred to Resources Company. The remaining 20% is owned by Kentucky
Utilities Company.
 EPA-
Environmental Protection Agency, a U.S. government agency.
 Equivalent
availability factor - A measure that indicates the percentage of time an
electric power generating unit was available for service during a
period.
 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.
 Form 10-K-The
combined Annual Report on Form 10-K for the year ended December 31, 2007, filed
by the Ameren Companies with the SEC.
 FSP - FASB
staff position. A publication that provides application guidance on FASB
literature.
 FTRs -
Financial transmission rights, financial instruments that entitle the holder to
pay or receive compensation for certain congestion-related transmission charges
between two designated points.
 GAAP-
Generally accepted accounting principles in the United States of
America.
 Genco-
Ameren Energy Generating Company, a Resources 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 Illinois utility
businesses, including the rate-regulated operations of CIPS, CILCO and
IP.
   5
  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 electric
settlement agreement -A comprehensive settlement of issues in Illinois
arising out of the end of ten years of frozen electric rates, as of January 2,
2007. The Illinois electric settlement agreement, which became effective on
August 28, 2007, was designed to avoid new rate rollback and freeze legislation
and legislation that would impose a tax on electric generation in Illinois. The
settlement addresses the issue of future power procurement, and it includes a
comprehensive rate relief and customer assistance program.
 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.
 IP-Illinois
Power Company, an Ameren Corporation subsidiary. IP operates a rate-regulated
electric and natural gas transmission and distribution business in Illinois as
AmerenIP.
 IP LLC -
Illinois Power Securitization Limited Liability Company, which is a
special-purpose Delaware limited-liability company.
 IP SPT -
Illinois Power Special Purpose Trust, which was created as a subsidiary of IP
LLC to issue TFNs as allowed under the Illinois Customer Choice
Law.
 IPA -
Illinois Power Agency, a state government agency that has broad authority to
assist in the procurement of electric power for residential and nonresidential
customers beginning in June 2009.
 Kilowatthour
-A
measure of electricity consumption equivalent to the use of 1,000 watts of power
over a period of one hour.
 Lehman -
Lehman Brothers Holdings, Inc.
 Marketing Company-Ameren
Energy Marketing Company, a Resources Company subsidiary that markets power for
Genco, AERG and EEI.
 Medina
Valley - AmerenEnergyMedina
Valley Cogen L.L.C., a Resources Company subsidiary, which owns a 40-megawatt
gas-fired electric generation plant.
 Megawatthour- One thousand kilowatthours.
 MGP-Manufactured
gas plant.
 MISO-Midwest
Independent Transmission System Operator, Inc.
 MISO Day Two
Energy Market-A
market that uses market-based pricing, incorporating transmission congestion and
line losses, to compensate market participants for power.
 Missouri
Regulated- A financial reporting segment consisting of UE’s
rate-regulated businesses.
 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
maintained for rate-regulated and non-rate-regulated business 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 Missouri
utility businesses, including the rate-regulated operations of UE.
 MW -
Megawatt.
 Native-load
- Wholesale customers and end-use retail customers, whom we are obligated to
serve by statute, franchise, contract, or other regulatory
requirement.
 Non-rate-regulated
Generation- A financial reporting segment consisting of the operations
or activities of Genco, CILCORP holding company, AERG, EEI, Medina Valley and
Marketing Company.
 NOx-Nitrogen
oxide.
 NRC-
Nuclear Regulatory Commission, a U.S. government agency.
 NYMEX-
New York Mercantile Exchange.
 OCI-Other
comprehensive income (loss) as defined by GAAP.
 Off-system
revenues - Revenues from nonnative-load sales.
 PGA-
Purchased Gas Adjustment tariffs, which allow the passing through of the actual
cost of natural gas to utility customers.
 PUHCA 2005
- The Public Utility Holding Company Act of 2005, enacted as part of the Energy
Policy Act of 2005, effective February 8, 2006.
 Regulatory
lag - Adjustments to retail electric and natural gas rates are based on
historic cost levels and rate increase requests can take up to 11 months to be
granted by the MoPSC and the ICC. As a result, revenue increases authorized by
regulators will lag behind changing costs.
 Resources Company- Ameren Energy Resources Company, LLC, an Ameren Corporation subsidiary
that consists of non-rate-regulated operations, including Genco, Marketing
Company, EEI, AFS, and Medina Valley. It is the successor to Ameren Energy
Resources Company, which was eliminated in an internal reorganization in
February 2008.
 RFP -
Request for proposal.
 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.
 SO2-Sulfur
dioxide.
 TFNs -
Transitional Funding Trust Notes issued by IP SPT as allowed under the Illinois
Customer Choice Law. IP designated a portion of cash received from customer
billings to pay the TFNs. The designated funds received by IP were remitted to
IP SPT. The designated funds were restricted for the sole purpose of making
payments of principal and interest on, and paying other fees and expenses
related to, the TFNs. Since the application of FIN 46R, IP does not consolidate
IP SPT. Therefore, the obligation to IP SPT appears on IP’s
   6
  balance
sheet as of December 31, 2007. In September 2008, IP redeemed the remaining
amount of TFNs.
 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 under Risk Factors and 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 as the outcome of the pending UE rate
      proceeding or future legislative actions that seek to limit or reverse
      rate increases;
 ·
              uncertainty
      as to the effect of implementation of the Illinois electric settlement
      agreement on Ameren, the Ameren Illinois Utilities, Genco and AERG,
      including implementation of a new power procurement
    process;
 ·
              changes
      in laws and other governmental actions, including monetary and fiscal
      policies;
 ·
              changes
      in laws or regulations that adversely affect the ability of electric
      distribution companies and other purchasers of wholesale electricity to
      pay their suppliers, including UE and Marketing
  Company;
 ·
              enactment
      of legislation taxing electric generators, in Illinois or
      elsewhere;
 ·
              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 occurred
      when the electric rate freeze and power supply contracts expired in
      Illinois at the end of 2006;
 ·
              the
      effects of participation in the
MISO;
 ·
              the
      cost and availability of fuel such as coal, natural gas, and enriched
      uranium used to produce electricity; the cost and 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, including forward
  prices;
 ·
              business
      and economic conditions, including their impact on interest rates, bad
      debt expense, and demand for our
products;
 ·
              disruptions
      of the capital markets or other events that make the Ameren Companies’
      access to necessary capital, including short-term credit, more difficult
      or costly;
 ·
              our
      assessment of our liquidity;
 ·
              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 the plant’s future operation;
 ·
              recoverability
      through insurance of costs associated with UE’s Taum Sauk pumped-storage
      hydroelectric plant incident;
 ·
              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,
      including those related to greenhouse gases, will be introduced over time,
      which could have a negative financial
effect;
 ·
              labor
      disputes, future wage and employee benefits costs, including changes in
      discount rates and returns on benefit plan
  assets;
 ·
              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.  7
 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 update or revise publicly any
forward-looking statements to reflect new information or future
events.
  
 8
 
 PART
I.  FINANCIAL INFORMATION
 
 ITEM
1.  FINANCIAL STATEMENTS.




AMEREN
      CORPORATIONCONSOLIDATED
      STATEMENT OF INCOME(Unaudited)
      (In millions, except per share amounts)Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      Revenues:Electric
            $
            1,928
            
            
            $
            1,872
            
            
            $
            4,944
            
            
            $
            4,855Gas
            
            132
            
            
            
            125
            
            
            
            987
            
            
            
            895Total
      operating revenues
            
            2,060
            
            
            
            1,997
            
            
            
            5,931
            
            
            
            5,750Operating
      Expenses:Fuel
            
            461
            
            
            
            338
            
            
            
            963
            
            
            
            864Coal
      contract settlement
            
            -
            
            
            
            -
            
            
            
            (60
            )
            
            
            -Purchased
      power
            
            371
            
            
            
            419
            
            
            
            964
            
            
            
            1,106Gas
      purchased for resale
            
            73
            
            
            
            68
            
            
            
            697
            
            
            
            622Other
      operations and maintenance
            
            449
            
            
            
            417
            
            
            
            1,340
            
            
            
            1,230Depreciation
      and amortization
            
            180
            
            
            
            176
            
            
            
            534
            
            
            
            534Taxes
      other than income taxes
            
            98
            
            
            
            97
            
            
            
            300
            
            
            
            295Total
      operating expenses
            
            1,632
            
            
            
            1,515
            
            
            
            4,738
            
            
            
            4,651Operating
      Income
            
            428
            
            
            
            482
            
            
            
            1,193
            
            
            
            1,099Other
      Income and Expenses:Miscellaneous
      income
            
            23
            
            
            
            20
            
            
            
            61
            
            
            
            53Miscellaneous
      expense
            
            (10
            )
            
            
            (9
            )
            
            
            (23
            )
            
            
            (19
            )Total
      other income
            
            13
            
            
            
            11
            
            
            
            38
            
            
            
            34Interest
      Charges
            
            113
            
            
            
            110
            
            
            
            331
            
            
            
            316Income
      Before Income Taxes, Minority Interestand
      Preferred Dividends of Subsidiaries
            
            328
            
            
            
            383
            
            
            
            900
            
            
            
            817Income
      Taxes
            
            113
            
            
            
            130
            
            
            
            319
            
            
            
            279Income
      Before Minority Interest and PreferredDividends
      of Subsidiaries
            
            215
            
            
            
            253
            
            
            
            581
            
            
            
            538Minority
      Interest and Preferred Dividends of Subsidiaries
            
            11
            
            
            
            9
            
            
            
            33
            
            
            
            28Net
      Income
            $
            204
            
            
            $
            244
            
            
            $
            548
            
            
            $
            510Earnings
      per Common Share – Basic and Diluted
            $
            0.97
            
            
            $
            1.18
            
            
            $
            2.61
            
            
            $
            2.46Dividends
      per Common Share
            $
            0.635
            
            
            $
            0.635
            
            
            $
            1.905
            
            
            $
            1.905Average
      Common Shares Outstanding
            
            210.3
            
            
            
            207.6
            
            
            
            209.5
            
            
            
            207.1




The
accompanying notes are an integral part of these consolidated financial
statements.
 9





AMEREN
      CORPORATIONCONSOLIDATED
      BALANCE SHEET(Unaudited)
      (In millions, except per share amounts)September
      30,
            
            
            December
      31,2008
            
            
            2007ASSETSCurrent
      Assets:Cash
      and cash equivalents
            $
            206
            
            
            $
            355Accounts
      receivable – trade (less allowance for doubtfulaccounts
      of $24 and $22, respectively)
            
            506
            
            
            
            570Unbilled
      revenue
            
            262
            
            
            
            359Miscellaneous
      accounts and notes receivable
            
            291
            
            
            
            280Materials
      and supplies
            
            956
            
            
            
            735Other
      current assets
            
            326
            
            
            
            181Total
      current assets
            
            2,547
            
            
            
            2,480Property
      and Plant, Net
            
            15,977
            
            
            
            15,069Investments
      and Other Assets:Nuclear
      decommissioning trust fund
            
            269
            
            
            
            307Goodwill
            
            831
            
            
            
            831Intangible
      assets
            
            167
            
            
            
            198Regulatory
      assets
            
            1,122
            
            
            
            1,158Other
      assets
            
            566
            
            
            
            685Total
      investments and other assets
            
            2,955
            
            
            
            3,179TOTAL
      ASSETS
            $
            21,479
            
            
            $
            20,728LIABILITIES
      AND STOCKHOLDERS' EQUITYCurrent
      Liabilities:Current
      maturities of long-term debt
            $
            269
            
            
            $
            221Short-term
      debt
            
            1,407
            
            
            
            1,472Accounts
      and wages payable
            
            509
            
            
            
            687Taxes
      accrued
            
            128
            
            
            
            84Other
      current liabilities
            
            605
            
            
            
            438Total
      current liabilities
            
            2,918
            
            
            
            2,902Long-term
      Debt, Net
            
            6,143
            
            
            
            5,691Preferred
      Stock of Subsidiary Subject to Mandatory Redemption
            
            -
            
            
            
            16Deferred
      Credits and Other Liabilities:Accumulated
      deferred income taxes, net
            
            2,072
            
            
            
            2,046Accumulated
      deferred investment tax credits
            
            102
            
            
            
            109Regulatory
      liabilities
            
            1,291
            
            
            
            1,240Asset
      retirement obligations
            
            583
            
            
            
            562Accrued
      pension and other postretirement benefits
            
            741
            
            
            
            839Other
      deferred credits and liabilities
            
            367
            
            
            
            354Total
      deferred credits and other liabilities
            
            5,156
            
            
            
            5,150Preferred
      Stock of Subsidiaries Not Subject to Mandatory Redemption
            
            195
            
            
            
            195Minority
      Interest in Consolidated Subsidiaries
            
            24
            
            
            
            22Commitments
      and Contingencies (Notes 2, 8, 9 and 10)Stockholders'
      Equity:Common
      stock, $.01 par value, 400.0 shares authorized –shares
      outstanding of 210.9 and 208.3, respectively
            
            2
            
            
            
            2Other
      paid-in capital, principally premium on common stock
            
            4,731
            
            
            
            4,604Retained
      earnings
            
            2,259
            
            
            
            2,110Accumulated
      other comprehensive income
            
            51
            
            
            
            36Total
      stockholders’ equity
            
            7,043
            
            
            
            6,752TOTAL
      LIABILITIES AND STOCKHOLDERS' EQUITY
            $
            21,479
            
            
            $
            20,728




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


10


AMEREN
      CORPORATIONCONSOLIDATED
      STATEMENT OF CASH FLOWS(Unaudited)
      (In millions)Nine
      Months EndedSeptember
      30,2008
            
            
            2007Cash
      Flows From Operating Activities:Net
      income
            $
            548
            
            
            $
            510Adjustments
      to reconcile net income to net cashprovided
      by operating activities:Gain
      on sales of emission allowances
            
            (2
            )
            
            
            (7
            )Net
      mark-to-market gain on derivatives
            
            (42
            )
            
            
            (7
            )Depreciation
      and amortization
            
            549
            
            
            
            557Amortization
      of nuclear fuel
            
            31
            
            
            
            26Amortization
      of debt issuance costs and premium/discounts
            
            14
            
            
            
            14Deferred
      income taxes and investment tax credits, net
            
            130
            
            
            
            18Minority
      interest
            
            25
            
            
            
            20Other
            
            (2
            )
            
            
            10Changes
      in assets and liabilities:Receivables
            
            144
            
            
            
            (220
            )Materials
      and supplies
            
            (216
            )
            
            
            (110
            )Accounts
      and wages payable
            
            (100
            )
            
            
            (113
            )Taxes
      accrued, net
            
            44
            
            
            
            75Assets,
      other
            
            46
            
            
            
            58Liabilities,
      other
            
            142
            
            
            
            151Pension
      and other postretirement benefit obligations
            
            2
            
            
            
            67Counterparty
      collateral asset
            
            (2
            )
            
            
            (71
            )Counterparty
      collateral liability
            
            2
            
            
            
            -Taum
      Sauk insurance receivable, net
            
            (68
            )
            
            
            (58
            )Net
      cash provided by operating activities
            
            1,245
            
            
            
            920Cash
      Flows From Investing Activities:Capital
      expenditures
            
            (1,316
            )
            
            
            (1,035
            )Nuclear
      fuel expenditures
            
            (161
            )
            
            
            (39
            )Purchases
      of securities – nuclear decommissioning trust fund
            
            (386
            )
            
            
            (110
            )Sales
      of securities – nuclear decommissioning trust fund
            
            360
            
            
            
            98Purchases
      of emission allowances
            
            (2
            )
            
            
            (12
            )Sales
      of emission allowances
            
            2
            
            
            
            5Other
            
            2
            
            
            
            -Net
      cash used in investing activities
            
            (1,501
            )
            
            
            (1,093
            )Cash
      Flows From Financing Activities:Dividends
      on common stock
            
            (399
            )
            
            
            (395
            )Capital
      issuance costs
            
            (9
            )
            
            
            (3
            )Short-term
      debt, net
            
            (65
            )
            
            
            590Dividends
      paid to minority interest holder
            
            (23
            )
            
            
            (16
            )Redemptions,
      repurchases, and maturities:Long-term
      debt
            
            (823
            )
            
            
            (465
            )Preferred
      stock
            
            (16
            )
            
            
            (1
            )Issuances:Common
      stock
            
            107
            
            
            
            71Long-term
      debt
            
            1,335
            
            
            
            425Net
      cash provided by financing activities
            
            107
            
            
            
            206Net
      change in cash and cash equivalents
            
            (149
            )
            
            
            33Cash
      and cash equivalents at beginning of year
            
            355
            
            
            
            137Cash
      and cash equivalents at end of period
            $
            206
            
            
            $
            170




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


11


UNION
      ELECTRIC COMPANYCONSOLIDATED
      STATEMENT OF INCOME(Unaudited)
      (In millions)Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      Revenues:Electric
      - excluding off-system
            $
            742
            
            
            $
            835
            
            
            $
            1,821
            
            
            $
            1,865Electric
      - off-system
            
            111
            
            
            
            92
            
            
            
            409
            
            
            
            303Gas
            
            21
            
            
            
            18
            
            
            
            139
            
            
            
            123Other
            
            1
            
            
            
            -
            
            
            
            1
            
            
            
            1Total
      operating revenues
            
            875
            
            
            
            945
            
            
            
            2,370
            
            
            
            2,292Operating
      Expenses:Fuel
            
            238
            
            
            
            179
            
            
            
            489
            
            
            
            447Purchased
      power
            
            45
            
            
            
            71
            
            
            
            135
            
            
            
            140Gas
      purchased for resale
            
            11
            
            
            
            9
            
            
            
            84
            
            
            
            73Other
      operations and maintenance
            
            234
            
            
            
            218
            
            
            
            689
            
            
            
            667Depreciation
      and amortization
            
            83
            
            
            
            81
            
            
            
            246
            
            
            
            252Taxes
      other than income taxes
            
            69
            
            
            
            70
            
            
            
            189
            
            
            
            187Total
      operating expenses
            
            680
            
            
            
            628
            
            
            
            1,832
            
            
            
            1,766Operating
      Income
            
            195
            
            
            
            317
            
            
            
            538
            
            
            
            526Other
      Income and Expenses:Miscellaneous
      income
            
            17
            
            
            
            9
            
            
            
            46
            
            
            
            28Miscellaneous
      expense
            
            (2
            )
            
            
            (5
            )
            
            
            (6
            )
            
            
            (9
            )Total
      other income
            
            15
            
            
            
            4
            
            
            
            40
            
            
            
            19Interest
      Charges
            
            51
            
            
            
            49
            
            
            
            142
            
            
            
            146Income
      Before Income Taxes and Equityin
      Income of Unconsolidated Investment
            
            159
            
            
            
            272
            
            
            
            436
            
            
            
            399Income
      Taxes
            
            60
            
            
            
            93
            
            
            
            160
            
            
            
            132Income
      Before Equity in Incomeof
      Unconsolidated Investment
            
            99
            
            
            
            179
            
            
            
            276
            
            
            
            267Equity
      in Income of Unconsolidated Investment, Net of Taxes
            
            -
            
            
            
            14
            
            
            
            11
            
            
            
            40Net
      Income
            
            99
            
            
            
            193
            
            
            
            287
            
            
            
            307Preferred
      Stock Dividends
            
            1
            
            
            
            1
            
            
            
            4
            
            
            
            4Net
      Income Available to Common Stockholder
            $
            98
            
            
            $
            192
            
            
            $
            283
            
            
            $
            303




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


12


UNION
      ELECTRIC COMPANYCONSOLIDATED
      BALANCE SHEET(Unaudited)
      (In millions, except per share amounts)September
      30,
            
            
            December
      31,2008
            
            
            2007ASSETSCurrent
      Assets:Cash
      and cash equivalents
            $
            -
            
            
            $
            185Accounts
      receivable – trade (less allowance for doubtfulaccounts
      of $7 and $6, respectively)
            
            193
            
            
            
            191Unbilled
      revenue
            
            102
            
            
            
            118Miscellaneous
      accounts and notes receivable
            
            228
            
            
            
            213Advances
      to money pool
            
            -
            
            
            
            15Accounts
      receivable – affiliates
            
            6
            
            
            
            90Materials
      and supplies
            
            351
            
            
            
            301Other
      current assets
            
            76
            
            
            
            50Total
      current assets
            
            956
            
            
            
            1,163Property
      and Plant, Net
            
            8,682
            
            
            
            8,189Investments
      and Other Assets:Nuclear
      decommissioning trust fund
            
            269
            
            
            
            307Intercompany
      note receivable – affiliate
            
            30
            
            
            
            -Intangible
      assets
            
            50
            
            
            
            56Regulatory
      assets
            
            696
            
            
            
            697Other
      assets
            
            354
            
            
            
            491Total
      investments and other assets
            
            1,399
            
            
            
            1,551TOTAL
      ASSETS
            $
            11,037
            
            
            $
            10,903LIABILITIES
      AND STOCKHOLDERS' EQUITYCurrent
      Liabilities:Current
      maturities of long-term debt
            $
            4
            
            
            $
            152Short-term
      debt
            
            -
            
            
            
            82Intercompany
      note payable – Ameren
            
            17
            
            
            
            -Accounts
      and wages payable
            
            160
            
            
            
            315Accounts
      payable – affiliates
            
            104
            
            
            
            212Taxes
      accrued
            
            138
            
            
            
            78Accrued
      interest
            
            75
            
            
            
            47Taum
      Sauk pumped-storage hydroelectric facility liability
            
            28
            
            
            
            103Other
      current liabilities
            
            79
            
            
            
            59Total
      current liabilities
            
            605
            
            
            
            1,048Long-term
      Debt, Net
            
            3,677
            
            
            
            3,208Deferred
      Credits and Other Liabilities:Accumulated
      deferred income taxes, net
            
            1,336
            
            
            
            1,273Accumulated
      deferred investment tax credits
            
            81
            
            
            
            85Regulatory
      liabilities
            
            903
            
            
            
            865Asset
      retirement obligations
            
            495
            
            
            
            476Accrued
      pension and other postretirement benefits
            
            229
            
            
            
            297Other
      deferred credits and liabilities
            
            46
            
            
            
            50Total
      deferred credits and other liabilities
            
            3,090
            
            
            
            3,046Commitments
      and Contingencies (Notes 2, 8, 9 and 10)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
            
            1,119
            
            
            
            1,119Retained
      earnings
            
            1,903
            
            
            
            1,855Accumulated
      other comprehensive income
            
            19
            
            
            
            3Total
      stockholders' equity
            
            3,665
            
            
            
            3,601TOTAL
      LIABILITIES AND STOCKHOLDERS' EQUITY
            $
            11,037
            
            
            $
            10,903




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


13


UNION
      ELECTRIC COMPANYCONSOLIDATED
      STATEMENT OF CASH FLOWS(Unaudited)
      (In millions)Nine
      Months EndedSeptember
      30,2008
            
            
            2007Cash
      Flows From Operating Activities:Net
      income
            $
            287
            
            
            $
            307Adjustments
      to reconcile net income to net cashprovided
      by operating activities:Gain
      on sales of emission allowances
            
            (1
            )
            
            
            (5
            )Net
      mark-to-market gain on derivatives
            
            (10
            )
            
            
            (1
            )Depreciation
      and amortization
            
            246
            
            
            
            252Amortization
      of nuclear fuel
            
            31
            
            
            
            26Amortization
      of debt issuance costs and premium/discounts
            
            5
            
            
            
            4Deferred
      income taxes and investment tax credits, net
            
            57
            
            
            
            19Other
            
            (19
            )
            
            
            1Changes
      in assets and liabilities:Receivables
            
            79
            
            
            
            (82
            )Materials
      and supplies
            
            (45
            )
            
            
            (49
            )Accounts
      and wages payable
            
            (226
            )
            
            
            (97
            )Taxes
      accrued, net
            
            57
            
            
            
            140Assets,
      other
            
            97
            
            
            
            61Liabilities,
      other
            
            55
            
            
            
            (26
            )Pension
      and other postretirement benefit obligations
            
            10
            
            
            
            27Taum
      Sauk insurance receivable, net
            
            (68
            )
            
            
            (58
            )Net
      cash provided by operating activities
            
            555
            
            
            
            519Cash
      Flows From Investing Activities:Capital
      expenditures
            
            (614
            )
            
            
            (493
            )Nuclear
      fuel expenditures
            
            (161
            )
            
            
            (39
            )Changes
      in money pool advances
            
            -
            
            
            
            5Proceeds
      from intercompany note receivable
            
            6
            
            
            
            -Purchases
      of securities – nuclear decommissioning trust fund
            
            (386
            )
            
            
            (110
            )Sales
      of securities – nuclear decommissioning trust fund
            
            360
            
            
            
            98Sales
      of emission allowances
            
            1
            
            
            
            4Net
      cash used in investing activities
            
            (794
            )
            
            
            (535
            )Cash
      Flows From Financing Activities:Dividends
      on common stock
            
            (193
            )
            
            
            (246
            )Dividends
      on preferred stock
            
            (4
            )
            
            
            (4
            )Capital
      issuance costs
            
            (5
            )
            
            
            (3
            )Short-term
      debt, net
            
            (82
            )
            
            
            (142
            )Intercompany
      note payable – Ameren, net
            
            17
            
            
            
            (20
            )Redemptions,
      repurchases, and maturities of long-term debt
            
            (378
            )
            
            
            -Issuances
      of long-term debt
            
            699
            
            
            
            425Capital
      contribution from parent
            
            -
            
            
            
            5Net
      cash provided by financing activities
            
            54
            
            
            
            15Net
      change in cash and cash equivalents
            
            (185
            )
            
            
            (1
            )Cash
      and cash equivalents at beginning of year
            
            185
            
            
            
            1Cash
      and cash equivalents at end of period
            $
            -
            
            
            $
            -




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


14


CENTRAL
      ILLINOIS PUBLIC SERVICE COMPANYSTATEMENT
      OF INCOME(Unaudited)
      (In millions)Three
      Months Ended
            
            
            Nine
      Months EndedSeptember
      30,
            
            
            September
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      Revenues:Electric
            $
            190
            
            
            $
            201
            
            
            $
            539
            
            
            $
            605Gas
            
            25
            
            
            
            22
            
            
            
            173
            
            
            
            159Other
            
            2
            
            
            
            1
            
            
            
            2
            
            
            
            3Total
      operating revenues
            
            217
            
            
            
            224
            
            
            
            714
            
            
            
            767Operating
      Expenses:Purchased
      power
            
            117
            
            
            
            142
            
            
            
            348
            
            
            
            416Gas
      purchased for resale
            
            13
            
            
            
            12
            
            
            
            117
            
            
            
            107Other
      operations and maintenance
            
            49
            
            
            
            40
            
            
            
            147
            
            
            
            124Depreciation
      and amortization
            
            16
            
            
            
            16
            
            
            
            50
            
            
            
            49Taxes
      other than income taxes
            
            8
            
            
            
            6
            
            
            
            27
            
            
            
            24Total
      operating expenses
            
            203
            
            
            
            216
            
            
            
            689
            
            
            
            720Operating
      Income
            
            14
            
            
            
            8
            
            
            
            25
            
            
            
            47Other
      Income and Expenses:Miscellaneous
      income
            
            3
            
            
            
            5
            
            
            
            9
            
            
            
            13Miscellaneous
      expense
            
            -
            
            
            
            (1
            )
            
            
            (2
            )
            
            
            (2
            )Total
      other income
            
            3
            
            
            
            4
            
            
            
            7
            
            
            
            11Interest
      Charges
            
            8
            
            
            
            10
            
            
            
            23
            
            
            
            28Income
      Before Income Taxes
            
            9
            
            
            
            2
            
            
            
            9
            
            
            
            30Income
      Taxes
            
            2
            
            
            
            1
            
            
            
            2
            
            
            
            11Net
      Income
            
            7
            
            
            
            1
            
            
            
            7
            
            
            
            19Preferred
      Stock Dividends
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            2Net
      Income Available to Common Stockholder
            $
            6
            
            
            $
            -
            
            
            $
            5
            
            
            $
            17




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




15







CENTRAL
      ILLINOIS PUBLIC SERVICE COMPANYBALANCE
      SHEET(Unaudited)
      (In millions)September
      30,
            
            
            December
      31,2008
            
            
            2007ASSETSCurrent
      Assets:Cash
      and cash equivalents
            $
            14
            
            
            $
            26Accounts
      receivable – trade (less allowance for doubtfulaccounts
      of $5 and $5, respectively)
            
            64
            
            
            
            62Unbilled
      revenue
            
            30
            
            
            
            66Miscellaneous
      accounts and notes receivable
            
            19
            
            
            
            19Accounts
      receivable – affiliates
            
            19
            
            
            
            9Current
      portion of intercompany note receivable – Genco
            
            42
            
            
            
            39Current
      portion of intercompany tax receivable – Genco
            
            9
            
            
            
            9Materials
      and supplies
            
            91
            
            
            
            66Other
      current assets
            
            32
            
            
            
            16Total
      current assets
            
            320
            
            
            
            312Property
      and Plant, Net
            
            1,194
            
            
            
            1,174Investments
      and Other Assets:Intercompany
      note receivable – Genco
            
            45
            
            
            
            87Intercompany
      tax receivable – Genco
            
            97
            
            
            
            105Regulatory
      assets
            
            92
            
            
            
            113Other
      assets
            
            12
            
            
            
            69Total
      investments and other assets
            
            246
            
            
            
            374TOTAL
      ASSETS
            $
            1,760
            
            
            $
            1,860LIABILITIES
      AND STOCKHOLDERS' EQUITYCurrent
      Liabilities:Current
      maturities of long-term debt
            $
            15
            
            
            $
            15Short-term
      debt
            
            96
            
            
            
            125Accounts
      and wages payable
            
            39
            
            
            
            44Accounts
      payable – affiliates
            
            19
            
            
            
            19Taxes
      accrued
            
            11
            
            
            
            8Customer
      deposits
            
            16
            
            
            
            16Mark-to-market
      derivative liability
            
            9
            
            
            
            1Mark-to-market
      derivative liability with affiliate
            
            10
            
            
            
            -Other
      current liabilities
            
            39
            
            
            
            30Total
      current liabilities
            
            254
            
            
            
            258Long-term
      Debt, Net
            
            421
            
            
            
            456Deferred
      Credits and Other Liabilities:Accumulated
      deferred income taxes and investment tax credits, net
            
            260
            
            
            
            269Regulatory
      liabilities
            
            238
            
            
            
            265Accrued
      pension and other postretirement benefits
            
            37
            
            
            
            67Other
      deferred credits and liabilities
            
            28
            
            
            
            28Total
      deferred credits and other liabilities
            
            563
            
            
            
            629Commitments
      and Contingencies (Notes 2, 8, and 9)Stockholders'
      Equity:Common
      stock, no par value, 45.0 shares authorized – 25.5 shares
      outstanding
            
            -
            
            
            
            -Other
      paid-in capital
            
            191
            
            
            
            191Preferred
      stock not subject to mandatory redemption
            
            50
            
            
            
            50Retained
      earnings
            
            281
            
            
            
            276Total
      stockholders' equity
            
            522
            
            
            
            517TOTAL
      LIABILITIES AND STOCKHOLDERS' EQUITY
            $
            1,760
            
            
            $
            1,860




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





16





CENTRAL
      ILLINOIS PUBLIC SERVICE COMPANYSTATEMENT
      OF CASH FLOWS(Unaudited)
      (In millions)Nine
      Months EndedSeptember
      30,2008
            
            
            2007Cash
      Flows From Operating Activities:Net
      income
            $
            7
            
            
            $
            19Adjustments
      to reconcile net income to net cashprovided
      by operating activities:Depreciation
      and amortization
            
            50
            
            
            
            49Amortization
      of debt issuance costs and premium/discounts
            
            1
            
            
            
            1Deferred
      income taxes and investment tax credits, net
            
            (2
            )
            
            
            (13
            )Changes
      in assets and liabilities:Receivables
            
            32
            
            
            
            (36
            )Materials
      and supplies
            
            (25
            )
            
            
            (7
            )Accounts
      and wages payable
            
            (6
            )
            
            
            (27
            )Taxes
      accrued, net
            
            3
            
            
            
            (6
            )Assets,
      other
            
            19
            
            
            
            (8
            )Liabilities,
      other
            
            -
            
            
            
            34Pension
      and other postretirement benefit obligations
            
            1
            
            
            
            5Net
      cash provided by operating activities
            
            80
            
            
            
            11Cash
      Flows From Investing Activities:Capital
      expenditures
            
            (65
            )
            
            
            (58
            )Proceeds
      from intercompany note receivable – Genco
            
            39
            
            
            
            37Changes
      in money pool advances
            
            -
            
            
            
            (94
            )Net
      cash used in investing activities
            
            (26
            )
            
            
            (115
            )Cash
      Flows From Financing Activities:Dividends
      on preferred stock
            
            (2
            )
            
            
            (2
            )Short-term
      debt, net
            
            (29
            )
            
            
            100Redemptions,
      repurchases, and maturities of long-term debt
            
            (35
            )
            
            
            -Capital
      contribution from parent
            
            -
            
            
            
            1Net
      cash provided by (used in) financing activities
            
            (66
            )
            
            
            99Net
      change in cash and cash equivalents
            
            (12
            )
            
            
            (5
            )Cash
      and cash equivalents at beginning of year
            
            26
            
            
            
            6Cash
      and cash equivalents at end of period
            $
            14
            
            
            $
            1




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





17







AMEREN
      ENERGY GENERATING COMPANYCONSOLIDATED
      STATEMENT OF INCOME(Unaudited)
      (In millions)Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      Revenues
            $
            238
            
            
            $
            221
            
            
            $
            667
            
            
            $
            652Operating
      Expenses:Fuel
            
            131
            
            
            
            102
            
            
            
            268
            
            
            
            257Coal
      contract settlement
            
            -
            
            
            
            -
            
            
            
            (60
            )
            
            
            -Purchased
      power
            
            -
            
            
            
            1
            
            
            
            -
            
            
            
            25Other
      operations and maintenance
            
            40
            
            
            
            39
            
            
            
            133
            
            
            
            122Depreciation
      and amortization
            
            16
            
            
            
            18
            
            
            
            48
            
            
            
            54Taxes
      other than income taxes
            
            5
            
            
            
            5
            
            
            
            16
            
            
            
            15Total
      operating expenses
            
            192
            
            
            
            165
            
            
            
            405
            
            
            
            473Operating
      Income
            
            46
            
            
            
            56
            
            
            
            262
            
            
            
            177Other
      Income and Expenses:Miscellaneous
      income
            
            -
            
            
            
            -
            
            
            
            1
            
            
            
            -Miscellaneous
      expense
            
            (1
            )
            
            
            -
            
            
            
            (1
            )
            
            
            -Total
      other expenses
            
            (1
            )
            
            
            -
            
            
            
            -
            
            
            
            -Interest
      Charges
            
            14
            
            
            
            15
            
            
            
            40
            
            
            
            43Income
      Before Income Taxes
            
            31
            
            
            
            41
            
            
            
            222
            
            
            
            136Income
      Taxes
            
            11
            
            
            
            16
            
            
            
            82
            
            
            
            52Net
      Income
            $
            20
            
            
            $
            25
            
            
            $
            140
            
            
            $
            84




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





18







AMEREN
      ENERGY GENERATING COMPANYCONSOLIDATED
      BALANCE SHEET(Unaudited)
      (In millions, except shares)September
      30,
            
            
            December
      31,2008
            
            
            2007ASSETSCurrent
      Assets:Cash
      and cash equivalents
            $
            2
            
            
            $
            2Accounts
      receivable – affiliates
            
            82
            
            
            
            93Miscellaneous
      accounts and notes receivable
            
            8
            
            
            
            12Advances
      to money pool
            
            13
            
            
            
            -Materials
      and supplies
            
            122
            
            
            
            93Other
      current assets
            
            6
            
            
            
            4Total
      current assets
            
            233
            
            
            
            204Property
      and Plant, Net
            
            1,830
            
            
            
            1,683Intangible
      Assets
            
            45
            
            
            
            63Other
      Assets
            
            8
            
            
            
            18TOTAL
      ASSETS
            $
            2,116
            
            
            $
            1,968LIABILITIES
      AND STOCKHOLDER'S EQUITYCurrent
      Liabilities:Short-term
      debt
            $
            -
            
            
            $
            100Current
      portion of intercompany note payable – CIPS
            
            42
            
            
            
            39Borrowings
      from money pool
            
            -
            
            
            
            54Accounts
      and wages payable
            
            35
            
            
            
            61Accounts
      payable – affiliates
            
            55
            
            
            
            57Current
      portion of intercompany tax payable – CIPS
            
            9
            
            
            
            9Taxes
      accrued
            
            13
            
            
            
            15Accrued
      interest
            
            27
            
            
            
            5Deferred
      taxes – current
            
            14
            
            
            
            7Other
      current liabilities
            
            15
            
            
            
            18Total
      current liabilities
            
            210
            
            
            
            365Long-term
      Debt, Net
            
            774
            
            
            
            474Intercompany
      Note Payable – CIPS
            
            45
            
            
            
            87Deferred
      Credits and Other Liabilities:Accumulated
      deferred income taxes, net
            
            157
            
            
            
            161Accumulated
      deferred investment tax credits
            
            7
            
            
            
            7Intercompany
      tax payable – CIPS
            
            97
            
            
            
            105Asset
      retirement obligations
            
            48
            
            
            
            47Accrued
      pension and other postretirement benefits
            
            31
            
            
            
            32Other
      deferred credits and liabilities
            
            45
            
            
            
            42Total
      deferred credits and other liabilities
            
            385
            
            
            
            394Commitments
      and Contingencies (Notes 2, 8 and 9)Stockholder's
      Equity:Common
      stock, no par value, 10,000 shares authorized – 2,000 shares
      outstanding
            
            -
            
            
            
            -Other
      paid-in capital
            
            503
            
            
            
            503Retained
      earnings
            
            223
            
            
            
            167Accumulated
      other comprehensive loss
            
            (24
            )
            
            
            (22
            )Total
      stockholder's equity
            
            702
            
            
            
            648TOTAL
      LIABILITIES AND STOCKHOLDER'S EQUITY
            $
            2,116
            
            
            $
            1,968




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


19





AMEREN
      ENERGY GENERATING COMPANYCONSOLIDATED
      STATEMENT OF CASH FLOWS(Unaudited)
      (In millions)Nine
      Months EndedSeptember
      30,2008
            
            
            2007Cash
      Flows From Operating Activities:Net
      income
            $
            140
            
            
            $
            84Adjustments
      to reconcile net income to net cashprovided
      by operating activities:Gain
      on sales of emission allowances
            
            (1
            )
            
            
            (1
            )Net
      mark-to-market (gain) loss on derivatives
            
            1
            
            
            
            (1
            )Depreciation
      and amortization
            
            68
            
            
            
            79Deferred
      income taxes and investment tax credits, net
            
            14
            
            
            
            28Other
            
            -
            
            
            
            (1
            )Changes
      in assets and liabilities:Receivables
            
            15
            
            
            
            (14
            )Materials
      and supplies
            
            (29
            )
            
            
            (1
            )Accounts
      and wages payable
            
            (18
            )
            
            
            (12
            )Taxes
      accrued, net
            
            (5
            )
            
            
            (7
            )Assets,
      other
            
            12
            
            
            
            (11
            )Liabilities,
      other
            
            11
            
            
            
            5Pension
      and other postretirement obligations
            
            1
            
            
            
            5Net
      cash provided by operating activities
            
            209
            
            
            
            153Cash
      Flows From Investing Activities:Capital
      expenditures
            
            (216
            )
            
            
            (131
            )Changes
      in money pool advances
            
            (13
            )
            
            
            -Purchases
      of emission allowances
            
            (2
            )
            
            
            (7
            )Sales
      of emission allowances
            
            1
            
            
            
            1Net
      cash used in investing activities
            
            (230
            )
            
            
            (137
            )Cash
      Flows From Financing Activities:Dividends
      on common stock
            
            (84
            )
            
            
            (113
            )Debt
      issuance costs
            
            (2
            )
            
            
            -Short-term
      debt, net
            
            (100
            )
            
            
            75Changes
      in money pool borrowings
            
            (54
            )
            
            
            (15
            )Intercompany
      note payable – CIPS
            
            (39
            )
            
            
            (37
            )Issuances
      of long-term debt
            
            300
            
            
            
            -Capital
      contribution from parent
            
            -
            
            
            
            75Net
      cash provided by (used in) financing activities
            
            21
            
            
            
            (15
            )Net
      change in cash and cash equivalents
            
            -
            
            
            
            1Cash
      and cash equivalents at beginning of year
            
            2
            
            
            
            1Cash
      and cash equivalents at end of period
            $
            2
            
            
            $
            2




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


20







CILCORP
      INC.CONSOLIDATED
      STATEMENT OF INCOME(Unaudited)
      (In millions)Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      Revenues:Electric
            $
            227
            
            
            $
            175
            
            
            $
            584
            
            
            $
            520Gas
            
            37
            
            
            
            36
            
            
            
            257
            
            
            
            231Other
            
            -
            
            
            
            -
            
            
            
            1
            
            
            
            1Total
      operating revenues
            
            264
            
            
            
            211
            
            
            
            842
            
            
            
            752Operating
      Expenses:Fuel
            
            40
            
            
            
            21
            
            
            
            93
            
            
            
            58Purchased
      power
            
            84
            
            
            
            80
            
            
            
            225
            
            
            
            221Gas
      purchased for resale
            
            25
            
            
            
            21
            
            
            
            190
            
            
            
            166Other
      operations and maintenance
            
            47
            
            
            
            46
            
            
            
            140
            
            
            
            130Depreciation
      and amortization
            
            24
            
            
            
            22
            
            
            
            70
            
            
            
            63Taxes
      other than income taxes
            
            4
            
            
            
            3
            
            
            
            18
            
            
            
            17Total
      operating expenses
            
            224
            
            
            
            193
            
            
            
            736
            
            
            
            655Operating
      Income
            
            40
            
            
            
            18
            
            
            
            106
            
            
            
            97Other
      Income and Expenses:Miscellaneous
      income
            
            1
            
            
            
            2
            
            
            
            2
            
            
            
            4Miscellaneous
      expense
            
            (2
            )
            
            
            (1
            )
            
            
            (4
            )
            
            
            (3
            )Total
      other income (expenses)
            
            (1
            )
            
            
            1
            
            
            
            (2
            )
            
            
            1Interest
      Charges
            
            13
            
            
            
            17
            
            
            
            41
            
            
            
            46Income
      Before Income Taxes and PreferredDividends
      of Subsidiaries
            
            26
            
            
            
            2
            
            
            
            63
            
            
            
            52Income
      Taxes
            
            8
            
            
            
            1
            
            
            
            20
            
            
            
            17Income
      Before Preferred Dividends of Subsidiaries
            
            18
            
            
            
            1
            
            
            
            43
            
            
            
            35Preferred
      Dividends of Subsidiaries
            
            -
            
            
            
            -
            
            
            
            1
            
            
            
            1Net
      Income
            $
            18
            
            
            $
            1
            
            
            $
            42
            
            
            $
            34




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





21





CILCORP
      INC.CONSOLIDATED
      BALANCE SHEET(Unaudited)
      (In millions, except shares)September
      30,
            
            
            December
      31,2008
            
            
            2007ASSETSCurrent
      Assets:Cash
      and cash equivalents
            $
            -
            
            
            $
            6Accounts
      receivable – trade (less allowance for doubtfulaccounts
      of $2 and $2, respectively)
            
            43
            
            
            
            52Unbilled
      revenue
            
            26
            
            
            
            54Accounts
      receivable – affiliates
            
            88
            
            
            
            47Advances
      to money pool
            
            2
            
            
            
            1Note
      receivable – affiliates
            
            1
            
            
            
            1Materials
      and supplies
            
            156
            
            
            
            110Income
      tax receivable
            
            -
            
            
            
            16Other
      current assets
            
            34
            
            
            
            24Total
      current assets
            
            350
            
            
            
            311Property
      and Plant, Net
            
            1,639
            
            
            
            1,494Investments
      and Other Assets:Goodwill
            
            542
            
            
            
            542Intangible
      assets
            
            36
            
            
            
            41Regulatory
      assets
            
            39
            
            
            
            32Other
      assets
            
            21
            
            
            
            39Total
      investments and other assets
            
            638
            
            
            
            654TOTAL
      ASSETS
            $
            2,627
            
            
            $
            2,459LIABILITIES
      AND STOCKHOLDER'S EQUITYCurrent
      Liabilities:Short-term
      debt
            $
            432
            
            
            $
            520Borrowings
      from money pool, net
            
            171
            
            
            
            -Intercompany
      note payable – Ameren
            
            63
            
            
            
            2Accounts
      and wages payable
            
            68
            
            
            
            75Accounts
      payable – affiliates
            
            38
            
            
            
            34Taxes
      accrued
            
            5
            
            
            
            3Other
      current liabilities
            
            79
            
            
            
            54Total
      current liabilities
            
            856
            
            
            
            688Long-term
      Debt, Net
            
            513
            
            
            
            537Preferred
      Stock of Subsidiary Subject to Mandatory Redemption
            
            -
            
            
            
            16Deferred
      Credits and Other Liabilities:Accumulated
      deferred income taxes, net
            
            203
            
            
            
            193Accumulated
      deferred investment tax credits
            
            5
            
            
            
            6Regulatory
      liabilities
            
            86
            
            
            
            92Accrued
      pension and other postretirement benefits
            
            112
            
            
            
            127Other
      deferred credits and liabilities
            
            74
            
            
            
            66Total
      deferred credits and other liabilities
            
            480
            
            
            
            484Preferred
      Stock of Subsidiary Not Subject to Mandatory Redemption
            
            19
            
            
            
            19Commitments
      and Contingencies (Notes 2, 8 and 9)Stockholder's
      Equity:Common
      stock, no par value, 10,000 shares authorized – 1,000 shares
      outstanding
            
            -
            
            
            
            -Other
      paid-in capital
            
            627
            
            
            
            627Retained
      earnings
            
            100
            
            
            
            58Accumulated
      other comprehensive income
            
            32
            
            
            
            30Total
      stockholder's equity
            
            759
            
            
            
            715TOTAL
      LIABILITIES AND STOCKHOLDER'S EQUITY
            $
            2,627
            
            
            $
            2,459




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




22




CILCORP
      INC.CONSOLIDATED
      STATEMENT OF CASH FLOWS(Unaudited)
      (In millions)Nine
      Months EndedSeptember
      30,2008
            
            
            2007Cash
      Flows From Operating Activities:Net
      income
            $
            42
            
            
            $
            34Adjustments
      to reconcile net income to net cashprovided
      by operating activities:Net
      mark-to-market loss on derivatives
            
            3
            
            
            
            -Depreciation
      and amortization
            
            71
            
            
            
            65Amortization
      of debt issuance costs and premium/discounts
            
            -
            
            
            
            1Deferred
      income taxes and investment tax credits
            
            30
            
            
            
            2Changes
      in assets and liabilities:Receivables
            
            (3
            )
            
            
            (38
            )Materials
      and supplies
            
            (46
            )
            
            
            (18
            )Accounts
      and wages payable
            
            16
            
            
            
