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, 2007March 31, 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 Avenue 
 St. Louis, Missouri 63103 
 (314) 621-3222 
   
1-2967
Union Electric Company
43-0559760
 (Missouri Corporation) 
 1901 Chouteau Avenue 
 St. Louis, Missouri 63103 
 (314) 621-3222 
   
1-3672
Central Illinois Public Service Company
37-0211380
 (Illinois Corporation) 
 607 East Adams Street 
 Springfield, Illinois 62739 
 (888) 789-2477 
   
333-56594
Ameren Energy Generating Company
37-1395586
 (Illinois Corporation) 
 1901 Chouteau Avenue 
 St. Louis, Missouri 63103 
 (314) 621-3222 
   
2-95569
CILCORP Inc.
37-1169387
 (Illinois Corporation) 
 300 Liberty Street 
 Peoria, Illinois 61602 
 (309) 677-5271 
   
1-2732
Central Illinois Light