            (29
            )Taxes
      accrued, net
            
            11
            
            
            
            (3
            )Assets,
      other
            
            (14
            )
            
            
            (16
            )Liabilities,
      other
            
            6
            
            
            
            22Pension
      and postretirement benefit obligations
            
            (9
            )
            
            
            -Net
      cash provided by operating activities
            
            107
            
            
            
            20Cash
      Flows From Investing Activities:Capital
      expenditures
            
            (223
            )
            
            
            (183
            )Changes
      in money pool advances
            
            (1
            )
            
            
            42Other
            
            2
            
            
            
            -Net
      cash used in investing activities
            
            (222
            )
            
            
            (141
            )Cash
      Flows From Financing Activities:Short-term
      debt, net
            
            (88
            )
            
            
            325Changes
      in money pool borrowings
            
            171
            
            
            
            -Intercompany
      note payable – Ameren, net
            
            61
            
            
            
            (73
            )Redemptions,
      repurchases, and maturities of:Long-term
      debt
            
            (19
            )
            
            
            (50
            )Preferred
      stock
            
            (16
            )
            
            
            (1
            )Net
      cash provided by financing activities
            
            109
            
            
            
            201Net
      change in cash and cash equivalents
            
            (6
            )
            
            
            80Cash
      and cash equivalents at beginning of year
            
            6
            
            
            
            4Cash
      and cash equivalents at end of period
            $
            -
            
            
            $
            84




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





23







CENTRAL
      ILLINOIS LIGHT COMPANYCONSOLIDATED
      STATEMENT OF INCOME(Unaudited)
      (In millions)Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      Revenues:Electric
            $
            227
            
            
            $
            175
            
            
            $
            584
            
            
            $
            520Gas
            
            37
            
            
            
            36
            
            
            
            257
            
            
            
            231Other
            
            -
            
            
            
            -
            
            
            
            1
            
            
            
            1Total
      operating revenues
            
            264
            
            
            
            211
            
            
            
            842
            
            
            
            752Operating
      Expenses:Fuel
            
            39
            
            
            
            18
            
            
            
            89
            
            
            
            52Purchased
      power
            
            84
            
            
            
            80
            
            
            
            225
            
            
            
            221Gas
      purchased for resale
            
            25
            
            
            
            21
            
            
            
            190
            
            
            
            166Other
      operations and maintenance
            
            48
            
            
            
            46
            
            
            
            145
            
            
            
            133Depreciation
      and amortization
            
            21
            
            
            
            18
            
            
            
            62
            
            
            
            54Taxes
      other than income taxes
            
            4
            
            
            
            4
            
            
            
            18
            
            
            
            17Total
      operating expenses
            
            221
            
            
            
            187
            
            
            
            729
            
            
            
            643Operating
      Income
            
            43
            
            
            
            24
            
            
            
            113
            
            
            
            109Other
      Income and Expenses:Miscellaneous
      income
            
            1
            
            
            
            2
            
            
            
            2
            
            
            
            4Miscellaneous
      expense
            
            (2
            )
            
            
            (1
            )
            
            
            (3
            )
            
            
            (3
            )Total
      other income (expenses)
            
            (1
            )
            
            
            1
            
            
            
            (1
            )
            
            
            1Interest
      Charges
            
            5
            
            
            
            8
            
            
            
            16
            
            
            
            19Income
      Before Income Taxes
            
            37
            
            
            
            17
            
            
            
            96
            
            
            
            91Income
      Taxes
            
            13
            
            
            
            7
            
            
            
            34
            
            
            
            33Net
      Income
            
            24
            
            
            
            10
            
            
            
            62
            
            
            
            58Preferred
      Stock Dividends
            
            -
            
            
            
            -
            
            
            
            1
            
            
            
            1Net
      Income Available To Common Stockholder
            $
            24
            
            
            $
            10
            
            
            $
            61
            
            
            $
            57




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




24





CENTRAL
      ILLINOIS LIGHT COMPANYCONSOLIDATED
      BALANCE SHEET(Unaudited)
      (In millions)September
      30,
            
            
            December
      312008
            
            
            2007ASSETSCurrent
      Assets:Cash
      and cash equivalents
            $
            -
            
            
            $
            6Accounts
      receivable – trade (less allowance for doubtfulaccounts
      of $2 and $2, respectively)
            
            43
            
            
            
            52Unbilled
      revenue
            
            26
            
            
            
            54Accounts
      receivable – affiliates
            
            86
            
            
            
            45Materials
      and supplies
            
            156
            
            
            
            110Other
      current assets
            
            34
            
            
            
            27Total
      current assets
            
            345
            
            
            
            294Property
      and Plant, Net
            
            1,638
            
            
            
            1,492Investments
      and Other Assets:Intangible
      assets
            
            1
            
            
            
            1Regulatory
      assets
            
            39
            
            
            
            32Other
      assets
            
            25
            
            
            
            43Total
      investments and other assets
            
            65
            
            
            
            76TOTAL
      ASSETS
            $
            2,048
            
            
            $
            1,862LIABILITIES
      AND STOCKHOLDERS' EQUITYCurrent
      Liabilities:Short-term
      debt
            $
            305
            
            
            $
            345Borrowings
      from money pool
            
            171
            
            
            
            -Accounts
      and wages payable
            
            68
            
            
            
            75Accounts
      payable – affiliates
            
            37
            
            
            
            34Taxes
      accrued
            
            10
            
            
            
            3Other
      current liabilities
            
            62
            
            
            
            45Total
      current liabilities
            
            653
            
            
            
            502Long-term
      Debt, Net
            
            129
            
            
            
            148Preferred
      Stock Subject to Mandatory Redemption
            
            -
            
            
            
            16Deferred
      Credits and Other Liabilities:Accumulated
      deferred income taxes, net
            
            176
            
            
            
            155Accumulated
      deferred investment tax credits
            
            5
            
            
            
            6Regulatory
      liabilities
            
            212
            
            
            
            220Accrued
      pension and other postretirement benefits
            
            112
            
            
            
            127Other
      deferred credits and liabilities
            
            74
            
            
            
            66Total
      deferred credits and other liabilities
            
            579
            
            
            
            574Commitments
      and Contingencies (Notes 2, 8 and 9)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
            
            429
            
            
            
            429Retained
      earnings
            
            233
            
            
            
            172Accumulated
      other comprehensive income
            
            6
            
            
            
            2Total
      stockholders' equity
            
            687
            
            
            
            622TOTAL
      LIABILITIES AND STOCKHOLDERS' EQUITY
            $
            2,048
            
            
            $
            1,862




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


25





CENTRAL
      ILLINOIS LIGHT COMPANYCONSOLIDATED
      STATEMENT OF CASH FLOWS(Unaudited)
      (In millions)Nine
      Months EndedSeptember
      30,2008
            
            
            2007Cash
      Flows From Operating Activities:Net
      income
            $
            62
            
            
            $
            58Adjustments
      to reconcile net income to net cashprovided
      by operating activities:Net
      mark-to-market loss on derivatives
            
            3
            
            
            
            -Depreciation
      and amortization
            
            62
            
            
            
            55Amortization
      of debt issuance costs and premium/discounts
            
            -
            
            
            
            1Deferred
      income taxes and investment tax credits, net
            
            30
            
            
            
            4Changes
      in assets and liabilities:Receivables
            
            (3
            )
            
            
            (32
            )Materials
      and supplies
            
            (46
            )
            
            
            (18
            )Accounts
      and wages payable
            
            15
            
            
            
            (17
            )Taxes
      accrued, net
            
            14
            
            
            
            (3
            )Assets,
      other
            
            (16
            )
            
            
            (21
            )Liabilities,
      other
            
            (2
            )
            
            
            16Pension
      and postretirement benefit obligations
            
            1
            
            
            
            5Net
      cash provided by operating activities
            
            120
            
            
            
            48Cash
      Flows From Investing Activities:Capital
      expenditures
            
            (223
            )
            
            
            (183
            )Changes
      in money pool advances
            
            -
            
            
            
            42Other
            
            2
            
            
            
            -Net
      cash used in investing activities
            
            (221
            )
            
            
            (141
            )Cash
      Flows From Financing Activities:Dividends
      on preferred stock
            
            (1
            )
            
            
            (1
            )Short-term
      debt, net
            
            (40
            )
            
            
            200Changes
      in money pool borrowings
            
            171
            
            
            
            -Redemptions,
      repurchases, and maturities of:Long-term
      debt
            
            (19
            )
            
            
            (50
            )Preferred
      stock
            
            (16
            )
            
            
            (1
            )Capital
      contribution from parent
            
            -
            
            
            
            14Net
      cash provided by financing activities
            
            95
            
            
            
            162Net
      change in cash and cash equivalents
            
            (6
            )
            
            
            69Cash
      and cash equivalents at beginning of year
            
            6
            
            
            
            3Cash
      and cash equivalents at end of period
            $
            -
            
            
            $
            72




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





26







ILLINOIS
      POWER COMPANYCONSOLIDATED
      STATEMENT OF INCOME(Unaudited)
      (In millions)Three
      Months Ended
            
            
            Nine
      Months EndedSeptember
      30,
            
            
            September
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      Revenues:Electric
            $
            303
            
            
            $
            307
            
            
            $
            799
            
            
            $
            859Gas
            
            49
            
            
            
            49
            
            
            
            414
            
            
            
            375Other
            
            1
            
            
            
            -
            
            
            
            3
            
            
            
            2Total
      operating revenues
            
            353
            
            
            
            356
            
            
            
            1,216
            
            
            
            1,236Operating
      Expenses:Purchased
      power
            
            185
            
            
            
            211
            
            
            
            499
            
            
            
            573Gas
      purchased for resale
            
            22
            
            
            
            26
            
            
            
            298
            
            
            
            267Other
      operations and maintenance
            
            74
            
            
            
            69
            
            
            
            217
            
            
            
            182Depreciation
      and amortization
            
            26
            
            
            
            25
            
            
            
            77
            
            
            
            75Amortization
      of regulatory assets
            
            5
            
            
            
            4
            
            
            
            13
            
            
            
            12Taxes
      other than income taxes
            
            12
            
            
            
            13
            
            
            
            48
            
            
            
            50Total
      operating expenses
            
            324
            
            
            
            348
            
            
            
            1,152
            
            
            
            1,159Operating
      Income
            
            29
            
            
            
            8
            
            
            
            64
            
            
            
            77Other
      Income and Expenses:Miscellaneous
      income
            
            3
            
            
            
            4
            
            
            
            9
            
            
            
            9Miscellaneous
      expense
            
            (2
            )
            
            
            (2
            )
            
            
            (5
            )
            
            
            (3
            )Total
      other income
            
            1
            
            
            
            2
            
            
            
            4
            
            
            
            6Interest
      Charges
            
            22
            
            
            
            19
            
            
            
            72
            
            
            
            55Income
      (Loss) Before Income Taxes (Benefit)
            
            8
            
            
            
            (9
            )
            
            
            (4
            )
            
            
            28Income
      Taxes (Benefit)
            
            3
            
            
            
            (5
            )
            
            
            (2
            )
            
            
            10Net
      Income (Loss)
            
            5
            
            
            
            (4
            )
            
            
            (2
            )
            
            
            18Preferred
      Stock Dividends
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            2Net
      Income (Loss) Available to Common Stockholder
            $
            4
            
            
            $
            (5
            )
            
            $
            (4
            )
            
            $
            16




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





27







ILLINOIS
      POWER COMPANYCONSOLIDATED
      BALANCE SHEET(Unaudited)
      (In millions)September
      30,
            
            
            December
      31,2008
            
            
            2007ASSETSCurrent
      Assets:Cash
      and cash equivalents
            $
            12
            
            
            $
            6Accounts
      receivable - trade (less allowance for doubtfulaccounts
      of $9 and $9, respectively)
            
            122
            
            
            
            137Unbilled
      revenue
            
            59
            
            
            
            118Accounts
      receivable – affiliates
            
            39
            
            
            
            17Advances
      to money pool
            
            9
            
            
            
            -Materials
      and supplies
            
            202
            
            
            
            134Other
      current assets
            
            74
            
            
            
            38Total
      current assets
            
            517
            
            
            
            450Property
      and Plant, Net
            
            2,285
            
            
            
            2,220Investments
      and Other Assets:Investment
      in IP SPT
            
            11
            
            
            
            10Goodwill
            
            214
            
            
            
            214Regulatory
      assets
            
            305
            
            
            
            316Other
      assets
            
            46
            
            
            
            109Total
      investments and other assets
            
            576
            
            
            
            649TOTAL
      ASSETS
            $
            3,378
            
            
            $
            3,319LIABILITIES
      AND STOCKHOLDERS’ EQUITYCurrent
      Liabilities:Current
      maturities of long-term debt
            $
            251
            
            
            $
            -Current
      maturities of long-term debt payable to IP SPT
            
            -
            
            
            
            54Short-term
      debt
            
            304
            
            
            
            175Accounts
      and wages payable
            
            96
            
            
            
            85Accounts
      payable – affiliates
            
            38
            
            
            
            36Taxes
      accrued
            
            10
            
            
            
            7Customer
      deposits
            
            49
            
            
            
            40Other
      current liabilities
            
            109
            
            
            
            40Total
      current liabilities
            
            857
            
            
            
            437Long-term
      Debt, Net
            
            757
            
            
            
            1,014Long-term
      Debt to IP SPT
            
            -
            
            
            
            2Deferred
      Credits and Other Liabilities:Regulatory
      liabilities
            
            86
            
            
            
            129Accrued
      pension and other postretirement benefits
            
            185
            
            
            
            189Accumulated
      deferred income taxes
            
            137
            
            
            
            148Other
      deferred credits and liabilities
            
            98
            
            
            
            92Total
      deferred credits and other liabilities
            
            506
            
            
            
            558Commitments
      and Contingencies (Notes 2, 8 and 9)Stockholders'
      Equity:Common
      stock, no par value, 100.0 shares authorized – 23.0 shares
      outstanding
            
            -
            
            
            
            -Other
      paid-in-capital
            
            1,194
            
            
            
            1,194Preferred
      stock not subject to mandatory redemption
            
            46
            
            
            
            46Retained
      earnings
            
            14
            
            
            
            64Accumulated
      other comprehensive income
            
            4
            
            
            
            4Total
      stockholders' equity
            
            1,258
            
            
            
            1,308TOTAL
      LIABILITIES AND STOCKHOLDERS' EQUITY
            $
            3,378
            
            
            $
            3,319




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





28





ILLINOIS
      POWER COMPANYCONSOLIDATED
      STATEMENT OF CASH FLOWS(Unaudited)
      (In millions)Nine
      Months EndedSeptember
      30,2008
            
            
            2007Cash
      Flows From Operating Activities:Net
      income (loss)
            $
            (2
            )
            
            $
            18Adjustments
      to reconcile net income (loss) to net cashprovided
      by operating activities:Depreciation
      and amortization
            
            83
            
            
            
            78Amortization
      of debt issuance costs and premium/discounts
            
            7
            
            
            
            6Deferred
      income taxes
            
            23
            
            
            
            8Other
            
            -
            
            
            
            (1
            )Changes
      in assets and liabilities:Receivables
            
            52
            
            
            
            (50
            )Materials
      and supplies
            
            (68
            )
            
            
            (34
            )Accounts
      and wages payable
            
            13
            
            
            
            (45
            )Taxes
      accrued, net
            
            5
            
            
            
            -Assets,
      other
            
            (14
            )
            
            
            (16
            )Liabilities,
      other
            
            31
            
            
            
            54Pension
      and other postretirement benefit obligations
            
            (10
            )
            
            
            5Net
      cash provided by operating activities
            
            120
            
            
            
            23Cash
      Flows From Investing Activities:Capital
      expenditures
            
            (128
            )
            
            
            (132
            )Changes
      in money pool advances
            
            (9
            )
            
            
            -Other
            
            (2
            )
            
            
            (1
            )Net
      cash used in investing activities
            
            (139
            )
            
            
            (133
            )Cash
      Flows From Financing Activities:Dividends
      on common stock
            
            (45
            )
            
            
            -Dividends
      on preferred stock
            
            (2
            )
            
            
            (2
            )Capital
      issuance costs
            
            (2
            )
            
            
            -Short-term
      debt, net
            
            129
            
            
            
            125Changes
      in money pool borrowings, net
            
            -
            
            
            
            52Redemptions,
      repurchases and maturities of long-term debt
            
            (337
            )
            
            
            -Issuance
      of long-term debt
            
            336
            
            
            
            -IP
      SPT maturities
            
            (54
            )
            
            
            (65
            )Net
      cash provided by financing activities
            
            25
            
            
            
            110Net
      change in cash and cash equivalents
            
            6
            
            
            
            -Cash
      and cash equivalents at beginning of year
            
            6
            
            
            
            -Cash
      and cash equivalents at end of period
            $
            12
            
            
            $
            -


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


29







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, 2008





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’s primary assets are the common stock
of its subsidiaries. Ameren’s subsidiaries are separate, independent legal
entities with separate businesses, assets and liabilities. These subsidiaries
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.
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 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,
which until February 29, 2008, was held 40% by UE and 40% by Development
Company. Ameren consolidates EEI for financial reporting purposes, while UE
reported EEI under the equity method until February 29, 2008. Effective February
29, 2008, UE’s and Development Company’s ownership interests in EEI were
transferred to Resources Company through an internal reorganization. UE’s
interest in EEI was transferred at book value indirectly through a dividend to
Ameren. See Note 8 - Related Party Transactions for additional
information.





The
following table presents summarized financial information of EEI for the three
months and nine months ended September 30, 2008 and 2007.





Three
      Months
            
            
            Nine
      Months2008
            
            
            2007
            
            
            2008
            
            
            2007Operating
      revenues
            $
            183
            
            
            $
            117
            
            
            $
            430
            
            
            $
            324Operating
      income
            
            64
            
            
            
            53
            
            
            
            196
            
            
            
            158Net
      income
            
            41
            
            
            
            34
            
            
            
            123
            
            
            
            99





The
financial statements of Ameren, Genco, CILCORP and CILCO are prepared on a
consolidated basis. CIPS has no subsidiaries and therefore is not consolidated.
UE had a subsidiary in 2007 (Union Electric Development Corporation), but in
January 2008 this subsidiary was transferred to Ameren in the form of a stock
dividend and in March 2008 was merged into an Ameren nonregistrant subsidiary.
Accordingly, UE’s financial statements were prepared on a consolidated basis for
2007 only. IP had a subsidiary in 2007 (Illinois Gas Supply Company) that was
dissolved on December 31, 2007. Accordingly, IP’s financial statements were
prepared on a consolidated basis for 2007 only.




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 that may be expected for a full year. These financial
statements should be read in conjunction with the financial statements and the
notes thereto included in the Form 10K.





Earnings
Per Share





There
were no material differences between Ameren’s basic and diluted earnings per
share amounts for the three






30


months
and nine months ended September 30, 2008 and 2007. The number of stock options,
restricted stock shares, and performance share units outstanding was
immaterial.




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





A summary
of nonvested shares as of September 30, 2008, under the Long-term Incentive Plan
of 1998, as amended, and the 2006 Omnibus Incentive Compensation Plan (2006
Plan) is presented below:





Performance
      Share Units
            Restricted
      SharesShares
            Weighted-average
              Fair
      Value Per Unit
            Shares
            Weighted-average
              Fair
      Value Per ShareNonvested
      at January 1,
      2008
            669,403
            $     
      57.88
            316,768
            $     46.23Granted(a)
            495,847
            47.57
            -
            -Dividends
            -
            -
            9,319
            41.51Forfeitures
            (7,747)
            54.39
            (2,163)
            48.19Vested(b)
            (236,811)
            53.50
            (114,286)
            44.05Nonvested
      at September 30,
      2008
            920,692
            $ 
          53.48
            209,638
            $
           47.46





(a)
            Includes
      performance share units (share units) granted to certain executive and
      nonexecutive officers and other eligible employees in February 2008 under
      the 2006 Plan.


(b)
            Share
      units vested due to 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.





The fair value of each share unit
awarded in February 2008 under the 2006 Plan was determined to be $47.57 based
on Ameren’s closing common share price of $44.30 per share at the grant date and
lattice simulations used to estimate expected share payout based on Ameren’s
attainment of certain financial measures relative to the designated peer group.
The significant assumptions used to calculate fair value also included a
three-year risk-free rate of 2.264%, dividend yields of 2.3% to 5.4% for the
peer group, volatility of 14.43% to 21.51% for the peer group, and Ameren’s
maintenance of its $2.54 annual dividend over the performance
period.





Ameren recorded compensation expense
of $7 million and $4 million for the quarters ended September 30, 2008 and 2007,
respectively, and a related tax benefit of $3 million and $2
million for the quarters ended September 30, 2008 and 2007, respectively. Ameren
recorded compensation expense of $21 million and $13 million for each of the
nine-month periods ended September 30, 2008 and 2007, respectively, and a
related tax benefit of $8 million and $5 million for the nine-month periods
ended September 30, 2008 and 2007, respectively. As of September 30, 2008, total
compensation cost of $21 million related to nonvested awards not yet recognized
is expected to be recognized over a weighted-average period of 22
months.





Accounting
Changes and Other Matters





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 required
disclosures about fair value measurements. See Note 7 - Fair Value Measurements
for additional information on our adoption of SFAS No. 157 in the first quarter
of 2008.





FSP
157-3, Determining the Fair
Value of a Financial Asset When the Market for That Asset Is Not
Active





In
October 2008, the FASB issued FSP 157-3, which clarifies the application of SFAS
No. 157 in a market that is not active and provides an example to illustrate key
considerations in determining the fair value of a financial asset when the
market for that financial asset is not active. FSP 157-3 was effective upon
issuance, and applied, retroactively to periods for which financial statements
had not yet been issued. We considered FSP 157-3 in our determination of
estimated fair values as of September 30, 2008, and it did not have a material
impact on our results of operations, financial condition, or
liquidity.





SFAS No.
161, Disclosures about
Derivative Instruments and Hedging Activities - an amendment of SFAS No.
133





In March
2008, the FASB issued SFAS No. 161, which requires enhanced disclosures for
derivative instruments and for hedging activities. SFAS No. 161 is intended to
enable investors to better understand the effects of derivative instruments and
hedging activities on an entity’s financial position, financial performance and
cash flows. SFAS No. 161 will be effective in the first quarter of 2009. The
adoption of SFAS No. 161 will not have a material impact on our results of
operations, financial position or liquidity since it only provides enhanced
disclosure requirements.








31





Goodwill
and Intangible Assets





Goodwill.Goodwill represents
the excess of the purchase price of an acquisition over the fair value of the
net assets acquired. We evaluate goodwill for impairment in the fourth quarter
of each year, or more frequently if events and circumstances indicate that the
carrying amount might be impaired. Ameren’s and IP’s goodwill relates to the
acquisitions of IP and an additional 20% ownership interest in EEI in 2004, and
Ameren’s and CILCORP’s goodwill relates to the acquisitions of CILCORP and
Medina Valley in 2003. For the period from January 1, 2008 to September 30,
2008, there were no changes in the carrying amount of goodwill.





Intangible Assets.We
evaluate intangible assets for impairment if events and circumstances indicate
that their carrying amount might be impaired. See also Note 9 - Commitments and
Contingencies. Ameren’s, UE’s, Genco’s, CILCORP’s and CILCO’s intangible assets
consisted of emission allowances at September 30, 2008.





The following table presents the
SO2
and NOx emission
allowances held and the related aggregate SO2 and
NOx
emission allowance book values that were carried as intangible assets as of
September 30, 2008. Emission allowances consist of various individual emission
allowance certificates and do not have expiration dates. Emission allowances are
charged to fuel expense as they are used in operations.





SO2
      (a)
            NOx
      (b)
            Book
      Value(c)Ameren(d)
            3.067
            15,834
            $     167(e)UE
            1.678
            5,610
            50Genco
            0.723
            8,928
            45CILCORP(f)
            0.342
            135
            36CILCO
      (AERG)
            0.342
            135
            1EEI
            0.324
            1,161
            9





(a)
            Vintages
      are from 2008 to 2018. Each company possesses additional allowances for
      use in periods beyond 2018. Units are in millions of SO2
      allowances (currently one allowance equals one ton
    emitted).


(b)
            Vintage
      is 2008. Units are in NOx
      allowances (one allowance equals one ton
  emitted).


(c)
            The
      book value represents SO2 and
      NOx
      emission allowances for use in periods through
  2031.


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


(e)
            Includes
      $27 million assigned to EEI allowances as a result of purchase
      accounting.


(f)
            Includes
      fair market value adjustments recorded in connection with Ameren’s
      acquisition of CILCORP.





The
following table presents the amortization expense based on usage of emission
allowances, net of gains from emission allowance sales, for Ameren, UE, Genco,
and CILCORP during the three months and nine months ended September 30, 2008 and
2007.





Three
      Months
            
            
            Nine
      Months2008
            
            
            2007
            
            
            2008
            
            
            2007Ameren(a)
            $
            9
            
            
            $
            7
            
            
            $
            25
            
            
            $
            27UE
            
            -
            
            
            
            (5
            )
            
            
            (1
            )
            
            
            (5
            )Genco
            
            7
            
            
            
            8
            
            
            
            20
            
            
            
            23CILCORP(b)
            
            2
            
            
            
            3
            
            
            
            5
            
            
            
            6





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


(b)
            Includes
      allowances consumed that were recorded through purchase
      accounting.





Excise
Taxes





Excise
taxes imposed on us are reflected on Missouri electric, Missouri gas, and
Illinois gas customer bills. They are recorded gross in Operating Revenues and
Taxes Other than Income Taxes on the statement of income. Excise taxes reflected
on Illinois electric customer bills are imposed on the consumer and are
therefore not included in revenues and expenses. They are recorded as tax
collections payable and included in Taxes Accrued. 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, 2008 and
2007:




Three
      Months
            
            
            Nine
      Months2008
            
            
            2007
            
            
            2008
            
            
            2007Ameren
            $
            43
            
            
            $
            46
            
            
            $
            130
            
            
            $
            128UE
            
            36
            
            
            
            38
            
            
            
            88
            
            
            
            88CIPS
            
            2
            
            
            
            2
            
            
            
            11
            
            
            
            11CILCORP
            
            1
            
            
            
            2
            
            
            
            8
            
            
            
            8CILCO
            
            1
            
            
            
            2
            
            
            
            8
            
            
            
            8IP
            
            4
            
            
            
            4
            
            
            
            23
            
            
            
            21




Coal
Contract Settlement





In June
2008, Genco entered into an agreement with a coal mine owner that provided Genco
a lump-sum payment of $60 million in July 2008, due to the coal mine owner’s
premature closing of a mine and the early termination of a




32


coal
supply contract. The settlement agreement compensates Genco, in total, for
higher fuel costs it expects to incur in 2008 and 2009 as a result of the mine
closure and contract termination.





Uncertain
Tax Positions





The
amount of unrecognized tax benefits as of September 30, 2008, was $115 million,
$19 million, less than $1 million, $43 million, $21 million, $21 million
and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP,
respectively. The total unrecognized tax benefits (detriments) that would impact
the effective tax rate, if recognized, for each of the respective companies was
as follows: Ameren - $23 million, UE - $3 million, CIPS - none, Genco - ($1
million), CILCORP - less than $1 million, CILCO - less than $1 million, and IP -
none.





Ameren is
currently under federal income tax examination for years 2005, 2006 and 2007.
State income tax returns are generally subject to examination for a period of
three years after filing of the return. The state impact of any federal changes
remains subject to examination by various states for a period of up to one year
after formal notification to the states.





It is
reasonably possible that events will occur during the next 12 months that would
cause the total amount of unrecognized tax benefits to increase or decrease;
however, the Ameren Companies do not believe such increases or decreases would
be material to their financial condition or results of operations.





Asset
Retirement Obligations





AROs at
Ameren and UE increased compared to December 31, 2007, to reflect the accretion
of obligations to their fair values.





NOTE
2 - RATE AND REGULATORY MATTERS





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





Missouri





Electric




UE filed
a request with the MoPSC in April 2008 to increase its annual revenues for
electric service by $251 million. The electric rate increase request
proposes an average increase in electric rates of 12.1% and is based on a 10.9%
return on equity, a capital structure composed of 51% common equity, a rate base
of $5.9 billion and a test year ended March 31, 2008, with updates for known and
measurable changes through September 30, 2008. In the filing, UE also requested
that the MoPSC approve implementation of a fuel and purchased power cost
recovery mechanism.





In August
2008, the MoPSC staff filed a report and direct testimony with the MoPSC
recommending an increase in annual revenues for electric service for UE of $51
million based on a 9.5% return on equity. The MoPSC staff opposed UE’s request
to implement a fuel and purchased power cost recovery mechanism. The Office of
Public Counsel and intervenors also filed testimony with the MoPSC in August
2008 opposing certain aspects of UE’s April 2008 request.





In
October 2008, UE filed rebuttal testimony with the MoPSC requesting approval of
a mechanism that would permit timely cost recovery of vegetation management and
infrastructure inspection and repair costs.





The MoPSC
proceeding relating to the proposed electric service rate changes will take
place over a period of up to 11 months, and a decision by the MoPSC in such
proceeding is required by March 2009. UE cannot predict the level of any
electric service rate change the MoPSC may approve, when any rate change may go
into effect, whether the fuel and purchased power cost recovery mechanism and
the vegetation management and infrastructure inspection and repair cost recovery
mechanism will be approved, or whether any rate increase that may eventually be
approved will be sufficient for UE to recover its costs and earn a reasonable
return on its investments when the increase goes into effect.





January
2007 Ice Storm Cost Recovery





UE
submitted a filing to the MoPSC in November 2007 requesting that operations and
maintenance expenses UE incurred as a result of a severe ice storm in January
2007 be deferred as a regulatory asset and, if approved, be amortized over five
years beginning with the effective date of electric rates approved in UE’s next
rate proceeding. UE incurred $25
million of operations and maintenance expenses in the first quarter of 2007 as a
result of the January storm. On April 30, 2008, the MoPSC issued an
accounting order that gave UE the ability to seek direct recovery of, and record
as a regulatory asset, all or a portion of these storm costs. The appropriate
amount to be amortized and the start date of the amortization will be decided in
UE’s rate case filed in April 2008. UE recorded a regulatory asset of $13
million in the second quarter of 2008, representing the minimum amount of its
storm costs that it expects to recover as a result of this order.




33




Illinois





Electric
and Natural Gas Delivery Service Rate Cases





On September 24, 2008, the ICC issued a
consolidated order approving a net increase in annual revenues for electric
delivery service of $123 million in the aggregate (CIPS - $22
million increase, CILCO - $3 million decrease, and IP - $104 million
increase) and a net increase in annual revenues for natural gas delivery service
of $38 million in the aggregate (CIPS - $7 million increase, CILCO - $9 million
decrease, and IP - $40 million increase), based on a 10.65% return on equity
with respect to electric delivery service and 10.68% return on equity with
respect to natural gas delivery service. These rate changes were effective on
October 1, 2008. Because of the Ameren Illinois Utilities’ pledge to keep the
overall residential electric bill increase resulting from these rate changes to
less than 10% for each utility, IP will not recover approximately $10 million in
revenue in the first year electric delivery service rates are in
effect.  Thereafter, residential electric delivery service rates will
be adjusted to recover the full increase.





In addition, the ICC changed the
depreciable lives used in calculating depreciation expense for the Ameren
Illinois Utilities’ electric and natural gas rates. As a result, annual
depreciation expense for the Ameren Illinois Utilities will be reduced for
financial reporting purposes by a net $13 million in the aggregate (CIPS - $4
million reduction, CILCO - $26
million reduction, and IP - $17 million increase).





The ICC rejected the Ameren Illinois
Utilities’ requested rate adjustment mechanisms for electric infrastructure
investments. As an alternative to the Ameren Illinois Utilities’ requested
decoupling of natural gas revenues from sales volumes, the ICC order approved an
increase in the percentage of costs to be recovered through fixed non-volumetric
residential and commercial customer charges to 80% from 53%.The ICC also
approved an increase in the Supply Cost Adjustment (SCA)factors for
the Ameren Illinois Utilities. The SCA is a charge applied only to the bills of
customers who take their power supply from the Ameren Illinois Utilities. The
change in the SCA factors is expected to result in increased electric revenues
of $9.5 million per year in the aggregate (CIPS - $2.6 million, CILCO - $1.6
million, and IP - $5.3 million), covering the increased cost of administering
the Ameren Illinois Utilities’ power supply responsibilities.





In October 2008, CIPS, CILCO and IP
requested that the ICC rehear its September 2008 consolidated order with respect
to its ruling regarding the treatment and level of short-term debt balances in
the capital structure. The Ameren Illinois Utilities assert that there is no
competent evidence in the record to support the staff position as adopted by the
ICC. Also in October 2008, other parties to these rate cases also filed for
rehearing of certain aspects of the ICC order. The Ameren Illinois Utilities
cannot predict the outcome of such requests for rehearing or, in the event the
requests are denied by the ICC, whether court appeals will be
filed.





Illinois Electric
Settlement Agreement





In 2007, an agreement was reached
among key stakeholders in Illinois to avoid rate rollback and freeze legislation
and legislation that would impose a tax on electric generation and to address
the increase in electric rates and the future power procurement process in
Illinois. The terms of the agreement include a comprehensive rate relief and
customer assistance program. The Illinois electric settlement agreement provides
approximately $1 billion of funding for rate relief for certain electric
customers in Illinois, including approximately $488 million to customers of the
Ameren Illinois Utilities. Pursuant to the Illinois electric settlement
agreement, the Ameren Illinois Utilities, Genco and CILCO (AERG) agreed to make
aggregate contributions of $150 million over a four-year period, with $60
million coming from the Ameren Illinois Utilities (CIPS - $21 million; CILCO -
$11 million; IP - $28 million), $62 million from Genco, and $28 million
from CILCO (AERG). See Note 9 - Commitments and Contingencies for information on
the remaining contributions to be made as of September 30, 2008.





The
Ameren Illinois Utilities, Genco and CILCO (AERG) recognize in their financial
statements the costs of their respective rate relief contributions and program
funding in a manner corresponding with the timing of the funding. Ameren, CIPS,
CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to
earnings, primarily recorded as a reduction to electric operating revenues,
during the quarter ended September 30, 2008, of $10 million, $2 million, less
than $1 million, $2 million, $4 million, and $2 million, respectively (quarter
ended September 30, 2007 - $59 million, $8 million, $5 million, $11 million, $24
million, and $11 million, respectively) and during the nine months ended
September 30, 2008, of $32 million, $5
million, $2 million, $6 million, $13 million, and $6 million, respectively
(nine months ended September 30, 2007 - $59 million, $8 million, $5
million, $11 million, $24 million, and $11 million, respectively) under the
terms of the Illinois electric settlement agreement.





Other
electric generators and utilities in Illinois agreed to contribute $851 million
to the comprehensive rate relief and customer assistance program. Contributions
by the other electric generators (the Generators) and utilities to the
comprehensive program are subject to funding agreements. Under these agreements,
at the end of each month, the Ameren Illinois Utilities send a bill, due in 30
days, to the Generators and utilities for their proportionate share of that
month’s rate relief and assistance. If any escrow funds have been provided by
the Generators, these funds will be drawn prior to seeking reimbursement from
the Generators. At September 30, 2008, Ameren, CIPS, CILCO (Illinois




34




Regulated)
and IP had receivable balances from nonaffiliated Illinois generators for
reimbursement of customer rate relief and program funding of $15 million, $5
million, $3 million, and $7
million, respectively.





Power
Procurement Plan





In September 2008, the IPA, which was
established as a part of the Illinois electric settlement agreement, filed an
electric power procurement plan with the ICC for both the Ameren Illinois
Utilities and Commonwealth Edison Company (Commonwealth Edison), the Illinois
electric utility subsidiary of Exelon Corporation. The plan, which requires the
approval of the ICC, outlines the wholesale products (capacity, energy swaps and
renewable energy credits) that the IPA will procure on behalf of the Ameren
Illinois Utilities for the period of June 1, 2009 through May 30, 2014. The
products will be procured through a RFP process, which is expected to begin in
February 2009, if the plan is approved. A decision is required by the ICC no
later than January 2009.





Redesigned
Rates





In late 2007, the ICC issued an
order, as amended, authorizing redesigned electric rates for CIPS, CILCO and IP
that was implemented January 1, 2008. These rates were designed to allow
utilities to recover their full costs while reducing seasonal fluctuations for
residential customers who use large amounts of electricity. While 2008 quarterly
results of operations and cash flows will be impacted, the redesigned rates are
not expected to have any impact on annual margins.





Natural
Gas Energy Efficiency Plan





In February 2008, the Ameren Illinois
Utilities filed a consolidated natural gas energy efficiency plan with the ICC.
In October 2008, the ICC issued an order approving the Ameren Illinois
Utilities’ natural gas energy efficiency plan as well as the cost recovery
mechanism by which the program costs will be recovered. The natural gas energy
efficiency plan includes annual reduction targets in natural gas usage as well
as spending limits for the 2009, 2010, and 2011 program years of $2 million, $4
million and $6 million, respectively.





ICC
Reliability Audit




In August 2007, the ICC retained Liberty Consulting Group to investigate,
analyze, and report to the ICC on the Ameren Illinois Utilities’ transmission
and distribution systems and reliability following the July 2006 wind storms and
a November 2006 ice storm. On October 8, 2008, Liberty Consulting Group
presented the ICC with a final report containing recommendations for the Ameren
Illinois Utilities to improve their systems and response to emergencies. The ICC
approved the report and directed the Ameren Illinois Utilities to prepare and
present to the ICC an implementation plan addressing Liberty Consulting Group’s
recommendations.  The implementation plan was submitted to the ICC on
November 8, 2008. Liberty Consulting Group will monitor the Ameren Illinois
Utilities’ efforts to implement the recommendations and any initiatives that the
Ameren Illinois Utilities undertake. At this time, we are unable to determine
the impact such implementation will have on our results of operations, financial
position, or liquidity.





Federal





Regional
Transmission Organization





As
required by the MoPSC, UE filed a study in November 2007 with the MoPSC
evaluating the costs and benefits of UE’s participation in MISO. UE’s
filing noted that there were a number of uncertainties associated with the
cost-benefit study, including issues associated with the UE-MISO service
agreement. The service agreement’s primary function was to ensure that the MoPSC
continued to set the transmission component of UE’s rates to serve its bundled
retail load. In June
2008, a stipulation and agreement among UE, the MoPSC staff, MISO and other
parties to the proceeding was filed with the MoPSC, which provides for UE’s
continued, conditional MISO participation through April 30, 2012. The
stipulation and agreement provides UE the right to seek permission from the
MoPSC for early withdrawal from MISO if UE determines that sufficient progress
toward mitigating some of the continuing uncertainties respecting its MISO
participation is not being made. The MoPSC issued an order, effective September
19, 2008, approving the stipulation and agreement.




FERC Order - MISO
Charges


In May
2007, UE, CIPS, CILCO and IP filed with the U.S.  Court of Appeals for the
District of Columbia Circuit, an appeal of FERC’s March 2007 order involving the
reallocation of certain MISO operational costs among MISO participants,
retroactive to 2005. In August 2007, the court granted FERC’s motion to hold the
appeal in abeyance pending completion of the continuing proceedings at FERC
regarding the allocation of these costs. Other MISO participants also filed
appeals. In November 2007, FERC issued two orders relative to these allocation
matters. One of these orders addressed requests for rehearing of prior orders in
the proceedings, and one concerned MISO’s compliance with FERC’s orders to date
in the proceedings. In December 2007, UE, CIPS, CILCO and IP requested FERC’s
clarification or rehearing of its November 2007 order regarding MISO’s
compliance with FERC’s orders. UE, CIPS, CILCO, and IP maintained that MISO is
required to reallocate certain of MISO’s operational costs among MISO market
participants resulting in refunds to UE, CIPS, CILCO, and IP. On November 7,
2008, FERC granted the request for clarification of UE, CIPS, CILCO and IP and
directed MISO to
   35
 reallocate
certain costs and provide refunds. We have not yet determined the impact of this
order on UE, CIPS, CILCO and IP, or on Genco and AERG, which are also market
participants in MISO.


UE
Power Purchase Agreement with Entergy Arkansas, Inc.





In July
2007, as a consequence of a series of orders issued by FERC addressing a
complaint filed by the Louisiana Public Service Commission (LPSC) against
Entergy Arkansas, Inc. (Entergy) and certain of its affiliates, which alleged
unjust and unreasonable cost allocations, Entergy commenced billing UE for
additional charges under a 165-megawatt power purchase agreement. Additional
charges are expected to continue during the remainder of the term of the power
purchase agreement, which expires August 25, 2009. Although UE was not a party
to the FERC proceedings that gave rise to these additional charges, UE has
intervened in related FERC proceedings and filed a complaint with the FERC
against Entergy and Entergy Services, Inc. in April 2008 to challenge the
additional charges. In September 2008, the presiding FERC administrative law
judge in this matter issued an initial decision finding that Entergy’s
allocation of such additional charges to UE is just and reasonable. The FERC is
expected to issue an order with respect to the administrative law judge’s
initial decision in 2009. UE is unable to predict whether FERC will grant it any
relief.




Additionally,
LPSC appealed FERC’s orders regarding LPSC’s complaint against Entergy to the
U.S. Court of Appeals for the District of Columbia. In April 2008, the court
issued a decision ordering further FERC proceedings regarding the LPSC
complaint. The court’s decision ordered FERC to explain its previous denial of
retroactive refunds and the implementation of prospective charges. FERC’s
decision on remand of the retroactive impact of these issues could have a
financial impact on UE. UE is unable to predict how FERC will respond to the
court’s decision. UE estimates that it could incur an additional one-time
expense of up to $25 million if FERC orders retroactive application for the
years 2001 to 2005. However, UE would contest such an order vigorously. Based on
existing facts and circumstances, UE believes that the likelihood of incurring
this $25 million expense is not probable, and, thus, no liability has been
recorded as of September 30, 2008. UE plans to participate in any proceeding
that FERC initiates to address the court’s decision.




Nuclear
Combined Construction and Operating License Application





In July 2008, UE filed an application
with the NRC for a combined construction and operating license for a potential
new 1,600 megawatt nuclear plant at UE’s existing Callaway County, Missouri
nuclear plant site. This COLA filing is not a commitment to build another
nuclear plant, but it is a necessary step to preserve the option to develop a
new nuclear plant in the future. The regulatory process for a COLA involves a
comprehensive review, estimated by the NRC to require up to 42 months for
completion.





Pumped-storage
Hydroelectric Facility Relicensing





In June
2008, UE filed a relicensing application with FERC in order to operate its Taum
Sauk pumped-storage hydroelectric facility for another 40 years. The current
FERC license expires on June 30, 2010. Approval and relicensure are expected in
2012. Operations are permitted to continue under the current license while the
renewal is pending.




NOTE
3 - SHORT-TERM BORROWINGS AND LIQUIDITY





The
liquidity needs of the Ameren Companies are typically supported through the use
of available cash, drawings under $2.15 billion of committed bank credit
facilities and commercial paper issuances.





The
following table summarizes the borrowing activity and relevant interest rates as
of September 30, 2008, under the $1.15 billion credit facility and the 2007
and 2006 $500 million credit facilities:





$1.15
      Billion Credit Facility
            Ameren
              (Parent)
            
            
            UE
            
            
            Genco
            
            
            TotalSeptember
      30, 2008:Average
      daily borrowings outstanding during 2008
            $
            424
            
            
            $
            169
            
            
            $
            54
            
            
            $
            647Outstanding
      short-term debt at period end
            
            275
            
            
            
            -
            
            
            
            -
            
            
            
            275Weighted-average
      interest rate during 2008
            
            3.69
            %
            
            
            3.42
            %
            
            
            3.97
            %
            
            
            3.64
            %Peak
      short-term borrowings during 2008(a)
            $
            675
            
            
            $
            493
            
            
            $
            150
            
            
            $
            1,068Peak
      interest rate during 2008
            
            7.25
            %
            
            
            5.65
            %
            
            
            5.53
            %
            
            
            7.25
            %








2007
      $500 Million Credit Facility
            
            CIPS
            
            
            CILCORP
              (Parent)
            
            
            CILCO
              (Parent)
            
            
            IP
            
            
            AERG
            
            
            TotalSeptember
      30, 2008:Average
      daily borrowings outstanding during 2008
            
            $
            -
            
            
            $
            125
            
            
            $
            56
            
            
            $
            161
            
            
            $
            94
            
            
            $
            436Outstanding
      short-term debt at period end
            
            
            -
            
            
            
            77
            
            
            
            75
            
            
            
            175
            
            
            
            100
            
            
            
            427Weighted-average
      interest rate during 2008
            
            
            -
            
            
            
            4.57
            %
            
            
            4.11
            %
            
            
            4.24
            %
            
            
            3.98
            %
            
            
            4.26
            %Peak
      short-term borrowings during 2008(a)
            
            $
            -
            
            
            $
            125
            
            
            $
            75
            
            
            $
            200
            
            
            $
            105
            
            
            $
            500Peak
      interest rate during 2008
            
            
            -
            
            
            
            6.66
            %
            
            
            6.47
            %
            
            
            6.15
            %
            
            
            6.22
            %
            
            
            6.66
            %2006
      $500 Million Credit FacilitySeptember
      30, 2008:Average
      daily borrowings outstanding during 2008
            
            $
            68
            
            
            $
            50
            
            
            $
            30
            
            
            $
            25
            
            
            $
            172
            
            
            $
            345Outstanding
      short-term debt at period end
            
            
            96
            
            
            
            50
            
            
            
            75
            
            
            
            129
            
            
            
            55
            
            
            
            405Weighted-average
      interest rate during 2008
            
            
            4.31
            %
            
            
            4.55
            %
            
            
            3.86
            %
            
            
            3.88
            %
            
            
            4.10
            %
            
            
            4.17
            %Peak
      short-term borrowings during 2008(a)
            
            $
            135
            
            
            $
            50
            
            
            $
            75
            
            
            $
            150
            
            
            $
            200
            
            
            $
            465Peak
      interest rate during 2008
            
            
            6.31
            %
            
            
            7.01
            %
            
            
            5.98
            %
            
            
            6.50
            %
            
            
            7.01
            %
            
            
            7.01
            %





(a)   The
simultaneous peak short-term borrowings under all three facilities during 2008
were $1.8 billion.





At
September 30, 2008, Ameren and certain of its subsidiaries had $2.15 billion of
committed credit facilities, consisting of the three facilities shown above, in
the amounts of $1.15
billion, $500 million and $500 million maturing in July 2010, January 2010, and
January 2010, respectively. Under the $1.15 billion facility, the termination
dates for UE’s and Genco’s direct borrowing sublimits thereunder are subject to
an annual 364-day renewal provision. Effective July 10, 2008, the termination
date was extended for UE and Genco from July 10, 2008, to July 9,
2009.




36


On
September 15, 2008, Lehman filed for protection under Chapter 11 of the federal
Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New
York. As of September 30, 2008, Lehman Brothers Bank, FSB, a subsidiary of
Lehman, had lending commitments of  $100 million and $21 million under
the $1.15 billion credit facility and the 2006 $500
million credit facility, respectively. The $50 million lending commitment of
another Lehman subsidiary under the 2007 $500 million credit facility was
assigned to a non-Lehman affiliated bank on or about September 17, 2008. At this
time, we do not know if Lehman Brothers Bank, FSB will seek to assign to other
parties any of its commitments within our credit facilities. Assuming Lehman
Brothers Bank, FSB does not fund its pro-rata share of funding or letter of
credit issuance requests under these two facilities, and such participations are
not assigned or otherwise transferred to other lenders, total amounts accessible
by the Ameren companies and AERG will be limited to amounts not less than $1.05
billion under the $1.15 billion credit facility and $479 million under the
2006 $500 million credit facility.





Based on
outstanding borrowings under the $1.15 billion credit facility and the 2007 and
2006 $500 million credit facilities (including reductions for a $9 million
letter of credit issued under the $1.15 billion credit facility and unfunded
Lehman participations under the $1.15 billion credit facility and the 2006 $500
million credit facility), the available amounts under the facilities at
September 30, 2008, were $791 million, $73 million, and $81 million,
respectively.





Access to
the $1.15 billion credit facility, the 2007 $500 million credit facility
and the 2006 $500 million credit facility for the Ameren Companies and AERG is
subject to reduction as borrowings are made by affiliates. Ameren and UE are
limited in their access to the commercial paper market as a result of downgrades
in 2006 in their short-term credit ratings.





On June
25, 2008, Ameren entered into a $300 million term loan agreement due June 24,
2009, which was fully drawn on June 26, 2008. In the event Ameren issues capital
stock or other equity interests (except for director or employee benefit or
dividend reinvestment plan purposes), certain equity-like hybrid securities or
certain additional indebtedness in amounts exceeding $25 million, Ameren is
required under the term loan agreement to use the resulting net proceeds to
prepay amounts borrowed under the agreement. The lenders under the term loan
agreement have waived this prepayment requirement to the extent the net proceeds
from the issuance of certain funded indebtedness are applied to repurchase or
redeem indebtedness of CILCORP. Additionally, if Ameren replaces its $1.15
billion credit facility with one or more credit facilities having a total
availablecommitment in
excess of $1.15
billion, Ameren is required under the term loan agreement to prepay amounts
borrowed thereunder in an amount equal to the excess of the new commitments over
$1.15 billion. Such mandatory prepayments are without premium or penalty (except
for any funding indemnity due in respect of Eurodollar loans).





Borrowings
under the $300 million term loan agreement will bear interest, at the election
of Ameren, at (1) a Eurodollar rate plus a margin, which margin is subject to a
floor of 0.90% per annum and a cap of 1.50% per annum, or (2) a rate equal to
the higher of the prime rate or the federal funds effective rate plus 0.50% per
year. Ameren used the proceeds borrowed under the term loan agreement to reduce
amounts borrowed under the $1.15 billion credit facility, which thereby made
additional amounts available for borrowing under that credit facility. The
average annual interest rate for borrowing under the $300 million term loan
agreement was 3.8% from its inception through September 30, 2008. The
obligations of Ameren under the term loan agreement are unsecured. No subsidiary
of Ameren is a party to, guarantor of, or borrower under, the term loan
agreement.





Indebtedness
Provisions and Other Covenants





The
information below presents a summary of the Ameren Companies’ and AERG’s
compliance with indebtedness provisions and other covenants. See Note 4 - Credit
Facilities and Liquidity in the Form 10-K for a detailed description of those
provisions.





The 2007
$500 million credit facility and 2006 $500 million credit facility limit
the amount of CIPS, CILCORP, CILCO and IP common and preferred stock dividend
payments to $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 received a below investment-grade credit rating from either
Moody’s or S&P. With respect to AERG, which currently is not rated by
Moody’s or S&P, the common and preferred stock dividend restriction will not
apply if its ratio of consolidated total debt to consolidated operating cash
flow, pursuant to a calculation defined in the facilities, is less than or equal
to 3.0 to 1.0. CILCORP’s senior unsecured long-term debt credit ratings from
Moody’s and S&P are below investment-grade, causing it to be subject to this
dividend payment limitation. As of September 30, 2008, AERG was in compliance
with the debt-to-operating cash flow ratio test in the 2007 and 2006 credit
facilities and thus was not subject to this limitation. CIPS, CILCO and IP are
not currently limited in their dividend payments by this provision of the 2007
or 2006 credit facilities. Ameren’s access to dividends from CILCO and AERG is
limited by the dividend payment limitation at CILCORP.





Under the
2007 $500 million and 2006 $500 million credit facilities, each of CIPS, CILCO
and IP had been required to reserve future bonding capacity under their
respective




37




mortgage
indentures (that is, they agreed to forego the issuance of additional mortgage
bonds otherwise permitted under the terms of each mortgage indenture). On March
26, 2008, CIPS, CILCO and IP and other parties to the credit facilities entered
into amendments to the credit facilities, which eliminated this
requirement.





The $300
million term loan agreement entered into in June 2008 has terms similar to the
$1.15 billion credit facility, except that amounts repaid under the term loan
agreement may not be reborrowed. The term loan agreement contains nonfinancial
covenants including restrictions on the ability to incur liens, dispose of
assets and merge with other entities. In addition, the term loan agreement has
nonfinancial covenants to limit the ability of Ameren to invest in or transfer
assets to other entities, including affiliates. The events of default under the
term loan agreement, including a cross default to the occurrence of an event of
default under the $1.15 billion credit facility or any other agreement covering
indebtedness of Ameren and its subsidiaries in excess of $25 million in the
aggregate, are similar to those contained in the $1.15 billion credit facility.
Each of CIPS, AERG, CILCORP, CILCO and IP and each of their subsidiaries is
excluded from the definition of “subsidiary” under the term loan agreement and
accordingly is not subject to certain of the covenants, representations, or
warranties under the term loan agreement. The term loan agreement requires
Ameren to maintain consolidated indebtedness of not more then 65% of
consolidated total capitalization pursuant to a calculation defined in the term
loan agreement.





The $1.15
billion credit facility, the 2007 $500 million credit facility, and the 2006
$500 million credit facility also limit the total indebtedness of each borrower
to 65% of total consolidated capitalization pursuant to a calculation set forth
in the facilities. As of September 30, 2008, the ratios of total indebtedness to
total consolidated capitalization, calculated in accordance with the provisions
of the $1.15 billion credit facility, were 53%, 48% and 50%, for Ameren, UE and
Genco, respectively. The ratios for CIPS, CILCORP, CILCO, IP and AERG,
calculated in accordance with the provisions of the 2007 $500 million credit
facility and 2006 $500 million credit facility, were 52%, 60%, 48%, 51% and 44%,
respectively. The ratio of consolidated indebtedness to consolidated total
capitalization for Ameren calculated in accordance with the provisions of the
$300 million term loan agreement was 53%.





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, 2008, management believes that the Ameren
Companies were in compliance with their credit facilities and term loan
agreement provisions and covenants.




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. Ameren
Services is responsible for the operation and administration of the money pool
agreements.





Utility





Through
the utility money pool, the pool participants may access borrowing capacity
available under the $1.15 billion, 2007 $500 million, and 2006 $500 million
credit facilities. See discussion above for amounts available under the
facilities at September 30, 2008. CIPS, CILCO and IP borrow from each other and
from Ameren through the utility money pool agreement subject to applicable
regulatory short-term borrowing authorizations. Ameren and AERG may participate
in the utility money pool only as lenders. The average interest rate for
borrowing under the utility money pool for the three months and nine months
ended September 30, 2008, was 2.9% and 3.3%, respectively (2007 - 5.4% and 5.7%,
respectively).





Non-state-regulated
Subsidiaries





Ameren
Services, Resources Company, Genco, AERG, Marketing Company, AFS and other
non-state-regulated Ameren subsidiaries have the ability, subject to Ameren
parent company authorization and applicable regulatory short-term borrowing
authorizations, to access borrowing capacity available under Ameren’s $1.15
billion credit facility through a non-state-regulated subsidiary money pool. See
discussion above for amount available under the $1.15 billion credit facility at
September 30, 2008. In addition, Ameren had $89 million of cash at September 30,
2008, which can be loaned into this arrangement. The average interest rate for
borrowing under the non-state-regulated subsidiary money pool for the three
months and nine months ended September 30, 2008, was 3.5% and 3.7%, respectively
(2007 - 5.6% and 5.1%, respectively).





See Note 8 - 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, 2008.





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) plan,
pursuant to an effective SEC Form S-8 registration statement, Ameren issued a
total of 0.8 million new shares of common stock




38




valued at
$32 million and 2.5 million new shares valued at $107 million in the three
months and nine months ended September 30, 2008, respectively.





UE





In April
2008, UE issued $250 million of 6.00% senior secured notes due April 1, 2018,
with interest payable semiannually on April 1 and October 1 of each year,
beginning in October 2008. UE received net proceeds of $248 million, which were
used to redeem certain of UE’s outstanding auction-rate environmental
improvement revenue refunding bonds discussed below and to repay short-term
debt. In connection with this issuance of $250 million of senior secured notes,
UE agreed, for so long as these senior secured notes are outstanding, that it
will not, prior to maturity, cause a first mortgage bond release date to occur.
The mortgage bond release date is the date at which the security provided by the
pledge under UE’s first mortgage indenture would no longer be available to
holders of any outstanding series of its senior secured notes and such
indebtedness would become senior unsecured indebtedness.





In April
2008, $63 million of UE’s Series 2000B auction-rate environmental improvement
revenue refunding bonds were redeemed at par value plus accrued
interest.





In May 2008, $43 million of UE’s
Series 1991, $64 million of UE’s Series 2000A and $60 million of UE’s Series
2000C auction-rate environmental improvement revenue refunding bonds were
redeemed at par value plus accrued interest. Also, in May 2008, $148 million of
UE’s 6.75% Series first mortgage bonds matured and were retired.





In June 2008, UE issued $450 million
of 6.70% senior secured notes due February 1, 2019, with interest payable
semiannually on February 1 and August 1 of each year, beginning in February
2009. UE received net proceeds of $446 million, which were used to repay
short-term debt, a portion of which was incurred to pay at maturity the 6.75%
Series first mortgage bonds noted above. In connection with this issuance of
$450 million of senior secured notes, UE agreed, for so long as these senior
secured notes are outstanding, that it will not, prior to maturity, cause a
first mortgage bond release date to occur.





CIPS





In April 2008, $35 million of CIPS’
Series 2004 auction-rate environmental improvement revenue refunding bonds were
redeemed at par value plus accrued interest.





Genco





In April 2008, Genco issued and sold,
with registration rights in a private placement, $300 million of 7.00% senior
unsecured notes due April 15, 2018, with interest payable semiannually on April
15 and October 15 of each year, beginning in October 2008. Genco received net
proceeds of $298 million, which are being used to fund capital expenditures,
repay short-term debt and for general corporate purposes.





In July 2008, Genco completed its
offer to exchange up to $300 million of its unregistered 7.00% senior unsecured
notes due April 15, 2018, for a like amount of registered 7.00% senior unsecured
notes due April 15, 2018. The entire aggregate principal amount of unregistered
notes was tendered for exchange and not withdrawn prior to the expiration of the
exchange offer.





CILCORP





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 and $4 million (2007 - $1 million and $4 million) for the
three months and nine months ended September 30, 2008, respectively, and was
included as a reduction to interest expense in the consolidated statements of
income of Ameren and CILCORP. See Note 4 - Credit Facilities and Liquidity in
the Form 10-K regarding CILCORP’s pledge of the common stock of CILCO as
security for its obligations under the 2007 $500 million credit facility and the
2006 $500 million credit facility.





In
September 2008, CILCORP commenced a cash tender offer for any and all of its
outstanding 8.70% senior notes due 2009 ($123.755 million aggregate principal
amount) and 9.375% senior bonds due 2029 ($210.565 million aggregate principal
amount), collectively, the “notes.” Concurrent with the tender offer, CILCORP
solicited consents from the holders of the notes to certain proposed amendments
to the indenture governing these securities. Any holder tendering securities as
part of this offer is deemed to consent to the proposed amendments. No consents
will be accepted separate from a tender of such holder’s securities. The
amendments would eliminate certain restrictive covenants in the indenture and
the notes. The total consideration for each $1,000 principal amount of 2009
notes validly tendered on or prior to the current consent and expiration date,
which has been extended to November 21, 2008, is $1,057.50. The total
consideration includes a consent payment of $40 per $1,000 principal amount of
such 2009 notes tendered on or prior to such date. The total consideration for
each $1,000 principal amount of 2029 bonds validly tendered on or prior to the
current November 21, 2008, consent and expiration date is $1,230, which includes
a consent payment of $50 per $1,000 principal amount of such 2029 bonds tendered
on or prior to such date. Holders validly tendering and not withdrawing notes on
or before the extended consent and expiration date are eligible to receive the
applicable total consideration. In




39




addition,
tenders of notes, including previously tendered notes, may be withdrawn (and
related consents may be rescinded) at any time prior to November 21, 2008. As of
October 31, 2008, CILCORP had received consents, net of those recinded, from the
holders of $122.8 million, or 99.3%, of its outstanding 2009 8.70% senior notes
and $206.7 million, or 98.2%, of its outstanding 2029 bonds. Consummation of the
tender offer and the consent solicitation is subject to a number of conditions,
including the absence of certain adverse legal and market developments, as
described in the offer to purchase. CILCORP has reserved the right to amend,
further extend, terminate, or waive any conditions to the tender offer and the
consent solicitation at any time. The impact on CILCORP’s net income of the
tender offer is expected to be approximately $3 million, if
consummated.





CILCO





In April
2008, $19 million of CILCO’s Series 2004 auction-rate environmental improvement
revenue refunding bonds were redeemed at par value plus accrued
interest.





In July
2008, CILCO redeemed the remaining 165,000 shares of its 5.85% Class A preferred
stock at a redemption price of $100 per share plus accrued and unpaid dividends.
The redemption completed CILCO’s mandatory redemption obligations for this
series of preferred stock.





IP





In
conjunction with Ameren’s acquisition of IP, IP’s long-term debt was recorded at
fair value. Amortization related to these fair value adjustments was $3 million
and $8 million (2007 - $3 million and $9 million) for the three months and nine
months ended September 30, 2008, respectively, and was included as a reduction
to interest expense in the consolidated statements of income of Ameren and
IP.





In April
2008, IP issued and sold, with registration rights in a private placement, $337
million of 6.25% senior secured notes due April 1, 2018, with interest payable
semiannually on April 1 and October 1 of each year, beginning in October 2008.
IP received net proceeds of $334 million, which were used to redeem all of IP’s
outstanding auction-rate pollution control revenue refunding bonds during May
and June 2008 as discussed below. In connection with IP’s April 2008 issuance of
$337 million of senior secured notes, IP agreed, for so long as these senior
secured notes are outstanding, that it will not, prior to maturity, cause a
first mortgage bond release date to occur. The mortgage bond release date is the
date at which the security provided by the pledge under IP’s first mortgage
indenture would no longer be available to holders of any outstanding series of
its senior secured notes and such indebtedness would become senior unsecured
indebtedness.





In May
2008, IP redeemed its $112 million Series 2001 Non-AMT, $75 million Series 2001
AMT, $70 million 1997 Series A, and $45 million 1997 Series B auction-rate
pollution control revenue bonds at par value plus accrued interest. In June
2008, IP redeemed its $35 million 1997 Series C auction-rate pollution control
revenue bonds at par value plus accrued interest.





In June 2008, IP completed its offer
to exchange up to $337 million of its unregistered 6.25% senior secured notes
due April 1, 2018, for a like amount of registered 6.25% senior secured notes
due April 1, 2018. The entire aggregate principal amount of unregistered
notes was tendered for exchange and not withdrawn prior to the expiration of the
exchange offer.





In September 2008, IP redeemed the
remaining portion of its $54 million principal amount 5.65% note payable to IP
SPT. Previous redemptions occurred in the first and second quarters of 2008 for
$19 million and $20 million, respectively. This was the remaining outstanding
amount of $864 million of TFNs issued by the IP SPT in December 1998, as allowed
under the Illinois Electric Utility Transition Funding Law.





In
October 2008, IP issued and sold, with registration rights in a private
placement, $400 million of 9.75% senior secured notes due November 15, 2018,
with interest payable semiannually on November 15 and May 15 of each year,
beginning in May 2009. IP received net proceeds of  $391 million,
which were used to repay short-term debt. In connection with IP’s October 2008
issuance of $400 million of senior secured notes, IP agreed, for so long as
these senior secured notes are outstanding, that it will not, prior to maturity,
cause a first mortgage bond release date to occur.




Indenture
Provisions and Other Covenants





The information below presents a
summary of the Ameren Companies’ compliance with indenture provisions and other
covenants. See Note 5 - Long-term Debt and Equity Financings in the Form 10-K
for a detailed description of those provisions.




40





UE’s,
CIPS’, CILCO’s and IP’s indentures and articles of incorporation include
covenants and provisions related to the issuances of first mortgage bonds and
preferred stock. The following table includes the required and actual earnings
coverage ratios for interest charges and preferred dividends and bonds and
preferred stock issuable based on the 12 months ended September 30, 2008, at an
assumed interest and dividend rate of 8%.





Required
      Interest Coverage Ratio(a)
            Actual
      Interest
              Coverage
      Ratio
            Bonds
              Issuable(b)
            Required
      Dividend Coverage Ratio(c)
            Actual
              Dividend
              Coverage
      Ratio
            Preferred
              Stock
              IssuableUE
            ≥
      2.0
            3.3
            $  
      1,703
            ≥
      2.5
            49.6
            $  
      1,400CIPS
            ≥
      2.0
            1.2
            38
            ≥
      1.5
            1.0
            -CILCO
            ≥
      2.0(d)
            15.3
            331
            ≥
      2.5
            49.7
            376(e)IP
            ≥
      2.0
            2.5
            873
            ≥
      1.5
            0.9
            -





(a)
            Coverage
      required on the annual interest charges on first mortgage bonds
      outstanding and to be issued. Coverage is not required in certain cases
      when additional first mortgage bonds are issued on the basis of retired
      bonds.


(b)
            Amount
      of bonds issuable based on either meeting required coverage ratios or
      unfunded property additions, whichever is more restrictive. In addition to
      these tests, UE, CIPS, CILCO and IP have the ability to issue bonds based
      upon retired bond capacity of $161 million, $38 million, $194 million
      and $686 million, respectively, which are included in the amounts
      above. No earnings coverage test is required for bonds issuable on the
      basis of retired bond capacity.


(c)
            Coverage
      required on the annual interest charges on all long-term debt (CIPS only)
      and the annual dividend on preferred stock outstanding and to be issued,
      as required in the respective company’s articles of incorporation. For
      CILCO, this ratio must be met for a period of 12 consecutive calendar
      months within the 15 months immediately preceding the
      issuance.


(d)
            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 nine months ended
      September 30, 2008, CILCO had earnings equivalent to at least 48% of the
      principal amount of all mortgage bonds
  outstanding.


(e)
            See
      Note 4 - Credit Facilities and Liquidity in the Form 10-K for a discussion
      regarding a restriction on the issuance of preferred stock by CILCO under
      the 2006 $500 million credit facility and the 2007 $500 million credit
      facility.





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 total retained earnings was restricted against payment of common
dividends, except those dividends payable in common stock, which left $1.9
billion of free and unrestricted retained earnings at September 30,
2008.





CILCO’s
articles of incorporation contain certain provisions that prohibit the payment
of dividends on its common stock (i) from either paid-in surplus or any surplus
created by a reduction of stated capital or capital stock, or (ii) if at the
time of dividend declaration, there shall not remain to the credit of earned
surplus account (after deducting the amount of such dividends) an amount at
least equal to two times the annual dividend requirement on all outstanding
shares of CILCO’s preferred stock.





Genco’s
and CILCORP’s indentures include provisions that require the companies to
maintain certain debt service coverage and/or debt-to-capital ratios in order
for the companies to pay dividends, to make certain principal or interest
payments, to make certain loans to or investments in affiliates, or to incur
additional indebtedness. The following table summarizes these ratios for the 12
months ended September 30, 2008:




Required
              Interest
      Coverage Ratio
            Actual
              Interest
      Coverage Ratio
            Required
              Debt-to-Capital
      Ratio
            Actual
              Debt-to-Capital
      RatioGenco(a)
            ≥1.75(b)
            9.3
            ≤60%
            49%CILCORP(c)
            ≥2.2
            3.8
            ≤67%
            24%





(a)
            Interest
      coverage ratio relates to covenants regarding certain dividends, principal
      and interest payments on certain subordinated intercompany borrowings and
      certain investments (collectively, restricted payments). 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 as projected for the
      succeeding four 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.





Genco’s
debt incurrence-related ratio restrictions and restricted payment limitations
under its indenture may be disregarded if both Moody’s and S&P reaffirm the
ratings of Genco in place at the time of the debt incurrence after considering
the additional indebtedness. In the event CILCORP is not in compliance with
these restrictions, CILCORP may make payments of dividends or intercompany loans
if its senior long-term debt rating is at least BB+ from S&P, Baa2 from
Moody’s, and BBB from Fitch. At September 30, 2008, CILCORP’s senior long-term
debt ratings from S&P, Moody’s and Fitch were BB+, Ba2, and BB+,
respectively. On October 16, 2008, Fitch upgraded CILCORP’s senior long-term
debt rating to BBB. The common stock of CILCO is pledged as security to the
holders of CILCORP’s senior notes and bonds and credit facility
obligations.




41




Off-Balance-Sheet
Arrangements





At
September 30, 2008, 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, 2008 and
2007:





Three
      Months
            
            
            Nine
      Months2008
            
            
            2007
            
            
            2008
            
            
            2007Ameren:(a)Miscellaneous
      income:Interest and dividend
      income
            $
            10
            
            
            $
            16
            
            
            $
            35
            
            
            $
            41Allowance for equity funds used
      during construction
            
            8
            
            
            
            2
            
            
            
            19
            
            
            
            2Other
            
            5
            
            
            
            2
            
            
            
            7
            
            
            
            10Total miscellaneous
      income
            $
            23
            
            
            $
            20
            
            
            $
            61
            
            
            $
            53Miscellaneous
      expense:Other
            $
            (10
            )
            
            $
            (9
            )
            
            $
            (23
            )
            
            $
            (19
            )Total miscellaneous
      expense
            $
            (10
            )
            
            $
            (9
            )
            
            $
            (23
            )
            
            $
            (19
            )UE:Miscellaneous
      income:Interest and dividend
      income
            $
            8
            
            
            $
            8
            
            
            $
            26
            
            
            $
            24Allowance for equity funds used
      during construction
            
            8
            
            
            
            1
            
            
            
            19
            
            
            
            1Other
            
            1
            
            
            
            -
            
            
            
            1
            
            
            
            3Total miscellaneous
      income
            $
            17
            
            
            $
            9
            
            
            $
            46
            
            
            $
            28Miscellaneous
      expense:Other
            $
            (2
            )
            
            $
            (5
            )
            
            $
            (6
            )
            
            $
            (9
            )Total miscellaneous
      expense
            $
            (2
            )
            
            $
            (5
            )
            
            $
            (6
            )
            
            $
            (9
            )CIPS:Miscellaneous
      income:Interest and dividend
      income
            $
            2
            
            
            $
            4
            
            
            $
            7
            
            
            $
            12Other
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            1Total miscellaneous
      income
            $
            3
            
            
            $
            5
            
            
            $
            9
            
            
            $
            13Miscellaneous
      expense:Other
            $
            -
            
            
            $
            (1
            )
            
            $
            (2
            )
            
            $
            (2
            )Total miscellaneous
      expense
            $
            -
            
            
            $
            (1
            )
            
            $
            (2
            )
            
            $
            (2
            )Genco:Miscellaneous
      income:Interest and dividend
      income
            $
            -
            
            
            $
            -
            
            
            $
            1
            
            
            $
            -Total miscellaneous
      income
            $
            -
            
            
            $
            -
            
            
            $
            1
            
            
            $
            -Miscellaneous
      expense:Other
            $
            (1
            )
            
            $
            -
            
            
            $
            (1
            )
            
            $
            -Total miscellaneous
      expense
            $
            (1
            )
            
            $
            -
            
            
            $
            (1
            )
            
            $
            -CILCORP:Miscellaneous
      income:Interest and dividend
      income
            $
            1
            
            
            $
            1
            
            
            $
            2
            
            
            $
            3Other
            
            -
            
            
            
            1
            
            
            
            -
            
            
            
            1Total miscellaneous
      income
            $
            1
            
            
            $
            2
            
            
            $
            2
            
            
            $
            4Miscellaneous
      expense:Other
            $
            (2
            )
            
            $
            (1
            )
            
            $
            (4
            )
            
            $
            (3
            )Total miscellaneous
      expense
            $
            (2
            )
            
            $
            (1
            )
            
            $
            (4
            )
            
            $
            (3
            )CILCO:Miscellaneous
      income:Interest and dividend
      income
            $
            1
            
            
            $
            1
            
            
            $
            2
            
            
            $
            3Other
            
            -
            
            
            
            1
            
            
            
            -
            
            
            
            1Total miscellaneous
      income
            $
            1
            
            
            $
            2
            
            
            $
            2
            
            
            $
            4


Miscellaneous
      expense:Other
            $
            (2
            )
            
            $
            (1
            )
            
            $
            (3
            )
            
            $
            (3
            )Total miscellaneous
      expense
            $
            (2
            )
            
            $
            (1
            )
            
            $
            (3
            )
            
            $
            (3
            )






42




Three
      Months
            
            
            Nine
      Months2008
            
            
            2007
            
            
            2008
            
            
            2007IP:Miscellaneous
      income:Interest and dividend
      income
            $
            -
            
            
            $
            2
            
            
            $
            4
            
            
            $
            5Other
            
            3
            
            
            
            2
            
            
            
            5
            
            
            
            4Total miscellaneous
      income
            $
            3
            
            
            $
            4
            
            
            $
            9
            
            
            $
            9Miscellaneous
      expense:Other
            $
            (2
            )
            
            $
            (2
            )
            
            $
            (5
            )
            
            $
            (3
            )Total miscellaneous
      expense
            $
            (2
            )
            
            $
            (2
            )
            
            $
            (5
            )
            
            $
            (3
            )





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





NOTE
6 - DERIVATIVE FINANCIAL INSTRUMENTS





The
following table presents the pretax net gain (loss) of power hedges and the net
change in market value of option and swap transactions used to manage our
positions in SO2
allowances, coal, heating oil, FTRs and nonhedge power and gas trading activity
for the three months and nine months ended September 30, 2008 and 2007. Certain
of these transactions have not been designated as cash flow hedges under SFAS
No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as
amended. The pretax net gain (loss) of power hedges 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 and is included in Operating Revenues - Electric. The net
change in the market value of SO2, coal and
heating oil options and swaps is recorded as Operating Expenses - Fuel. The
nonhedge power and gas transactions are recorded in Operating Revenues -
Electric and Operating Revenues - Gas.





Three
      Months
            
            
            Nine
      MonthsGains
      (Losses)
            2008
            
            
            2007
            
            
            2008
            
            
            2007Power
      hedges:Ameren
            $
            77
            
            
            $
            22
            
            
            $
            47
            
            
            $
            35UE
            
            10
            
            
            
            2
            
            
            
            5
            
            
            
            -SO2
      options and swaps:Ameren
            
            (1
            )
            
            
            -
            
            
            
            (1
            )
            
            
            6UE
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            5Genco
            
            (1
            )
            
            
            -
            
            
            
            (1
            )
            
            
            1Coal
      options:Ameren
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            2UE
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            2Heating
      oil options:Ameren
            
            (105
            )
            
            
            -
            
            
            
            4
            
            
            
            3UE
            
            (55
            )
            
            
            -
            
            
            
            5
            
            
            
            -Genco
            
            (29
            )
            
            
            -
            
            
            
            -
            
            
            
            -CILCORP/CILCO
            
            (7
            )
            
            
            -
            
            
            
            -
            
            
            
            -FTRs:Ameren
            
            (10
            )
            
            
            -
            
            
            
            4
            
            
            
            -UE
            
            (9
            )
            
            
            -
            
            
            
            3
            
            
            
            -Nonhedge
      power swaps and forwards:Ameren
            
            8
            
            
            
            3
            
            
            
            8
            
            
            
            (2
            )UE
            
            (1
            )
            
            
            2
            
            
            
            1
            
            
            
            (2
            )Gas
      forwards and swaps:Ameren
            
            (6
            )
            
            
            (2
            )
            
            
            (4
            )
            
            
            -UE
            
            (4
            )
            
            
            (2
            )
            
            
            (1
            )
            
            
            -CILCORP/CILCO
            
            (3
            )
            
            
            -
            
            
            
            (3
            )
            
            
            -




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, regulatory assets, or regulatory liabilities as of September 30,
2008:




Ameren(a)
              
              
              UE
              
              
              CIPS
              
              
              Genco
              
              
              CILCORP/
                CILCO
              
              
              IPDerivative
      instruments carrying value:Current assets
              $
              120
              
              
              $
              49
              
              
              $
              3
              
              
              $
              1
              
              
              $
              2
              
              
              $
              5Other assets
              
              34
              
              
              
              5
              
              
              
              8
              
              
              
              -
              
              
              
              5
              
              
              
              14Current
    liabilities
              
              92
              
              
              
              20
              
              
              
              19
              
              
              
              2
              
              
              
              16
              
              
              
              33Other deferred credits and
      liabilities(b)
              
              7
              
              
              
              3
              
              
              
              4
              
              
              
              -
              
              
              
              2
              
              
              
              5Gains
      (losses) deferred in accumulated OCI:Power forwards(c)
              
              46
              
              
              
              23
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Interest rate swaps(d)(e)
              
              (11
              )
              
              
              -
              
              
              
              -
              
              
              
              (11
              )
              
              
              -
              
              
              
              -
   43
  Ameren(a)
              
              
              UE
              
              
              CIPS
              
              
              Genco
              
              
              CILCORP/
                CILCO
              
              
              IP
 Gas swaps and futures
      contracts(f)
              
              (2
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Coal options and
      swaps
              
              7
              
              
              
              8
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Gains
      (losses) deferred in regulatory assets or liabilitiesGas
      swaps and futures contracts(f)
              
              (37
              )
              
              
              (3
              )
              
              
              (10
              )
              
              
              -
              
              
              
              (9
              )
              
              
              (15
              )Financial
      contracts(g)
              
              -
              
              
              
              -
              
              
              
              (2
              )
              
              
              -
              
              
              
              (1
              )
              
              
              (3
              )


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


(b)
            Includes
      Ameren and UE’s carrying value of fair value foreign currency forward
      contracts.


(c)
            Represents
      the mark-to-market value for the hedged portion of electricity price
      exposure for periods of up to three years, including gains of $59 million
      and $21 million over the next 12 months at Ameren and UE,
      respectively.


(d)
            Includes
      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. The
      carrying value at September 30, 2008, was $2
  million.


(e)
            Includes
      a loss associated with interest rate swaps at Genco. The swaps were
      executed during the fourth quarter of 2007 as a partial hedge of interest
      rate risks associated with Genco’s April 2008 debt issuance. The
      cumulative loss on the interest rate swaps is being amortized over a
      10-year period that began in April 2008. The carrying value at September
      30, 2008 was a loss of $13 million.


(f)
            Represents
      losses associated with natural gas swaps and futures contracts. The swaps
      and futures contracts are a partial hedge of our natural gas requirements
      through 2012 at Ameren, UE, and CIPS, and through 2011 at CILCORP, CILCO
      and IP.


(g)
            Current
      gains deferred as regulatory liabilities include $3 million at CIPS, $2
      million at CILCO, and $5 million at IP that were recorded in other current
      liabilities at September 30, 2008. Current losses deferred as regulatory
      assets include $(10) million at CIPS, $(5) million at CILCO, and $(15)
      million at IP that were recorded in other current assets at September 30,
      2008.





As part
of the Illinois electric settlement agreement, the Ameren Illinois Utilities
entered into financial contracts with Marketing Company. These financial
contracts are derivative instruments being accounted for as cash flow hedges at
Marketing Company. Consequently, the Ameren Illinois Utilities and Marketing
Company record the fair value of the contracts on their respective balance
sheets and the changes to the fair value in regulatory assets or liabilities for
the Ameren Illinois Utilities and OCI at Marketing Company. In Ameren’s
consolidated financial statements, all financial statement effects of the swap
are eliminated. See Note 2 - Rate and Regulatory Matters under Part II, Item 8
in the Form 10-K for additional information on these financial
contracts.




During
the third quarter ended September 30, 2008, UE entered into foreign currency
forward contracts. These derivative instruments are intended to fix the amount
of U.S. dollars UE will pay for future equipment deliveries denominated in euros
as part of a firm commitment to purchase heavy forgings needed if UE decides to
build a second nuclear plant. These forward contracts qualify as fair value
hedges and, as a result, both the derivative positions and the foreign currency
exposure on the firm commitment are recorded at fair value. The change in the
fair value of both the derivative instrument and the hedged item are recorded in
earnings.  For the quarter ended September 30, 2008, this hedging program
was highly effective, resulting in no impact to net income.


Derivative
instruments are subject to various credit-related losses in the event of
nonperformance by counterparties to the contracts. In order to mitigate these
risks, collateral requirements are established. As of September 30, 2008,
Ameren, UE, CIPS, CILCORP, CILCO and IP had collateral postings with external
parties of $35 million, $2 million, $7 million, $5
million, $5 million, and $11 million, respectively. The amounts of collateral
external counterparties posted with Ameren, UE, CIPS, CILCORP, CILCO, and IP
were immaterial at September 30, 2008. See Note 8 - Related Party Transactions
for information regarding collateral postings with affiliates.





On
September 15, 2008, Lehman filed for protection under Chapter 11 of the federal
Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New
York. At that time, UE, CIPS, Genco, IP, Marketing Company and AFS were
counterparties with Lehman Brothers Commodity Services Inc. (Lehman Commodity
Services) and Eagle Energy Partners I, LP (Eagle Energy), subsidiaries of
Lehman, in energy commodity transactions that support their utility and
generation businesses. The obligations of Lehman Commodity Services and
Eagle Energy are guaranteed
by Lehman, and the Lehman bankruptcy filing gives UE, CIPS, Genco, IP, Marketing
Company and AFS the right to terminate any open transactions. As of October
31, 2008, Ameren’s and its subsidiaries’ direct exposure to Lehman Commodity
Services and Eagle Energy, based on existing transactions and current market
prices, was estimated to be less than $1
million before taxes, collectively.





NOTE
7 - FAIR VALUE MEASUREMENTS





SFAS No.
157 provides a framework for measuring fair value for all assets and liabilities
that are measured and reported at fair value. This standard was effective and
adopted by the Ameren Companies as of January 1, 2008, for financial assets and
liabilities. The impact of this adoption of SFAS No. 157 was not material. SFAS
No. 157 will be effective in the first quarter of 2009 for all nonfinancial
assets and liabilities that are measured and






44




reported
on a fair value basis. The impact of adoption of SFAS No. 157 for nonfinancial
assets and liabilities is not expected to be material. SFAS No. 157 defines fair
value as the exchange price that would be received for an asset or paid to
transfer a liability (an exit price) in the principal or most advantageous
market for the asset or liability in an orderly transaction between market
participants on the measurement date. We use various methods to determine fair
value, including market, income and cost approaches. Based on these approaches,
we use certain assumptions that market participants would use in pricing the
asset or liability, including assumptions about risk or the risks inherent in
the inputs to the valuation. Inputs to valuation can be readily observable,
market corroborated, or unobservable. We use valuation techniques that maximize
the use of observable inputs and minimize the use of unobservable inputs. SFAS
No. 157 also establishes a fair value hierarchy that prioritizes the inputs used
to measure fair value. All financial assets and liabilities carried at fair
value are classified and disclosed in one of the following three hierarchy
levels:





Level 1:
Inputs based on quoted prices in active markets for identical assets or
liabilities. Level 1 assets and liabilities primarily include exchange-traded
derivatives and assets such as U.S. treasury securities and listed equity
securities, such as those held in UE’s Nuclear Decommissioning Trust
Fund.





Level 2:
Market-based inputs corroborated by third party brokers or exchanges based on
transacted market data. Level 2 assets and liabilities include certain assets
held in UE’s Nuclear Decommissioning Trust Fund, including corporate bonds and
other fixed income securities, and certain over-the-counter derivative
instruments, including natural gas swaps and financial power transactions.
Derivative instruments classified as Level 2 are valued using corroborated
observable inputs including those from pricing services or prices from similar
instruments that trade in liquid markets. Our development and corroboration
process entails obtaining multiple quotes or prices from outside sources. To
derive our forward view to price our derivative instruments at fair value, we
average the midpoints of the bid/ask spreads. In order to validate forward
prices from outside parties, the pricing is compared to recently settled market
transactions. Additionally, a review of all sources is performed to
identify any anomalies or potential errors. Further, the volume of transactions
that occurred on certain trading platforms is considered in our reasonableness
assessment of the averaged midpoint.





Level 3:
Unobservable inputs that are not corroborated by market data. Level 3 assets and
liabilities are valued based on internally-developed models and assumptions or
methodologies using significant unobservable inputs. Level 3 assets and
liabilities include derivative instruments that trade in less liquid markets
where pricing is largely unobservable, including the financial contracts entered
into between the Ameren Illinois Utilities and Marketing Company as part of the
Illinois electric settlement agreement. We value Level 3 instruments using
pricing models with inputs, which are often unobservable in the market, and
certain internal assumptions. Our development and corroboration process entails
obtaining multiple quotes or prices from outside sources. As a part of our
reasonableness review, a review of all sources is performed to identify any
anomalies or potential errors.





We
perform an analysis each quarter to determine the appropriate hierarchy level of
the assets and liabilities that are subject to SFAS No. 157. Financial assets
and liabilities are classified in their entirety based on the lowest level of
input that is significant to the fair value measurement. All assets and
liabilities where the fair value measurement is based on significant
unobservable inputs are classified as Level 3.





We
consider nonperformance risk in our valuation of derivative instruments by
analyzing the credit standing of our counterparties and considering any
counterparty credit enhancements (e.g. collateral). SFAS No. 157 also requires
that the fair value measurement of liabilities reflect the nonperformance risk
of the reporting entity, as applicable. Therefore, we have factored the impact
of our credit standing as well as any potential credit enhancements into the
fair value measurement of both derivative assets and derivative liabilities.
Included in our valuation, and based on current market conditions, is a
valuation adjustment for counterparty default derived from market data such as
the price of credit default swaps, bond yields and credit ratings. Ameren
recorded $2.5 million in losses in
the third quarter of 2008 related to valuation adjustments for counterparty
default risk. At September 30, 2008, the counterparty default risk valuation
adjustment related to net derivative (assets) liabilities totaled $(4)
million, $(2) million, and $1 million for Ameren, UE, and IP,
respectively.




45


The
following table sets forth, by level within the fair value hierarchy, our assets
and liabilities measured at fair value on a recurring basis as of September 30,
2008:





Quoted
      Prices in
              Active
      Markets for
              Identified
      Assets
              (Level
      1)
            
            
            Significant
      Other
              Observable
      Inputs
              (Level
      2)
            
            
            Significant
      Other
              Unobservable
      Inputs
              (Level
      3)
            
            
            TotalAssets:Ameren(a)
            Other
      current
      assets
            
            $
            -
            
            
            $
            -
            
            
            $
            16
            
            
            $
            16Derivative
      assets(b)
            
            
            -
            
            
            
            41
            
            
            
            113
            
            
            
            154Nuclear
      DecommissioningTrust
      Fund(c)
            
            
            200
            
            
            
            83
            
            
            
            1
            
            
            
            284UE
            Derivative
      assets
            
            
            -
            
            
            
            24
            
            
            
            30
            
            
            
            54Nuclear
      DecommissioningTrust
      Fund(c)
            
            
            200
            
            
            
            83
            
            
            
            1
            
            
            
            284CIPS
            Derivative
      assets(b)
            
            
            -
            
            
            
            -
            
            
            
            11
            
            
            
            11Genco
            Derivative
      assets(b)
            
            
            -
            
            
            
            -
            
            
            
            1
            
            
            
            1CILCORP/CILCO
            Derivative
      assets(b)
            
            
            -
            
            
            
            -
            
            
            
            7
            
            
            
            7IP
            Derivative
      assets(b)
            
            
            -
            
            
            
            -
            
            
            
            19
            
            
            
            19Liabilities:Ameren(a)
            Derivative
      liabilities(b)
            
            $
            6
            
            
            $
            21
            
            
            $
            72
            
            
            $
            99UE
            Derivative
      liabilities(b)
            
            
            -
            
            
            
            14
            
            
            
            9
            
            
            
            23CIPS
            Derivative
      liabilities(b)
            
            
            -
            
            
            
            -
            
            
            
            23
            
            
            
            23Genco
            Derivative
      liabilities(b)
            
            
            -
            
            
            
            -
            
            
            
            2
            
            
            
            2CILCORP/CILCO
            Derivative
      liabilities(b)
            
            
            3
            
            
            
            -
            
            
            
            15
            
            
            
            18IP
            Derivative
      liabilities(b)
            
            
            -
            
            
            
            -
            
            
            
            38
            
            
            
            38





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


(b)
            The
      derivative asset and liability balances are presented net of counterparty
      credit considerations.


(c)
            Balance
      excludes $(15) million of receivables, payables, and accrued income,
      net.





The
following table summarizes the changes in the fair value of financial assets and
liabilities classified as Level 3 in the fair value hierarchy for the three
months ended September 30, 2008:




Change
      inTotal
              
              
              
              
              
              
              
              
              UnrealizedRealized and Unrealized Gains
      (Losses)
              
              
              Realized
              
              
              Purchases,
              
              
              
              
              
              Gains
      (Losses)Beginning
              
              
              
              
              
              Included
      in
              
              and
              
              
              Issuances,
              
              Net
              
              Ending
              
              Related
      toBalance
      at
              
              
              
              
              
              Regulatory
              
              Unrealized
              
              
              and
      Other
              
              Transfers
      In
              
              Balance
      at
              
              Assets/LiabilitiesJuly
      1,
              
              Included
      in
              
              Included
              
              Assets/
              
              Gains
              
              
              Settlements,
              
              and/or
      (Out)
              
              September
      30,
              
              Still
      Held at2008
              
              Earnings(a)
              
              In
      OCI
              
              Liabilities
              
              (Losses)
              
              
              Net
              
              of
      Level 3
              
              2008
              September
      30, 2008Other
      current
                assets
              Ameren
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              16
              
              $
              16
              
              $
              -Net
      derivative
              Ameren
              
              $
              202
              
              
              $
              (66
              )
              
              $
              64
              
              $
              (161
              )
              
              $
              (163
              )
              
              $
              (33
              )
              
              $
              35
              
              $
              41
              
              $
              (252
              )contracts
              UE
              
              
              40
              
              
              
              (4
              )
              
              
              2
              
              
              (2
              )
              
              
              (4
              )
              
              
              (26
              )
              
              
              11
              
              
              21
              
              
              6CIPS
              
              
              112
              
              
              
              (1
              )
              
              
              -
              
              
              (115
              )
              
              
              (116
              )
              
              
              (8
              )
              
              
              -
              
              
              (12
              )
              
              (31
              )Genco
              
              
              4
              
              
              
              (5
              )
              
              
              -
              
              
              -
              
              
              
              (5
              )
              
              
              -
              
              
              
              -
              
              
              (1
              )
              
              (4
              )CILCORP/CILCO
              
              
              77
              
              
              
              (6
              )
              
              
              -
              
              
              (72
              )
              
              
              (78
              )
              
              
              (7
              )
              
              
              -
              
              
              (8
              )
              
              (34
              )IP
              
              
              195
              
              
              
              (1
              )
              
              
              -
              
              
              (208
              )
              
              
              (209
              )
              
              
              (5
              )
              
              
              -
              
              
              (19
              )
              
              (77
              )Nuclear
              Ameren
              
              $
              1
              
              
              $
              -
              
              
              $
              -
              
              $
              -
              
              
              $
              -
              
              
              $
              (b
              )
              
              $
              -
              
              $
              1
              
              $
              -Decommissioning
              UE
              
              
              1
              
              
              
              -
              
              
              
              -
              
              
              -
              
              
              
              -
              
              
              (b
              )
              
              
              -
              
              
              1
              
              
              -Trust
      Fund


(a)
            Net
      gains and losses on power options are recorded in Operating Revenues -
      Electric, while net gains and losses on coal, heating oil, and SO2
      options and swaps are recorded as Operating Expenses -
    Fuel.


(b)
            Less
      than $1 million.








46





The
following table summarizes the changes in the fair value of financial assets and
liabilities classified as Level 3 in the fair value hierarchy for the nine
months ended September 30, 2008:





Change
      inTotal
            
            
            
            
            
            
            
            UnrealizedRealized and Unrealized Gains
      (Losses)
            
            
            Realized
            
            Purchases,
            
            
            
            
            
            Gains
      (Losses)Beginning
            
            
            
            
            
            
            Included
      in
            
            
            and
            
            Issuances,
            
            Net
            
            Ending
            
            Related
      toBalance
      at
            
            
            
            
            
            
            Regulatory
            
            
            Unrealized
            
            and
      Other
            
            Transfers
      In
            
            Balance
      at
            
            Assets/LiabilitiesJanuary
      1,
            
            
            Included
      in
            
            Included
            
            Assets/
            
            
            Gains
            
            Settlements,
            
            and/or
      (Out)
            
            September
      30,
            
            Still
      Held at2008
            
            
            Earnings(a)
            
            In
      OCI
            
            Liabilities
            
            
            (Losses)
            
            Net
            
            of
      Level 3
            
            2008
            September
      30, 2008Other
      current
              assets
            Ameren
            $
            -
            
            
            $
            -
            
            $
            -
            
            $
            -
            
            
            $
            -
            
            $
            -
            
            $
            16
            
            $
            16
            
            $
            -Net
      derivative
            Ameren
            $
            19
            
            
            $
            26
            
            $
            5
            
            $
            17
            
            
            $
            48
            
            $
            (50
            )
            $
            24
            
            $
            41
            
            $
            10contracts
            UE
            
            3
            
            
            
            7
            
            
            12
            
            
            17
            
            
            
            36
            
            
            (30
            )
            
            12
            
            
            21
            
            
            10CIPS
            
            38
            
            
            
            -
            
            
            -
            
            
            (41
            )
            
            
            (41
            )
            
            (9
            )
            
            -
            
            
            (12
            )
            
            (36
            )Genco
            
            1
            
            
            
            (1
            )
            
            -
            
            
            -
            
            
            
            (1
            )
            
            (1
            )
            
            -
            
            
            (1
            )
            
            -CILCORP/CILCO
            
            21
            
            
            
            (7
            )
            
            -
            
            
            (10
            )
            
            
            (17
            )
            
            (12
            )
            
            -
            
            
            (8
            )
            
            (21
            )IP
            
            55
            
            
            
            (1
            )
            
            -
            
            
            (67
            )
            
            
            (68
            )
            
            (6
            )
            
            -
            
            
            (19
            )
            
            (59
            )Nuclear
            Ameren
            $
            5
            
            
            $
            -
            
            $
            -
            
            $
            -
            
            
            $
            -
            
            $
            (4
            )
            $
            -
            
            $
            1
            
            $
            -Decommissioning
            UE
            
            5
            
            
            
            -
            
            
            -
            
            
            -
            
            
            
            -
            
            
            (4
            )
            
            -
            
            
            1
            
            
            -Trust
      Fund





(a)
            Net
      gains and losses on power options are recorded in Operating Revenues -
      Electric, while net gains and losses on coal, heating oil, and SO2
      options and swaps are recorded as Operating Expenses -
    Fuel.





Transfers
in or out of Level 3 represent either (1) existing assets and liabilities that
were previously categorized as a higher level but were recategorized to Level 3
because the inputs to the model became unobservable during the period or (2)
existing assets and liabilities that were previously classified as Level 3 but
were recategorized to a higher level because the lowest significant input became
observable during the period. Transfers between Level 2 and Level 3 were
primarily caused by changes in availability of financial power trades observable
on electronic exchanges compared to previous periods for the three and nine
months ended September 30, 2008. Any reclassifications are reported as transfers
in/out of Level 3 at the fair value measurement reported at the beginning of the
period in which the changes occur.





NOTE
8 - 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 12 - Related Party Transactions
under Part II, Item 8 of the Form 10-K.





Illinois
Electric Settlement Agreement





As part
of the Illinois electric settlement agreement, the Ameren Illinois Utilities,
Genco and AERG agreed to make aggregate contributions of $150 million over four
years as part of a comprehensive program providing approximately $1 billion of
funding for rate relief to certain Illinois electric customers, including
customers of the Ameren Illinois Utilities. At September 30, 2008, CIPS, CILCO
and IP had receivable balances from Genco for reimbursement of customer rate
relief of $1 million, less than $1 million, and $1 million, respectively. Also
at September 30, 2008, CIPS, CILCO and IP had receivable balances from AERG for
reimbursement of customer rate relief of less than $1 million each. During the
three months ended September 30, 2008, Genco incurred charges to earnings of $4
million for customer rate relief contributions and program funding
reimbursements to the Ameren Illinois Utilities (CIPS - $1
million, CILCO - $1 million, IP - $2 million), and AERG incurred charges to
earnings of $2 million (less than $1 million at CIPS, CILCO and IP,
respectively). For the nine months ended September 30, 2008, Genco incurred
charges to earnings of $13 million for customer rate relief contributions and
program funding reimbursements to the Ameren Illinois Utilities (CIPS -$5
million, CILCO - $2 million, IP - $6 million), and AERG incurred charges to
earnings of $6 million (CIPS - $2 million, CILCO - $1 million, IP - $3
million). The Ameren Illinois Utilities recorded most of the reimbursements
received as electric revenue, with an immaterial amount recorded as
miscellaneous revenue.





In addition, as part of the Illinois
electric settlement agreement, the Ameren Illinois Utilities entered into financial
contracts with Marketing Company to lock-in energy prices for a portion of their
around-the-clock power requirements from 2008 to 2012 at relevant market prices.
These financial contracts became effective on August 28, 2007. See Note 6 -
Derivative Financial Instruments for additional information on the financial
contracts and Note 2 - Rate and Regulatory Matters for additional
information on the Illinois electric settlement agreement.




47




Electric
Power Supply and Resource Sharing 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, 2008 and 2007:





Three
      Months
            Nine
      Months2008
            2007
            2008
            2007Genco
      sales to
              Marketing
      Company
            4,276
            4,754
            12,217
            12,711AERG
      sales to
              Marketing
      Company
            1,794
            1,270
            5,107
            3,912Marketing
      Company
              sales
      to CIPS
            463
            671
            1,557
            1,852Marketing
      Company
              sales
      to CILCO
            222
            349
            702
            922Marketing
      Company
              sales
      to IP
            715
            1,016
            2,217
            2,716





In
December 2006, Genco and Marketing Company entered into a new power supply
agreement (Genco PSA) whereby Genco agreed to sell and Marketing Company agreed
to purchase all of the capacity available from Genco’s generation fleet and all
the associated energy. On  March 28, 2008, Genco and Marketing Company
entered into an amendment of the Genco PSA. Under the amendment, Genco is
liable to Marketing Company in the event of an unplanned outage or derate
(reduction in rated capacity) due to sudden, unanticipated failure or accident
within the generating plant site of one or more of its generating
units. Genco’s liability in such case will be for the positive difference,
if any, between the market price of capacity and/or energy Genco does not
deliver and the contract price under the Genco PSA for that capacity and/or
energy. Genco has insurance with an affiliate company that covers many, but
not all, of these situations, subject to deductibles and policy limits. An
unplanned outage or derate that continues for one year or more is an event of
default under the Genco PSA. In the event of Marketing Company’s unexcused
failure to receive energy under the Genco PSA, Marketing Company would be
required to pay Genco the positive difference, if any, between the contract
price and the price actually received by Genco, acting in a commercially
reasonable manner, to resell the unreceived energy, less any reasonable related
transmission, ancillary service, or brokerage costs.





Also in
December 2006, AERG and Marketing Company entered into a power supply agreement
(AERG PSA) whereby AERG agreed to sell and Marketing Company agreed to purchase
all of the capacity available from AERG’s generation fleet and all the
associated energy. On March 28, 2008, AERG and Marketing Company entered into an
amendment of the AERG PSA that is substantially identical to the amendment to
the Genco PSA described above. Under the amendment, AERG is liable to
Marketing Company in the event of an unplanned outage or derate due
to sudden, unanticipated failure or accident within the generating plant
site of one or more of its generating units. AERG’s liability in such case
will be for the positive difference, if any, between the market price of
capacity and/or energy AERG does not deliver and the contract price under
the AERG PSA for that capacity and/or energy. AERG has insurance with an
affiliate company that covers many, but not all of these situations, subject to
deductibles and policy limits. An unplanned outage or derate that continues
for one year or more is an event of default under the AERG PSA. In the
event of Marketing Company’s unexcused failure to receive energy under the AERG
PSA, Marketing Company would be required to pay AERG the positive difference, if
any, between the contract price and the price actually received by AERG, acting
in a commercially reasonable manner, to resell the unreceived energy, less any
reasonable related transmission, ancillary service, or brokerage
costs.





One-third
of the Ameren Illinois Utilities’ supply contracts that served the load needs of
their fixed-price residential and small commercial customers, and all of the
supply contracts that served large commercial and industrial customers, expired
on May 31, 2008. To replace a portion of these expired supply contracts, the
Ameren Illinois Utilities used RFP processes in early 2008, pursuant to the
Illinois electric settlement agreement, to contract for the necessary energy and
capacity requirements for the period from June 1, 2008 through May 31, 2009.
Marketing Company was one of the winning suppliers in the Ameren Illinois
Utilities’ energy and capacity RFPs. Marketing Company entered into financial
instruments that fixed the price that the Ameren Illinois Utilities will pay for
approximately two million megawatthours at approximately $60 per megawatthour.
Marketing Company contracted to supply a portion of the Ameren Illinois
Utilities’ capacity for approximately $6 million. In addition, UE contracted to
supply a portion of the Ameren Illinois Utilities’ capacity for approximately $1
million.





On June 1, 2008, FERC accepted an
electric resource sharing agreement among the Ameren Illinois Utilities for
various joint costs of the Ameren Illinois Utilities, including capacity,
renewable energy credits, and rate swaps. The purpose of the agreement is to
allocate these costs among the
Ameren Illinois Utilities in an equitable manner, based on their respective
retail loads.





Collateral
Postings





Under the
terms of the power supply agreements between Marketing Company and the Ameren
Illinois Utilities, which were entered into as part of the September 2006
Illinois power procurement auction, cash collateral is required to be posted by
Marketing Company under certain market conditions to protect the Ameren Illinois
Utilities in






48




the event
of nonperformance by Marketing Company. The collateral postings are unilateral,
meaning that Marketing Company as the supplier is the only counterparty required
to post collateral. At September 30, 2008, there were no collateral postings by
Marketing Company related to the 2006 auction power supply agreements, and
at December 31, 2007, Marketing Company had posted $1 million, less
than $1 million, and $1 million for the benefit of CIPS, CILCO, and IP,
respectively.





In
addition, under the terms of the 2008 Illinois power procurement RFPs, cash
collateral is required to be posted by Marketing Company and the Ameren Illinois
Utilities under certain market conditions. The collateral postings are
bilateral, meaning that either counterparty may be required to post collateral.
As of September 30, 2008, the Ameren Illinois Utilities had cash collateral
postings as follows with Marketing Company: CIPS - $7 million, CILCO - $4
million and IP - $10 million. These bilateral collateral postings were
eliminated in consolidation on Ameren’s financial statements.





Intercompany
Transfers





On January 1, 2008, UE transferred
its interest in Union Electric Development Corporation at book value to Ameren
by means of a $3 million dividend-in-kind. On March 31, 2008, Union Electric
Development Corporation was merged into Ameren Development Company, with Ameren
Development Company surviving the merger.





On February 29, 2008, UE contributed
its entire 40% ownership interest in EEI at book value to Resources Company
valued at $39 million, in exchange for a 50% interest in Resources Company, and
then immediately transferred its interest in Resources Company to Ameren by
means of a $39 million dividend-in-kind. Also on February 29, 2008, Development
Company, which formerly held a 40% ownership interest in EEI, merged into Ameren
Energy Resources Company, which then merged into Resources Company. As a result,
Resources Company now has an 80% ownership interest in EEI and consolidates it
accordingly.




Money
Pools





See Note 3 - Short-term Borrowings and
Liquidity for a discussion of affiliate borrowing arrangements.





Intercompany
Borrowings





Genco’s subordinated note payable to
CIPS associated with the transfer in 2000 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 $2 million
(2007 - $2 million) and $6 million (2007 - $7 million) for the three months and
nine months ended September 30, 2008 and 2007, respectively.





CILCORP had outstanding borrowings
directly from Ameren of $63 million and $2 million at September 30, 2008 and
December 31, 2007, respectively. The average interest rate on these borrowings
was 3.5% and 3.7% for the three months and nine months ended September 30, 2008,
respectively (2007 - not applicable for the three months ended September 30,
2007, and 4.8% for the nine months ended September 30, 2007). CILCORP recorded
interest expense of less than $1 million for these borrowings for the three
months and nine months ended September 30, 2008, and September 30,
2007.





UE had outstanding borrowings
directly from Ameren of $17 million at September 30, 2008, and none at December
31, 2007. The average interest rate on these borrowings was 3.5% and 3.7% for
the three months and nine months ended September 30, 2008, respectively (2007 -
5.6% and 5.1%, respectively). UE recorded interest expense of less than $1
million for these borrowings for the three months and nine months ended
September 30, 2008, respectively (2007 - less than $1 million and $3 million for
the three months and nine months ended September 30,
2007 respectively).





UE had an intercompany note
receivable of $30 million from Ameren Development Company at September 30,
2008. This note was transferred to Ameren Development Company from Union
Electric Development Corporation in connection with the merger discussed above.
The average interest rate on this borrowing was 5.0% and 5.1%, respectively, for
the three months and nine months ended September 30, 2008. UE recorded interest
revenue of $1 million and $2 million for these borrowings for the three months
and nine months ended September 30, 2008, respectively.




49





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, 2008 and 2007. It is based primarily on the agreements discussed
above and in Note 12 - Related Party Transactions under Part II, Item 8 of the
Form 10-K, and the money pool arrangements discussed in Note 3 - Short-term
Borrowings and Liquidityof this
report.




Three
      Months
              
              
              Nine
      MonthsAgreement
              
              
              UE
              
              
              CIPS
              
              
              Genco
              
              
              CILCORP(a)
              
              
              IP
              
              
              UE
              
              
              CIPS
              
              
              Genco
              
              
              CILCORP(a)
              
              
              IPOperating
      Revenues:Genco
      and AERG power supply
              2008
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              233
              
              
              $
              99
              
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              658
              
              
              $
              252
              
              
              $
              (b)agreements
      with Marketing Company
              2007
              
              (b)
              
              
              (b)
              
              
              
              222
              
              
              
              73
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              615
              
              
              
              207
              
              
              (b)Ancillary
      service agreement
              2008
              
              
              3
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              9
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)with
      CIPS, CILCO and IP
              2007
              
              
              5
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              13
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)Genco
      gas sales to CILCO
              2008
              
              (b)
              
              
              (b)
              
              
              (c)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              6
              
              
              (b)
              
              
              (b)2007
              
              (b)
              
              
              (b)
              
              
              
              -
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              -
              
              
              (b)
              
              
              (b)UE
      and Genco gas transportation
              2008
              
              
              1
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              1
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)agreement
              2007
              
              (c)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (c)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)Total
      Operating Revenues
              2008
              
              $
              4
              
              
              $
              (b)
              
              
              $
              233
              
              
              $
              99
              
              
              $
              (b)
              
              
              $
              10
              
              
              $
              (b)
              
              
              $
              664
              
              
              $
              252
              
              
              $
              (b)2007
              
              
              5
              
              
              (b)
              
              
              
              222
              
              
              
              73
              
              
              (b)
              
              
              
              13
              
              
              (b)
              
              
              
              615
              
              
              
              207
              
              
              
              (b)Fuel
      and Purchased Power:CIPS,
      CILCO and IP agreements with
              2008
              
              $
              (b)
              
              
              $
              32
              
              
              $
              (b)
              
              
              $
              15
              
              
              $
              49
              
              
              $
              (b)
              
              
              $
              104
              
              
              $
              (b)
              
              
              $
              47
              
              
              $
              148Marketing
      Company (2006 auction
              2007
              
              (b)
              
              
              
              42
              
              
              (b)
              
              
              
              22
              
              
              
              64
              
              
              (b)
              
              
              
              120
              
              
              (b)
              
              
              
              60
              
              
              
              176and
      energy and capacity agreements)Ancillary
      service agreement with UE
              2008
              
              (b)
              
              
              
              1
              
              
              (b)
              
              
              
              1
              
              
              
              1
              
              
              (b)
              
              
              
              3
              
              
              (b)
              
              
              
              1
              
              
              
              52007
              
              (b)
              
              
              
              2
              
              
              (b)
              
              
              
              1
              
              
              
              2
              
              
              (b)
              
              
              
              5
              
              
              (b)
              
              
              
              2
              
              
              
              6Ancillary
      service agreement with
              2008
              
              (b)
              
              
              
              1
              
              
              (b)
              
              
              
              1
              
              
              
              2
              
              
              (b)
              
              
              
              5
              
              
              (b)
              
              
              
              3
              
              
              
              8Marketing
      Company
              2007
              
              (b)
              
              
              
              1
              
              
              (b)
              
              
              
              -
              
              
              
              2
              
              
              (b)
              
              
              
              3
              
              
              (b)
              
              
              
              1
              
              
              
              4Executory
      tolling agreement with
              2008
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              8
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              30
              
              
              (b)Medina
      Valley
              2007
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              8
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              28
              
              
              (b)UE
      and Genco gas transportation
              2008
              
              (b)
              
              
              (b)
              
              
              
              1
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              1
              
              
              (b)
              
              
              (b)agreement
              2007
              
              (b)
              
              
              (b)
              
              
              (c)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (c)
              
              
              (b)
              
              
              (b)Total
      Fuel and Purchased Power
              2008
              
              $
              (b)
              
              
              $
              34
              
              
              $
              1
              
              
              $
              25
              
              
              $
              52
              
              
              $
              (b)
              
              
              $
              112
              
              
              $
              1
              
              
              $
              82
              
              
              $
              1612007
              
              (b)
              
              
              
              45
              
              
              (c)
              
              
              
              31
              
              
              
              68
              
              
              (b)
              
              
              
              128
              
              
              (c)
              
              
              
              91
              
              
              
              186Gas
      Purchased for ResaleCILCO
      gas purchases from Genco
              2008
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              (c)
              
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              6
              
              
              $
              (b)2007
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              -
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              -
              
              
              (b)Other
      Operations and Maintenance Expense:Ameren
      Services support services
              2008
              
              $
              36
              
              
              $
              14
              
              
              $
              7
              
              
              $
              14
              
              
              $
              21
              
              
              $
              110
              
              
              $
              43
              
              
              $
              22
              
              
              $
              43
              
              
              $
              65agreement
              2007
              
              
              37
              
              
              
              14
              
              
              
              6
              
              
              
              13
              
              
              
              21
              
              
              
              113
              
              
              
              41
              
              
              
              19
              
              
              
              41
              
              
              
              63Ameren
      Energy, Inc. support
              2008
              
              (e)
              
              
              (e)
              
              
              (e)
              
              
              (e)
              
              
              (e)
              
              
              (e)
              
              
              (e)
              
              
              (e)
              
              
              (e)
              
              
              (e)services
      agreement
              2007
              
              
              2
              
              
              (b)
              
              
              (c)
              
              
              (b)
              
              
              (b)
              
              
              
              7
              
              
              (b)
              
              
              (c)
              
              
              (b)
              
              
              (b)AFS
      support services agreement
              2008
              
              
              2
              
              
              
              -
              
              
              
              1
              
              
              
              1
              
              
              
              -
              
              
              
              5
              
              
              
              1
              
              
              
              2
              
              
              
              2
              
              
              
              12007
              
              
              2
              
              
              
              -
              
              
              
              1
              
              
              
              1
              
              
              
              -
              
              
              
              5
              
              
              
              1
              
              
              
              2
              
              
              
              2
              
              
              
              1Insurance
      premiums(d)
              2008
              
              
              2
              
              
              (b)
              
              
              
              1
              
              
              
              1
              
              
              (b)
              
              
              
              7
              
              
              (b)
              
              
              
              3
              
              
              
              3
              
              
              (b)2007
              
              
              7
              
              
              (b)
              
              
              
              1
              
              
              
              -
              
              
              (b)
              
              
              
              16
              
              
              (b)
              
              
              
              3
              
              
              
              1
              
              
              (b)Total Other Operations
      and
              2008
              
              $
              40
              
              
              $
              14
              
              
              $
              9
              
              
              $
              16
              
              
              $
              21
              
              
              $
              122
              
              
              $
              44
              
              
              $
              27
              
              
              $
              48
              
              
              $
              66Maintenance
      Expenses
              2007
              
              
              48
              
              
              
              14
              
              
              
              8
              
              
              
              14
              
              
              
              21
              
              
              
              141
              
              
              
              42
              
              
              
              24
              
              
              
              44
              
              
              
              64Interest
      expense on commercial
              2008
              
              $
              -
              
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              1
              
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              (b)
              
              
              $
              (b)paper
      held by affiliate
              2007
              
              
              1
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              
              3
              
              
              (b)
              
              
              (b)
              
              
              (b)
              
              
              (b)Interest
      expense (income) from
              2008
              
              
              -
              
              
              (c)
              
              
              (c)
              
              
              
              1
              
              
              (c)
              
              
              
              -
              
              
              (c)
              
              
              (c)
              
              
              
              1
              
              
              (c)money
      pool borrowings (advances)
              2007
              
              
              -
              
              
              (c)
              
              
              
              3
              
              
              (c)
              
              
              (c)
              
              
              
              -
              
              
              (c)
              
              
              
              7
              
              
              (c)
              
              
              (c)





(a)
            Amounts
      represent CILCORP and CILCO
activity.


(b)
            Not
      applicable.(c)
            Amount
      less than $1 million.(d)
            Represents
      insurance expense on affiliate policies for replacement power, property
      damage and terrorism coverage.(e)
            Ameren
      Energy, Inc. was eliminated December 31, 2007 through an internal
      reorganization.




50





NOTE
9 - COMMITMENTS AND CONTINGENCIES





We are
involved in legal, tax and regulatory proceedings before various courts,
regulatory commissions, and governmental agencies with respect to matters that
arise in the ordinary course of business, some of which involve substantial
amounts of money. We believe that the final disposition of these proceedings,
except as otherwise disclosed in these notes to our financial statements, will
not have a material adverse effect on our results of operations, financial
position, or liquidity.





Reference
is made to Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate
and Regulatory Matters, Note 12 - Related Party Transactions, and Note 13 -
Commitments and Contingencies under Part II, Item 8 of the Form 10-K. See also
Note 1 - Summary of Significant Accounting Policies, Note 2 - Rate and
Regulatory Matters, Note 8 - Related Party Transactions and Note 10 - Callaway
Nuclear Plant in this report.





Callaway
Nuclear Plant





The
following table presents insurance coverage at UE’s Callaway nuclear plant at
October 29, 2008. The property coverage and the nuclear liability coverage must
be renewed on October 1 and January 1, respectively, of each year.





Type
      and Source of Coverage
            
            Maximum
      Coverages
            
            Maximum
      Assessments for Single IncidentsPublic
      liability and nuclear worker liability:American Nuclear
      Insurers
            
            $
            300
            (a)
            
            $
            -Pool participation
            
            
            10,461
            
            
            
            117.5
            (b)$
            10,761
            (c)
            
            $
            117.5Property
      damage:Nuclear Electric Insurance
      Ltd.
            
            $
            2,750
            (d)
            
            $
            24Replacement
      power:Nuclear Electric Insurance
      Ltd.
            
            $
            490
            (e)
            
            $
            9Energy Risk Assurance
      Company
            
            $
            64
            (f)
            
            $
            -





(a)
            Provided
      through mandatory participation in an industry-wide retrospective premium
      assessment program.


(b)
            Retrospective
      premium under the Price-Anderson liability provisions of the Atomic Energy
      Act of 1954, as amended. This is 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 $17.5 million per
      year.


(c)
            Limit
      of liability for each incident under Price-Anderson. This limit is subject
      to change to account for the effects of inflation and changes in the
      number of licensed reactors.


(d)
            Provides
      for $500 million in property damage and decontamination, excess property
      insurance, and premature decommissioning coverage up to $2.25 billion
      for losses in excess of the $500 million primary
  coverage.


(e)
            Provides
      the replacement power cost insurance in the event of a prolonged
      accidental outage at a nuclear plant. 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.


(f)
            Provides
      the replacement power cost insurance in the event of a prolonged
      accidental outage at a nuclear plant. The coverage commences after the
      first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd.
      and is for a weekly indemnity of $900,000 for 71 weeks in excess of the
      $3.6 million per week set forth above. Energy Risk Assurance Company is an
      affiliate and has reinsured this coverage with third-party insurance
      companies. See Note 8 - Related Party Transactions for more
      information on this affiliate
transaction.





The
Price-Anderson Act is a federal law that 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. The limit of liability
and the maximum potential annual payments are adjusted at least every five years
for inflation to reflect changes in the Consumer Price Index. The five-year
inflationary adjustment as prescribed by the most recent Price-Anderson Act
renewal was effective October 29, 2008. Owners of 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.





After the
terrorist attacks on September 11, 2001, Nuclear Electric Insurance Ltd.
confirmed that losses resulting from terrorist attacks would be covered under
its policies. However, Nuclear Electric Insurance Ltd. imposed an industry-wide
aggregate policy limit of $3.24 billion within a 12-month period for coverage
for such terrorist acts.





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 were to occur, it could have
a material adverse effect on Ameren’s and UE’s results of operations, financial
position, or liquidity.





Other
Obligations





We have
entered into various long-term commitments for the procurement of coal, natural
gas and nuclear fuel to supply a portion of the fuel requirements of our
generating plants. In addition, we have entered into various long-term
commitments for the




51


purchase
of electricity and natural gas for distribution. For a complete listing of our
obligations and commitments, see Note 13 - Commitments and Contingencies under
Part II, Item 8 of the Form 10-K.





Our
commitments for the procurement of coal have materially changed from amounts
previously disclosed as of December 31, 2007. The following table presents
our total estimated coal purchase commitments at September 30,
2008:





2008
            
            
            2009
            
            
            2010
            
            
            2011
            
            
            2012
            
            
            ThereafterAmeren(a)
            
            $
            126
            
            
            $
            498
            
            
            $
            294
            
            
            $
            148
            
            
            $
            17
            
            
            $
            -UE
            
            
            72
            
            
            
            293
            
            
            
            181
            
            
            
            80
            
            
            
            -
            
            
            
            -Genco
            
            
            25
            
            
            
            111
            
            
            
            44
            
            
            
            24
            
            
            
            -
            
            
            
            -CILCORP/CILCO
            
            
            14
            
            
            
            42
            
            
            
            36
            
            
            
            27
            
            
            
            17
            
            
            
            -





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





Our
commitments for the procurement of natural gas have materially changed from
amounts previously disclosed as of December 31, 2007. The following table
presents our total estimated natural gas purchase commitments at September 30,
2008:




2008
            
            
            2009
            
            
            2010
            
            
            2011
            
            
            2012
            
            
            ThereafterAmeren(a)
            
            $
            178
            
            
            $
            524
            
            
            $
            399
            
            
            $
            249
            
            
            $
            135
            
            
            $
            138UE
            
            
            21
            
            
            
            86
            
            
            
            59
            
            
            
            41
            
            
            
            27
            
            
            
            43CIPS
            
            
            37
            
            
            
            112
            
            
            
            70
            
            
            
            63
            
            
            
            45
            
            
            
            60Genco
            
            
            7
            
            
            
            10
            
            
            
            8
            
            
            
            8
            
            
            
            5
            
            
            
            8CILCORP/CILCO
            
            
            43
            
            
            
            136
            
            
            
            101
            
            
            
            52
            
            
            
            30
            
            
            
            19IP
            
            
            67
            
            
            
            173
            
            
            
            160
            
            
            
            85
            
            
            
            27
            
            
            
            8





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





Our
commitments for the procurement of nuclear fuel have materially changed from
amounts previously disclosed as of December 31, 2007. The following table
presents our total estimated nuclear fuel purchase commitments at September 30,
2008:





2008
            
            
            2009
            
            
            2010
            
            
            2011
            
            
            2012
            
            
            ThereafterAmeren
            
            $
            3
            
            
            $
            68
            
            
            $
            74
            
            
            $
            52
            
            
            $
            67
            
            
            $
            232UE
            
            
            3
            
            
            
            68
            
            
            
            74
            
            
            
            52
            
            
            
            67
            
            
            
            232





UE’s firm commitments to purchase
heavy forgings for construction of a potential new nuclear power plant have
changed from amounts previously disclosed as of December 31, 2007. The following
table presents the total estimated heavy forgings commitments at September 30,
2008:





2008
            
            
            2009
            
            
            2010
            
            
            2011
            
            
            2012
            
            
            ThereafterAmeren
            
            $
            -
            
            
            $
            10
            
            
            $
            35
            
            
            $
            23
            
            
            $
            23
            
            
            $
            -UE
            
            
            -
            
            
            
            10
            
            
            
            35
            
            
            
            23
            
            
            
            23
            
            
            
            -





The
Illinois electric settlement agreement provides approximately $1 billion of
funding over a four-year period that commenced in 2007 for rate relief for
certain electric customers in Illinois. Funding for the settlement will come
from electric generators in Illinois and certain Illinois electric utilities.
The Ameren Illinois Utilities, Genco and AE RG agreed
to fund an aggregate of $150 million, of which the following contributions
remained to be made at September 30, 2008:





Ameren
            
            
            CIPS
            
            
            CILCO
              (Illinois
              Regulated)
            
            
            IP
            
            
            Genco
            
            
            CILCO
              (AERG)2008(a)
            
            $
            12.2
            
            
            $
            1.9
            
            
            $
            0.9
            
            
            $
            2.7
            
            
            $
            4.6
            
            
            $
            2.12009(a)
            
            
            25.4
            
            
            
            3.6
            
            
            
            1.8
            
            
            
            4.8
            
            
            
            10.5
            
            
            
            4.72010(a)
            
            
            2.0
            
            
            
            0.3
            
            
            
            0.1
            
            
            
            0.4
            
            
            
            0.8
            
            
            
            0.4Total
            
            $
            39.6
            
            
            $
            5.8
            
            
            $
            2.8
            
            
            $
            7.9
            
            
            $
            15.9
            
            
            $
            7.2





(a)    Estimated.




One-third
of the Ameren Illinois Utilities’ supply contracts that served the load needs of
their fixed-price residential and small commercial customers expired
on  May 31, 2008. To replace a portion of these expired supply
contracts, the Ameren Illinois Utilities used RFP processes in early 2008,
pursuant to the Illinois electric settlement agreement. Specifically, the Ameren
Illinois Utilities used RFPs to procure energy swaps, capacity, and renewable
energy credits for the period June 1, 2008 through May 31, 2009. The
Ameren Illinois Utilities contracted to purchase approximately two million
megawatthours of energy swaps at an average price of approximately $60 per
megawatthour. As a result of a capacity RFP, the Ameren Illinois Utilities
contracted to purchase approximately 1,800 megawatts of capacity at an average
price of approximately $50 per MW-day. A renewable energy credits RFP resulted
in the Ameren Illinois Utilities contracting to purchase 415,000 credits at an
average price of approximately $17 per credit.





Environmental
Matters





We are subject to various
environmental laws and regulations enforced 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, natural gas storage plants, and natural gas transmission and
distribution facilities, our activities involve compliance with diverse laws and
regulations. These laws and regulations address noise, emissions, and impacts to
air and water, protected and cultural resources (such as wetlands, endangered
species, and archeological and historical resources), and chemical and waste
handling. Our activities often require complex and lengthy processes as


52




we obtain
approvals, permits or licenses for new, existing or modified facilities.
Additionally, the use and handling of various chemicals or hazardous materials
(including wastes) requires 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. The more significant matters are discussed below.





Clean
Air Act





Both
federal and state laws require significant reductions in SO2and
NOx
emissions that result from burning fossil fuels. In May 2005, the EPA issued
regulations with respect to SO2 and
NOx
emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air
Mercury Rule). During 2008, the U.S. Court of Appeals for the District of
Columbia issued separate decisions that vacated the federal Clean Air Interstate
Rule and the federal Clean Air Mercury Rule. Other federal regulations remain in
effect under the Clean Air Act for controlling SO2 and
NOx
emissions, including the Acid Rain Program and the NOx Budget
Trading Program.





In
February 2008, the U.S. Court of Appeals for the District of Columbia issued a
decision that vacated the federal Clean Air Mercury Rule. The court ruled that
the EPA erred in the method used to remove electric generating units from the
list of sources subject to the maximum available control technology requirements
under the Clean Air Act. The EPA and a group representing the electric utility
industry filed petitions for rehearing; however, the court denied those
petitions in May 2008. A group representing the electric utility industry and
the EPA filed petitions for review of the U.S. Court of Appeals decision with
the U.S. Supreme Court in September 2008 and October 2008,
respectively.





In July
2008, the U.S. Court of Appeals for the District of Columbia issued a decision
that vacated the federal Clean Air Interstate Rule. The court ruled that the
regulation contained several fatal flaws, including a regional cap-and-trade
program that cannot be used to facilitate the attainment of ambient air quality
standards for ozone and fine particulate matter. In September 2008, the EPA as
well as several environmental groups, a group representing the electric utility
industry and the National Mining Association filed petitions for rehearing with
the U.S. Court of Appeals. If the court denies these petitions, remedy could be
sought with a petition for review by the U.S. Supreme Court.





We are
currently evaluating the impact that these court decisions will have on our
environmental compliance strategy. At this time, we are unable to predict the
outcome of these legal proceedings, the actions the EPA or U.S. Congress may
take in response to these court decisions and the timing of such actions. We
also cannot predict at this time the ultimate impact these court decisions and
resulting regulatory actions will have on our estimated capital costs for
compliance with environmental rules.





Illinois
and Missouri regulators will likely need to evaluate the impact of the U.S.
Court of Appeals decision to vacate the federal Clean Air Interstate Rule. Both
states had relied on the federal Clean Air Interstate Rule when adopting their
respective state regulations. Such regulations will remain in effect until
appeals relating to the U.S. Court of Appeals decision have been completed and
Illinois and Missouri determine whether revisions to their implementing
regulations are required.





We do not
believe the recent court decisions that vacated the federal Clean Air Interstate
Rule and the federal Clean Air Mercury Rule will significantly affect pollution
control obligations in Illinois. Illinois regulations incorporate an agreement,
which was reached in 2006 among Genco, CILCO (AERG), EEI and the Illinois EPA.
Under the agreement, Illinois generators may defer until 2015 the requirement to
reduce mercury emissions by 90% in exchange for accelerated installation of
NOx
and SO2 controls.
This agreement was codified in Illinois regulations and is referred to as the
Multi-Pollutant Standard (MPS) rule. To comply with the rule, in 2009, Genco,
CILCO (AERG) and EEI will begin putting into service equipment designed to
reduce mercury emissions. This rule, when fully implemented, is expected to
reduce mercury emissions 90%, NOx emissions
50%, and SO2 emissions
70% by 2015 in Illinois.





On
October 1, 2008, Genco, CILCO (AERG) and EEI submitted a request for a variance
from the MPS rule to the Illinois Pollution Control Board. In reparing this
request Genco, CILCO (AERG) and EEI worked with the Illinois EPA and agreed to
the installation of more stringent SO2 and
NOx
controls at various stages between 2010 and 2020 in order to make the variance
proposal "environmentally neutral." If granted, this variance would allow Genco
to defer approximately $500 million of environmental capital expenditures
from the 2009-2012 timeframe to the 2013-2015 timeframe. The Illinois Pollution
Control Board is expected to render a decision on this variance by January 31,
2009.





The state of Missouri had adopted the
Federal Clean Air Interstate Rule for regulating SO2 and
NOx
emissions from coal-fired power plants in Missouri. The rules were a significant
part of Missouri’s plan to attain existing ambient standards for ozone and fine
particulates, as well as




53


meeting
the Federal Clean Air Visibility Rule. The state will need to adopt new rules as
a result of the U.S. Court of Appeals’ decision. It is anticipated that Missouri
will adopt new replacement rules developed by the EPA next year. Currently, we
do not anticipate independent state actions that will significantly affect our
compliance strategy or compliance costs. However, this could change depending
upon how the EPA will require the state to respond to the court’s
decision.





The EPA finalized regulations in
March 2008 that will lower the ambient standard for ozone. It is expected that
areas will be designated as nonattainment in 2009 and that state implementation
plans will need to be submitted in 2013 unless Illinois and Missouri seek
extensions of various requirement dates. Additional emission reductions may be
required as a result of the future state implementation plans. At this time, we
are unable to determine the impact such state actions would have on our results
of operations, financial position, or liquidity.





The table below presents estimated
capital costs that were based on current technology to comply with the now
vacated federal Clean Air Interstate Rule and federal Clean Air MercuryRule
and related state implementation plans through 2017 as well as federal ambient
air quality standards including ozone and fine particulates, and the federal
Clean Air Visibility rule. Because of the 2008 U.S. Court of Appeals decisions
to vacate the Clean Air Interstate Rule and the Clean Air MercuryRule,
the timing and ultimate amount of the capital costs are under review at this
time. The estimates described below could change depending upon additional
federal or state requirements, the ultimate outcome of any appeals relative to
the Clean Air Interstate Rule and the Clean Air Mercury Rule U.S. Court of
Appeals decisions, whether the variance request with respect to the Illinois MPS
rule discussed above is granted, new technology, variations in costs of material
or labor, or alternative compliance strategies, among other reasons. The timing
of estimated capital costs may also be influenced by whether emission allowances
are used to comply with any future rules, thereby deferring capital
investment.





2008
            2009
      - 2012
            2013
      - 2017
            TotalUE(a)
            $ 255
            $   
      215- $   295
            $
      1,300-$1,700
            $
      1,770- $ 2,250Genco
            300
            955-   1,210
            45-      
      70
            1,300-   
      1,580CILCO
            170
            380-      500
            70-  
          90
            620-       760EEI
            30
            260-      350
            20-      
      30
            310-       410Ameren
            $ 755
            $
      1,810- $2,355
            $
      1,435-$1,890
            $
      4,000- $ 5,000





(a)
            UE’s
      expenditures are expected to be recoverable in rates over
      time.





Emission Allowances




The Clean
Air Act, under the Acid Rain Program and the NOx Budget
Trading Program, created marketable commodities called allowances. Currently
each allowance gives the owner the right to emit one ton of SO2 or NOx. All
existing generating facilities have been allocated allowances 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 SO2 limits
through the use and purchase of allowances, through the use of low-sulfur fuels,
and through the application of pollution control technology. The NOx Budget
Trading Program limits emissions of NOx during the
ozone season (May through September). The NOx Budget
Trading Program has applied to all electric generating units in Illinois since
2004; it was applied to the eastern third of Missouri, where UE’s coal-fired
power plants are located, in 2007. Our generating facilities are expected to
comply with the NOx limits
through the use and purchase of allowances or through the application of
pollution control technology, including low-NOx burners,
over-fire air systems, combustion optimization, rich-reagent injection,
selective noncatalytic reduction, and selective catalytic reduction systems. See
Note 1 - Summary of Significant Accounting Policies for the SO2 and
NOx
emission allowances held and the related SO2 and
NOx
emission allowance book values that were carried as intangible assets as of
September 30, 2008.





UE,
Genco, CILCO and EEI expect to use a substantial portion of their SO2 and
NOx
allowances for ongoing operations. Environmental regulations, 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
federal Clean Air Interstate Rule required a reduction in SO2 emissions
by increasing the ratio of Acid Rain Program allowances surrendered for each ton
of SO2
emitted. As discussed above, in July 2008 the U.S. Court of Appeals for the
District of Columbia vacated the federal Clean Air Interstate Rule and in
September 2008, the EPA and other groups petitioned the court for rehearing of
its decision. If the U.S. Court of Appeals decision is not reversed, then
SO2
allowances will only be used for the Acid Rain Program with the value of one
SO2
allowance for each ton emitted. Additionally, the annual NOx trading
program under the federal Clean Air Interstate Rule will no longer be required;
however, we expect the existingNOx Budget
Trading Program to continue. We evaluated the impact of the court’s decision on
the recoverability of the carrying amounts of our emission allowances and
concluded that our emission allowances were not impaired as a result of the
ruling.




54





Global
Climate





Future
initiatives regarding greenhouse gas emissions and global warming are subject to
active consideration in the U.S. Congress. In June 2008, the U.S. Senate
considered legislation proposed by Senators Lieberman, Warner, and Boxer that
would set up a “cap and trade” program for greenhouse gas emissions. That
legislation was not approved by the U.S. Senate. In October 2008, the U.S. House
of Representatives, Energy and Commerce Committee, Subcommittee on Energy and
Air Quality issued a “discussion draft” of climate legislation. The discussion
draft proposes establishing an economy-wide cap and trade program. The
overarching goal of such legislation is to reduce greenhouse gas emissions to a
level that is 6% below 2005 levels by 2020 and 80% below 2005 levels by the year
2050. In addition, individual members of Congress have proposed cap and trade
legislation. However, it is unlikely that such legislation will be taken up this
year.





In
addition, President Bush has supported climate initiatives that would focus on
technology development to eliminate the growth in greenhouse gas emissions by
2025, a proposal much more moderate than the Lieberman-Warner-Boxer legislation
that was considered in the Senate. In July 2008, the “Group of Eight” (G8)
countries, which includes the U.S., issued a statement that they had agreed to
consider and adopt a greenhouse gas reduction target of 50% by 2050. This
agreement was a significant departure from prior Bush administration
policy.





The
outcome of these initiatives cannot be determined at this time. However,
President-elect Obama has expressed support for a greenhouse gas emissions cap
and trade program. Therefore, the likelihood that some form of federal
greenhouse gas legislation will become law increases under the next presidential
administration.





Ameren
believes that currently-proposed legislation can be classified as moderate to
extreme depending upon proposed CO2 emission
limits, the timing of implementation of those limits, and the method of
allocating allowances. The moderate scenarios include provisions for a “safety
valve” that provides a ceiling price for emission allowance purchases. As a
result of our diverse fuel portfolio, our contribution to greenhouse gases
varies among our generating facilities, but coal-fired power plants are
significant sources of CO2, a
principal greenhouse gas. Ameren’s current analysis shows that under some policy
scenarios being considered in Congress, household costs and rates for
electricity could rise significantly. The burden could fall particularly hard on
electricity consumers and the Midwest economy because of the region's reliance
on electricity generated by coal-fired power plants. Natural gas emits about
half the amount of CO2 that coal
emits. As a result, economy-wide shifts favoring natural gas as a fuel source
for electric generation also could affect nonelectric transportation, heating
for our customers and many industrial processes. Under some policy scenarios
being considered by Congress, Ameren believes that wholesale natural gas costs
could rise significantly as well. Higher costs for energy could contribute to
reduced demand for electricity and natural gas.





Future
initiatives regarding greenhouse gas emission and global warming may also be
subject to the activities of the Midwest Greenhouse Gas Reduction Accord - an
agreement signed by the governors of Illinois, Iowa, Kansas, Michigan, Wisconsin
and Minnesota - to develop a strategy to achieve energy security and reduce
greenhouse gas emissions through a cap and trade mechanism. It is expected that
the advisory group to the midwest governors will provide recommendations on the
design of a greenhouse gas reduction program by the third quarter of 2009.
However, it is uncertain if legislation to implement the recommendations will be
implemented or passed by the state of Illinois.





Future
federal and state legislation or regulations that mandate limits on the emission
of greenhouse gases would result in significant increases in capital
expenditures and operating costs. The costs to comply with future legislation or
regulations could be so expensive that Ameren and other similarly-situated
electric power generators may be forced to close some coal-fired facilities.
Mandatory limits could have a material adverse impact on Ameren’s, UE’s,
Genco’s, AERG’s and EEI’s results of operations, financial position, or
liquidity.





With
regard to greenhouse gas regulation under existing law, in April 2007, the U.S.
Supreme Court issued a decision that determined that the EPA has the authority
to regulate CO2 and other
greenhouse gases from automobiles as “air pollutants” under the Clean Air Act.
The Supreme Court sent the case back to the EPA, which must conduct a rulemaking
process to determine whether greenhouse gas emissions contribute to climate
change “which may reasonably be anticipated to endanger public health or
welfare.” In July 2008, the EPA issued an advance notice of public rulemaking
(ANPR) in response to the U.S. Supreme Court’s directive. The ANPR invites
public comments on the benefits and ramifications of regulating greenhouse gases
under the Clean Air Act. However, in a preface to the ANPR, EPA Administrator,
Stephen Johnson, expressed a concern that the Clean Air Act is ill-suited for
this purpose and would result in a convoluted and ineffective set of
regulations. New regulations resulting from the rulemaking process are not
expected this year, but the EPA could begin to regulate greenhouse gas emissions
at some point in the future.




55




Ameren
has taken actions to address the global climate issue. These
include:





·
            seeking
      partners to develop wind energy for our generation
    portfolio;


·
            participating
      in DOE-sponsored research into the feasibility of sequestering CO2
      underground in the Illinois basin, the Plains sequestration partnership,
      and a Missouri sequestration project to be conducted in Southwest
      Missouri;


·
            increasing
      the operating efficiency and capacity of our nuclear and hydroelectric
      plants to provide more energy to offset fossil
  generation;


·
            participating
      in the PowerTree Carbon Company, LLC, whose purpose is to reforest acreage
      in the lower Mississippi valley to sequester
  carbon;


·
            using
      coal combustion by-products as a direct replacement for cement, thereby
      reducing carbon emissions at cement
kilns;


·
            participating
      in a DOE and state of Missouri Department of Natural Resources project
      evaluating Missouri wind resources for the next generation of wind
      turbines;


·
            funding
      a project investigating opportunities to reduce nitrous oxide (N2O), a
      potent greenhouse gas from agricultural usage and tracking those
      reductions;


·
            participating
      in “Illinois Clean Energy Community Foundation”, a program that supports
      energy efficiency, promotes renewable energy, and provides educational
      opportunities;


·
            establishing
      Pure Power, UE’s voluntary renewable energy program that allows UE’s
      electric customers to support development of wind farms and other
      renewable energy facilities in the Midwest;
and


·
            purchasing
      Renewable Energy Credits - the Ameren Illinois Utilities purchased 415,000
      renewable energy credits in April
2008.





The
impact on us of future initiatives related to greenhouse gas emissions and
global warming is unknown. Although compliance costs are unlikely in the near
future, our costs of complying with any mandated federal or state greenhouse gas
program could have a material impact on our future results of operations,
financial position, or liquidity.





Clean
Water Act





In July
2004, the EPA issued rules under the Clean Water Act that require cooling-water
intake structures to have the best technology available for minimizing adverse
environmental impacts on aquatic species. These rules pertain to all existing
generating facilities that currently employ a cooling-water intake structure
whose flow exceeds 50 million gallons per day. The rules may require us to
install additional intake screens or other protective measures and to do
extensive site-specific study and monitoring. There is also the possibility that
the rules may lead to the installation of cooling towers on some of our
facilities. In January 2007, the U.S. Court of Appeals for the Second Circuit
remanded many provisions of these rules to the EPA for revision. In April 2008,
the U.S. Supreme Court agreed to hear an appeal of the lower court ruling. The
U.S. Supreme Court is expected to hear the case by the end of 2008. However, the
EPA is expected to reissue the rules early in 2009. Until a decision is issued
by the Supreme Court, the new rules are adopted and the studies on the power
plants are completed, we are unable to estimate the costs of complying with
these rules. Such costs are not expected to be incurred prior to
2012.





New
Source Review





The EPA
has been conducting an enforcement initiative to determine whether modifications
at a number of coal-fired power plants owned by electric generators in the
United States are subject to New Source Review (NSR) 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. In
December 2006, the EPA issued a second Section 114(a) request to Genco regarding
projects at the Newton facility. All of these facilities are coal-fired power
plants. In September 2008, the EPA issued a third Section 114(a) request
regarding projects at all of Ameren’s Illinois coal-fired power plants. We are
in the process of responding to this request. We are currently in discussions
with the EPA and the state of Illinois regarding resolution of these matters,
but we are unable to predict the outcome of these discussions.





In March 2008, Ameren 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 UE’s
Labadie, Meramec, Rush Island, and Sioux facilities. All of these facilities are
coal-fired power plants. The information request required UE to provide
responses to specific EPA questions regarding certain projects and maintenance
activities to determine compliance with state and federal regulatory
requirements. UE is complying with this information request, but we are unable
to predict the outcome of this matter.




56


Resolution of these matters could
have a material adverse impact on the future results of operations, financial
position or liquidity of Ameren, UE, Genco, AERG and EEI. A resolution could
result in increased capital expenditures for the installation of control
technology, increased operations and maintenance expenses, and fines or
penalties.





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





As of
September 30, 2008, CIPS, CILCO and IP owned or were otherwise responsible for
several former MGP sites in Illinois. CIPS has 14, CILCO four, and IP 25. 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 its former MGP sites from its 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, 2008, estimated obligations were:  CIPS - $18 million
to $31 million, CILCO - $10 million to $15 million, and IP - $77
million to $145 million. CIPS, CILCO and IP recorded liabilities of $18
million, $10 million and $77 million, respectively, to provide for estimated
minimum obligations, as no other amount within the range was a better
estimate.





CIPS is
also responsible for the cleanup of a former landfill in Coffeen, Illinois. As
of September 30, 2008, CIPS estimated its obligation at $0.5 million to $6
million. CIPS recorded a liability of $0.5 million to represent its estimated
minimum obligation for this site as no other amount within the range was a
better estimate. IP is also responsible for the cleanup of a landfill,
underground storage tanks, and a water treatment plant in Illinois. As of
September 30, 2008, IP recorded a liability of $1 million to represent its best
estimate of the obligation for these sites.





In
addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and
one in Iowa. UE does not currently have in effect in Missouri a rate rider
mechanism that permits remediation costs associated with MGP sites to be
recovered from utility customers. UE does not have any retail utility operations
in Iowa that would provide a source of recovery of these remediation costs. As
of September 30, 2008, UE estimated its obligation at $3 million to $5
million. UE recorded a liability of $3 million to represent its estimated
minimum obligation for its MGP sites as no other amount within the range was a
better estimate. UE also is responsible for four electric sites in Missouri that
have corporate cleanup liability, most as a result of federal agency
mandates.





In June
2000, the EPA notified UE and numerous other companies, including Solutia, that
former landfills and lagoons in Sauget, Illinois, may contain soil and
groundwater contamination. These sites are known as Sauget Area 2. From about
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 (PRPs) to evaluate the extent of potential
contamination with respect to Sauget Area 2.





Sauget
Area 2 investigation activities under the oversight of the EPA are largely
completed, and the results will be submitted to the EPA in June 2009. Following
this submission, the EPA will ultimately select a remedy alternative and begin
negotiations with various PRPs to implement it. Over the last several years,
numerous other parties have joined the PRP group and presumably will participate
in the funding of any required remediation. In addition, Pharmacia Corporation
and Monsanto Company have agreed to assume the liabilities related to Solutia’s
former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s
filing for bankruptcy protection. As of September 30, 2008, UE estimated its
obligation at $0.8 million to $10 million. UE recorded a liability of $0.8
million to represent its estimated minimum obligation as no other amount within
the range was a better estimate.





In March
2008, the EPA issued an administrative order to CIPS requesting that it
participate in a portion of an environmental cleanup of a site within Sauget
Area 2 previously occupied by Clayton Chemical Company. CIPS was formerly a
customer of Clayton Chemical Company that, before its dissolution, was a
recycler of waste solvents and oil. Other former customers of Clayton Chemical
Company were issued similar orders by the EPA. Pursuant to that order, CIPS and
three other PRPs agreed to install an engineered barrier on portions of the
Clayton Chemical Company site. This work is expected to be concluded by the
first quarter of 2009 or earlier. As of September 30, 2008,




57




CIPS
recorded a liability of $0.25 million to represent its best estimate of its
obligation for this site.





In July
2008, the EPA issued an administrative order to UE pertaining to a former coal
tar distillery operated by Koppers Company or its predecessor and successor
companies. UE is the current owner of the site but did not conduct any of the
manufacturing operations involving coal tar or its by-products. UE is currently
in negotiations with other PRPs concerning the scope of future site
investigations. As of September 30, 2008, UE estimated its obligation at $2
million to $5 million. UE recorded a liability of $2 million to represent its
estimated minimum obligation as no other amount within the range was a better
estimate.





In
December 2004, AERG submitted a comprehensive package to the Illinois EPA to
address groundwater and surface water issues associated with the recycle pond,
ash ponds, and reservoir at the Duck Creek power plant facility. Information
submitted by AERG is currently under review by the Illinois EPA. CILCORP and
CILCO both have a liability of $1 million at September 30, 2008, 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 of and, in appropriate circumstances, the cleanup of substances
regulated under environmental protection laws. We are unable to determine the
impact these actions may have on our results of operations, financial position,
or liquidity.





Polychlorinated
Biphenyls Information Request





Polychlorinated
biphenyls (PCBs) are a blend of chemical compounds that were historically used
in a variety of industrial products because of their chemical and thermal
stability. In natural gas systems, PCBs were used as a compressor lubricant and
a valve sealant before their sale for these applications was banned by the EPA
in 1979. During the third quarter of 2007, the Ameren Illinois Utilities
received requests from the Illinois attorney general and the EPA for information
regarding their experiences with PCBs in their gas distribution systems. The
Ameren Illinois Utilities responded to these information requests.





The
Ameren Illinois Utilities evaluated their gas distribution systems for the
presence of PCBs. They believe that the presence of PCBs is limited to discrete
areas and is not widespread throughout their service territories. We cannot
predict whether any further actions will be required on the part of the Ameren
Illinois Utilities regarding this matter or what the ultimate outcome will
be.





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.





UE has
settled all state and federal issues associated with the December 2005 Taum Sauk
incident. In addition, UE received approval from FERC to rebuild the upper
reservoir at its Taum Sauk plant and has begun rebuilding the facility. The
estimated cost to rebuild the upper reservoir is in the range of $480 million.
UE expects the Taum Sauk plant to be out of service through early
2010.





In
December 2006, 10 business owners filed a lawsuit regarding the Taum Sauk
breach. The suit, which was filed in the Missouri Circuit Court of Reynolds
County and remains pending, contains allegations of negligence, violations of
the Missouri Clean Water Act, and various other statutory and common law claims
and seeks damages relating to business losses, lost profit, and unspecified
punitive damages. UE has filed a motion to dismiss the lawsuit, arguing that
Missouri law does not permit the plaintiffs to recover purely economic loss
under theories of negligence and strict liability. This motion is currently
pending.





At this
time, UE believes that substantially all damages and liabilities caused by the
breach, including costs related to the settlement agreement with the state of
Missouri, the cost of rebuilding the plant, and the cost of replacement power,
up to $8 million annually, will be covered by insurance. Insurance will not
cover lost electric margins and penalties paid to FERC. UE expects that the
total cost for cleanup, damage and liabilities, excluding costs to rebuild the
reservoir, will range from $202 million to $222 million. As of September 30,
2008, UE had paid $174 million, including costs resulting from the
FERC-approved stipulation and consent agreement, and accrued a $28 million
liability while expensing $34 million and recording a $168 million receivable
due from insurance companies. As of September 30, 2008, UE had received $79
million from insurance companies, which reduced the insurance receivable balance
to $89 million.





As of
September 30, 2008, UE had recorded a $263 million receivable due from
insurance companies related to the rebuilding of the facility and the
reimbursement for replacement power costs. As of September 30, 2008, UE had
received $150 million from insurance companies, which reduced the insurance
receivable balance as of September 30, 2008, to $113 million.




58


Under
UE’s insurance policies, all claims by or against UE are subject to review by
its insurance carriers.





In
September 2007, the Missouri Coalition for the Environment, the Sierra Club, and
American Rivers filed a motion to seek intervention and rehearing and a stay of
FERC authorization granted to UE to rebuild the upper reservoir at its Taum Sauk
plant. In December 2007, FERC granted intervention, denied rehearing, and
dismissed the request for stay. In February 2008, the Missouri Coalition for the
Environment and the Missouri Parks Association filed an appeal of FERC’s
decision with the U.S. Court of Appeals for the Eighth Circuit. In October
2008, the Court of Appeals denied this appeal.





Until
litigation has been resolved and the insurance review is completed, among other
things, we are unable to determine the total impact the breach may have on
Ameren’s and UE’s results of operations, financial position, or liquidity beyond
those amounts already recognized.





Mechanics’
Liens





Approximately
20 mechanics’ liens have been filed by various subcontractors who provided labor
or material for a 2007 maintenance outage at the Duck Creek facility of AERG.
The total lien claim amount was $26 million plus interest at September 30, 2008.
In November 2007, the primary subcontractor on the project filed a complaint for
foreclosure of its mechanic’s lien of $19 million plus interest against AERG in
the Circuit Court of Fulton County, Illinois. Since that time, various second
tier subcontractors of the primary subcontractor have filed for foreclosure of
their mechanics’ lien claims against AERG in the Circuit Court of Fulton County,
Illinois in addition to filing their claim against the primary subcontractor.
These claims were primarily based on additional work outside of the original
contract scope and were not approved by AERG. Since the time of the lien
filings, the primary subcontractor on the project has paid or has agreed to pay
approximately $4 million of the second tier subcontractors’ claims. In addition,
AERG has paid approximately $1 million to various parties that have claims
against the primary subcontractor. AERG plans to deduct these payments from a
contract-allowed holdback of $4 million.  AERG has filed its answers
to the claims in the foreclosure lawsuits denying the validity of the liens. At
this time, we do not believe that the resolution of these liens and lawsuits
will have a material impact on CILCO’s or AERG’s results of operations,
financial position, or liquidity.





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 161 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,
2008, the average number of parties was 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 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 have contractually agreed to
indemnify Genco and AERG, respectively, for liabilities associated with
asbestos-related claims arising from activities prior to the transfer. Each
lawsuit seeks unspecified damages, which, if awarded at trial, typically would
be shared among various defendants.





From July 1, 2008, through September
30, 2008, one additional asbestos-related lawsuit was filed against UE, CIPS,
CILCO and IP, in the Circuit Court of Madison County, Illinois. Seven lawsuits
were dismissed. The following table presents the status as of September 30,
2008, of the asbestos-related lawsuits that have been filed against the Ameren
Companies:





Specifically
      Named as DefendantTotal(a)
            Ameren
            UE
            CIPS
            Genco
            CILCO
            IPFiled
            367
            33
            202
            152
            2
            50
            182Settled
            131
            -
            68
            60
            -
            20
            66Dismissed
            171
            30
            112
            61
            2
            19
            82Pending
            65
            3
            22
            31
            -
            11
            34





(a)
            Totals
      do not equal to the sum of the subsidiary unit lawsuits because some of
      the lawsuits name multiple Ameren entities as
  defendants.





As of
September 30, 2008, 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.





IP has a
tariff rider to recover the costs of asbestos-related litigation claims, subject
to the following terms. 90% of cash expenditures in excess of the amount
included in base electric rates are recovered by IP from a trust fund
established




59




by IP and
financed with contributions of $10 million each by Ameren and Dynegy. At
September 30, 2008, the trust fund balance was $23 million, including
accumulated interest.





If cash
expenditures are less than the amount in base rates, IP will contribute 90% of
the difference to the fund. Once the trust fund is depleted, 90% of allowed cash
expenditures in excess of base rates will be recovered through charges assessed
to customers under the tariff rider.





The
Ameren Companies believe that the final disposition of these proceedings will
not have a material adverse effect on their results of operations, financial
position, or liquidity.





NOTE
10 - 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 before 2020. 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. UE
intends to submit a license extension application with the NRC to extend its
Callaway nuclear plant’s operating license to 2044. It is assumed that the
Callaway nuclear plant site will be decommissioned based on the 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 2007,
2006 and 2005. 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 cost study was
filed in September 2008. The 2008 study included the minor tritium contamination
discovered on the Callaway nuclear plant site, which did not result in a
significant increase in the decommissioning cost estimate. 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 or
regulatory liability, as appropriate.





See Note
2 - Rate and Regulatory Matters for information on the COLA filed by UE with the
NRC for a potential new nuclear plant.








NOTE
11 - 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, 2008 and 2007, is shown
below for the Ameren Companies:





Three
      Months
            
            
            Nine
      Months2008
            
            
            2007
            
            
            2008
            
            
            2007Ameren:(a)Net
      income
            
            $
            204
            
            
            $
            244
            
            
            $
            548
            
            
            $
            510Unrealized
      net gain on derivative hedging instruments, net of taxes of $89, $8, $26
              and
      $6, respectively
            
            
            157
            
            
            
            15
            
            
            
            46
            
            
            
            10Reclassification
      adjustments for derivative (gain) included in net income, net of taxes of
      $23,
      $9, $17 and $19, respectively
            
            
            (40
            )
            
            
            (17
            )
            
            
            (29
            )
            
            
            (33
            )Adjustment
      to pension and benefit obligation, net of taxes (benefit) of $-, $1, $1
      and $(2), respectively
            
            
            -
            
            
            
            1
            
            
            
            (2
            )
            
            
            2Total
      comprehensive income, net of taxes
            
            $
            321
            
            
            $
            243
            
            
            $
            563
            
            
            $
            489




60




Three
      Months
            
            
            Nine
      Months2008
            
            
            2007
            
            
            2008
            
            
            2007UE:Net
      income
            
            $
            99
            
            
            $
            193
            
            
            $
            287
            
            
            $
            307Unrealized
      net gain on derivative hedging instruments, net of taxes of $23, $3, $12
      and $3, respectively
            
            
            38
            
            
            
            5
            
            
            
            21
            
            
            
            4Reclassification
      adjustments for derivative (gain) included in net income, net of taxes of
      $2, $1,
              $3
      and $2, respectively
            
            
            (4
            )
            
            
            (1
            )
            
            
            (5
            )
            
            
            (3
            )Total
      comprehensive income, net of taxes
            
            $
            133
            
            
            $
            197
            
            
            $
            303
            
            
            $
            308CIPS:Net
      income
            
            $
            7
            
            
            $
            1
            
            
            $
            7
            
            
            $
            19Reclassification
      adjustments for derivative (gain) included in net income, net of taxes of
      $-, $-,
              $-
      and$1,
      respectively
            
            
            -
            
            
            
            (1
            )
            
            
            -
            
            
            
            (1
            )Total
      comprehensive income, net of taxes
            
            $
            7
            
            
            $
            -
            
            
            $
            7
            
            
            $
            18Genco:Net
      income
            
            $
            20
            
            
            $
            25
            
            
            $
            140
            
            
            $
            84Unrealized
      net (loss) on derivative hedging instruments, net of taxes (benefit) of
      $-, $-, $- and
              $(1),respectively
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (2
            )Reclassification
      adjustments for derivative (gain) included in net income, net of taxes of
      $-, $-,
              $4
      and $-, respectively
            
            
            -
            
            
            
            -
            
            
            
            (5
            )
            
            
            -Adjustment
      to pension and benefit obligation, net of taxes (benefit) of $-, $1, $(2)
      and $(1), respectively
            
            
            -
            
            
            
            1
            
            
            
            3
            
            
            
            (1
            )Total
      comprehensive income, net of taxes
            
            $
            20
            
            
            $
            26
            
            
            $
            138
            
            
            $
            81CILCORP:Net
      income
            
            $
            18
            
            
            $
            1
            
            
            $
            42
            
            
            $
            34Unrealized
      net (loss) on derivative hedging instruments, net of taxes (benefit) of
      $-, $(1), $- and
              $-,
      respectively
            
            
            -
            
            
            
            (1
            )
            
            
            -
            
            
            
            (1
            )Reclassification
      adjustments for derivative (gain) included in net income, net of taxes of
      $-, $-,
              $1
      and $1, respectively
            
            
            -
            
            
            
            -
            
            
            
            (1
            )
            
            
            (2
            )Adjustment
      to pension and benefit obligation, net of taxes of $-, $-, $1 and $-,
      respectively
            
            
            -
            
            
            
            -
            
            
            
            3
            
            
            
            1Total
      comprehensive income, net of taxes
            
            $
            18
            
            
            $
            -
            
            
            $
            44
            
            
            $
            32CILCO:Net
      income
            
            $
            24
            
            
            $
            10
            
            
            $
            62
            
            
            $
            58Reclassification
      adjustments for derivative (gain) included in net income, net of taxes of
      $-, $-,
              $-
      and $1, respectively
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            (2
            )Adjustment
      to pension and benefit obligation, net of taxes of $-, $-, $3 and $-,
      respectively
            
            
            -
            
            
            
            -
            
            
            
            4
            
            
            
            -Total
      comprehensive income, net of taxes
            
            $
            24
            
            
            $
            10
            
            
            $
            66
            
            
            $
            56IP:Net
      income (loss)
            
            $
            5
            
            
            $
            (4
            )
            
            $
            (2
            )
            
            $
            18Total
      comprehensive income (loss), net of taxes
            
            $
            5
            
            
            $
            (4
            )
            
            $
            (2
            )
            
            $
            18





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





NOTE
12 - STOCKHOLDER RIGHTS PLAN





Ameren’s
stockholder rights plan expired on October 9, 2008. Ameren’s Board of Directors
decided not to renew the plan.





NOTE
13 - RETIREMENT BENEFITS





Ameren's
pension and postretirement plans are funded in compliance with income tax
regulations, federal funding requirements and state regulatory agreements. In
May 2007, the MoPSC issued an electric rate order for UE that allows UE to
recover, through customer rates, pension expense incurred under GAAP. Ameren
expects to fund its pension plans at a level equal to the greater of the pension
expense or the legally required minimum contribution. Based on Ameren's
assumptions at December 31, 2007, and declining investment performance in 2008,
and reflecting Ameren’s pension funding policy, Ameren expects annual
contributions of $50 million to $200 million in each of the next five years.
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. Our policy for postretirement benefits is primarily
to fund the Voluntary Employee Beneficiary Association trusts to match the
annual postretirement expense.




61


Ameren
made contributions to its pension and postretirement benefit plans of $32
million and $22 million, respectively, during the nine months ended September
30, 2008, as compared to a $26 million contribution to its postretirement plan
during the nine months ended September 30, 2007.





The
following table presents 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, 2008 and 2007:





Pension
      Benefits(a)
            
            
            Postretirement
      Benefits(a)Three
      Months
            
            
            Nine
      Months
            
            
            Three
      Months
            
            
            Nine
      Months2008
            
            
            2007
            
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Service
      cost
            
            $
            15
            
            
            $
            16
            
            
            $
            44
            
            
            $
            47
            
            
            $
            5
            
            
            $
            5
            
            
            $
            14
            
            
            $
            15Interest
      cost
            
            
            46
            
            
            
            45
            
            
            
            139
            
            
            
            135
            
            
            
            17
            
            
            
            18
            
            
            
            52
            
            
            
            54Expected
      return on plan assets
            
            
            (53
            )
            
            
            (51
            )
            
            
            (159
            )
            
            
            (154
            )
            
            
            (14
            )
            
            
            (13
            )
            
            
            (43
            )
            
            
            (39
            )Amortization
      of:Transition
      obligation
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            1
            
            
            
            1
            
            
            
            2
            
            
            
            2Prior service cost
      (benefit)
            
            
            3
            
            
            
            3
            
            
            
            9
            
            
            
            9
            
            
            
            (2
            )
            
            
            (2
            )
            
            
            (6
            )
            
            
            (6
            )Actuarial
      loss
            
            
            1
            
            
            
            5
            
            
            
            2
            
            
            
            16
            
            
            
            2
            
            
            
            6
            
            
            
            6
            
            
            
            18Net
      periodic benefit cost
            
            $
            12
            
            
            $
            18
            
            
            $
            35
            
            
            $
            53
            
            
            $
            9
            
            
            $
            15
            
            
            $
            25
            
            
            $
            44





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





UE, CIPS,
Genco, CILCORP, CILCO and IP are participants in Ameren’s plans and are
responsible for their proportional share of the pension and postretirement
costs. The following table presents the pension costs and the postretirement
benefit costs incurred for the three months and nine months ended September 30,
2008 and 2007:





Pension
      Costs
            
            
            Postretirement
      CostsThree
      Months
            
            
            Nine
      Months
            
            
            Three
      Months
            
            
            Nine
      Months2008
            
            
            2007
            
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007
            
            
            2008
            
            
            2007Ameren(a)
            
            $
            12
            
            
            $
            18
            
            
            $
            35
            
            
            $
            53
            
            
            $
            9
            
            
            $
            15
            
            
            $
            25
            
            
            $
            44UE
            
            
            8
            
            
            
            10
            
            
            
            27
            
            
            
            30
            
            
            
            4
            
            
            
            7
            
            
            
            10
            
            
            
            22CIPS
            
            
            2
            
            
            
            2
            
            
            
            5
            
            
            
            6
            
            
            
            -
            
            
            
            2
            
            
            
            2
            
            
            
            5Genco
            
            
            1
            
            
            
            2
            
            
            
            4
            
            
            
            4
            
            
            
            -
            
            
            
            1
            
            
            
            1
            
            
            
            3CILCORP
            
            
            -
            
            
            
            2
            
            
            
            (2
            )
            
            
            7
            
            
            
            2
            
            
            
            2
            
            
            
            2
            
            
            
            5CILCO
            
            
            1
            
            
            
            2
            
            
            
            3
            
            
            
            7
            
            
            
            3
            
            
            
            3
            
            
            
            5
            
            
            
            8IP
            
            
            -
            
            
            
            1
            
            
            
            (2
            )
            
            
            4
            
            
            
            3
            
            
            
            2
            
            
            
            10
            
            
            
            8





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





NOTE
14 - SEGMENT INFORMATION





Ameren
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 former 40% interest in EEI and
other non-rate regulated activities, which are included in Other. UE’s interest
in EEI was transferred to Resources Company on February 29, 2008. 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 consists primarily of the operations or activities
of Genco, the CILCORP parent company, AERG, EEI, and Marketing Company. The
category called Other primarily includes Ameren parent company activities and
the leasing activities of CILCORP, AERG, Resources Company, and CIPSCO
Investment Company. CIPSCO
Investment Company was eliminated on March 31, 2008, through an internal
reorganization.





UE 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 former 40% interest in EEI
and other non-rate-regulated activities, which are included in
Other.





CILCORP
and CILCO have two reportable segments: Illinois Regulated and
Non-rate-regulated Generation. The Illinois Regulated segment for CILCORP and
CILCO consists 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. For CILCORP and CILCO, Other
comprises parent company activity and minor activities not reported in the
Illinois Regulated or Non-rate-regulated Generation segments for
CILCORP.




62


The
following table presents information about the reported revenues and specified
items included in net income of Ameren for the three months and nine months
ended September 30, 2008 and 2007, and total assets as of September 30, 2008 and
December 31, 2007.





Three
      Months
            
            Missouri
              Regulated
            
            
            Illinois
              Regulated
            
            
            Non-rate-
              regulated
              Generation
            
            
            Other
            
            
            Intersegment
              Eliminations
            
            
            Consolidated2008:External
      revenues
            
            $
            865
            
            
            $
            724
            
            
            $
            478
            
            
            $
            (7
            )
            
            $
            -
            
            
            $
            2,060Intersegment
      revenues
            
            
            10
            
            
            
            7
            
            
            
            114
            
            
            
            3
            
            
            
            (134
            )
            
            
            -Net
      income (loss)(a)
            
            
            98
            
            
            
            13
            
            
            
            108
            
            
            
            (15
            )
            
            
            -
            
            
            
            2042007:External
      revenues
            
            $
            934
            
            
            $
            704
            
            
            $
            372
            
            
            $
            (13
            )
            
            $
            -
            
            
            $
            1,997Intersegment
      revenues
            
            
            11
            
            
            
            21
            
            
            
            125
            
            
            
            10
            
            
            
            (167
            )
            
            
            -Net
      income (loss)(a)
            
            
            178
            
            
            
            (8
            )
            
            
            71
            
            
            
            3
            
            
            
            -
            
            
            
            244Nine
      Months2008:External
      revenues
            
            $
            2,340
            
            
            $
            2,487
            
            
            $
            1,110
            
            
            $
            (6
            )
            
            $
            -
            
            
            $
            5,931Intersegment
      revenues
            
            
            30
            
            
            
            30
            
            
            
            341
            
            
            
            11
            
            
            
            (412
            )
            
            
            -Net
      income (loss)(a)
            
            
            272
            
            
            
            15
            
            
            
            284
            
            
            
            (23
            )
            
            
            -
            
            
            
            5482007:External
      revenues
            
            $
            2,258
            
            
            $
            2,513
            
            
            $
            980
            
            
            $
            (1
            )
            
            $
            -
            
            
            $
            5,750Intersegment
      revenues
            
            
            34
            
            
            
            34
            
            
            
            386
            
            
            
            30
            
            
            
            (484
            )
            
            
            -Net
      income(a)
            
            
            263
            
            
            
            45
            
            
            
            197
            
            
            
            5
            
            
            
            -
            
            
            
            510As
      of September 30, 2008:Total
      assets
            
            $
            11,037
            
            
            $
            6,363
            
            
            $
            4,269
            
            
            $
            1,037
            
            
            $
            (1,227
            )
            
            $
            21,479As
      of December 31, 2007:Total
      assets
            
            $
            10,852
            
            
            $
            6,385
            
            
            $
            4,027
            
            
            $
            965
            
            
            $
            (1,501
            )
            
            $
            20,728





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





The
following table presents information about the reported revenues and specified
items included in net income of UE for the three months and nine months ended
September 30, 2008 and 2007, and total assets as of September 30, 2008 and
December 31, 2007.





Three
      Months
            
            Missouri
      Regulated
            
            
            Other
      (a)
            
            
            Consolidated
              UE2008:Revenues
            
            $
            875
            
            
            $
            -
            
            
            $
            875Net
      income(b)
            
            
            98
            
            
            
            -
            
            
            
            982007:Revenues
            
            $
            945
            
            
            $
            -
            
            
            $
            945Net
      income(b)
            
            
            178
            
            
            
            14
            
            
            
            192Nine
      Months2008:Revenues
            
            $
            2,370
            
            
            $
            -
            
            
            $
            2,370Net
      income(b)
            
            
            272
            
            
            
            11
            
            
            
            2832007:Revenues
            
            $
            2,292
            
            
            $
            -
            
            
            $
            2,292Net
      income(b)
            
            
            263
            
            
            
            40
            
            
            
            303As
      of September 30, 2008:Total
      assets
            
            $
            11,037
            
            
            $
            -
            
            
            $
            11,037As
      of December 31, 2007:Total
      assets
            
            $
            10,852
            
            
            $
            51
            
            
            $
            10,903





(a)
            Included
      40% interest in EEI through February 29,
2008.


(b)
            Represents
      net income available to the common shareholder
  (Ameren).






63


The
following table presents information about the reported revenues and specified
items included in net income of CILCORP for the three months and nine months
ended September 30, 2008 and 2007, and total assets as of September 30, 2008 and
December 31, 2007.





Three
      Months
            
            Illinois
              Regulated
            
            
            Non-rate-
              regulated
              Generation
            
            
            CILCORP
              Other
            
            
            Intersegment
              Eliminations
            
            
            Consolidated
              CILCORP2008:External
      revenues
            
            $
            162
            
            
            $
            102
            
            
            $
            -
            
            
            $
            -
            
            
            $
            264Intersegment
      revenues
            
            
            1
            
            
            
            -
            
            
            
            -
            
            
            
            (1
            )
            
            
            -Net
      income(a)
            
            
            4
            
            
            
            14
            
            
            
            -
            
            
            
            -
            
            
            
            18


2007:External
      revenues
            
            $
            144
            
            
            $
            67
            
            
            $
            -
            
            
            $
            -
            
            
            $
            211Intersegment
      revenues
            
            
            -
            
            
            
            1
            
            
            
            -
            
            
            
            (1
            )
            
            
            -Net
      income (loss)(a)
            
            
            (4
            )
            
            
            5
            
            
            
            -
            
            
            
            -
            
            
            
            1Nine
      Months2008:External
      revenues
            
            $
            590
            
            
            $
            252
            
            
            $
            -
            
            
            $
            -
            
            
            $
            842Intersegment
      revenues
            
            
            3
            
            
            
            -
            
            
            
            -
            
            
            
            (3
            )
            
            
            -Net
      income(a)
            
            
            15
            
            
            
            27
            
            
            
            -
            
            
            
            -
            
            
            
            422007:External
      revenues
            
            $
            547
            
            
            $
            205
            
            
            $
            -
            
            
            $
            -
            
            
            $
            752Intersegment
      revenues
            
            
            -
            
            
            
            3
            
            
            
            -
            
            
            
            (3
            )
            
            
            -Net
      income(a)
            
            
            11
            
            
            
            23
            
            
            
            -
            
            
            
            -
            
            
            
            34As
      of September 30, 2008:Total
      assets(b)
            
            $
            1,231
            
            
            $
            1,616
            
            
            $
            2
            
            
            $
            (222
            )
            
            $
            2,627As
      of December 31, 2007:Total
      assets(b)
            
            $
            1,202
            
            
            $
            1,455
            
            
            $
            1
            
            
            $
            (199
            )
            
            $
            2,459





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


(b)
            Total
      assets for Illinois Regulated and Non-rate-regulated Generation include an
      allocation of goodwill and other purchase accounting amounts related to
      CILCO that are recorded at CILCORP (parent
  company).





The
following table presents information about the reported revenues and specified
items included in net income of CILCO for the three months and nine months ended
September 30, 2008 and 2007, and total assets as of September 30, 2008 and
December 31, 2007.





Three
      Months
            
            Illinois
              Regulated
            
            
            Non-rate-
              regulated
              Generation
            
            
            CILCO
              Other
            
            
            Intersegment
              Eliminations
            
            
            Consolidated
              CILCO2008:External
      revenues
            
            $
            162
            
            
            $
            102
            
            
            $
            -
            
            
            $
            -
            
            
            $
            264Intersegment
      revenues
            
            
            1
            
            
            
            -
            
            
            
            -
            
            
            
            (1
            )
            
            
            -Net
      income(a)
            
            
            4
            
            
            
            20
            
            
            
            -
            
            
            
            -
            
            
            
            242007:External
      revenues
            
            $
            144
            
            
            $
            67
            
            
            $
            -
            
            
            $
            -
            
            
            $
            211Intersegment
      revenues
            
            
            -
            
            
            
            1
            
            
            
            -
            
            
            
            (1
            )
            
            
            -Net
      income (loss)(a)
            
            
            (4
            )
            
            
            14
            
            
            
            -
            
            
            
            -
            
            
            
            10Nine
      Months2008:External
      revenues
            
            $
            590
            
            
            $
            252
            
            
            $
            -
            
            
            $
            -
            
            
            $
            842Intersegment
      revenues
            
            
            3
            
            
            
            -
            
            
            
            -
            
            
            
            (3
            )
            
            
            -Net
      income(a)
            
            
            15
            
            
            
            46
            
            
            
            -
            
            
            
            -
            
            
            
            612007:External
      revenues
            
            $
            547
            
            
            $
            205
            
            
            $
            -
            
            
            $
            -
            
            
            $
            752Intersegment
      revenues
            
            
            -
            
            
            
            3
            
            
            
            -
            
            
            
            (3
            )
            
            
            -Net
      income(a)
            
            
            11
            
            
            
            46
            
            
            
            -
            
            
            
            -
            
            
            
            57As
      of September 30, 2008:Total
      assets
            
            $
            1,042
            
            
            $
            1,007
            
            
            $
            -
            
            
            $
            (1
            )
            
            $
            2,048As
      of December 31, 2007:Total
      assets
            
            $
            1,012
            
            
            $
            859
            
            
            $
            -
            
            
            $
            (9
            )
            
            $
            1,862





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







64




ITEM
2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS.
 
 The
following discussion should be read in conjunction with the financial statements
contained in this Form 10-Q as well as Management’s Discussion and Analysis of
Financial Condition and Results of Operations and Risk Factors contained in the
Form 10-K. We intend for this discussion to provide the reader with
information that will assist in understanding our financial statements, the
changes in certain key items in those financial statements, and the primary
factors that accounted for those changes, as well as how certain accounting
principles affect our financial statements. The discussion also provides
information about the
financial results of the various segments of our business to provide a better
understanding of how those segments and their results affect the financial
condition and results of operations of Ameren as a whole.




OVERVIEW
  Ameren
Executive Summary
 
 Ameren’s
earnings in the third quarter of 2008 were lower than its earnings in the 2007
comparable period principally because of net unrealized mark-to-market losses
from nonqualifying hedges, the negative impacts of milder summer
weather, higher fuel prices, increased spending on utility distribution
system reliability, and higher other operating expenses. These factors more than
offset the positive impacts of the reduced impact in 2008 of the Illinois
electric settlement agreement, higher electric margins from Non-rate-regulated
Generation’s operations, and the timing benefit of seasonally redesigned
electric rates in Illinois.
 
 Ameren’s
earnings in the first nine months of 2008 exceeded its earnings in the
comparable period in 2007 principally because of the impact of net
unrealized mark-to-market gains from nonqualifying hedges; a lump-sum payment in
July 2008 from a coal supplier for expected higher fuel costs for our
Non-rate-regulated Generation segment in 2009 as a result of the premature
closure of a mine in late 2007 and the resulting termination of a contract; the
absence of costs in 2008 that were incurred in January 2007 associated with
electric outages caused by severe ice storms; the estimated minimum amount of
January 2007 storm costs that UE expects to recover, as a result of an
accounting order issued by the MoPSC, which was recorded as a regulatory asset
in the second quarter of 2008; a March 2007 FERC order that resettled costs
among market participants retroactive to 2005; and the reduced impact in 2008 of
the Illinois electric settlement agreement.
 
 In
September 2008, the ICC authorized increases in electric and natural gas rates
for CIPS, CILCO and IP totaling $161 million. The new Illinois rates went into
effect on October 1, 2008. These increased rates will improve the
earnings and cash flows of the Ameren Illinois Utilities from depressed
levels. However, the Ameren Illinois Utilities continue to expect that
these rates will not keep pace with the level of costs they are currently
experiencing. Consequently, the Ameren Illinois Utilities are evaluating
the timing of their next rate case filings in Illinois. The Ameren Illinois
Utilities expect to file rate cases more frequently in the future to minimize
regulatory lag as well as to make bill increases more manageable for
customers.
 
 UE’s
pending electric rate case is progressing. UE requested an annual electric
revenue increase of approximately $251 million due to higher costs across its
business, including fuel and reliability costs, as well as higher infrastructure
investments. The MoPSC staff filed in August 2008 a report and direct testimony
with the MoPSC recommending a $51 million increase, and the staff did not
support UE’s request for a fuel and purchased power cost recovery mechanism. UE
expects the MoPSC to issue a rate order in late January or early February 2009,
with new rates effective March 1, 2009.
 
 The
global financial markets have experienced extreme volatility and disruption in
2008, and in particular, since early September. This disruption has lead to
major financial institutions coming under financial duress, significant strains
in the capital and credit markets, deteriorating global economic conditions and
steep declines in stock prices.
 
 We believe that the extreme
disruption in the capital and credit markets has made our ability to access the
capital and credit markets to support our operations and refinance short-term
debt more challenging. We are proactively taking prudent actions to modify our
short-term plans to address the current economic and financial market
uncertainties. At October 31, 2008, our available liquidity, which
represents our cash on hand and amounts available under our credit facilities,
was approximately $1.45 billion, up about $550 million from this same time last
year. Despite this solid liquidity position, we are reducing 2009 operating
and capital expenditures in our Non-rate-regulated Generation business by a
total of $400 million to $500 million. Operating and capital expenditures in
2009 for this business will be approximately $300 million to $400 million below
2008 levels. Other meaningful capital expenditure deferral and reduction
opportunities are also under review throughout the rest of our company. We will
remain focused on prudently managing our operations and maintaining strong
overall liquidity to meet our operating, capital and financing needs, as well as
executing our long-term strategic plans.


65




General 
 Ameren,
headquartered in St. Louis, Missouri, is a public utility holding company under
PUHCA 2005 administered by FERC. Ameren’s primary assets are the common stock of
its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities
with separate businesses, assets and liabilities. These subsidiaries 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. Dividends on Ameren’s common stock are
dependent on distributions made to it by its subsidiaries. Ameren’s principal
subsidiaries are listed below.





·
            UE
      operates a rate-regulated electric generation, transmission and
      distribution business, and a rate-regulated natural gas transmission and
      distribution business in Missouri.


·
            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
      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 average
diluted common shares outstanding during the applicable period. All tabular
dollar amounts are in millions, unless otherwise indicated.




RESULTS
OF OPERATIONS





Earnings
Summary





Our
results of operations and financial position are affected by many factors.
Weather, economic conditions, and the actions of key customers or competitors
can significantly affect the demand for our services. Our results are also
affected by seasonal fluctuations: winter heating and summer cooling demands.
The vast majority of Ameren’s revenues are subject to state or federal
regulation. This regulation has a material impact on the price we charge for our
services. Non-rate-regulated Generation sales are also subject to market
conditions for power. We principally use coal, nuclear fuel, natural gas, and
oil in our operations. The prices for these commodities can fluctuate
significantly due to the global economic and political environment, weather,
supply and demand, and many other factors. We do not currently have a fuel and
purchased power cost recovery mechanism in Missouri for our electric utility
business. We do have natural gas cost recovery mechanisms for our Illinois and
Missouri gas delivery businesses and purchased power cost recovery mechanisms
for our Illinois electric delivery businesses. See Note 2 - Rate and Regulatory
Matters to our financial statements under Part I, Item 1, for a discussion of
UE’s pending electric rate case, the September 24, 2008 ICC order in the Ameren
Illinois Utilities rate proceedings and the Illinois electric settlement
agreement. Fluctuations in interest rates and conditions in the capital and
credit markets affect our cost of borrowing and our pension and postretirement
benefits costs. We employ various risk management strategies to reduce our
exposure to commodity risk and other risks inherent in our business. The
reliability of our power plants and transmission and distribution systems, the
level of purchased power costs, operating and administrative costs, and capital
investment are key factors that we seek to control to optimize our results of
operations, financial position, and liquidity.





Ameren’s
net income decreased to $204 million, or 97 cents per share, in the third
quarter of 2008, from $244 million, or $1.18 per share, in the third
quarter of 2007. Net income in the third quarter of 2008 increased in the
Illinois Regulated and Non-rate-regulated Generation segments by $21 million and
$37 million, respectively, from the prior-year period, while net income in the
Missouri Regulated segment declined by $80 million from the same period in
2007.





Ameren’s
net income increased to $548 million, or $2.61 per share, in the first nine
months of 2008, from $510 million, or $2.46 per share, in the first nine
months of 2007. Net income increased in the Missouri Regulated and
Non-rate-regulated Generation segments by $9 million and $87
million, respectively, in the first nine months of 2008 compared to the
prior-year period, while net income in the Illinois Regulated segment decreased
by $30 million from the same period in 2007.







66




Earnings
were favorably impacted in the third quarter and first nine months of 2008 as
compared with the same periods in 2007 by:





·
            the
      reduced impact in 2008 of the electric rate relief and customer assistance
      programs provided to certain Ameren Illinois Utilities electric customers
      under the Illinois electric settlement agreement (15 cents per share and 8
      cents per share, respectively);


·
            the
      implementation of redesigned seasonal electric delivery service rates at
      the Ameren Illinois Utilities, which impacts quarterly earnings
      comparisons in 2008 but is not expected to have an impact on annual
      margins (11 cents per share and 5 cents per share, respectively);
      and


·
            higher
      realized electric margins in the Non-rate-regulated Generation
      segment.





Earnings
were negatively impacted in the third quarter and first nine months of 2008 as
compared with the same periods in 2007 by:





·
            higher
      fuel and related transportation prices, excluding net mark-to-market
      losses on fuel-related transactions, (8 cents per share and 25 cents
      per share, respectively);


·
            unfavorable
      weather conditions (estimated at 18 cents per share in both
      periods);


·
            increased
      distribution system reliability expenditures (6 cents per share and 20
      cents per share, respectively);


·
            higher
      plant operations and maintenance expense (2 cents per share and 10
      cents per share, respectively);


·
            higher
      labor and employee benefit costs (3 cents per share and 9 cents per share,
      respectively);


·
            higher
      bad debt expenses (2 cents per share and 5 cents per share,
      respectively);


·
            increased
      depreciation and amortization expense (2 cents per share and 5 cents
      per share, respectively); and


·
            higher
      financing costs (1 cent per share and 7 cents per share,
      respectively).





In addition to the above items
affecting both periods, earnings were favorably impacted in the first nine
months of 2008 as compared with the first nine months of 2007 by:





·
            a
      settlement agreement with a coal mine owner reached in June 2008 that
      reimbursed Genco, in the form of a lump-sum payment of $60 million, for
      increased costs for coal and transportation that it is incurring in
      2008 ($33 million) and expects to incur in 2009 ($27 million) due to
      the premature closure of an Illinois mine at the end of 2007 (18 cents per
      share);


·
            the
      absence of costs in 2008 that were incurred in 2007 relating to a
      refueling and maintenance outage at UE’s Callaway nuclear plant (16 cents
      per share);


·
            net
      unrealized mark-to-market gains primarily related to
      energy-related transactions (6 cents per
  share);


·
            the
      absence of costs in 2008 that were incurred in January 2007 associated
      with electric outages caused by severe ice storms (9 cents per
      share);


·
            the
      minimum amount of January 2007 storm costs that UE expects to recover, as
      a result of an accounting order issued by the MoPSC, which was recorded as
      a regulatory asset(4
      cents per share);


·
            higher
      electric rates, lower depreciation expense and decreased income tax
      expense in the Missouri Regulated segment pursuant to the MoPSC electric
      rate order for UE issued in May 2007 (8 cents per share);
    and


·
            a
      March 2007 FERC order that resettled costs among market participants
      retroactive to 2005 (5 cents per
share).







Earnings
were negatively impacted in the first nine months of 2008 as compared with the
first nine months of 2007 by the absence in 2008 of the reversal, recorded in
2007, of the Illinois Customer Elect electric rate increase phase-in plan
accrual (5 cents per share) and higher labor and employee benefit costs (4 cents
per share).





Earnings
were negatively impacted in the third quarter of 2008 as compared with the third
quarter of 2007 by net unrealized mark-to-market losses on nonqualifying hedges
primarily related to fuel-related transactions (20 cents per
share).





The cents
per share information presented above is based on average shares outstanding in
the third quarter and first nine months of 2007.




67




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, 2008 and 2007:





Three
      Months
            
            
            Nine
      Months2008
            
            
            2007
            
            
            2008
            
            
            2007Net
      income (loss):UE(a)
            
            $
            98
            
            
            $
            192
            
            
            $
            283
            
            
            $
            303CIPS
            
            
            6
            
            
            
            -
            
            
            
            5
            
            
            
            17Genco
            
            
            20
            
            
            
            25
            
            
            
            140
            
            
            
            84CILCORP
            
            
            18
            
            
            
            1
            
            
            
            42
            
            
            
            34IP
            
            
            4
            
            
            
            (5
            )
            
            
            (4
            )
            
            
            16Other(b)
            
            
            58
            
            
            
            31
            
            
            
            82
            
            
            
            56Ameren
      net income
            
            $
            204
            
            
            $
            244
            
            
            $
            548
            
            
            $
            510





(a)
            Includes
      earnings from a non-rate-regulated 40% interest in EEI through February
      29, 2008.


(b)
            Includes
      earnings from non-rate-regulated operations and an 80% interest in EEI
      held by Resources Company since February 29, 2008, as well as corporate
      general and administrative expenses, and intercompany eliminations. Prior
      to February 29, 2008, included a 40% interest in EEI held by Development
      Company, as well as corporate general and administrative expenses and
      intercompany eliminations.





Below is
a table of income statement components by segment for the three months and nine
months ended September 30, 2008 and 2007:





Missouri
              Regulated
            
            
            Illinois
              Regulated
            
            
            Non-rate-
              regulated
              Generation
            
            
            Other
      /
              Intersegment
              Eliminations
            
            
            TotalThree
      Months 2008:Electric
      margin
            
            $
            570
            
            
            $
            234
            
            
            $
            315
            
            
            $
            (23
            )
            
            $
            1,096Gas
      margin
            
            
            10
            
            
            
            50
            
            
            
            -
            
            
            
            (1
            )
            
            
            59Other
      revenues
            
            
            1
            
            
            
            -
            
            
            
            -
            
            
            
            (1
            )
            
            
            -Other
      operations and
      maintenance
            
            
            (234
            )
            
            
            (149
            )
            
            
            (77
            )
            
            
            11
            
            
            
            (449
            )Depreciation
      and
      amortization
            
            
            (83
            )
            
            
            (60
            )
            
            
            (29
            )
            
            
            (8
            )
            
            
            (180
            )Taxes
      other than income
      taxes
            
            
            (69
            )
            
            
            (24
            )
            
            
            (6
            )
            
            
            1
            
            
            
            (98
            )Other
      income and
      (expenses)
            
            
            15
            
            
            
            3
            
            
            
            (1
            )
            
            
            (4
            )
            
            
            13Interest
      expense
            
            
            (51
            )
            
            
            (34
            )
            
            
            (24
            )
            
            
            (4
            )
            
            
            (113
            )Income
      taxes
            
            
            (60
            )
            
            
            (5
            )
            
            
            (61
            )
            
            
            13
            
            
            
            (113
            )Minority
      interest and preferred dividends
            
            
            (1
            )
            
            
            (2
            )
            
            
            (9
            )
            
            
            1
            
            
            
            (11
            )Net
      income
      (loss)
            
            $
            98
            
            
            $
            13
            
            
            $
            108
            
            
            $
            (15
            )
            
            $
            204Three
      Months 2007:Electric
      margin
            
            $
            677
            
            
            $
            186
            
            
            $
            265
            
            
            $
            (13
            )
            
            $
            1,115Gas
      margin
            
            
            9
            
            
            
            49
            
            
            
            -
            
            
            
            (1
            )
            
            
            57Other
      revenues
            
            
            1
            
            
            
            1
            
            
            
            -
            
            
            
            (2
            )
            
            
            -Other
      operations and
      maintenance
            
            
            (222
            )
            
            
            (138
            )
            
            
            (77
            )
            
            
            20
            
            
            
            (417
            )Depreciation
      and
      amortization
            
            
            (81
            )
            
            
            (59
            )
            
            
            (28
            )
            
            
            (8
            )
            
            
            (176
            )Taxes
      other than income
      taxes
            
            
            (70
            )
            
            
            (23
            )
            
            
            (6
            )
            
            
            2
            
            
            
            (97
            )Other
      income and
      (expenses)
            
            
            8
            
            
            
            6
            
            
            
            1
            
            
            
            (4
            )
            
            
            11Interest
      expense
            
            
            (49
            )
            
            
            (35
            )
            
            
            (28
            )
            
            
            2
            
            
            
            (110
            )Income
      taxes
            
            
            (94
            )
            
            
            7
            
            
            
            (49
            )
            
            
            6
            
            
            
            (130
            )Minority
      interest and preferred dividends
            
            
            (1
            )
            
            
            (2
            )
            
            
            (7
            )
            
            
            1
            
            
            
            (9
            )Net
      income
      (loss)
            
            $
            178
            
            
            $
            (8
            )
            
            $
            71
            
            
            $
            3
            
            
            $
            244Nine
      Months 2008:Electric
      margin
            
            $
            1,606
            
            
            $
            600
            
            
            $
            911
            
            
            $
            (40
            )
            
            $
            3,077Gas
      margin
            
            
            55
            
            
            
            239
            
            
            
            -
            
            
            
            (4
            )
            
            
            290Other
      revenues
            
            
            1
            
            
            
            -
            
            
            
            -
            
            
            
            (1
            )
            
            
            -Other
      operations and
      maintenance
            
            
            (689
            )
            
            
            (446
            )
            
            
            (245
            )
            
            
            40
            
            
            
            (1,340
            )Depreciation
      and
      amortization
            
            
            (246
            )
            
            
            (181
            )
            
            
            (86
            )
            
            
            (21
            )
            
            
            (534
            )Taxes
      other than income
      taxes
            
            
            (189
            )
            
            
            (91
            )
            
            
            (20
            )
            
            
            -
            
            
            
            (300
            )Other
      income and
      (expenses)
            
            
            40
            
            
            
            10
            
            
            
            -
            
            
            
            (12
            )
            
            
            38Interest
      expense
            
            
            (142
            )
            
            
            (106
            )
            
            
            (74
            )
            
            
            (9
            )
            
            
            (331
            )Income
      taxes
            
            
            (160
            )
            
            
            (5
            )
            
            
            (177
            )
            
            
            23
            
            
            
            (319
            )Minority
      interest and preferred dividends
            
            
            (4
            )
            
            
            (5
            )
            
            
            (25
            )
            
            
            1
            
            
            
            (33
            )Net
      income
      (loss)
            
            $
            272
            
            
            $
            15
            
            
            $
            284
            
            
            $
            (23
            )
            
            $
            548Nine
      Months 2007:Electric
      margin
            
            $
            1,579
            
            
            $
            572
            
            
            $
            766
            
            
            $
            (32
            )
            
            $
            2,885Gas
      margin
            
            
            50
            
            
            
            227
            
            
            
            -
            
            
            
            (4
            )
            
            
            273Other
      revenues
            
            
            2
            
            
            
            3
            
            
            
            -
            
            
            
            (5
            )
            
            
            -Other
      operations and
      maintenance
            
            
            (668
            )
            
            
            (383
            )
            
            
            (234
            )
            
            
            55
            
            
            
            (1,230
            )Depreciation
      and
      amortization
            
            
            (252
            )
            
            
            (177
            )
            
            
            (85
            )
            
            
            (20
            )
            
            
            (534
            )




68




Missouri
              Regulated
            
            
            Illinois
              Regulated
            
            
            Non-rate-
              regulated
              Generation
            
            
            Other
      /
              Intersegment
              Eliminations
            
            
            TotalTaxes
      other than income
      taxes
            
            
            (187
            )
            
            
            (89
            )
            
            
            (20
            )
            
            
            1
            
            
            
            (295
            )Other
      income and
      (expenses)
            
            
            24
            
            
            
            16
            
            
            
            3
            
            
            
            (9
            )
            
            
            34Interest
      expense
            
            
            (146
            )
            
            
            (97
            )
            
            
            (81
            )
            
            
            8
            
            
            
            (316
            )Income
      taxes
            
            
            (135
            )
            
            
            (22
            )
            
            
            (132
            )
            
            
            10
            
            
            
            (279
            )Minority
      interest and preferred dividends
            
            
            (4
            )
            
            
            (5
            )
            
            
            (20
            )
            
            
            1
            
            
            
            (28
            )Net
      income
            
            $
            263
            
            
            $
            45
            
            
            $
            197
            
            
            $
            5
            
            
            $
            510





Margins





The
following table presents the favorable (unfavorable) variations in the
registrants’ electric and gas margins for the three months and nine months ended
September 30, 2008, compared with the same periods in 2007. Electric margins are
defined as electric revenues less fuel and purchased power costs. Gas margins
are defined as gas revenues less gas purchased for resale. 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
            
            
            IPElectric
      revenue change:Effect
      of weather (estimate)
            
            $
            (76
            )
            
            $
            (30
            )
            
            $
            (13
            )
            
            $
            -
            
            
            $
            (8
            )
            
            $
            (8
            )
            
            $
            (25
            )Interchange
      revenues, excludingestimate
              weather
      impact of  $44 million
            
            
            (33
            )
            
            
            (33
            )
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Illinois
      electric settlementagreement,
      net
              of
      reimbursement
            
            
            43
            
            
            
            -
            
            
            
            7
            
            
            
            17
            
            
            
            12
            
            
            
            12
            
            
            
            10Illinois
      rate redesign
            
            
            46
            
            
            
            -
            
            
            
            15
            
            
            
            -
            
            
            
            7
            
            
            
            7
            
            
            
            24Net
      mark-to-market gains (losses) on
              energy
      contracts
            
            
            55
            
            
            
            (5
            )
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Other,
      including growth and Illinois
              customer
      switching
            
            
            21
            
            
            
            (6
            )
            
            
            (20
            )
            
            
            -
            
            
            
            41
            
            
            
            41
            
            
            
            (13
            )Total
      electric revenue change
            
            $
            56
            
            
            $
            (74
            )
            
            $
            (11
            )
            
            $
            17
            
            
            $
            52
            
            
            $
            52
            
            
            $
            (4
            )Fuel
      and purchased power change:Fuel:Generation
      and other
            
            $
            18
            
            
            $
            13
            
            
            $
            -
            
            
            $
            12
            
            
            $
            (7
            )
            
            $
            (9
            )
            
            $
            -Emission
      allowance sales (costs)
            
            
            (1
            )
            
            
            (5
            )
            
            
            -
            
            
            
            3
            
            
            
            -
            
            
            
            -
            
            
            
            -Net
      mark-to-market (losses) on fuel
              contracts
            
            
            (111
            )
            
            
            (59
            )
            
            
            -
            
            
            
            (30
            )
            
            
            (8
            )
            
            
            (8
            )
            
            
            -Price
            
            
            (29
            )
            
            
            (8
            )
            
            
            -
            
            
            
            (14
            )
            
            
            (4
            )
            
            
            (4
            )
            
            
            -Purchased
      power
            
            
            57
            
            
            
            26
            
            
            
            28
            
            
            
            1
            
            
            
            (3
            )
            
            
            (3
            )
            
            
            31Illinois
      rate redesign
            
            
            (9
            )
            
            
            -
            
            
            
            (3
            )
            
            
            -
            
            
            
            (1
            )
            
            
            (1
            )
            
            
            (5
            )Total
      fuel and purchased power change
            
            $
            (75
            )
            
            $
            (33
            )
            
            $
            25
            
            
            $
            (28
            )
            
            $
            (23
            )
            
            $
            (25
            )
            
            $
            26Net
      change in electric margins
            
            $
            (19
            )
            
            $
            (107
            )
            
            $
            14
            
            
            $
            (11
            )
            
            $
            29
            
            
            $
            27
            
            
            $
            22Net
      change in gas margins
            
            $
            2
            
            
            $
            1
            
            
            $
            2
            
            
            $
            -
            
            
            $
            (3
            )
            
            $
            (3
            )
            
            $
            4Nine
      MonthsElectric
      revenue change:Effect
      of weather (estimate)
            
            $
            (100
            )
            
            $
            (35
            )
            
            $
            (20
            )
            
            $
            -
            
            
            $
            (11
            )
            
            $
            (11
            )
            
            $
            (34
            )UE
      electric rate increase
            
            
            16
            
            
            
            16
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Interchange
      revenues, excluding estimated
              weather
      impact of $54 million
            
            
            41
            
            
            
            41
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Illinois
      electric settlement agreement, net
              of
      reimbursement
            
            
            24
            
            
            
            -
            
            
            
            4
            
            
            
            8
            
            
            
            6
            
            
            
            6
            
            
            
            6FERC-ordered
      MISO resettlements -
              March
      2007
            
            
            (16
            )
            
            
            -
            
            
            
            -
            
            
            
            (12
            )
            
            
            (4
            )
            
            
            (4
            )
            
            
            -Illinois
      rate redesign
            
            
            16
            
            
            
            -
            
            
            
            5
            
            
            
            -
            
            
            
            2
            
            
            
            2
            
            
            
            9Net
      mark-to-market gains on
              energy
      contracts
            
            
            48
            
            
            
            13
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -
            
            
            
            -Other,
      including growth and Illinois
              customer
      switching
            
            
            60
            
            
            
            27
            
            
            
            (55
            )
            
            
            19
            
            
            
            71
            
            
            
            71
            
            
            
            (41
            )Total
      electric revenue change
            
            $
            89
            
            
            $
            62
            
            
            $
            (66
            )
            
            $
            15
            
            
            $
            64
            
            
            $
            64
            
            
            $
            (60
            )Fuel
      and purchased power change:Fuel:Generation
      and other
            
            $
            (1
            )
            
            $
            7
            
            
            $
            -
            
            
            $
            17
            
            
            $
            (26
            )
            
            $
            (28
            )
            
            $
            -




69




Nine
      Months
            
            Ameren(a)
            
            
            UE
            
            
            CIPS
            
            
            Genco
            
            
            CILCORP
            
            
            CILCO
            
            
            IPEmission
      allowance sales
            
            
            2
            
            
            
            (4
            )
            
            
            -
            
            
            
            5
            
            
            
            -
            
            
            
            -
            
            
            
            -Net
      mark-to-market (losses) on fuel
              contracts
            
            
            (12
            )
            
            
            (5
            )
            
            
            -
            
            
            
            (2
            )
            
            
            -
            
            
            
            -
            
            
            
            -Price
            
            
            (88
            )
            
            
            (40
            )
            
            
            -
            
            
            
            (31
            )
            
            
            (9
            )
            
            
            (9
            )
            
            
            -Coal
      contract settlement
            
            
            60
            
            
            
            -
            
            
            
            -
            
            
            
            60
            
            
            
            -
            
            
            
            -
            
            
            
            -Purchased
      power
            
            
            108
            
            
            
            (6
            )
            
            
            60
            
            
            
            25
            
            
            
            (8
            )
            
            
            (8
            )
            
            
            63Illinois
      rate redesign
            
            
            2
            
            
            
            -
            
            
            
            1
            
            
            
            -
            
            
            
            1
            
            
            
            1
            
            
            
            -FERC-ordered
      MISO resettlements -
              March
      2007
            
            
            32
            
            
            
            11
            
            
            
            7
            
            
            
            -
            
            
            
            3
            
            
            
            3
            
            
            
            11Total
      fuel and purchased power change
            
            $
            103
            
            
            $
            (37
            )
            
            $
            68
            
            
            $
            74
            
            
            $
            (39
            )
            
            $
            (41
            )
            
            $
            74Net
      change in electric margins
            
            $
            192
            
            
            $
            25
            
            
            $
            2
            
            
            $
            89
            
            
            $
            25
            
            
            $
            23
            
            
            $
            14Net
      change in gas margins
            
            $
            17
            
            
            $
            5
            
            
            $
            4
            
            
            $
            -
            
            
            $
            2
            
            
            $
            2
            
            
            $
            8





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







Ameren
 
 Ameren’s
electric margin decreased by $19 million, or 2% for the three months ended
September 30, 2008, compared with the same period in 2007. However, Ameren’s
electric margin increased by $192 million, or 7%, for the nine months ended
September 30, 2008, compared with the same period in 2007. The following items
had a favorable impact on electric margin for the three and nine months ended
September 30, 2008, as compared to the year-ago periods, unless otherwise
noted:
 
 ·
              Net
      mark-to-market gains on energy transactions of $55 million and $48 million
      for the third quarter and nine months ended September 30, 2008,
      respectively. These net unrealized gains were primarily related to
      nonqualifying hedges of changes in market prices for
      electricity.
 ·
              Implementation
      of redesigned seasonal electric delivery service rates at the Ameren
      Illinois Utilities, effective January 1, 2008, increased electric margin
      by $37 million and $18 million for the three and nine months ended
      September 30, 2008, respectively. These redesigned seasonal delivery
      service rates have an impact on quarterly earnings comparisons but are not
      expected to impact annual margins.
 ·
              The
      reduced impact of the Illinois electric settlement agreement increased
      electric margin by $43 million and $24 million for the three and nine
      months ended September 30, 2008,
respectively.
 ·
              Reduced
      net MISO purchased power costs of $16 million for the nine months ended
      September 30, 2008, due to the absence of the March 2007 FERC order that
      resettled costs in 2007 among market participants retroactive to
      2005.
 ·
              Other
      MISO net purchased power costs, excluding the effect of the March 2007
      FERC order, decreased by $17 million and $9 million for the three and nine
      months ended September 30, 2008,
respectively.
 ·
              An
      increase in margin on interchange sales of $4 million for the nine months
      ended September 30, 2008, due to a 13%
      increase in realized sales prices and increased hydroelectric generation
      due to improved water levels. Interchange margin decreased $2 million
      during the third quarter of 2008 due primarily to lower overnight market
      prices.
 ·
              Lower
      fuel expense as a result of Genco’s June 2008 agreement with a coal mine
      owner to receive a lump-sum payment of $60 million for the early
      termination of a contract. Genco is incurring incremental fuel costs in
      2008 and in 2009 to replace coal from an Illinois mine that was
      prematurely closed by its owner at the end of
  2007.
 ·
              A
      38-day planned refueling and maintenance outage at UE’s Callaway nuclear
      plant in the second quarter of 2007 that did not recur in the nine months
      ended September 30, 2008.
 ·
              UE’s
      electric rate increase that went into effect June 4, 2007, which increased
      electric margin by an estimated $16 million for the nine months ended
      September 30, 2008.
 
 The
following items had an unfavorable impact on electric margin for the three and
nine months ended September 30, 2008, as compared to the year-ago periods,
unless otherwise noted:
 
 ·
              Net
      mark-to-market losses on fuel-related transactions of $111 million and $12
      million for the third quarter and the nine months ended September 30,
      2008, respectively. These net unrealized losses were primarily related to
      financial instruments that were acquired to mitigate the risk of rising
      diesel fuel price adjustments embedded in coal transportation contracts
      for the period 2008 through 2012.
 ·
              Unfavorable
      weather conditions, as evidenced by a 27% reduction in cooling degree-days
      for the third quarter and nine months ended September 30, 2008, decreased
      electric margin by an estimated $54 million and $63 million for the
      three and nine months ended September 30, 2008,
    respectively.
 ·
              Excluding
      the impact of the agreement between Genco and a coal mine owner discussed
      above, fuel prices
   70
    Ameren’s
gas margin increased by $2 million, or 4%, and $17 million, or 6%, for the three
and nine months ended September 30, 2008, respectively, compared with the same
periods in 2007. The following items had a favorable impact on gas margin for
the three and nine months ended September 30, 2008, as compared to the year-ago
periods, unless otherwise noted:
 
 ·
              A
      September 24, 2008, ICC rate order concluded that a portion of
      non-recoverable purchased gas costs should be capitalized, resulting in a
      one-time increase in margin of $5 million for the third quarter and nine
      months ended September 30, 2008.
 ·
              Favorable
      weather conditions, as evidenced by a 12% increase in heating degree-days,
      increased margin an estimated $8 million for the nine months ended
      September 30, 2008.
 ·
              UE’s
      gas rate increase that went into effect April 1, 2007, increased margin by
      $1 million for the nine months ended September 30,
  2008.
 
 Missouri
Regulated
 
 UE
 
 UE’s electric margin decreased by $107
million, or 16%, for the three months ended September 30, 2008, compared with
the same period in 2007, but increased $25 million, or 2%, for the nine months
ended September 30, 2008, compared with the same period in 2007. The following
items had a favorable impact on electric margin for the three and nine months
ended September 30, 2008, as compared to the year-ago periods, unless otherwise
noted:
 
 ·
              An
      increase in margin on interchange sales of $4 million for the nine months
      ended September 30, 2008, due to a 13% increase in realized sales prices
      and increased hydroelectric generation due to improved water levels.
      Interchange margin decreased $2 million during the third quarter of 2008
      due primarily to lower overnight market
prices.
 ·
              Reduced
      MISO purchased power costs of $11 million for the nine months ended
      September 30, 2008, due to the absence of the March 2007 FERC
      order.
 ·
              Other
      MISO net purchased power costs, excluding the effect of the March 2007
      FERC order, decreased by $13 million and $7 million for the three and
      nine months ended September 30, 2008,
  respectively.
 ·
              A
      38-day planned refueling and maintenance outage at Callaway nuclear plant
      in the second quarter of 2007 that did not recur in the first nine months
      of 2008.
 ·
              UE’s
      electric rate increase that went into effect June 4, 2007, which increased
      electric margin by an estimated $16 million for the nine months ended
      September 30, 2008.
 ·
              Net
      mark-to-market gains on energy transactions of $13 million for the
      nine months ended September 30, 2008. These unrealized gains primarily
      related to nonqualifying hedges of changes in market prices for
      electricity.
 
 The
following items had an unfavorable impact on electric margin for the three
months and nine months ended September 30, 2008, as compared to the year-ago
periods, unless otherwise noted:
 
 ·
              A
      7% and 11% increase in fuel prices for the third quarter and first nine
      months of 2008, respectively.
 ·
              Unfavorable
      weather conditions, as evidenced by a 25% and 27% reduction in cooling
      degree-days for the third quarter and nine months ended September 30,
      2008, decreased electric margin by an estimated $38 million and $41
      million for the three and nine months ended September 30, 2008,
      respectively.
 ·
              Net
      mark-to-market losses on fuel-related transactions of $59 million and $5
      million for the third quarter and the nine months ended September 30,
      2008, respectively. These unrealized losses related to financial
      instruments that were acquired to mitigate the risk of rising diesel fuel
      price adjustments embedded in coal transportation contracts for the period
      2008 through 2012.
 ·
              Net
      mark-to-market losses on energy transactions of $5 million for the
      three months ended September 30, 2008. These unrealized losses related to
      nonqualifying hedges of changes in market prices for
      electricity.
 
 UE’s gas
margin was comparable for the three months ended September 30, 2008, to the same
period in 2007 and increased by $5 million, or 10%, for the nine months ended
September 30, 2008, compared to the same period in 2007, due to a gas rate
increase that went into effect April 1, 2007, and favorable weather conditions
as evidenced by an 11% increase in heating degree-days.
 
 Illinois
Regulated
 
 Illinois Regulated’s electric margin
increased by $48 million, or 26%, and $28 million, or 5%, for the three months
and nine months ended September 30, 2008, respectively, compared with the same
periods in 2007. Illinois Regulated’s gas margin was comparable for the three
months ended September 30, 2008, with the same period in 2007. Illinois
Regulated’s gas margin increased by $12 million, or 5%, for the nine months
ended September 30, 2008, compared with the same period in 2007.
  71
 CIPS
 
 CIPS’ electric margin increased by
$14 million, or 24%, and $2 million, or 1%, for the three and nine months ended
September 30, 2008, respectively, compared with the same periods in 2007. The
following items had a favorable impact on electric margin for the three and nine
months ended September 30, 2008, as compared to the year-ago periods, unless
otherwise noted:
 
 ·
              The
      implementation of redesigned seasonal electric delivery service rates
      increased electric margin by $12 million and $6 million for the three
      and nine months ended September 30, 2008, respectively. These redesigned
      seasonal delivery service rates have an impact on quarterly earnings
      comparisons but are not expected to impact annual
  margins.
 ·
              The
      reduced impact of the Illinois electric settlement agreement increased
      electric margin by $7 million and $4 million for the three and nine
      months ended September 30, 2008,
respectively.
 ·
              Reduced
      MISO purchased power costs of $7 million for the nine months ended
      September 30, 2008, due to the absence of the March 2007 FERC order that
      resettled costs in 2007 among market participants retroactive to
      2005.
 ·
              Other
      MISO net purchased power costs, excluding the effect of the March 2007
      FERC order, decreased by $5 million and $6 million for the three and
      nine months ended September 30, 2008,
  respectively.
 
 The
following items had an unfavorable impact on electric margin for the three and
nine months ended September 30, 2008, as compared to the year-ago periods,
unless otherwise noted:
 
 ·
              Unfavorable
      weather conditions, as evidenced by a 27% and 28% reduction in cooling
      degree-days for the third quarter and nine months ended September 30,
      2008, respectively, which decreased electric margin by an estimated $5
      million and $6 million for the three and nine months ended September 30,
      2008, respectively.
 ·
              Decreased
      delivery service margin of $5 million and $4 million for the three
      and nine months ended September 30, 2008, respectively, due to ongoing
      MISO resettlements.
 
 CIPS’ gas
margin increased by $2 million, or 20%, and $4 million, or 8%, for the three and
nine months ended September 30, 2008, compared with the same periods in 2007,
primarily because of favorable weather conditions as evidenced by an 11%
increase in year-to-date heating degree-days.In addition,
a September 24, 2008, ICC rate order concluded that a portion of non-recoverable
purchased gas costs should be capitalized, resulting in a one-time increase in
margin of $1 million for CIPS for the third quarter and nine months ended
September 30, 2008.
 
 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 and nine
months ended September 30, 2008, as compared with the same periods in
2007:
 
 Three
      Months
              
              
              Nine
      MonthsCILCO
      (Illinois Regulated)
              
              $
              14
              
              
              $
              13CILCO
      (AERG)
              
              
              13
              
              
              
              10Total
      change in electric margin
              
              $
              27
              
              
              $
              23
 
 CILCO’s
(Illinois Regulated) electric margin increased by $14 million, or 52%, and $13
million, or 14%, for the three and nine months ended September 30, 2008,
respectively.
 
 The
following items had a favorable impact on electric margin for the three and nine
months ended September 30, 2008, as compared to the year-ago periods, unless
otherwise noted:
 
 ·
              The
      implementation of redesigned seasonal electric delivery service rates
      increased electric margin by $6 million and $3 million for the three
      and nine months ended September 30, 2008, respectively. These redesigned
      seasonal delivery service rates have an impact on quarterly earnings
      comparisons but are not expected to impact annual
  margins.
 ·
              The
      reduced impact of the Illinois electric settlement agreement increased
      electric margin by $4 million and $2 million for the three and nine
      months ended September 30, 2008,
respectively.
 ·
              Reduced
      MISO purchased power costs of $3 million for the nine months ended
      September 30, 2008, due to the absence of the March 2007 FERC order that
      resettled costs in 2007 among market participants retroactive to
      2005.
 ·
              Increased
      delivery service margin of $2 million and $4 million for the three
      and nine months ended September 30, 2008, respectively, due to the reduced
      impact of MISO settlements that occurred last year. In addition,
      generation service margins increased $5 million and $3 million for the
      three and nine months ended September 30, 2008, respectively. These
      generation service margins are derived from rate riders, which are
      designed to offset certain operating
expenses.
 
 The
favorable variances were partially offset by unfavorable weather conditions, as
evidenced by a 25% and 26% reduction in cooling degree-days for the third
quarter and nine months ended September 30, 2008, respectively, which decreased
electric margin by an estimated $3 million and
  72
   $4
million for the three and nine months ended September 30, 2008,
respectively.
 
 See Non-rate-regulated Generation
below for an explanation of CILCO’s (AERG) change in electric margin for the
three and nine months ended September 30, 2008, as compared with the same
periods in 2007.
 
 CILCO’s
(Illinois Regulated) gas margin decreased $3 million, or 20%, for the three
months ended September 30, 2008, compared to the year-ago period due to net
mark-to-market losses on natural gas swaps. CILCO’s (Illinois Regulated) gas
margin increased by $2 million, or 3%, for the nine months ended September 30,
2008, compared with the same period in 2007 because of favorable weather
conditions as evidenced by a 10% increase in year-to-date heating degree-days
and increased growth, offset by net mark-to-market losses of $3
million on natural gas swaps.
 
 IP
 
 IP’s electric margin increased by $22
million, or 23%, and $14 million, or 5%, for the three and nine months ended
September 30, 2008, respectively, compared with the same periods in 2007. The
following items had a favorable impact on electric margin for the three and nine
months ended September 30, 2008, as compared to the year-ago periods, unless
otherwise noted:
 
 ·
              The
      implementation of redesigned seasonal electric delivery service rates
      increased electric margin by $19 million and $9 million for the three
      and nine months ended September 30, 2008, respectively. These redesigned
      seasonal delivery service rates will impact quarterly earnings comparisons
      but are not expected to impact annual
margins.
 ·
              The
      reduced impact of the Illinois electric settlement agreement, increased
      electric margin by $10 million and $6 million for the three and nine
      months ended September 30, 2008,
respectively.
 ·
              Reduced
      MISO purchased power costs of $11 million for the nine months ended
      September 30, 2008, due to the absence of the March 2007 FERC order that
      resettled costs in 2007 among market participants retroactive to
      2005.
 
 The
following items had an unfavorable impact on electric margin for the three and
nine months ended September 30, 2008, as compared to the year-ago periods,
unless otherwise noted:
 
 ·
              Unfavorable
      weather conditions, as evidenced by a 33% and 32% reduction in cooling
      degree-days for the third quarter and nine months ended September 30,
      2008, respectively, which decreased electric margin by an estimated $8
      million and $12 million for the three and nine months ended September 30,
      2008, respectively.
 ·
              Other
      MISO net purchased power costs, excluding the effect of the March 2007
      FERC order, increased by $7 million for the nine months ended
      September 30, 2008.
 
 IP’s gas
margin increased by $4 million, or 17%, and $8 million, or 7%, for the
three and nine months ended September 30, 2008, respectively, compared with the
same periods in 2007, primarily because of favorable weather conditions as
evidenced by a 14% increase in year-to-date heating degree-days. In addition, a
September 24, 2008, ICC rate order concluded that a portion of non-recoverable
purchased gas costs should be capitalized, resulting in a one-time increase in
margin of $4 million for IP for the third quarter and nine months ended
September 30, 2008.
 
 Non-rate-regulated
Generation
 
 Non-rate-regulated
Generation’s electric margin increased by $50 million, or 19%, and $145 million,
or 19%, for the three and nine months ended September 30, 2008, respectively,
compared with the same periods in 2007.
 
 Genco
 
 Genco’s electric margin decreased by
$11 million, or 9%, for the three months ended September 30, 2008, compared to
the year-ago period. Genco’s electric margin increased by
 $89
million, or 24%, for the nine months ended September 30, 2008, compared to the
year-ago period due in part to lower fuel expense as a result of Genco’s June
2008 agreement with a coal mine owner to receive a lump-sum payment
of   $60 million for the early termination of a contract. Genco
is incurring incremental fuel costs in 2008 and expects to incur incremental
fuel costs in 2009 to replace coal from an Illinois mine that was closed
prematurely at the end of 2007.
 
 The
following items also had a favorable impact on electric margin for the three and
nine months ended September 30, 2008, as compared to the year-ago periods,
unless otherwise noted:
 
 ·
              The
      reduced impact of the Illinois electric settlement agreement, increased
      electric margin by $17 million and $8 million for the three and nine
      months ended September 30, 2008,
respectively.
 ·
              Gain
      on the sale of oil and off-system natural gas increased electric
      margin by $2 million and $6 million for the three and nine months ended
      September 30, 2008, respectively.
 ·
              Reduced
      purchased power costs of $17 for the nine months ended September 30, 2008,
      due to the absence of MISO resettlement costs experienced in early
      2007.
   73
  ·
              Increased
      revenues allocated to Genco under its power supply agreement (Genco PSA)
      with Marketing Company for the nine months ended September 30, 2008,
      compared to the year-ago period. Marketing Company’s average revenue
      per megawatt hour sold under the Genco PSA increased 9% and 5% for the
      three and nine months ended September 30, 2008, respectively, compared to
      the year-ago periods due primarily to re-pricing of wholesale and retail
      electric power supply agreements. Genco’s allocated revenues also
      increased 5% for the nine months ended September 30, 2008, compared with
      the same period in 2007 due to an increase in reimbursable expenses
      in accordance with the Genco PSA. Genco’s allocated revenues for the
      third quarter were comparable to the year-ago
  period.
 
 The following items had an
unfavorable impact on electric margin for the three and nine months ended
September 30, 2008, as compared to the year-ago periods, unless otherwise
noted:
 
 ·
              Excluding
      the impact of the agreement between Genco and a coal mine owner discussed
      above, fuel prices increased 19% and 16% for the third quarter and the
      first nine months of 2008,
respectively.
 ·
              Net
      mark-to-market losses on fuel-related transactions of $30 million and $2
      million for the third quarter and nine months ended September 30, 2008,
      respectively. These unrealized losses related to financial instruments
      that were acquired to mitigate the risk of rising diesel fuel price
      adjustments embedded in coal transportation contracts for the period 2008
      through 2012.
 ·
              Reduced
      MISO-related revenues of $12 million for the nine months ended September
      30, 2008, due to the absence of the March 2007 FERC
  order.
 ·
              Decreased
      baseload coal-fired plant availability during the third quarter of 2008
      compared to the same period last year primarily due to an outage caused by
      a transformer fire at one of Genco’s power plants. Genco’s generating
      plants’ average capacity and equivalent availability factors for the three
      months ended   September 30, 2008, were 75% and 87%,
      respectively, compared with 80% and 92%, respectively, in the same period
      in 2007. Genco’s generating plants’ average capacity and equivalent
      availability factors for the nine months ended September 30, 2008, were
      comparable with the same periods in
2007.
 
 CILCO (AERG)
 
 AERG’s
electric margin increased by $13 million, or 28%, and $10 million, or 7%, for
the three and nine months ended September 30, 2008, respectively, compared with
the same periods in 2007. The following items had a favorable impact on electric
margin for the three and nine months ended September 30, 2008, as compared to
the year-ago periods, unless otherwise noted:
 
 ·
              The
      reduced impact of the Illinois electric settlement agreement increased
      electric margin by $8 million and $4 million for the three and nine
      months ended September 30, 2008,
respectively.
 ·
              Increased
      baseload coal-fired plant availability due to the lack of an extended
      plant outage this year. AERG’s generating plants’ average capacity and
      equivalent availability factors for the nine months ended September 30,
      2008, were 72% and 79%, respectively, in 2008, compared with 54% and 60%,
      respectively, in 2007.
 
 The
following items had an unfavorable impact on electric margin for the three and
nine months ended September 30, 2008, as compared to the year-ago periods unless
otherwise noted:
 
 ·
              A
      27% and 19% increase in coal prices for the third quarter and the nine
      months ended September 30, 2008, respectively, due to a greater percentage
      of higher-cost Illinois coal burned this year. In addition, oil consumed
      during plant startups increased $4 million for the nine months ended
      September 30, 2008.
 ·
              A
      2% and a 7% decrease in average sales price per megawatt hour allocated to
      AERG under its power supply agreement (AERG PSA) with Marketing Company
      for the three and nine months ended September 30, 2008, respectively, due
      primarily to a reduction in reimbursable expenses in accordance with the
      AERG PSA.
 ·
              Net
      mark-to-market losses on fuel-related transactions of $8 million for the
      three months ended September 30, 2008. These unrealized losses primarily
      related to financial instruments that were acquired to mitigate the risk
      of rising diesel fuel price adjustments embedded in coal transportation
      contracts for the period 2008 through
2012.
 ·
              Reduced
      MISO-related revenues of $4 million for the nine months ended September
      30, 2008, due to the absence of the March 2007 FERC
  order.
 
 EEI
 
 EEI’s electric margin increased by
$11 million, or 16%, and $35 million, or 17% for the three and nine months ended
September 30, 2008, respectively, compared with the same periods in 2007. The
following items had a favorable impact on electric margin for the three and nine
months ended September 30, 2008, as compared to the year-ago periods, unless
otherwise noted:
 
 ·
              Net
      mark-to-market losses on fuel-related transactions of $6 million for the
      third quarter and net mark-to-market gains on fuel-related transactions of
      $2 million for the nine months ended September 30, 2008.
    These
   74
    ·
              A
      20% increase in the average sales price for power during the nine months
      ended September 30, 2008.
 
 The
favorable variances were offset by an 8% increase in fuel prices for both the
third quarter and the nine months ended September 30, 2008.
 
 Marketing
Company
 
 A
decrease in market prices during the third quarter of 2008 resulted in
nonaffiliated mark-to-market gains on energy transactions of $35 million and $60
million for the three and nine months ended September 30, 2008, respectively.
These unrealized gains primarily related to nonqualifying hedges of changes in
market prices for electricity.
 
 Operating
Expenses and Other Statement of Income Items
 
 Other
Operations and Maintenance
 
 Ameren
 
 Three
months - Other operations and maintenance expenses increased $32 million in the
third quarter of 2008 compared with the third quarter of 2007, primarily because
of higher distribution system reliability expenditures of  $14 million,
increased labor costs of $18 million, net unrealized mark-to-market losses of
$10 million due to the decline in the cash surrender value of company-owned life
insurance policies, and higher bad debt expense. Reducing the unfavorable effect
of these items were lower injuries and damages expenses and reduced employee
benefit costs.
 
 Nine
months - Other operations and maintenance expenses increased $110 million in the
first nine months of 2008 compared with the first nine months of 2007, primarily
because of higher distribution system reliability expenditures of $36 million,
increased plant maintenance expenditures at coal-fired plants of $24 million due
to outages, increased information technology costs, higher labor costs and
net unrealized mark-to-market losses of $16 million due to the decline in the
cash surrender value of company-owned life insurance policies. Bad debt expense
also increased $17 million, primarily at the Ameren Illinois Utilities.
Additionally, in the first quarter of 2007, a $15 million accrual established in
2006 for contributions to assist customers through the Illinois Customer Elect
electric rate increase phase-in plan was reversed due to the termination of the
plan, with no similar item in 2008. This plan was replaced with the Illinois
electric settlement agreement in August 2007. Reducing the unfavorable effect of
these items was the less significant impact of ice storms in the first quarter
of 2008, as compared with the same period in 2007. In January 2007, UE and CIPS
experienced a severe ice storm in their service territories resulting in system
repair expenditures of $28
million, as compared with $18 million in expenditures for minor storms in 2008.
Additionally, the absence of a Callaway refueling and maintenance outage in the
first nine months of the current year and the effect of a MoPSC storm cost
accounting order received in the second quarter of 2008 resulted in decreased
operations and maintenance expenses compared to the prior-year period. The MoPSC
accounting order resulted in UE reversing previously-recorded expenses of $13
million related to 2007 storms and recording them as a regulatory
asset.
 
 Variations
in other operations and maintenance expenses in Ameren’s, CILCORP’s and CILCO’s
business segments and for the Ameren Companies for the three months and nine
months ended September 30, 2008, compared with the same periods in 2007, were as
follows:
 
 Missouri
Regulated
 
 UE
 
 Three months - Other operations and
maintenance expenses increased $16 million in the third quarter of 2008 compared
with the same period in 2007 primarily because of higher labor costs, net
unrealized mark-to-market losses of $6 million due to the decline in the cash
surrender value of company-owned life insurance policies, increased distribution
system reliability expenditures, and higher bad debt expense.
 
 Nine months - UE’s other operations
and maintenance expenses increased $22 million in the first nine months of 2008,
as compared with the same period in 2007, primarily because of increased
distribution system reliability expenditures, higher labor and employee benefit
costs, net unrealized mark-to-market losses of $11 million due to the decline in
the cash surrender value of company-owned life insurance policies, and increased
plant maintenance expenditures at coal-fired plants. Reducing the effect of
these items was the absence of a Callaway refueling and maintenance outage this
spring and the effect of the MoPSC storm cost accounting order discussed above.
Decreased storm repair expenditures of $7 million in 2008, as compared with
$25 million in 2007, further decreased other operations and maintenance expenses
compared to the prior-year period.
 Illinois
Regulated
 
 Other
operations and maintenance expenses increased $11 million and $63 million in the
Illinois Regulated segment in the three months and nine months ended September
30, 2008, respectively, compared with the same periods in 2007.
  75
 CIPS
 
 Three
months - Other operations and maintenance expenses increased $9 million in the
third quarter of 2008, compared with the same period in 2007, primarily because
of higher labor costs, increased distribution system reliability expenditures,
and higher bad debt expense.
 Nine
months - Other operations and maintenance expenses increased $23 million in the
first nine months of 2008 compared with the same period in 2007. The increase
was partially because of the reversal in the first quarter of 2007 of an accrual
of $4 million, established in 2006, for contributions to assist customers
through the Illinois Customer Elect electric rate increase phase-in plan, with
no similar item in 2008. Additionally, storm repair expenditures in the first
nine months of 2008 exceeded the cost of storm repairs in the first nine months
of 2007 by $3 million. Other distribution system reliability expenditures and
labor costs were also higher than in the prior-year period.
 
 CILCO
(Illinois Regulated)
 
 Three
months - Other operations and maintenance expenses were comparable between
periods.
 
 Nine
months - Other operations and maintenance expenses increased $7 million in the
first nine months of 2008, as compared with the same period in 2007, primarily
because of higher distribution system reliability expenditures. Additionally, in
the first quarter of 2007, CILCO (Illinois Regulated) reversed a $3 million
accrual established in 2006 for the Illinois Customer Elect electric rate
increase phase-in plan contributions, with no similar item in 2008. Lower
employee benefit costs reduced the effect of these unfavorable
items.
 
 IP
 
 Three
months - Other operations and maintenance expenses increased $5 million in the
third quarter of 2008 compared with the third quarter of 2007, primarily because
of higher distribution system reliability expenditures, partially reduced by a
decrease in injuries and damages expenses.
 
 Nine
months - Other operations and maintenance expenses increased $35 million in the
first nine months of 2008, as compared with the same period in 2007, primarily
because of higher distribution system reliability expenditures and increased bad
debt expense. Additionally, in the first quarter of 2007, IP reversed an $8
million accrual established in 2006 for the Illinois Customer Elect electric
rate increase phase-in plan contributions, with no similar item in
2008.
 
 Non-rate-regulated
Generation
 
 Other
operations and maintenance expenses were comparable in the third quarter of 2008
with the third quarter of 2007. Other operations and maintenance expenses
increased $11
million in the nine months ended September 30, 2008, compared with the same
period in 2007.
  Genco
& CILCO (AERG)
 
 Three
months - Other operations and maintenance expenses were comparable between
periods.
 
 Nine
months - Other operations and maintenance expenses increased $11 million at
Genco and $6 million at CILCO (AERG) in the first nine months of 2008, as
compared with the same period in 2007, primarily because of higher plant
maintenance costs due to scheduled outages. Genco and CILCO (AERG) paid $3
million and $2 million, respectively, to the IPA in the prior year as part of
the Illinois electric settlement agreement, with no similar item in 2008,
reducing other operations and maintenance expenses between periods.
 
 CILCORP
(Parent Company Only)
 
 Three and
nine months - Other operations and maintenance expenses were comparable between
periods.
 
 EEI
 
 Three
months - Other operations and maintenance expenses were comparable between
periods.
 
 Nine
months - Other operations and maintenance expenses decreased $3 million in the
first nine months of 2008, as compared with the same period in 2007, primarily
because of reduced plant maintenance costs.
 
 Depreciation
and Amortization
 
 Ameren
 
 Three months - Ameren’s depreciation
and amortization expenses were comparable between periods.
 
 Nine months - Ameren’s depreciation
and amortization expenses were comparable between periods as a reduction in
depreciation because of changes in the useful lives of UE’s plants, as discussed
below, was offset by increased capital additions over the past
year.
 
 Variations in depreciation and
amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and
for the Ameren Companies for the three months and nine
   76
  months
ended September 30, 2008, compared with the same periods in 2007 were as
follows:
 
 Missouri
Regulated
 
 UE
 
 Three months - Depreciation and
amortization expenses were comparable between periods.
  Nine
months - Depreciation and amortization expenses decreased $6 million in the nine
months ended September 30, 2008, compared with the same period in 2007,
primarily because of the extension of UE’s nuclear and coal-fired plants’ useful
lives for purposes of calculating depreciation expense in conjunction with a
MoPSC electric rate order effective June 2007. Reducing the benefit of this item
was an increase in capital additions over the past year.
 
 Illinois
Regulated
 
 Depreciation
and amortization expenses were comparable in the third quarter of 2008 with the
third quarter of 2007. Depreciation and amortization expenses increased $4
million in the nine months ended September 30, 2008, compared with the same
period in 2007, in the Illinois Regulated segment and at CIPS, CILCO (Illinois
Regulated) and IP, primarily because of capital additions.
 
 Non-rate-regulated
Generation
 
 Depreciation
and amortization expenses were comparable in the third quarter and first nine
months of 2008 with the same periods in 2007 in the Non-rate-regulated
Generation segment and for CILCORP (Parent Company Only) and EEI. Depreciation
and amortization expenses decreased $2 million and $6 million at Genco in the
third quarter and first nine months of 2008, respectively, compared with the
same periods in 2007 as a result of a depreciation study completed in September
2007. Depreciation and amortization expenses increased $2 million and $7 million
at CILCO (AERG) in the third quarter and first nine months of 2008,
respectively, compared with the same periods in 2007 because of capital
additions over the past year.
 
 Taxes
Other Than Income Taxes
 
 Ameren
 
 Three
months - Ameren’s taxes other than income taxes were comparable between
periods.
 
 Nine months - Ameren’s taxes other
than income taxes increased $5 million in the first nine months of 2008 compared
with the same period in 2007 primarily because of higher payroll and gross
receipts taxes. Increases in property taxes were partially reduced by invested
capital electricity distribution tax credits in the Illinois Regulated segment
related to payments made in a previous year.
 
 Variations in taxes other than income
taxes in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren
Companies for the three months and nine months ended September 30, 2008,
compared with the same periods in 2007 were as follows:
  Missouri
Regulated
 
 UE
 
 Three and
nine months - Taxes other than income taxes were comparable between
periods.
 
 Illinois
Regulated
 
 Three
months - Taxes other than income taxes were comparable between periods in the
Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated) and
IP.
  Nine
months - Taxes other than income taxes were comparable in the Illinois Regulated
segment in the first nine months of 2008 with the same period in 2007 as
increased property taxes at CIPS were offset by the favorable impact of the
invested capital electricity distribution tax credits mentioned above and by
reduced excise taxes at IP.
 
 Non-rate-regulated
Generation
 
 Taxes
other than income taxes were comparable in the three months and nine months
ended September 30, 2008, with the same periods in 2007 in the
Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company
Only), CILCO (AERG) and EEI.
 
 Other
Income and Expenses
 
 Ameren
 
 Three and
nine months - Miscellaneous income increased $3 million and $8 million in the
third quarter and first nine months of 2008, respectively, compared with the
same periods in 2007, primarily because of an increase at UE in allowance for
funds used during construction, partially reduced by lower interest income.
Miscellaneous expense was comparable in the third quarter of 2008 with the same
period in 2007. Miscellaneous expense increased in the first nine months of 2008
compared with the same period in 2007 primarily because of increased expenses
associated with energy efficiency and customer assistance programs; in part,
under the Illinois electric settlement agreement.
  77
 Variations
in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business
segments and for the Ameren Companies for the three months and nine months ended
September 30, 2008, compared with the same periods in 2007, were as
follows:
  Missouri
Regulated
 
 UE
 
 Three and
nine months - Miscellaneous income increased $8 million and $18 million in the
three months and nine months ended September 30, 2008, respectively, compared
with the same periods in 2007, primarily because of an increase in allowance for
funds used during construction. The increase in allowance for funds used during
construction resulted from higher rates and increased construction-in-progress
balances. Miscellaneous expense decreased $3 million in both the third
quarter and first nine months of 2008, as compared with the same periods in
2007, primarily because of charges recorded in the prior year associated with a
commodity contract.
 
 Illinois
Regulated
 
 Other
income and expenses decreased in the third quarter and first nine months of 2008
in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated) and
IP, as compared with the same periods in 2007, primarily because of lower
interest income.
 
 Non-rate-regulated
Generation
 
 Other
income and expenses in the Non-rate-regulated Generation segment and at Genco,
CILCORP (Parent Company Only), CILCO (AERG) and EEI were comparable in the three
months and nine months ended September 30, 2008, with the same periods in
2007.
 
 Interest
 
 Ameren
 
 Three
months - Interest expense was comparable between periods because increased
interest expense resulting from debt issuances at the Ameren Companies as noted
below was mitigated by decreased short-term borrowings.
 
 Nine
months - Interest expense increased $15 million in the nine months ended
September 30, 2008, compared with the same period in 2007. Long-term debt
issuances, net of maturities and redemptions, and the cost of refinancing
auction-rate environmental improvement and pollution control revenue refunding
bonds resulted in increased interest expense in the 2008 period. See Insured
Auction-Rate Tax-exempt Bonds under Part I, Item 3. Quantitative and Qualitative
Disclosures About Market Risk of this report for additional information. These
increases were reduced by the reversal of $12 million of interest reserves for
uncertain tax positions resulting from a federal tax settlement in the first
quarter of 2008.
  Variations
in interest expense in Ameren’s, CILCORP’s and CILCO’s business segments and for
the Ameren Companies for the three months and nine months ended September 30,
2008, compared with the same periods in 2007 were as follows:
 
 Missouri
Regulated
 
 UE
 
 Three
months - Interest expense was comparable between periods as increased interest
expense resulting from debt issuances was reduced by decreased short-term
borrowings.
 
 Nine
months - Interest expense decreased $4 million primarily because of the reversal
of $8 million of interest reserves resulting from the federal tax settlement
noted above. Interest expense associated with the issuance of senior secured
notes for $450 million, $250 million, and $425 million in June 2008, April
2008 and June 2007, respectively, was largely offset by a reduction in
short-term borrowings due to the long-term debt financings. The senior secured
notes were issued, in part, to refinance auction-rate environmental improvement
revenue refunding bonds.
 
 Illinois
Regulated
 
 Interest
expense was comparable in the third quarter of 2008 with the same period in
2007. Interest expense increased $9 million in the first nine months of 2008, as
compared with the same period in the prior year, primarily because of debt
issuances at IP as noted below.
 
 CIPS
 
 Three
months - Interest expense was comparable between periods.
 
 Nine
months - Interest expense decreased $5 million in the first nine months of 2008
compared with the same period in 2007, primarily because of reduced short-term
borrowings. Additionally, the reversal of $2 million of interest reserves
resulting from the federal tax settlement noted above reduced interest
expense.
  78
 CILCO
(Illinois Regulated)
 
 Three and
nine months - Interest expense was comparable between periods.
 
 IP
 
 Three
months - Interest expense was comparable between periods.
  Nine
months - Interest expense increased $17 million in the first nine months of 2008
compared with the same period in 2007, primarily because of the issuance of $250
million of senior secured notes at IP in November 2007 and the cost of
refinancing auction-rate pollution control revenue refunding bonds, including
the issuance of $337 million of senior secured notes in April 2008.
 
 Non-rate-regulated
Generation
 
 Interest expense decreased $4 million
in the third quarter of 2008 compared with the third quarter of 2007 and $7
million in the nine months ended September 30, 2008, compared with the same
period in 2007.
 
 Genco
 
 Three
months - Interest expense was comparable between periods.
 
 Nine
months - Interest expense decreased $3 million at Genco in the first nine months
of 2008, as compared with the same period in 2007, as increased interest expense
resulting from the issuance of $300 million of senior unsecured notes in April
2008 was more than offset by a resulting reduction in short-term borrowings.
Additionally, interest expense was reduced by the reversal of $2 million of
interest reserves at Genco from the federal tax settlement noted
above.
 
 CILCO
(AERG)
 
 Three
months - Interest expense was comparable between periods.
 
 Nine
months - Interest expense decreased $2 million at CILCO (AERG) in the first nine
months of 2008, as compared with the same period in 2007, primarily because of
reduced short-term borrowings.
 
 CILCORP
(Parent Company Only) & EEI
 
 Three and
nine months - Interest expense was comparable between periods.
 
 Income
Taxes
 
 Ameren
 
 Three
and nine months - Ameren’s effective tax rate in the third quarter of 2008 was
comparable to the third quarter of 2007.  Ameren’s effective tax rate
for the first nine months of 2008 was higher than the effective tax rate for the
same period in the prior year, due to variations discussed below.
 
 Variations
in effective tax rates for Ameren’s, CILCORP’s and CILCO’s business segments and
for the Ameren Companies for the three months and nine months ended September
30, 2008, compared with the same periods in 2007 were as follows:
 
 Missouri
Regulated
 
 UE
 
 Three and nine months - The effective
tax rates for both the third quarter and first nine months of 2008 were higher
than the effective tax rates for the same periods in the prior year, primarily
because of lower favorable net amortization of property-related regulatory
assets and liabilities, along with decreased production activity deductions in
the current-year periods.
 
 Illinois
Regulated
 
 The
effective tax rates for both the third quarter and first nine months of 2008
were lower than the effective tax rates for the same periods in 2007 in the
Illinois Regulated segment because of items detailed below.
 
 CIPS
 
 Three and nine months - The effective
tax rates for both the third quarter and first nine months of 2008 were lower
than the effective tax rates for the same periods in 2007, primarily because of
the impact of the net amortization of property-related regulatory assets and
liabilities and permanent items in the current year periods as compared with the
same periods in 2007.
 
 CILCO (Illinois
Regulated)
 
 Three months - The effective tax rate
for the third quarter of 2008 was lower than the effective tax rate for the
third quarter in 2007, primarily because of the impact of permanent items, net
amortization of property-related regulatory assets and liabilities, and
amortization of investment tax credit on pretax book income during the
current-year period as compared with the impact on a pretax book loss in the
third quarter of 2007.
   79
 
 Nine months - The effective tax rate
for the first nine months of 2008 was higher than the effective tax rate for the
same period in 2007, primarily because of lower estimated tax credits, lower
favorable net amortization of property-related regulatory asset and liabilities,
and lower favorable permanent benefits related to company-owned life insurance
during the current-year period compared to the same period in 2007.
 
 IP
 
 Three months - The effective tax rate
for the third quarter of 2008 was lower than the effective tax rate for the same period in
2007, primarily because of the impact of permanent items, the net amortization
of property-related regulatory assets and liabilities, and estimated tax credits
on pretax book income during the current-year period as compared with the impact
on a pretax book loss in the third quarter of 2007.
 
 Nine
months - The effective tax rate for the first nine months of 2008 was higher
than the effective tax rate for the same period in 2007, primarily because of
the impact of the net amortization of property-related regulatory assets and
liabilities and estimated tax credits on a pretax book loss during the
current-year period as compared with the impact on pretax book income in the
same period in 2007.
 
 Non-rate-regulated
Generation
 
 The
effective tax rates of both the third quarter and first nine months of 2008 were
lower than the effective tax rates for the same periods in 2007 in the
Non-rate-regulated Generation segment, because of items detailed
below.
 
 Genco
 
 Three and
nine months - The effective tax rates for both the third quarter and first nine
months of 2008 were lower than the effective tax rates for the same periods in
the prior year, primarily because of the increased impact of the production
activity deductions and research tax credits during the current-year
periods.
 
 CILCO
(AERG)
 
 Three and nine months - The effective
tax rates for both the third quarter and first nine months of 2008 were lower
than the effective tax rates for the same periods in 2007, primarily because of
the impact of production activity deductions, along with changes to reserves in
uncertain tax positions during the current-year periods.
 
 CILCORP (Parent Company
Only)
 
 Three and nine months - The effective
tax rates for both the third quarter and first nine months of 2008 were higher
than the effective tax rates for the same periods in 2007, primarily due to the
effect of permanent items on higher consolidated pretax book income in the
current-year periods.
 
 EEI
 
 Three months and nine months - The
effective tax rate was comparable between periods.
 
 
 LIQUIDITY
AND CAPITAL RESOURCES
 
 The
tariff-based gross margins of Ameren’s rate-regulated utility operating
companies (UE, CIPS, CILCO (Illinois Regulated) 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 (Illinois Regulated) and IP. For operating
cash flows, Genco and AERG rely on power sales to Marketing Company, which sold
power through the September 2006 Illinois power procurement auction, financial
contracts that were part of the Illinois electric settlement agreement and the
2008 Illinois RFP process for energy and capacity that was used pursuant to the
Illinois electric settlement agreement. Marketing Company is also selling power
through other primarily market-based contracts with wholesale and retail
customers. In addition to cash flows from operating activities, the Ameren
Companies use available cash, credit facilities, money pool or other short-term
borrowings from affiliates or commercial paper 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, 2008, for Ameren, CILCORP, CILCO, and IP. In October 2008 IP issued $400
million in senior secured notes that mitigated its working capital deficit. The
Ameren Companies may reduce their short-term borrowings with cash from
operations or discretionarily with long-term borrowings, or in the case of
Ameren subsidiaries, with equity infusions from Ameren. The Ameren Companies
expect to incur significant capital expenditures over the next five years as
they comply with environmental regulations and make significant investments in
their electric and gas utility infrastructure to improve overall system
reliability. Expenditures not funded with operating cash flows are expected to
be funded primarily with debt. The global capital and credit markets have been
experiencing extreme volatility and disruption in 2008. See Outlook for a
discussion of the implications of this volatility and disruption for the Ameren
Companies and our plans to address these issues. See Note 2 - Rate and
Regulatory Matters to our financial statements under Part I, Item 1, of this
report for a discussion of the Illinois electric settlement agreement and the
power procurement plan, which among other
   80
  things,
has changed the process for power procurement in Illinois and will affect future
cash flows of the Ameren Companies, except UE. The settlement resulted in
customer refunds and credits during the first nine months of 2008, and it will
result in further credits to customers through 2010. The Ameren Illinois
Utilities will receive reimbursement for most of these refunds and credits from
Illinois power generators, including Genco and AERG.
  The following table presents netcash provided by (used in)
operating, investing and financing activities for the nine months ended
September 30, 2008 and 2007:
 
 Net
      Cash Provided By
                Operating
      Activities
              
              
              Net
      Cash Used In
                Investing
      Activities
              
              
              Net
      Cash Provided By
                (Used
      In) Financing Activities2008
              
              
              2007
              
              
              Variance
              
              
              2008
              
              
              2007
              
              
              Variance
              
              
              2008
              
              
              2007
              
              
              VarianceAmeren (a)
              
              $
              1,245
              
              
              $
              920
              
              
              $
              325
              
              
              $
              (1,501
              )
              
              $
              (1,093
              )
              
              $
              (408
              )
              
              $
              107
              
              
              $
              206
              
              
              $
              (99
              )UE
              
              
              555
              
              
              
              519
              
              
              
              36
              
              
              
              (794
              )
              
              
              (535
              )
              
              
              (259
              )
              
              
              54
              
              
              
              15
              
              
              
              39CIPS
              
              
              80
              
              
              
              11
              
              
              
              69
              
              
              
              (26
              )
              
              
              (115
              )
              
              
              89
              
              
              
              (66
              )
              
              
              99
              
              
              
              (165
              )Genco
              
              
              209
              
              
              
              153
              
              
              
              56
              
              
              
              (230
              )
              
              
              (137
              )
              
              
              (93
              )
              
              
              21
              
              
              
              (15
              )
              
              
              36CILCORP
              
              
              107
              
              
              
              20
              
              
              
              87
              
              
              
              (222
              )
              
              
              (141
              )
              
              
              (81
              )
              
              
              109
              
              
              
              201
              
              
              
              (92
              )CILCO
              
              
              120
              
              
              
              48
              
              
              
              72
              
              
              
              (221
              )
              
              
              (141
              )
              
              
              (80
              )
              
              
              95
              
              
              
              162
              
              
              
              (67
              )IP
              
              
              120
              
              
              
              23
              
              
              
              97
              
              
              
              (139
              )
              
              
              (133
              )
              
              
              (6
              )
              
              
              25
              
              
              
              110
              
              
              
              (85
              )
 
 (a)
              Includes
      amounts for Ameren registrant and nonregistrant subsidiaries and
      intercompany eliminations.
  
 Cash
Flows from Operating Activities
 
 Ameren’s
cash from operating activities increased in the first nine months of 2008, as
compared with the first nine months of 2007, primarily due to increased electric
and gas margins as discussed in Results of Operations, and a reduction in
receivables. In the 2007 period, receivables increased primarily due to the
January 2, 2007, electric rate increases at the Ameren Illinois Utilities,
related uncertainty surrounding a potential settlement and deterioration of
collections. In addition, receivables were higher in the prior year because of
initial billings to generators for reimbursements under the Illinois electric
settlement agreement. However, in 2008, receivable balances have decreased
and past-due balances have improved. Cash flow from operations during the 2008
period was also positively affected compared with the 2007 period by a decrease
in income taxes (net of refunds) of $118 million and by the Illinois electric
settlement agreement, as reimbursements from generators exceeded credits
provided to customers by $17 million. In addition, net collateral postings
decreased by $71
million. Factors that reduced cash flows from operations included a larger
increase in gas inventories during the first nine months of 2008 compared to the
same period in the prior year as both volumes and prices increased, and
increased under-recovery under the PGA. In addition, cash payments related to
the December 2005 Taum Sauk incident (net of insurance recoveries) increased $10
million in the nine months ended September 30, 2008, as compared with the nine
months ended September 30, 2007.
 
 At UE,
cash from operating activities increased in the first nine months of 2008,
compared with the first nine months of 2007, primarily because of increased
electric margins and the lack of a Callaway nuclear plant refueling and
maintenance outage as discussed in Results of Operations, the collection of an
$85 million affiliate receivable, and a $32 million decrease in payments for
storm restorations. Reducing the positive effects mentioned above were a $10
million increase in cash payments (net of insurance recoveries) related to the
December 2005 Taum Sauk incident, increased income tax payments
(net of refunds) of $13 million, and net decreases in various affiliate
payables.
 
 At CIPS, cash from operating
activities increased in the first nine months of 2008, compared with the first
nine months of 2007, primarily because of a $47 million decrease in income tax
payments (net of refunds), increases in electric margins
as discussed in Results of Operations, and favorable fluctuations in
receivables, including affiliate receivables. In the 2007 period, receivables
increased due to the January 2, 2007, electric rate increases at the Ameren
Illinois Utilities, related uncertainty surrounding a potential settlement
disclosure and deterioration of collections. In addition, receivables were
higher in the prior year because of initial billings to generators for
reimbursements under the Illinois electric settlement agreement. However,
receivable balances at September 30, 2008, were comparable with the balances at
December 31, 2007, and past-due balances have improved. In addition, the
Illinois electric settlement agreement had a positive effect on cash from
operations in the first nine months of 2008. Generator reimbursements under the
Illinois electric settlement agreement exceeded credits provided to customers by
$6 million. Working capital changes that benefited cash from operations included
favorable changes in affiliate accounts payable and in MISO payables compared to
the prior year. Partially offsetting these increases in cash from operations was
a larger increase in gas inventories during the first nine months of 2008
compared to the same period in the prior year as both volumes and prices
increased.
 
 Genco’s
cash from operating activities increased in the first nine months of 2008
compared to the 2007 period, primarily because of an increase in electric
margins and working capital changes in the ordinary course of business.
Partially offsetting these increases in cash from operations
   81
  were an
increase in fuel inventory and an increase in income tax payments (net of
refunds) of $10 million.
 
 Cash from operating activities
increased for CILCORP and CILCO in the nine months ended September 30, 2008,
compared with the same period in 2007, primarily due to decreases in income tax
payments (net of refunds) of $43 million and $49 million at CILCORP and
CILCO, respectively,
increased electric and gas margins, and favorable fluctuations in receivables.
In the 2007 period, receivables increased due to the January 2, 2007, electric
rate increases at the Ameren Illinois Utilities, related uncertainty surrounding
a potential settlement and deterioration of collections. In addition,
receivables were higher in the prior year because of initial billings to
generators for reimbursements under the Illinois electric settlement agreement.
However, in 2008, receivable balances have decreased and past-due balances have
improved. Other increases in cash flow from operations were primarily due to
fluctuations in working capital in the normal course of business. Partially
offsetting these increases in cash from operations were a larger increase in gas
inventories during the first nine months of 2008 compared to the same period in
the prior year as both volumes and prices increased and an increase in
under-recovery under the PGA.
 
 IP’s cash
from operating activities increased in the nine months ended September 30, 2008,
compared with the same period in 2007, primarily due to a $45 million decrease
in income tax payments (net of refunds), increased electric and gas margins, and
a reduction in receivables. In the 2007 period receivables increased due to the
January 2, 2007, electric rate increases at the Ameren Illinois Utilities,
related uncertainty surrounding a potential settlement and deterioration of
collections. In addition, receivables were higher in the prior year because of
initial billings to generators for reimbursements under the Illinois electric
settlement agreement. However, in 2008, receivable balances have decreased and
past-due balances have improved. In addition, net changes in collateral postings
were favorable and storm costs were lower in the current period compared to
the same period last year. The Illinois electric settlement agreement also had a
positive effect on cash from operations in the first nine months of 2008 as
generator reimbursements exceeded credits provided to customers by $9
million. Partially offsetting the aforementioned increases in cash from
operations was a larger increase in gas inventories during the first nine months
of 2008 compared to the same period in the prior year as both volumes and prices
increased.
 
 Cash
Flows from Investing Activities
 
 Ameren used more cash for investing
activities in the first nine months of 2008 than in the first nine months
of 2007. Net cash used for capital expenditures increased in 2008 as a result of
power plant scrubber projects, upgrades at various power plants, and reliability
improvements of the transmission and distribution system. Additionally,
increased purchases and higher prices resulted in a $122 million increase in
nuclear fuel expenditures.
 
 UE’s cash used in investing activities
increased during the nine months ended September 30, 2008, compared to the same
period in 2007, principally because of a $122 million increase in nuclear fuel
expenditures resulting from increased purchases for future refueling outages and
higher prices. Capital expenditures increased $121 million. This increase was a
result of increased spending related to a power plant scrubber project,
reliability improvements of the transmission and distribution system, and
various plant upgrades.
 
 CIPS’ cash used in investing activities
during the first nine months of 2008 decreased compared to the same period in
2007. During both periods, cash used for capital expenditures, primarily for
reliability improvements of the transmission and distribution system, was offset
by similar amounts of proceeds received from an intercompany note. During 2007,
CIPS contributed $94 million in net money pool advances, while no such advances
occurred in 2008.
 
 Genco’s cash used in investing
activities increased in the first nine months of 2008 compared with the same
period in 2007. Capital expenditures increased $85 million, principally due to a
power plant scrubber project. This increase was offset, in part, by a $5 million
decrease in emission allowance purchases.
 
 CILCORP’s and CILCO’s cash used in
investing activities increased in the nine months ended September 30, 2008,
compared with the same period in 2007. Cash used in investing activities
increased as a result of a $40 million increase in capital expenditures,
primarily due to a power plant scrubber project and plant upgrades at AERG. The
receipt of a $42 million net repayment of prior-year money pool advances reduced
cash flows used in investing activities in the 2008 period compared to
2007.
 
 IP’s cash used in investing activities
increased in the first nine months of 2008 compared to the same period in 2007.
Capital expenditures decreased by $4 million in the first nine months of 2008
from the year-ago period primarily because of a reduction in storm-related
capital expenditures. Net money pool advances increased by $9 million in the
first nine months of 2008 compared with the prior-year period.
 
 See Note
9 - Commitments and Contingencies to our financial statements under Part I, Item
1, of this report for a discussion of future environmental capital expenditure
estimates.
 
 We continually review our power
supply needs. As a result, we could modify plans for generation capacity, which
  82
  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
 
 During
the nine months ended September 30, 2008, the Ameren Companies issued $1.3
billion of senior debt. The proceeds were used to repurchase, redeem, and
fund $823 million of long-term debt, reduce short-term borrowings, and fund
capital expenditures and other working capital needs at UE, CIPS, Genco, CILCO,
and IP. The refinancing activity that occurred during the first nine months of
2008 resulted in a decrease in cash provided by financing activities compared
with the year-ago period. The first nine months of 2007 included net borrowings
of $590 million of short-term debt that were used to fund maturities of
long-term debt, fund working capital needs at Ameren subsidiaries and build
liquidity during a period of legislative uncertainty in Illinois. Additionally,
CILCO redeemed the remaining shares of its 5.85% Class A preferred stock to
complete the mandatory sinking fund redemption requirement resulting in a $16
million use of cash during 2008 compared with 2007. Benefiting the nine months
ended September 30, 2008, compared with the year-ago period was a $36
million increase in proceeds from the issuance of Ameren common stock resulting
from increased sales through Ameren’s 401(k) plan and DRPlus.
 
 UE’s net
cash provided by financing activities increased in the first nine months of
2008, compared with the same period of the prior year. During the nine months
ended September 30, 2008, UE used $699 million in proceeds from the issuance of
senior secured notes to reduce short-term debt, redeem outstanding auction-rate
environmental improvement revenue refunding bonds that had adjusted to higher
rates as a result of the collapse of the auction-rate securities market, and
fund the current maturity of UE’s 6.75% first mortgage bonds. Comparably, during
the nine months ended September 30, 2007, UE issued $425 million in senior
secured notes to fund working capital requirements and reduced short-term debt
by $142 million. A net increase in borrowings under an intercompany borrowing
arrangement with Ameren also benefited the nine months ended September 30, 2008,
compared with the year-ago period.
 
 CIPS had a net use of cash from
financing activities in the nine months ended September 30, 2008, compared with
a net source of cash in the first nine months of 2007. This change was a result
of CIPS using existing cash to fund a net reduction in short-term debt and to
redeem $35 million of auction-rate environmental improvement revenue refunding
bonds that had adjusted to higher rates as a result of the collapse of the
auction-rate securities market. CIPS had $29 million net repayments of
short-term debt in the first nine months of 2008 compared with net borrowings of
$100 million in the first nine months of 2007.
 
 Genco issued $300 million of 7.00%
senior unsecured notes during the first nine months of 2008 resulting in a net
source of cash from financing activities compared with a net use of cash in the
year-ago period. The proceeds from the issuance were used to fund capital
expenditures and other working capital requirements, including a net reduction
in money pool borrowings and $100 million of short-term borrowings during the
2008 period compared with the 2007 period.
 
 CILCORP’s and CILCO’s cash provided
by financing activities decreased during the nine months ended September 30,
2008, compared to the 2007 period. This decrease is primarily the result of
CILCORP’s and CILCO’s net repayments of short-term borrowings during the nine
months ended September 30, 2008, compared with the 2007 period. These repayments
were funded by an increase in money pool borrowings of $171 million, primarily
at AERG. Partially offsetting this were reduced redemptions and maturities of
long-term debt in 2008. During the 2008 period, $19 million of auction-rate
environmental improvement revenue refunding bonds that had adjusted to higher
rates as a result of the collapse of the auction-rate securities market were
redeemed at CILCO, compared with the maturity of $50 million of CILCO’s 7.50%
bonds during the 2007 period. Also benefiting the nine months ended September
30, 2008, were net borrowings of a $61 million direct loan from Ameren at
CILCORP compared with $73 million net repayments during the 2007 period. A $14
million capital contribution received by CILCO in the third quarter of 2007 from
CILCORP resulted in a positive impact on cash flows at CILCO for the first nine
months of 2007.
 
 IP’s cash from financing activities
decreased in the first nine months of 2008, compared with the same period in
2007. During the first nine months of 2008, IP issued $336 million of senior
secured notes and used the proceeds to redeem all of IP’s outstanding
auction-rate pollution control revenue refunding bonds that had adjusted to
higher rates as a result of the collapse of the auction-rate securities market.
Additionally, during the 2008 period, IP funded $45 million of dividends and had
net short-term borrowings of $129 million. Comparatively, in the first nine
months of 2007, IP paid no dividends and had $125 million of net borrowings
under the 2007 credit facility and net money pool borrowings of $52
million. These borrowings were used to fund $65 million of long-term debt
maturities and build liquidity in 2007.
  83
 
 Short-term
Borrowings and Liquidity
 
 External
short-term borrowings typically consist of drawings under committed bank credit
facilities and commercial paper issuances. See Note 3 - Short-term Borrowings
and Liquidity to our financial statements under Part I, Item 1, of this report
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.
 
 The following table presents the
various credit facilities of the Ameren Companies and AERG, and their
availability as of September 30, 2008:
 
 Credit
      Facility
              Expiration
              Amount
      Committed
              Amount
      Available(a)Ameren,
      UE and Genco:Multiyear revolving(b)
              July
      2010
              1,150
              791(f)CIPS,
      CILCORP, CILCO, IP and AERG:2007 Multiyear revolving(c)(d)
              January
      2010
              500
              732006 Multiyear revolving(c)(e)
              January
      2010
              500
              81
 
 (a)
              After
      excluding unfunded Lehman Brothers Bank, FSB participations, under the
      $1.15 billion and 2006 $500 million credit
  facilities.
 (b)
              Ameren
      Companies may access this credit facility through intercompany borrowing
      arrangements.
 (c)
              See
      Note 3 - Short-term Borrowings and Liquidity to our financial statements
      under Part I, Item 1, of this report for discussion of the amendments to
      these facilities.
 (d)
              The
      maximum amount available to each borrower under this facility at September
      30, 2008, including for the issuance of letters of credit, was limited as
      follows: CILCORP -$125
      million, CILCO - $75 million, IP - $200 million and AERG - $100 million.
      CIPS and CILCO have the option of permanently reducing their ability to
      borrow under the 2006 $500 million credit facility and shifting such
      capacity, up to the same limits, to the 2007 $500 million credit facility.
      In July 2007, CILCO shifted $75 million of its sublimit under the 2006
      $500 million credit facility to this
facility.
 (e)
              The
      maximum amount available to each borrower under this facility at September
      30, 2008, including for issuance of letters of credit, was limited as
      follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $75 million,
      IP - $150 million and AERG - $200 million. In July 2007, CILCO shifted $75
      million of its capacity under this facility to the 2007 $500 million
      credit facility. Accordingly, as of September 30, 2008, CILCO had a
      sublimit of $75 million under this facility and a $75 million sublimit
      under the 2007 credit facility.
 (f)
              In
      addition to amounts drawn on this facility, the amount available is
      further reduced by standby letters of credit, which have been issued. The
      amount of such letters of credit at September 30, 2008, was $9
      million.
  
 On
September 15, 2008, Lehman filed for protection under Chapter 11 of the federal
Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New
York. As of September 30, 2008, Lehman Brothers Bank, FSB, a subsidiary of
Lehman, had lending commitments of $100 million and $21 million under the
$1.15 billion credit facility and the 2006 $500
million credit facility, respectively. The $50 million lending commitment
of another Lehman subsidiary under the 2007 $500 million credit facility was
assigned to a non-Lehman affiliated bank on or about September 17, 2008. At this
time, we do not know if Lehman Brothers Bank, FSB will seek to assign to other
parties any of its commitments within our credit facilities. Assuming Lehman
Brothers Bank, FSB does not fund its pro-rata share of funding or letter of
credit issuance requests under these two facilities, and such participations are
not assigned or otherwise transferred to other lenders, total amounts accessible
by the Ameren Companies and AERG will be limited to amounts not less than $1.05
billion under the $1.15 billion credit facility and $479 million under the
2006 $500 million credit facility. The Ameren Companies and AERG do not believe
that the potential reduction in available capacity under the credit facilities
if Lehman Brothers Bank, FSB does not fund its commitments will have a material
impact on their liquidity.
 
 On June
25, 2008, Ameren entered into a $300 million term loan agreement due June 24,
2009, which was fully drawn on
June 26, 2008. See Note 3 - Short-term Borrowings and Liquidity for additional
information.
 
 A further
source of liquidity for the Ameren Companies from time to time is available cash
and cash equivalents. At September
30, 2008, Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP had $206 million, less
than $1 million, $14
million, $2 million, less than $1 million, less than $1 million, and $12
million, respectively, of cash and cash equivalents.
 
 The issuance of short-term debt
securities by Ameren’s utility subsidiaries is subject to approval by FERC under
the Federal Power Act. In March 2008, FERC issued an order authorizing the
issuance of short-term debt securities subject to the following limits on
outstanding balances: UE - $1 billion, CIPS - $250 million, and CILCO - $250
million. The authorization was effective as of April 1, 2008, with an expiration
date of March 31, 2010. IP has unlimited short-term debt authorization from
FERC.
 
 Genco was
authorized by FERC in its March 2008 order to have up to $500 million of
short-term debt outstanding at any time. AERG and EEI have unlimited short-term
debt authorization from FERC.
 
 The
issuance of short-term debt securities by Ameren and CILCORP (parent) is not
subject to approval by any regulatory body.
  84
 The
Ameren Companies continually evaluate the adequacy and appropriateness of their
credit arrangements given changing business conditions. When business conditions
warrant, changes may be made to existing credit agreements or other short-term
borrowing arrangements.
 
 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 (net of any issuance
discounts and including any redemption premiums) for the nine months
ended September 30, 2008 and 2007, for the Ameren Companies. For additional
information related to the terms and uses of these issuances and the sources of
funds and terms for the redemptions, 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
      MonthsRepurchased
      or Matured
              
              2008
              
              
              2007IssuancesLong-term
      debtUE:6.00% Senior secured notes due
      2018
              April
              
              $
              250
              
              
              $
              -6.40% Senior secured notes due
      2017
              June
              
              
              -
              
              
              
              4256.70% Senior secured notes due
      2019
              June
              
              
              449
              
              
              
              -Genco:7.00% Senior unsecured notes
      due 2018
              April
              
              
              300
              
              
              
              -IP:6.25% Senior secured notes due
      2018
              April
              
              
              336
              
              
              
              -Total
      Ameren long-term debt issuances
              
              
              $
              1,335
              
              
              $
              425Common
      stockAmeren:DRPlus and
    401(k)
              Various
              
              $
              107
              
              
              $
              71Total
      common stock issuances
              
              
              $
              107
              
              
              $
              71Total
      Ameren long-term debt and common stock issuances
              
              
              $
              1,442
              
              
              $
              496Redemptions,
      Repurchases and MaturitiesLong-term
      debtAmeren:2002 5.70% notes due
      2007
              February
              
              $
              -
              
              
              $
              100Senior notes due
      2007
              May
              
              
              -
              
              
              
              250UE:2000 Series B environmental
      improvement bonds due 2035
              April
              
              
              63
              
              
              
              -2000 Series A environmental
      improvement bonds due 2035
              May
              
              
              64
              
              
              
              -2000 Series C environmental
      improvement bonds due 2035
              May
              
              
              60
              
              
              
              -1991 Series environmental
      improvement bonds due 2020
              May
              
              
              43
              
              
              
              -6.75% Series first mortgage
      bonds due 2008
              May
              
              
              148
              
              
              
              -CIPS:2004 Series pollution control
      bonds due 2025
              April
              
              
              35
              
              
              
              -CILCO:7.50% First mortgage bonds due
      2007
              January
              
              
              -
              
              
              
              50Series 2004 pollution control
      bonds due 2039
              April
              
              
              19
              
              
              
              -IP:Series 2001 Non-AMT bonds due
      2028
              May
              
              
              112
              
              
              
              -Series 2001 AMT bonds due
      2017
              May
              
              
              75
              
              
              
              -1997 Series A pollution control
      bonds due 2032
              May
              
              
              70
              
              
              
              -1997 Series B pollution control
      bonds due 2032
              May
              
              
              45
              
              
              
              -1997 Series C pollution control
      bonds due 2032
              June
              
              
              35
              
              
              
              -Note payable to IP
      SPT:5.65% Series due
      2008
              Various
              
              
              54
              
              
              
              65Preferred
      StockCILCO:5.85% Series
              July
              
              
              16
              
              
              
              1Total
      Ameren long-term debt and preferred stock redemptions, repurchases
      and
                maturities
              
              
              $
              839
              
              
              $
              466
 
 
 85
 
 The
following table presents the authorized amounts under SEC Form S-3 shelf
registration statements filed and declared effective for certain Ameren
Companies as of September 30, 2008:
 
 Effective
                Date
              Authorized
                Amount
              Issued
              AvailableAmeren
              June
      2004
              $  2,000
              $  459
              $ 
      1,541UE(a)
              June
      2008
              Not
      limited
              450
              Not limitedCIPS
              May
      2001
              250
              211
              39
 
 (a)
              In
      June 2008, UE, as a well-known seasoned issuer, filed a Form S-3 shelf
      registration statement registering the issuance of an indeterminate amount
      of certain types of securities, which expires in June 2011. In June 2008,
      UE issued $450 million principal amount of senior secured notes pursuant
      to this shelf registration
statement.
 
 In July
2008, Ameren filed a Form S-3 registration statement with the SEC authorizing
the offering of six million additional shares of its common stock under the
DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly
issued shares, treasury shares, or shares purchased in the open market or in
privately negotiated transactions. Ameren is currently selling newly issued
shares of its common stock under DRPlus.
 
 Ameren is
also currently selling newly issued shares of its common stock under its 401(k)
plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus
and its 401(k) plan (including a subsidiary plan that is now merged into the
Ameren 401(k) plan), Ameren issued a total of 0.8 million new shares of common
stock valued at $32 million and 2.5
million new shares valued at $107 million in the three months and nine months
ended September 30, 2008, respectively.
 
 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 that meets the requirements of the Securities Act of 1933 and
the rules and regulations thereunder.
 
 Indebtedness
Provisions and Other Covenants
 
 See Note
4 - Credit Facilities and Liquidity and Note 5 - Long-term Debt and Equity
Financings in the Form 10-K for a discussion of covenants and provisions (and
applicable cross-default provisions) contained in our bank credit facilities and
in certain of the Ameren Companies’ indenture agreements and articles of
incorporation. Also see Note 3 - Short-term Borrowings and Liquidity to our
financial statements under Part I, Item 1, of this report for a discussion of
covenants and provisions contained in the $300 million term-loan agreement
(including applicable cross-default provisions) and the March 2008 amendments to
the 2007 $500 million and 2006 $500 million credit facilities.
 
 At
September 30, 2008, the Ameren Companies were in compliance with their credit
facility, term loan agreement, indenture, and articles of incorporation
provisions and covenants.
 
 We
consider access to short-term and long-term capital markets a significant source
of funding for capital requirements not satisfied by our operating cash flows.
Inability to raise capital on favorable terms, particularly during times of
uncertainty in the capital markets, could negatively affect our ability to
maintain and expand our businesses. After assessing our current operating
performance, liquidity, and credit ratings (see Credit Ratings below), we
believe that we will continue to have access to the capital markets. However,
events beyond our control may create uncertainty in the capital markets or make
our access to the capital markets uncertain or limited. Such events could
increase our cost of capital and adversely affect our ability to access the
capital markets.
 
 Dividends
 
 Ameren paid to its shareholders
common stock dividends totaling $399 million, or $1.905 per share, during the
first nine months of 2008 (2007 - $395 million or $1.905 per share). On October
10, 2008, Ameren’s board of directors declared a quarterly common stock dividend
of 63.5 cents per share payable on December 31, 2008, to shareholders of record
on December 10, 2008.
 
 See Note 4 - Credit Facilities and
Liquidity in the Form 10-K for a discussion of covenants and provisions
contained in certain of the Ameren Companies’ financial agreements and articles
of incorporation that would restrict the Ameren Companies’ payment of dividends
in certain circumstances. At September 30, 2008, except as discussed below with
respect to the 2007 $500 million credit facility and the 2006 $500 million
credit facility, none of these circumstances existed at the Ameren Companies
and, as a result, they were allowed to pay dividends.
 
 The 2007
$500 million credit facility and 2006 $500 million credit facility limit
CIPS, CILCORP, CILCO and IP to common and preferred 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 received a below investment-grade credit rating
from either Moody’s or S&P. With respect to AERG, which currently is not
rated by Moody’s or S&P, the common and preferred stock dividend restriction
will not apply if its ratio of consolidated total debt to consolidated operating
cash flow, pursuant to a calculation defined in the facilities, is less than or
equal to 3.0 to 1.0. CILCORP’s senior unsecured long-term debt credit ratings
from Moody’s and S&P are below investment-grade, causing it to be subject to
this dividend payment limitation. As
  86
 of
September 30, 2008, AERG was in compliance with the debt-to-operating cash flow
ratio test in the 2007 and 2006 $500 million credit facilities and thus not
subject to this limitation. The other borrowers thereunder are not currently
limited in their dividend payments by this provision of the 2007 or 2006 $500
million credit facilities.
 
 The
following table presents common stock dividends paid by Ameren Corporation and
by Ameren’s subsidiaries to their respective parents for the nine months ended
September 30, 2008 and 2007.
 
 Nine
      Months2008
              
              
              2007UE
              
              $
              193
              
              
              $
              246Genco
              
              
              84
              
              
              
              113IP
              
              
              45
              
              
              
              -Nonregistrants
              
              
              77
              
              
              
              36Dividends
      paid by Ameren
              
              $
              399
              
              
              $
              395
 
 Contractual
Obligations
 
 For a
complete listing of our obligations and commitments, see Contractual Obligations
under Part II, Item 7 and Note 13 - Commitments and Contingencies under Part II,
Item 8 of the Form 10-K, and Other Obligations in Note 9 - Commitments and
Contingencies under Part I, Item 1, of this report. See Note 13 - 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. See
also Note 1 - Summary of Significant Accounting Policies to our financial
statements under Part I, Item 1, of this report for the unrecognized tax
benefits under the provisions of FIN 48.
 
 Subsequent to December 31, 2007,
obligations related to the procurement of coal, natural gas, nuclear fuel, and
heavy forgings materially changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and
IP to $3,293 million, $1,490 million, $387 million, $250 million, $517 million,
$517 million and $520 million, respectively. Total other obligations, including
the amount of unrecognized tax benefits, at September 30, 2008, for Ameren, UE,
CIPS, Genco, CILCORP, CILCO and IP were $4,039 million, $1,873 million, $424
million, $293 million, $572 million, $572
million and $653 million, respectively.
 
 As a
result of the Illinois electric settlement agreement, the Ameren Illinois
Utilities, Genco and AERG agreed to make aggregate contributions of $150 million
over a four-year period, with $60 million coming from the Ameren Illinois
Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62
million from Genco and $28 million from AERG. Ameren, CIPS, CILCO (Illinois
Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily
recorded as a reduction to electric operating revenues, during the quarter ended
September 30, 2008, of $10 million, $2 million, less than $1 million, $2
million, $4 million, and $2 million, respectively, (quarter ended September
30, 2007 - $59 million, $8 million, $5 million, $11 million, $24 million, and
$11 million, respectively) and during the nine months ended September 30, 2008,
of $32 million, $5 million, $2 million, $6 million, $13 million, and $6
million, respectively (nine months ended September 30, 2007 - $59 million, $8
million, $5 million, $11 million, $24 million, and $11 million, respectively)
under the terms of the Illinois electric settlement agreement. At September 30,
2008, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances
from nonaffiliated Illinois generators for reimbursement of customer rate relief
and program funding of $15 million, $5 million, $3 million and $7 million,
respectively. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of
this report for additional information regarding the Illinois electric
settlement agreement.
 
 Credit
Ratings
 
 The
following table presents the principal credit ratings of the Ameren Companies by
Moody’s, S&P and Fitch effective on the date of this report:
 
 Moody’s
              S&P
              FitchAmeren:Issuer/corporate
      credit rating
              Baa3
              BBB-
              BBB+Senior
      unsecured debt
              Baa3
              BB+
              BBB+Commercial
      paper
              P-3
              A-3
              F2UE:Issuer/corporate
      credit rating
              Baa2
              BBB-
              A-Secured
      debt
              Baa1
              BBB
              A+Commercial
      paper
              P-3
              A-3
              F2CIPS:Issuer/corporate
      credit rating
              Ba1
              BBB-
              BBB-Secured
      debt
              Baa3
              BBB+
              BBB+Senior
      unsecured debt
              Ba1
              BBB-
              BBBGenco:Issuer/corporate
      credit rating
              -
              BBB-
              BBB+Senior
      unsecured debt
              Baa3
              BBB-
              BBB+CILCORP:Issuer/corporate
      credit rating
              -
              BBB-
              BBB-Senior
      unsecured debt
              Ba2
              BB+
              BBB-CILCO:Issuer/corporate
      credit rating
              Ba1
              BBB-
              BBBSecured
      debt
              Baa2
              BBB+
              A-IP:Issuer/corporate
      credit rating
              Ba1
              BBB-
              BBB-Secured
      debt
              Baa3
              BBB
              BBB+
 
 Moody’s
Ratings Actions
 
 On
February 12, 2008, Moody’s affirmed the ratings of Ameren and Genco but changed
their rating outlooks to negative from stable. Moody’s placed the long-term
credit ratings of UE under review for possible downgrade and affirmed UE’s
commercial paper rating. In addition, Moody’s affirmed the ratings of CIPS,
CILCORP, CILCO and IP and maintained a positive rating outlook on these four
companies. According to Moody’s, the review of UE’s ratings was prompted by
declining cash flow coverage metrics, increased operating costs, higher capital
expenditures for environmental
 87
  compliance
and transmission and distribution system investment, and significant regulatory
lag in the recovery of these costs. Moody’s stated that the negative outlook on
the credit rating of Genco reflected Genco’s “position as a predominantly coal
generating company that is likely to be seriously affected by more stringent
environmental regulations, including a potential cap or tax on carbon
emissions.” The negative outlook on the ratings of Ameren reflects the
factors that impacted its subsidiaries, UE and Genco, according to
Moody’s.
 
 On May
21, 2008, Moody's lowered the credit ratings of UE to Baa1 for its senior
secured debt and to Baa2 for its issuer rating and changed the rating outlook to
stable. In its reasons for these actions, Moody’s reiterated the items noted
above, attributing the declining cash flow metrics to increased fuel and
purchased power costs, growing capital expenditures for environmental compliance
and for transmission system reliability, and higher labor costs. They noted that
UE is one of the few utilities in the country operating without fuel, purchased
power, and environmental cost recovery mechanisms. Moody’s also placed UE’s
commercial paper rating on review for possible downgrade due to its review of
Ameren’s short-term rating as noted below. At the same time, the ratings of
Ameren and Genco were changed from negative outlook to being on review for
possible downgrade.
 
 On August 13, 2008, Moody’s
downgraded both the issuer and senior unsecured debt ratings of Ameren and the
senior unsecured debt rating of Genco to Baa3 from Baa2. The outlooks on
these ratings are now stable. Moody’s also downgraded the commercial paper
ratings of Ameren and UE to P-3 from P-2. Moody’s stated that these downgrades
were because of declining consolidated coverage ratios over the last several
years and the expectation that ongoing cost pressures and the lack of timely
regulatory recovery of some costs will prevent ratios from returning to
historical levels in the near-term.
 
 S&P
Ratings Actions
 
 On March 19, 2008, S&P raised its
senior unsecured debt ratings for CIPS to BBB- from B+ and for CILCORP to BB
from B+.
 
 On September 11, 2008, S&P
upgraded its corporate credit ratings on CILCORP, CILCO, CIPS and IP to BBB-
from BB. Senior secured debt ratings at CILCO and CIPS were upgraded to BBB+
from BBB and were upgraded at IP to BBB from BBB-. CILCORP’s senior unsecured
debt rating was raised to BB+ from BB. All of Ameren’s other ratings were
affirmed and all outlooks are now stable. At the same time, S&P raised the
business profiles of CIPS and IP to “strong” from “satisfactory.”  The
business profiles of CILCORP and CILCO remain “satisfactory.” S&P stated
that the ratings upgrades were due to its assessment that the regulatory and
political environment in Illinois will be reasonably supportive of investment
grade credit quality with regard to the Ameren Illinois Utilities’ then pending
rate cases. See Note 2 - Rate and Regulatory Matters under Part I, Item 1, of
this report for a discussion of the order issued by the ICC in these rate cases
on September 24, 2008.
 
 Fitch
Ratings Actions
 
 On
October 16, 2008, Fitch upgraded its issuer credit ratings on CILCO to BBB from
BB+ and on CILCORP, CIPS and IP to BBB- from BB+. The senior secured debt
ratings were raised at CIPS and IP to BBB+ from BBB and at CILCO to A- from BBB.
Senior unsecured debt ratings were raised at CIPS and IP to BBB from BBB-, at
CILCO to BBB+ from BBB-, and at CILCORP to BBB- from BB+. The outlook for each
of these entities was changed to stable from rating watch positive. Fitch stated
that the ratings upgrades were a result of the expected positive financial
impact of electric and gas rate case decisions issued by the ICC in September
2008 and the reduction in business risk associated with the Illinois electric
settlement agreement in 2007.
 
 Collateral
Postings
 
 Any
adverse change in the Ameren Companies’ credit ratings may reduce access to
capital and trigger additional collateral postings and prepayments. Such changes
may also increase the cost of borrowing and fuel, power and gas supply, among
other things, resulting in a negative impact on earnings. Collateral postings
and prepayments made with external parties at September 30, 2008, were $37
million, $2 million, $7 million, $6 million, $6 million, and $12 million at
Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively. Sub-investment-grade
issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at
September 30, 2008, could have resulted in Ameren, UE, CIPS, Genco, CILCORP,
CILCO or IP being required to post additional collateral or other assurances for
certain trade obligations amounting to $205 million, $40 million, $32 million,
$16 million, $46 million, $46 million, and $64
million, respectively.
 
 In addition, the cost of borrowing
under our credit facilities can increase or decrease depending upon the credit
ratings of the borrower. 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. See Quantitative and Qualitative Disclosures about Market Risk -
Interest Rate Risk under Part I, Item 3, for information on credit rating
changes with respect to insured tax-exempt auction-rate bonds.
  88
 
 OUTLOOK
 
 Below are
some key events and trends that may affect the Ameren Companies’ financial
condition, results of operations, or liquidity in 2008 and beyond.
 
 Capital
and Credit Markets
  The
global capital and credit markets have experienced extreme volatility and
disruption in 2008, and in particular, since early September. Several factors
have driven this situation, including deteriorating global economic conditions
and the weakened financial condition of major financial institutions, as
evidenced by the bankruptcy of Lehman.  These conditions have led
governments around the world to establish policies and programs that are
designed to strengthen the global financial system, enhance liquidity and
restore investor confidence. We believe that these recent events have several
implications for the capital and credit markets, the economy and our industry as
a whole, including Ameren. They include the following:
 
 ·
              Access to Capital
      Markets - The extreme disruption in the capital markets has limited
      companies’, including the Ameren Companies’, ability to freely access the
      capital and credit markets to support their operations and refinance debt.
      We are unable to predict how long these conditions will persist, but we
      expect the capital markets to remain uncertain throughout 2009 and
      potentially longer. However, we believe we will continue to have access to
      the capital markets on terms commercially acceptable to us, as evidenced
      by IP's recent sale of $400 million in senior secured notes in October
      2008.
 ·
              Cost of Capital
      - The disruption in the capital and credit markets has led to higher
      financing costs compared to recent years. We expect this trend to continue
      while the current level of uncertainty in the financial markets
      persists.
 ·
              Credit
      Facilities - At September 30, 2008, the Ameren Companies had in
      place revolving bank credit facilities aggregating $2.15 billion. In
      total, eighteen banks participate in these credit facilities. In January
      2010, $1 billion of these facilities expire, and $1.15 billion expire in
      July 2010.  Due to the Lehman bankruptcy filing, the size of our
      facilities was effectively reduced by up to $121 million. We cannot
      predict whether other banks that are currently participating in our credit
      facilities will declare bankruptcy or otherwise fail to honor their
      commitments thereunder, and thus reduce the level of access we have to our
      credit facilities. However, as stated previously, governments around the
      world have taken aggressive actions to provide incremental capital and
      other assurances to improve the financial condition of, and confidence in,
      financial institutions, individually and as a whole, including the
      participants in our credit facilities. We are actively developing plans
      and strategies to renew these facilities prior to their expiration dates.
      We are unable to predict whether the size and terms of any new credit
      facilities will be comparable to the existing
  facilities.
 ·
              Economic
      Conditions - We believe that the disruption in the capital and
      credit markets will also further weaken global economic conditions as the
      limited access to capital and higher cost of capital for businesses and
      consumers will reduce spending, result in job losses, and pressure
      economic growth for the foreseeable future.  These weak economic
      conditions will likely result in volatility in the power and commodity
      markets, greater risk of defaults by our counterparties, weaker customer
      sales growth, higher bad debt expense, and possible impairment of goodwill
      and long-lived assets, among other things. To date, the level of defaults
      by counterparties, lower sales growth, and bad debt expense resulting from
      the weak economy have not significantly impacted the Ameren Companies;
      however, we are unable to predict the ultimate impact of these weak
      economic conditions on our results of operations, financial position, or
      liquidity.
 ·
              Investment
      Returns - The disruption in the capital markets, coupled with weak
      global economic conditions, has adversely affected financial markets. As a
      result, we expect to experience lower than assumed investment returns in
      2008 in our pension and postretirement benefit funds. These lower returns
      could increase our pension and postretirement expenses,
      pension funding levels and charges to OCI. Our future expenses and
      funding levels will also be impacted by future discount rate levels. We
      are unable to predict what our future returns will be on our investments,
      as well as future discount rate levels and the resulting impact on our
      pension and postretirement benefit expense levels and
    funding.
 ·
              Operating and Capital
      Expenditures - The Ameren Companies will continue to make
      significant levels of investments and incur expenditures for their
      electric and gas utility infrastructure to improve overall system
      reliability, comply with environmental regulations and improve plant
      performance. However, due to the significant recent level of disruption
      and uncertainties in the capital and credit markets, we are actively
      evaluating opportunities to defer or reduce planned capital spending and
      operating expenses to mitigate the risks associated with accessing these
      uncertain markets. We have already taken actions in this regard by
      reducing expected 2009 operating and capital expenditures in Ameren’s
      Non-rate-regulated Generation segment by $400 million to $500 million.
      Other cost deferral and reduction opportunities have been identified in
      our regulated businesses and administrative support functions that we will
      execute in the event of continued disruption of the capital and
      credit markets. In our regulated businesses and administrative support
      functions, we have identified $400 million to $500 million
   89
   ·
              At
      October 31, 2008, Ameren had available liquidity, which represented
      its cash on hand and amounts available under its existing credit
      facilities of approximately $1.45 billion, excluding unfunded Lehman bank
      facility participation commitments, which was $550 million higher than
      this same time last year.  We expect our available liquidity to
      remain solid through the end of 2008 and throughout 2009 as we
      strategically access the capital markets and execute the expenditure
      control initiatives discussed above. However, we are unable to predict
      whether significant changes in economic conditions, further disruption in
      the capital and credit markets or other unforeseen events may occur, which
      could materially impact our
estimate.
 
 While we
believe the uncertainty in the capital and credit markets will persist
throughout 2009, and potentially longer, we do believe that actions taken by the
U.S. government and governments around the world will ultimately help ease the
extreme volatility and disruption of these markets. In addition, we believe we
will continue to have access to the capital markets on terms commercially
acceptable to us. Additional financings are expected through 2009, subject to
market conditions. We believe that our expected operating cash flows, capital
expenditure and related financing plans (including accessing our existing credit
facilities) will provide the necessary liquidity to meet our operating,
investing, and financing needs, at a minimum, through the end of 2009. However,
there can be no assurance that significant changes in economic conditions,
further disruptions in the capital and credit markets or other unforeseen events
will not materially impact our ability to execute our expected operating,
capital or financing plans.
  Current
Capital Expenditure Plans
 
 ·
              Between
      2008 and 2017, Ameren estimated that certain Ameren Companies would be
      required to invest between   $4 billion and $5 billion to
      retrofit their coal-fired power plants with pollution control equipment.
      Costs for these types of projects continue to escalate. However, because
      of the 2008 U.S. Court of Appeals for the District of Columbia decisions
      to vacate the Clean Air Interstate Rule and the Clean Air Mercury Rule,
      the timing and ultimate amount of these capital costs are under review at
      this time. Any pollution control investments will result in decreased
      plant availability during construction and significantly higher ongoing
      operating expenses. Approximately 45% of this investment was expected to
      be in our Regulated Missouri operations, and therefore was expected to be
      recoverable from ratepayers. The recoverability of amounts expended in
      Non-rate-regulated Generation operations will depend on whether market
      prices for power adjust as a result of market conditions reflecting
      increased environmental costs for
generators.
 ·
              Future
      federal and state legislation or regulations that mandate limits on the
      emission of greenhouse gases would result in significant increases in
      capital expenditures and operating costs. Excessive costs to comply with
      future legislation or regulations might force Ameren and other
      similarly-situated electric power generators to close some coal-fired
      facilities. Investments to control carbon emissions at Ameren’s coal-fired
      power plants would significantly increase future capital expenditures and
      operation and maintenance expenses.
 ·
              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 2018 to 2020. 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 that would use coal or nuclear fuel. In July 2008, UE
      filed a COLA with the NRC for a potential new nuclear plant at UE’s
      existing Callaway County, Missouri nuclear plant site. UE has also signed
      contracts for certain long lead-time nuclear-plant related equipment. The
      filing of the COLA and entering into these contracts does not mean a
      decision has been made to build a nuclear plant. These are only the first
      steps in the regulatory licensing and procurement process and are
      necessary actions to preserve the option to develop a new nuclear
      plant.
 ·
              UE
      intends to submit a license extension application with the NRC to extend
      its Callaway nuclear plant’s operating license by twenty years so that the
      operating license will expire in 2044. UE cannot predict whether or when
      the NRC will approve the license
extension.
   90
  ·
              Over
      the next few years, we expect to make significant investments in our
      electric and gas infrastructure and to incur increased operations and
      maintenance expenses to improve overall system reliability. We are
      projecting higher labor and material costs for these capital expenditures.
      We would expect these costs or investments at our rate-regulated
      businesses to be ultimately recovered in
rates.
 ·
              Increased
      investments for environmental compliance, reliability improvement, and new
      baseload capacity will result in higher depreciation and financing
      costs.
 
 Revenues
 
 ·
              The
      earnings of UE, CIPS, CILCO and IP are largely determined by the
      regulation of their rates by state agencies. With rising costs, including
      fuel and related transportation, purchased power, labor, material,
      depreciation and financing costs, coupled with increased capital and
      operations and maintenance expenditures targeted at enhanced distribution
      system reliability and environmental compliance, Ameren, UE, CIPS, CILCO
      and IP expect to experience regulatory lag until requests to increase
      rates to recover such costs are granted by state regulators. Ameren, UE,
      CIPS, CILCO and IP expect more frequent rate cases will be necessary in
      the future. UE agreed not to file a natural gas delivery rate case before
      March 15, 2010.
 ·
              The
      ICC issued a consolidated order in September 2008 approving a net increase
      in annual revenues for electric delivery service of $123 million in the
      aggregate (CIPS - $22 million increase, CILCO - $3 million decrease
      and   IP - $104 million increase) and a net increase in
      annual revenues for natural gas delivery service of $38 million in the
      aggregate (CIPS -$7
      million increase, CILCO - $9 million decrease, and IP - $40 million
      increase), based on a 10.65% return on equity with respect to electric
      delivery service and 10.68% return on equity with respect to natural gas
      delivery service. These rate changes were effective on October 1, 2008.
      Because of the Ameren Illinois Utilities’ pledge to keep the overall
      residential electric bill increase resulting from these rate changes to
      less than 10% for each utility, IP will not recover approximately $10
      million in revenue in the first year electric delivery service rates are
      in effect. Thereafter, residential electric delivery service rates will be
      adjusted to recover the full increase. In addition, the ICC changed the
      depreciable lives used in calculating depreciation expense for the Ameren
      Illinois Utilities’ electric and natural gas rates. As a result, annual
      depreciation expense for the Ameren Illinois Utilities will be reduced for
      financial reporting purposes by a net $13 million in the aggregate (CIPS -
      $4 million reduction, CILCO - $26 million reduction, and IP - $17
      million increase). The Ameren Illinois Utilities and some parties to the
      rate case have requested that the ICC rehear certain aspects of the
      order.
 ·
              UE
      filed an electric rate case with the MoPSC in April 2008 in order to
      recover rising costs and to earn a reasonable return on its investments.
      UE’s return on equity was 9% in 2007 and is expected to decrease to 7% in
      2008. UE requested to increase its annual electric revenues by $251
      million. The electric rate increase is based on a 10.9% return on equity,
      a capital structure composed of 51% common equity, a rate base
      of  $5.9 billion and a test year ended March 31, 2008, with
      updates for known and measurable changes through September 30, 2008. In
      August 2008, the MoPSC staff filed a report and direct testimony with the
      MoPSC recommending an increase in annual revenues for electric service for
      UE of $51 million based on a 9.5% return on equity. The Office of Public
      Counsel and intervenors also filed testimony with the MoPSC in August 2008
      opposing certain aspects of UE’s April 2008 request. The MoPSC has until
      March 2009 to render a decision in this rate
  case.
 ·
              In
      current and future rate cases, UE, CIPS, CILCO and IP will also seek cost
      recovery mechanisms from their state regulators to reduce regulatory lag.
      In the ICC consolidated electric and natural gas rate order issued in
      September 2008, the ICC rejected the Ameren Illinois Utilities’ requested
      rate adjustment mechanisms for electric infrastructure investments. As an
      alternative to the Ameren Illinois Utilities’ requested decoupling of
      natural gas revenues from sales volumes, the ICC order approved an
      increase in the percentage of costs to be recovered through fixed
      non-volumetric residential and commercial customer charges to 80% from
      53%.The ICC
      also approved an increase in the Supply Cost Adjustment (SCA) factors for
      the Ameren Illinois Utilities. The SCA is a charge applied only to the
      bills of customers who take their power supply from the Ameren Illinois
      Utilities. The change in the SCA factors is expected to result in
      increased electric revenues of $9.5
      million per year in the aggregate (CIPS -  $2.6 million, CILCO -
      $1.6 million, and IP - $5.3 million) covering the increased cost of
      administering the Ameren Illinois Utilities’ power supply
      responsibilities. In its pending electric rate case, UE is requesting the
      MoPSC approve implementation of a fuel and purchased power cost
      recovery mechanism and a mechanism that would permit timely cost recovery
      of vegetation management and infrastructure inspection and repair costs.
      The MoPSC staff opposed UE’s request to implement a fuel and
      purchased power cost recovery mechanism in direct testimony filed in
      August 2008.
 ·
              Average
      residential electric rates for CIPS, CILCO and IP increased significantly
      following the expiration of a rate freeze at the end of 2006. Electric
      rates rose because of the increased cost of power purchased on behalf of
      the Ameren Illinois Utilities’ customers and an increase
      in
   91
   
 Ameren
              
              
              CIPS
              
              
              CILCO
                (Illinois
                Regulated)
              
              
              IP
              
              
              Genco
              
              
              CILCO
                (AERG)2008(a)
              
              $
              12.2
              
              
              $
              1.9
              
              
              $
              0.9
              
              
              $
              2.7
              
              
              $
              4.6
              
              
              $
              2.12009(a)
              
              
              25.4
              
              
              
              3.6
              
              
              
              1.8
              
              
              
              4.8
              
              
              
              10.5
              
              
              
              4.72010(a)
              
              
              2.0
              
              
              
              0.3
              
              
              
              0.1
              
              
              
              0.4
              
              
              
              0.8
              
              
              
              0.4Total
              
              $
              39.6
              
              
              $
              5.8
              
              
              $
              2.8
              
              
              $
              7.9
              
              
              $
              15.9
              
              
              $
              7.2
 
 (a)  
Estimated.
 
 ·
              In
      September 2008, the IPA filed an electric power procurement plan with the
      ICC for both the Ameren Illinois Utilities and Commonwealth Edison. The
      plan, which requires the approval of the ICC, outlines the wholesale
      products (capacity, energy swaps and renewable energy credits) that the
      IPA will procure on behalf of the Ameren Illinois Utilities for the period
      of June 1, 2009 through May 30, 2014. The products will be procured
      through a RFP process, which is expected to begin in February 2009, if the
      plan is approved. A decision is required by the ICC no later than January
      2009. The impact of the new procurement process in Illinois is
      uncertain.
 ·
              As
      part of the Illinois electric settlement agreement, the Ameren Illinois
      Utilities entered into financial contracts with Marketing Company (for the
      benefit of Genco and AERG), to lock-in energy prices for 400 to 1,000
      megawatts annually of their around-the-clock power requirements during the
      period June 1, 2008 to December 31, 2012, at then relevant market prices.
      These financial contracts do not include capacity, are not load-following
      products and do not involve the physical delivery of
    energy.
 ·
              Volatile
      power prices in the Midwest affect the amount of revenues Ameren, UE,
      Genco, CILCO (through AERG) and EEI can generate by marketing power into
      the wholesale and spot markets and influence the cost of power purchased
      in the spot markets.
 ·
              The
      availability and performance of UE’s, Genco’s, AERG’s and EEI’s electric
      generation fleet can materially impact their revenues. Genco and AERG are
      seeking to raise the equivalent availability and capacity factors of their
      power plants over the long-term through greater investments and a process
      improvement program. The Non-rate-regulated Generation segment expects to
      generate 31 million megawatthours of baseload power in 2008 (Genco - 16
      million, AERG - 7 million, EEI - 8 million), 33 million megawatthours
      in 2009 (Genco - 17 million, AERG - 8 million, EEI - 8 million)
      and 30 million megawatthours in 2010 (Genco - 15 million, AERG - 7
      million, EEI - 8 million).
 ·
              All
      but 5 million megawatthours of Genco’s and AERG’s pre-2006 wholesale and
      retail electric power supply agreements expired during 2006. In 2007, 1
      million megawatthours of these agreements, which had an average embedded
      selling price of $35 per megawatthour, expired. Another 2 million
      contracted megawatthours will expire by the end of 2008, which have an
      average embedded selling price of $33 per megawatthour. These agreements
      are being replaced with market-based
sales.
 ·
              The
      marketing strategy for the Non-rate-regulated Generation segment is to
      optimize generation output in a low risk manner to minimize volatility of
      earnings and cash flow, while seeking to capitalize on its low-cost
      generation fleet to provide solid, sustainable returns. To accomplish this
      strategy, the Non-rate-regulated Generation segment has established hedge
      targets for near-term years. Through a mix of physical and financial sales
      contracts, Marketing Company targets to hedge Non-rate-regulated
      Generation’s expected output by 80% to 90% for the following year, 50% to
      70% for two years out, and 30% to 50% for three years
  out.
 ·
              As
      of October 31, 2008, Marketing Company had sold approximately 98%, 85%,
      and 50% of Non-rate regulated Generation’s expected generation in 2008,
      2009, and 2010, respectively.
 ·
              The
      future development of ancillary services and capacity markets in MISO
      could increase the electric margins of UE, Genco, AERG and EEI. Ancillary
      services are services necessary to support the transmission of energy from
      generation resources to loads while maintaining reliable operation of the
      transmission provider’s system. MISO is currently in the process of
      developing a centralized regional wholesale ancillary services market,
      which is expected to begin in January 2009. We expect Non-rate-regulated
      Generation’s ancillary services market revenues to increase to $15
      million in 2008 from $5 million realized in 2007. Ancillary services
      market revenues are allocated to Genco and AERG in accordance with their
      power supply agreements with Marketing
Company.
 ·
              We
      expect MISO will begin development of a capacity market once its ancillary
      services market is in place. A capacity market allows participants to
      purchase or sell capacity products that meet reliability requirements. We
      expect demand for capacity to strengthen from current levels because of
      improving market liquidity and decreasing actual reserve margins in MISO.
      Non-rate-regulated Generation’s capacity revenues are expected
  92
  to
increase to approximately $40 million in 2008 from $25 million in 2007. EEI
receives payment for 100% of its capacity sales under its power supply agreement
with Marketing Company. Capacity revenues are allocated to Genco and AERG based
on their generation in accordance with their power supply agreements with
Marketing Company.
 ·
              Future
      energy efficiency programs developed by UE, CIPS, CILCO and IP and others
      could also result in reduced demand for our electric generation and our
      electric and gas transmission and distribution
  services.
 
 Fuel
and Purchased Power
 
 ·
              In
      2007, 84% of Ameren’s electric generation (UE - 76%, Genco - 96%, AERG -
      99%, EEI - 100%) was supplied by coal-fired power plants. About 94% of the
      coal used by these plants (UE - 97%, Genco - 88%, AERG - 92%, EEI - 100%)
      was delivered by railroads from the Powder River Basin in Wyoming. In the
      past, deliveries from the Powder River Basin have been restricted because
      of rail maintenance, weather, and derailments. In June and early July
      2008, severe Midwest flooding disrupted rail deliveries. However, as of
      September 30, 2008, coal inventories for UE, Genco, AERG and EEI were
      adequate and in excess of historical levels. Disruptions in coal
      deliveries could cause UE, Genco, AERG and EEI to pursue a strategy that
      could include reducing sales of power during low-margin periods, buying
      higher-cost fuels to generate required electricity, and purchasing power
      from other sources.
 ·
              Genco
      is incurring incremental fuel costs in 2008 and 2009 to replace coal from
      an Illinois mine that was prematurely closed by its owner at the end of
      2007. A settlement agreement with the coal mine owner was reached in June
      2008 that fully reimbursed Genco, in the form of a lump-sum payment of $60
      million, for increased costs for coal and transportation that it is
      incurring in 2008 ($33 million) and expects to incur in 2009 ($27
      million). Since the entire settlement was recorded in 2008 earnings,
      Ameren’s and Genco’s earnings in 2009 will be lower than they otherwise
      would have been.
 ·
              Ameren’s
      fuel costs (including transportation) are expected to increase in 2008 and
      beyond. See Item 3 - Quantitative and Qualitative Disclosures about Market
      Risk of this report for additional information about the percentage of
      fuel and transportation requirements that are price-hedged for 2008
      through 2012.
 
 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. UE has settled all
      state and federal issues associated with the December 2005 Taum Sauk
      incident. In addition, UE received approval from FERC to rebuild the upper
      reservoir at its Taum Sauk plant and is in the process of rebuilding the
      facility. The estimated cost to rebuild the upper reservoir is in the
      range of $480 million. UE expects the Taum Sauk plant to be out of service
      through early 2010. UE believes that substantially all damages and
      liabilities caused by the breach, including costs related to the
      settlement agreement with the state of Missouri, the cost of rebuilding
      the plant, and the cost of replacement power, up to $8 million annually,
      will be covered by insurance. Insurance will not cover lost electric
      margins and penalties paid to FERC. 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 is engaged in litigation initiated by
      certain private parties. We are unable to predict the timing or outcomes
      of this litigation, or its possible effect on UE’s results of operation,
      financial position, or liquidity. See Note 2 - Rate and Regulatory Matters
      and Note 9 - Commitments and Contingencies to our financial statements
      under Part I, Item 1, of this report for a further discussion of Taum Sauk
      matters.
 ·
              UE's
      Callaway nuclear plant had a 28 day scheduled refueling and maintenance
      outage during the fourth quarter of 2008.  UE’s Callaway nuclear
      plant’s next scheduled refueling and maintenance outage is in the spring
      of 2010. During a scheduled 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 at our
      other facilities. Insurance premiums may also increase as a result of
      insurance market conditions and loss experience, among other
      things.
 
 Other
 
 ·
              As
      required by the MoPSC, UE filed a study in November 2007 with the MoPSC
      evaluating the costs and benefits of
      UE’s participation in MISO. UE’s filing noted that there were a number of
      uncertainties associated with the cost-benefit study, including issues
      associated with the UE-MISO service agreement. In June 2008, a stipulation
      and agreement among UE, the MoPSC staff, MISO and other parties to the
      proceeding was filed with the MoPSC, which provides for UE’s continued,
      conditional MISO participation through April 30, 2012. The stipulation and
      agreement provides UE the right to seek permission from the MoPSC for
      early withdrawal from MISO if UE determines that sufficient progress
      toward mitigating some of the continuing uncertainties respecting its MISO
      participation is not being made. In September 2008, the MoPSC issued
      an order approving the stipulation and
      agreement.
   93
  ·
              A
      ballot initiative was passed by Missouri voters in November 2008 that
      created a renewable energy portfolio requirement.  UE and other
      Missouri investor-owned utilities will be required to purchase or generate
      electricity from renewable energy sources equaling at least 2% of native
      load sales by 2011, with that percentage increasing in subsequent years to
      at least 15% by 2021, subject to a 1% limit on customer rate impacts. At
      least 2% of each portfolio requirement must be derived from solar
      energy. Detailed rules will need to be issued by the MoPSC. UE has
      and is continuing to study the possible impacts of this renewable
      energy requirement, but we expect that any related costs or investments
      would ultimately be recovered in
rates.
 
 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
nonderivative, 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. The following discussion of our risk management activities includes
forward-looking statements that involve risks and uncertainties. Actual results
could differ materially from those projected in the forward-looking statements.
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 and pursue market opportunities within
prudent risk parameters. Our risk management policies are set by a risk
management steering committee, which is composed 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 Form 10-K. See Item 7A under
Part II of the 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, 2008:
 
 Interest
      Expense
              
              
              Net
      Income(a)Ameren
              
              $
              16
              
              
              $
              (10
              )UE
              
              
              2
              
              
              
              (1
              )CIPS
              
              
              1
              
              
              (b
              )Genco
              
              
              -
              
              
              
              -CILCORP
              
              
              7
              
              
              
              (4
              )CILCO
              
              
              5
              
              
              
              (3
              )IP
              
              
              3
              
              
              
              (2
              )
 
 (a)
              Calculations
      are based on an effective tax rate of
38%.
 (b)
              Less
      than $1 million
 
 The
estimated changes above do 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.
 
 94
 
 Insured
Auction-Rate Tax-exempt Bonds
 
 Certain
auction-rate tax-exempt environmental improvement and pollution control revenue
bonds previously issued for the benefit of UE, CIPS, CILCO and IP through
governmental authorities were insured by “monoline” bond insurers. See Note 5 -
Long-term Debt and Equity Financings under Part II, Item 8 of the Form 10-K for
a description and details of this indebtedness. As a result of developments in
the capital markets with respect to residential mortgage-backed securities and
collateralized debt obligations, the credit rating agencies downgraded the
monoline bond insurers’ credit ratings due to their insuring of such securities.
As a result, our insured auction-rate bonds were similarly downgraded. We
experienced higher interest expense and/or “failed auctions” with respect to a
portion of our auction-rate bonds. According to press reports, many other series
of auction-rate securities similarly experienced “failed auctions.”
 
 To mitigate the effect of these
credit ratings downgrades and the resulting impact on the interest rates of our
auction-rate tax-exempt environmental improvement and pollution control revenue
bonds, we redeemed all of UE’s, CIPS’, CILCO’s and IP’s outstanding auction-rate
bonds except for UE’s 1992 Series and 1998 Series A, B and C bonds, which had an
aggregate balance of $207 million at September 30, 2008, and interest rates
ranging from 2.678% to 8.54% during the three months ended September 30, 2008
(2.678% to 8.54% during the nine months ended September 30, 2008). In April
2008, UE and IP issued senior secured notes in the principal amount of $250
million and $337 million, respectively, to refinance their auction-rate
indebtedness. See Note 4 - Long-term Debt and Equity Financings under Part I,
Item 1 of this report for a description of these redemptions and
refinancings.
 
 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. In 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 receivable and executory contracts with market risk exposures.
The risk associated with trade receivables is mitigated by the large number of
customers in a broad range of industry groups who make up our customer
base.
 
 The 2007
increase in electric rates in Illinois, and a related increase in extended
payment plan arrangements, resulted in an increase in the Ameren Illinois
Utilities’ past-due accounts receivable balances during 2007 and the first
quarter of 2008. Such past-due balances have improved during the second and
third quarters of 2008, primarily as a result of enhanced collection efforts and
an increase in the volume of write-offs of past-due balances deemed
uncollectible. The Ameren Illinois Utilities will continue to monitor the impact
of increased electric rates on customer collections and make adjustments to
their allowances for doubtful accounts, as deemed necessary, to ensure that such
allowances are adequate to cover estimated uncollectible customer account
balances.
 
 At
September 30, 2008, no nonaffiliated customer represented more than 10%, in the
aggregate, of our accounts receivable. Our revenues are primarily derived from
sales or delivery of electricity and natural gas to customers in Missouri and
Illinois. UE, CIPS, Genco, CILCO, AERG, IP, AFS and Marketing Company may have
credit exposure associated with interchange or wholesale purchase and sale
activity with nonaffiliated companies. At September 30, 2008, UE’s, CIPS’,
Genco’s, CILCO’s, AERG’s, IP’s, AFS’ and Marketing Company’s combined credit
exposure to nonaffiliated non-investment-grade trading counterparties was $1
million, net of collateral (2007 - less than $1 million). 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 lease. We estimate our credit exposure to
MISO associated with the MISO Day Two Energy Market to be $64 million
at   September 30, 2008 (2007 - $32 million).
 
 The Ameren Illinois Utilities will be
exposed to credit risk in the event of nonperformance by the parties
contributing to the Illinois comprehensive rate relief and assistance programs
under the Illinois electric settlement agreement, which provides $488 million in
rate relief over a four-year period that commenced in 2007 to certain electric
customers of the Ameren Illinois Utilities. Under funding agreements among the
parties contributing to the rate relief and assistance programs, at the end of
each month, the Ameren Illinois Utilities will bill the participating generators
for their proportionate share of that month’s rate relief and assistance, which
is due in 30 days, or drawn from the funds provided by the generators’ escrow.
See Note 2 - Rate and Regulatory Matters to our financial statements under Part
I, Item 1 of this report for additional information.
 
 Equity
Price Risk
 
 Our costs
of providing defined benefit retirement and
  95
  postretirement
benefit plans are dependent upon 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 or regulatory assets, and in the
amount of cash required to be contributed to the plans.
 
 Foreign
Currency Risk
 
 Ameren
and UE are exposed to foreign currency exchange risk from UE’s procurement
agreement related to construction of a potential new nuclear plant. This
agreement provides a fixed price for heavy forgings as well as consulting
services to aid with design certification. The agreement requires UE to pay
for goods and services rendered in Euros. UE uses foreign currency forward
contracts for the purchase of Euros to mitigate the impact of changes in foreign
currency exchange rates, which could affect the amount of U.S. dollars required
to satisfy the obligation denominated in Euros. To the extent the value of
the U.S. dollar versus the Euro declines, the effect would be reflected in
construction work in process within property and plant, net, and subject to
routine depreciation and impairment considerations.
  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. Genco, AERG and EEI also seek to sell
power forward to wholesale, municipal and industrial customers to limit exposure
to changing prices. 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). However, a portion of the generation capacity of UE, Genco,
AERG and EEI is not contracted through physical or financial hedge arrangements
and is therefore exposed to volatility in market prices.
 
 The following table shows how Ameren’s
cumulative earnings might decrease if power prices were to decrease by 1% on
unhedged economic generation for the remainder of 2008 through
2010:
 
 Net Income(a)Ameren(b)
              $     (12)UE
              (5)Genco
              (3)CILCO
      (AERG)
              (1)EEI
              (5)
 
 (a)
              Calculations
      are based on an effective tax rate of
38%.
 (b)
              Includes
      amounts for Ameren registrant and nonregistrant subsidiaries and
      intercompany eliminations.
 
 Ameren
also uses its portfolio management and trading capabilities both to manage risk
and to deploy risk capital to generate additional returns. Due to our physical
presence in the market, we are able to identify and pursue opportunities which
can generate additional returns through portfolio management and trading
activities. All of this activity is performed within a controlled risk
management process. We establish value at risk (VaR) and stop-loss limits that
are intended to prevent any material negative financial impact.
 
 On
September 15, 2008, Lehman filed for protection under Chapter 11 of the federal
Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New
York. At that time, UE, CIPS, Genco, IP, Marketing Company and AFS were
counterparties with Lehman Brothers Commodity Services Inc. (Lehman Commodity
Services) and Eagle Energy Partners I, LP (Eagle Energy), subsidiaries of
Lehman, in energy commodity transactions that support their utility and
generation businesses. The obligations of Lehman Commodity Services and
Eagle Energy are guaranteed by Lehman, and the Lehman bankruptcy filing gives
UE, CIPS, Genco, IP, Marketing Company and AFS the right to terminate any open
transactions. As of October 31, 2008, Ameren’s and its subsidiaries’ direct
exposure to Lehman Commodity Services and Eagle Energy, based on existing
transactions and current market prices, was estimated to be less than $1 million
before taxes, collectively.
 
 Similar
techniques are used to manage risks associated with changing prices of fuel for
generation. Most UE, Genco, AERG and EEI fuel supply contracts are physical
forward contracts. UE, Genco, AERG and EEI do not have a provision similar to
the PGA clause for electric operations, so UE, Genco, AERG and EEI have entered
into long-term contracts with various suppliers to purchase coal and nuclear
fuel to manage their exposure to fuel prices. The coal hedging strategy is
intended to secure a reliable coal supply while reducing exposure to commodity
price volatility. Price and volumetric risk mitigation is accomplished primarily
through periodic bid procedures, whereby the amount of coal purchased is
determined by the current market prices and the minimum and maximum coal
purchase guidelines for the given year. We generally purchase coal up to five
years in advance, but we may purchase coal beyond five years to take advantage
of favorable deals or market conditions. The strategy also allows for the
decision not to purchase coal to avoid unfavorable market
conditions.
 
 Transportation
costs for coal and natural gas can be a significant portion of fuel costs. We
typically hedge coal transportation forward to provide supply certainty and to
mitigate transportation price volatility. Natural gas transportation expenses
for Ameren’s gas distribution utility companies and the gas-fired generation
units of UE, Genco, AERG and EEI are regulated by FERC through approved tariffs
governing the rates, terms and conditions of transportation and storage
services. Certain firm transportation and storage capacity agreements held by
 96
    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 no
generation, that are price-hedged over the remainder of 2008 through 2012, as of
September 30, 2008. The projected required supply of these commodities could be
significantly impacted by changes in our assumptions for such matters as
customer demand of our electric generation and our electric and natural gas
distribution services, generation output, and inventory levels, among other
matters.
 
 2008
              
              
              2009
              
              
              2010
      - 2012Ameren:Coal
              100
              %
              
              98
              %
              
              47
              %Coal
      transportation
              100
              
              
              94
              
              
              28Nuclear
      fuel
              100
              
              
              100
              
              
              88Natural
      gas for
      generation
              84
              
              
              14
              
              
              1Natural
      gas for
      distribution(a)
              75
              
              
              22
              
              
              7Purchased
      power for Illinois
      Regulated(b)
              97
              
              
              80
              
              
              51UE:Coal
              100
              %
              
              99
              %
              
              50
              %Coal
      transportation
              100
              
              
              96
              
              
              31Nuclear
      fuel
              100
              
              
              100
              
              
              88Natural
      gas for
      generation
              79
              
              
              16
              
              
              1Natural
      gas for
      distribution(a)
              73
              
              
              30
              
              
              9CIPS:Natural
      gas for
      distribution(a)
              82
              %
              
              24
              %
              
              9
              %Purchased
      power(b)
              97
              
              
              80
              
              
              51Genco:Coal
              99
              %
              
              97
              %
              
              42
              %Coal
      transportation
              100
              
              
              98
              
              
              -Natural
      gas for
      generation
              100
              
              
              -
              
              
              -CILCORP/CILCO:Coal
      (AERG)
              99
              %
              
              91
              %
              
              41
              %Coal
      transportation
      (AERG)
              100
              
              
              70
              
              
              -Natural
      gas for
      distribution(a)
              80
              
              
              20
              
              
              5Purchased
      power(b)
              97
              
              
              80
              
              
              51IP:Natural
      gas for
      distribution(a)
              69
              %
              
              21
              %
              
              6
              %Purchased
      power(b)
              97
              
              
              80
              
              
              51EEI:Coal
              100
              %
              
              99
              %
              
              49
              %Coal
      transportation
              100
              
              
              100
              
              
              100
  (a)
              Represents
      the percentage of natural gas price hedged for peak winter season of
      November through March. The year 2008 represents November 2008 through
      March 2009. The year 2009 represents November 2009 through March 2010.
      This continues each successive year through March
  2013.
 (b)
              Represents
      the percentage of purchased power price-hedged for fixed-price residential
      and small commercial customers with less than 1 megawatt of demand.
      Includes the financial contracts that the Ameren Illinois Utilities
      entered into with Marketing Company, effective August 28, 2007, and
      additional financial contracts entered into with Marketing Company and
      other suppliers, effective March 20, 2008, as part of the Illinois
      electric settlement agreement. Larger customers are purchasing power from
      the competitive markets. See Note 2 - Rate and Regulatory Matters and Note
      9 - Commitments and Contingencies under Part I, Item 1, of this report for
      a discussion of these financial contracts and the new power procurement
      process pursuant to the Illinois electric settlement
      agreement.
  97
 The
following table shows how our cumulative fuel expense might increase and how our
cumulative 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 period 2008 through 2012.
 
 Coal
              
              
              TransportationFuel
                Expense
              
              
              Net
                Income(a)
              
              
              Fuel
                Expense
              
              
              Net
                Income(a)Ameren(b)
              
              $
              31
              
              
              $
              (19
              )
              
              $
              18
              
              
              $
              (11
              )UE
              
              
              12
              
              
              
              (7
              )
              
              
              10
              
              
              
              (6
              )Genco
              
              
              12
              
              
              
              (7
              )
              
              
              6
              
              
              
              (4
              )CILCORP
              
              
              5
              
              
              
              (3
              )
              
              
              2
              
              
              
              (1
              )CILCO
      (AERG)
              
              
              5
              
              
              
              (3
              )
              
              
              2
              
              
              
              (1
              )EEI
              
              
              2
              
              
              
              (1
              )
              
              (c
              )
              
              (c
              )
 
 (a)
              Calculations
      are based on an effective tax rate of
38%.
 (b)
              Includes
      amounts for Ameren registrant and nonregistrant
    subsidiaries.
 (c)
              Amount
      less than $1 million.
 
 In
addition, coal and coal transportation costs are sensitive to the price of
diesel fuel as a result of rail freight fuel surcharges. If diesel fuel costs
were to increase or decrease by $0.25
per gallon, Ameren’s fuel expense could increase or decrease by $13 million
annually (UE - $7 million, Genco - $3 million, AERG -
$1 million and EEI - $2 million). As of September 30, 2008,
Ameren had price-hedged approximately 100% of expected fuel surcharges in 2008
and 2009.
 
 In the
event of a significant change in coal prices, UE, Genco, AERG and EEI 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.
 See Note
9 - 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.
 
 Fair
Value of Contracts
 
 Most of
our commodity contracts qualify for treatment as normal purchases and sales. We
use derivatives principally to manage the risk of changes in market prices for
natural gas, fuel, electricity, FTRs and emission allowances. 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, 2008. We use various methods to determine the fair value of
our contracts. In accordance with SFAS No. 157 hierarchy levels, our sources
used to determine the fair value of these contracts were active quotes (Level
1), inputs corroborated by market data (Level 2), and other modeling and
valuation methods that are not corroborated by market data (Level 3). All of
these contracts have maturities of less than five years. See Note 7 - Fair Value
Measurements to our financial statements under Part I, Item 1, of this report
for further information regarding the methods used to determine the fair value
of these contracts.
 
 Ameren(a)
              
              
              UE
              
              
              CIPS
              
              
              Genco
              
              
              CILCORP/
                CILCO
              
              
              IPThree
      MonthsFair
      value of contracts at beginning of period, net
              
              $
              123
              
              
              $
              11
              
              
              $
              112
              
              
              $
              4
              
              
              $
              77
              
              
              $
              195Contracts
      realized or otherwise settled during theperiod
              
              
              (13
              )
              
              
              (6
              )
              
              
              (1
              )
              
              
              (1
              )
              
              
              2
              
              
              
              -Changes
      in fair values attributable to changes in valuation
                technique
      and assumptions
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Fair value of new
      contracts entered into during the period
              
              
              2
              
              
              
              24
              
              
              
              (17
              )
              
              
              (2
              )
              
              
              (12
              )
              
              
              (18
              )Other
      changes in fair value
              
              
              (57
              )
              
              
              2
              
              
              
              (106
              )
              
              
              (2
              )
              
              
              (78
              )
              
              
              (196
              )Fair
      value of contracts outstanding at end ofperiod,
      net
              
              $
              55
              
              
              $
              31
              
              
              $
              (12
              )
              
              $
              (1
              )
              
              $
              (11
              )
              
              $
              (19
              )Nine
      MonthsFair
      value of contracts at beginning of period, net
              
              $
              13
              
              
              $
              7
              
              
              $
              38
              
              
              $
              (4
              )
              
              $
              21
              
              
              $
              55Contracts
      realized or otherwise settled duringthe
      period
              
              
              (45
              )
              
              
              (12
              )
              
              
              (4
              )
              
              
              4
              
              
              
              (5
              )
              
              
              (4
              )Changes
      in fair values attributable to changes invaluation
                technique
      and assumptions
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Fair value of new
      contracts entered into during the period
              
              
              38
              
              
              
              21
              
              
              
              (10
              )
              
              
              (1
              )
              
              
              (10
              )
              
              
              (15
              )Other
      changes in fair value
              
              
              49
              
              
              
              15
              
              
              
              (36
              )
              
              
              -
              
              
              
              (17
              )
              
              
              (55
              )Fair
      value of contracts outstanding at end ofperiod,
      net
              
              $
              55
              
              
              $
              31
              
              
              $
              (12
              )
              
              $
              (1
              )
              
              $
              (11
              )
              
              $
              (19
              )
 
 (a)
              Includes
      amounts for Ameren registrant and nonregistrant subsidiaries and
      intercompany eliminations.
  98
  The
following table presents maturities of derivative contracts as of September 30,
2008, based on the hierarchy levels used to determine the fair value of the
contracts:
 
 Sources
      of Fair Value
              
              Maturity
                Less
      than
                1
      Year
              
              
              Maturity
                1-3
      Years
              
              
              Maturity
                4-5
      Years
              
              
              Maturity
      in
                Excess
      of
                5
      Years
              
              
              Total
                Fair
      ValueAmeren:Level
      1
              
              $
              (6
              )
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              (6
              )Level
      2(a)
              
              
              20
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              20Level
      3(b)
              
              
              14
              
              
              
              27
              
              
              
              -
              
              
              
              -
              
              
              
              41Total
              
              $
              28
              
              
              $
              27
              
              
              $
              -
              
              
              $
              -
              
              
              $
              55UE:Level
      1
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -Level
      2(a)
              
              
              10
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              10Level
      3(b)
              
              
              18
              
              
              
              3
              
              
              
              -
              
              
              
              -
              
              
              
              21Total
              
              $
              28
              
              
              $
              3
              
              
              $
              -
              
              
              $
              -
              
              
              $
              31CIPS:Level
      1
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -Level
      2(a)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Level
      3(b)
              
              
              (16
              )
              
              
              4
              
              
              
              -
              
              
              
              -
              
              
              
              (12
              )Total
              
              $
              (16
              )
              
              $
              4
              
              
              $
              -
              
              
              $
              -
              
              
              $
              (12
              )Genco:Level
      1
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -Level
      2(a)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Level
      3(b)
              
              
              (1
              )
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              (1
              )Total
              
              $
              (1
              )
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              (1
              )
 CILCORP/CILCO:Level
      1
              
              $
              (3
              )
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              (3
              )Level
      2(a)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Level
      3(b)
              
              
              (11
              )
              
              
              3
              
              
              
              -
              
              
              
              -
              
              
              
              (8
              )Total
              
              $
              (14
              )
              
              $
              3
              
              
              $
              -
              
              
              $
              -
              
              
              $
              (11
              )IP:Level
      1
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -
              
              
              $
              -Level
      2(a)
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -
              
              
              
              -Level
      3(b)
              
              
              (28
              )
              
              
              8
              
              
              
              1
              
              
              
              -
              
              
              
              (19
              )Total
              
              $
              (28
              )
              
              $
              8
              
              
              $
              1
              
              
              $
              -
              
              
              $
              (19
              )
 
 (a)
              Principally
      fixed price for floating over-the-counter power swaps, power forwards and
      fixed price for floating over-the-counter natural gas
    swaps.
 (b)
              Principally
      coal and SO2
      option values based on a Black-Scholes model that includes information
      from external sources and our estimates. Also includes interruptible power
      forward and option contract values based on our
  estimates.
 
 ITEM
4 and ITEM 4T. CONTROLS AND PROCEDURES.
 
 (a)
              Evaluation
      of Disclosure Controls and
Procedures
 
 As of
September 30, 2008, evaluations were performed, under the supervision and with
the participation of management, including the principal executive officer and
principal financial officer of each of the Ameren Companies, of the
effectiveness of the design and operation of such registrant’s disclosure
controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the
Exchange Act). Based upon those evaluations, the principal executive officer and
principal financial officer of each of the Ameren Companies have concluded that
such disclosure controls and procedures are effective to provide assurance that
information required to be disclosed in such registrant’s reports filed or
submitted under the Exchange Act is recorded, processed, summarized and reported
within the time periods specified in the SEC’s rules and forms and such
information is accumulated and communicated to its management, including its
principal executive and principal financial officers, to allow timely decisions
regarding required disclosure.
 
 (b)
              Change
      in Internal Controls
 
 There has
been no change in any of 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, each of their internal control
over financial reporting.
   99
 
 PART
II. OTHER INFORMATION
 
 ITEM
1. LEGAL PROCEEDINGS.
 
 We are
involved in legal and administrative proceedings before various courts and
agencies with respect to matters that arise in the ordinary course of business,
some of which involve sub­stantial amounts of money. We believe that the
final disposition of these proceedings, except as otherwise disclosed in this
report, will not have a material adverse effect on our results of operations,
financial position, or liquidity. Risk of loss is mitigated, in some cases, by
insurance or contractual or statutory indemnification. We believe that we have
established appropriate reserves for potential losses.
 
 In
October 2008, Caterpillar Inc., in conjunction with other industrial customers
as a coalition, filed a request with the ICC for rehearing of its September 2008
consolidated order in the November 2007 rate cases filed by CIPS, CILCO and IP
with the ICC to modify their electric and natural gas delivery service rates.
Caterpillar Inc., in its filings, asked the ICC to rehear its rulings with
respect to return on equity and rate design. Douglas R. Oberhelman is
an officer of Caterpillar Inc. and a member of the board of directors of
Ameren. Mr. Oberhelman did not participate in Ameren’s board and committee
deliberations relating to these matters.
 
 In August
and October 2008, The Boeing Company, in conjunction with other industrial
customers as a coalition, filed testimony in the MoPSC proceeding relating to
UE’s pending request for an increase in its electric service rates. The Boeing
Company, in its testimony, opposed UE’s filing on issues regarding rate design,
revenue requirements, return on equity and the fuel and purchased power cost
recovery mechanism. James C. Johnson is an officer of The Boeing Company and a
member of the board
of directors of Ameren. Mr. Johnson did not participate in Ameren’s board and
committee deliberations relating to this matter.
 
 For additional information on legal and
administrative proceedings, see Note 2 - Rate and Regulatory Matters, Note 8 -
Related Party Transactions and Note 9 - Commitments and Contingencies to our
financial statements under Part I, Item 1 of this report.
 
 ITEM
1A. RISK FACTORS.
 
 The Form
10-K 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 the Form 10-K.
 
 Our
businesses are dependent on our ability to access the capital markets
successfully. We may not have access to sufficient capital in the amounts and at
the times needed.
 
 The
global capital and credit markets have experienced extreme volatility and
disruption in 2008, and in particular, since early September. Several factors
have driven this situation, including deteriorating global economic conditions
and the weakened financial condition of major financial institutions, as
evidenced by the bankruptcy filing of Lehman. The extreme disruption in the
capital markets has limited companies’, including the Ameren Companies’, ability
to access the capital and credit markets to support their operations and
refinance debt and has led to higher financing costs compared to recent years.
At September 30, 2008, the Ameren Companies had in place revolving bank credit
facilities aggregating $2.15 billion. In total, eighteen banks, including a
Lehman subsidiary, participate in these credit facilities. Due to the Lehman
bankruptcy, the size of our credit facilities was effectively reduced by up to
$121 million at September 30, 2008.
 
 We use
short-term and long-term capital markets as a significant source of liquidity
and funding for capital requirements not satisfied by our operating cash flow,
including requirements related to future environmental compliance. As a result
of rising costs and increased capital and operations and maintenance
expenditures, coupled with near-term regulatory lag, we expect to need more
short-term and long-term debt financing. The inability to raise capital on
favorable terms, particularly during times of uncertainty in the capital
markets, could negatively affect our ability to maintain and to expand our
businesses. Our current credit ratings cause us to believe that we will continue
to have access to the capital markets. However, events beyond our control, such
as the collapse of the subprime mortgage market and the extreme volatility and
disruption in global capital and credit markets in 2008, may create uncertainty
that could increase our cost of capital or impair our ability to access the
capital markets, including the ability to draw on our bank credit facilities.
Certain of the Ameren Companies rely, in part, on Ameren for access to capital.
Circumstances that limit Ameren’s access to capital, including those relating to
its other subsidiaries, could impair its ability to provide those Ameren
Companies with needed capital.
  100
 ITEM
2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.
 
 The
following table presents CILCO’s purchases of equity securities reportable under
Item 703 of Regulation SK:
 
 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
      ProgramsJuly
      1 - July 31,
      2008
              165,000
              $    100.00
              -
              -August
      1 - August 31,
      2008
              -
              -
              -
              -September
      1 - September 30, 2008
              -
              -
              -
              -Total
              165,000
              $    100.00
              -
              -
 
 (a)     CILCO
redeemed these remaining shares of its 5.85% Class A preferred stock to complete
the mandatory sinking fund redemption requirement for this series of preferred
stock. 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, 2008 period.
  ITEM
6. EXHIBITS.
 
 The
documents listed below are being filed or have previously been filed on behalf
of the Ameren Companies and are incorporated herein by reference from the
documents indicated and made a part hereof. Exhibits not identified as
previously filed are filed herewith.
 
 Exhibit
      Designation
              Registrant(s)
              Nature
      of Exhibit
              Previously
      Filed as Exhibit to:By-Laws3.1(ii)
              Ameren
              By-Laws
      of Ameren as amended October 10, 2008
              October
      14, 2008 Form 8-K, Exhibit 3.1(ii), File No. 1-14756Instruments
      Defining Rights of Securities Holders, Including
Indentures4.1
              Ameren
                IP
              IP
      Company Order dated October 23, 2008, establishing the 9.75% Senior
      Secured Notes due 2018 (including forms of global and definitive
      notes)
              October
      23, 2008 Form 8-K, Exhibit 4.2, File No. 1-30044.2
              Ameren
                IP
              Supplemental
      Indenture dated as of October 1, 2008 by and between IP and The Bank of
      New York Mellon Trust Company, N.A., as Trustee under The General Mortgage
      Indenture and Deed of Trust dated as of November 1, 1992, related to IP
      Mortgage Bonds, Senior Notes Series DD securing IP 9.75% Senior Secured
      Notes due 2018.
              October
      23, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004Material
      Contracts10.1
              Ameren
              *
      Summary Sheet of Ameren Corporation Non-Management Director Compensation
      revised on August 8, 2008Statement
      re: Computation of Ratios12.1
              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
      Requirements
   101
  Exhibit
      Designation
              Registrant(s)
              Nature
      of Exhibit
              Previously
      Filed as Exhibit to:
 12.4
              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
      Requirements12.7
              IP
              IP’s
      Statement of Computation of Ratio of Earnings to Fixed Charges and
      Combined Fixed Charges and Preferred Stock Dividend
      RequirementsRule 13a-14(a) / 15d-14(a)
      Certifications31.1
              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
      Ameren
 31.3
              UE
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Executive Officer of
      UE31.4
              UE
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Financial Officer of
      UE31.5
              CIPS
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Executive Officer of
      CIPS31.6
              CIPS
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Financial Officer of
      CIPS31.7
              Genco
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Executive Officer of
      Genco31.8
              Genco
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Financial Officer of
      Genco31.9
              CILCORP
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Executive Officer of
      CILCORP31.10
              CILCORP
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Financial Officer of
      CILCORP31.11
              CILCO
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Executive Officer of
      CILCO31.12
              CILCO
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Financial Officer of
      CILCO31.13
              IP
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Executive Officer of
      IP31.14
              IP
              Rule
      13a-14(a)/15d-14(a) Certification of Principal Financial Officer of
      IPSection
      1350 Certifications32.1
              Ameren
              Section
      1350 Certification of Principal Executive Officer and Principal Financial
      Officer of Ameren32.2
              UE
              Section
      1350 Certification of Principal Executive Officer and Principal Financial
      Officer of UE32.3
              CIPS
              Section
      1350 Certification of Principal Executive Officer and Principal Financial
      Officer of CIPS32.4
              Genco
              Section
      1350 Certification of Principal Executive Officer and Principal Financial
      Officer of Genco
   102
  Exhibit
      Designation
              Registrant(s)
              Nature
      of Exhibit
              Previously
      Filed as Exhibit to:
 32.5
              CILCORP
              Section
      1350 Certification of Principal Executive Officer and Principal Financial
      Officer of CILCORP32.6
              CILCO
              Section
      1350 Certification of Principal Executive Officer and Principal Financial
      Officer of CILCO32.7
              IP
              Section
      1350 Certification of Principal Executive Officer and Principal Financial
      Officer of IP
 
 *
              Management
      compensatory plan or
arrangement.
  103
  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
 SeniorVice President and
Chief Accounting
Officer
 (Principal
Accounting Officer)
 
 
 
 
 UNION
ELECTRIC COMPANY
 (Registrant)
 
  /s/ Martin J.
Lyons
 Martin
J. Lyons
 SeniorVice President and
Chief Accounting
Officer
 (Principal
Accounting Officer)
 
 
 CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
 (Registrant)
  /s/ Martin J.
Lyons
 Martin
J. Lyons
 SeniorVice President and
Chief Accounting
Officer
 (Principal
Accounting Officer)
 
 
 
 AMEREN
ENERGY GENERATING COMPANY
 (Registrant)
  /s/ Martin J.
Lyons
 Martin
J. Lyons
 SeniorVice President and
Chief Accounting
Officer
 (Principal
Accounting Officer)
    104
  CILCORP
INC.
 (Registrant)
  /s/ Martin J.
Lyons
 Martin
J. Lyons
 SeniorVice President and
Chief Accounting
Officer
 (Principal
Accounting Officer)
 
  
 
 
 CENTRAL
ILLINOIS LIGHT COMPANY
 (Registrant)
  /s/ Martin J.
Lyons
 Martin
J. Lyons
 SeniorVice President and
Chief Accounting
Officer
 (Principal
Accounting Officer)
  
 
 ILLINOIS
POWER COMPANY
 (Registrant)
  /s/ Martin J.
Lyons
 Martin
J. Lyons
 SeniorVice President and
Chief Accounting
Officer
 (Principal
Accounting Officer)
  
 
 Date:  November
10, 2008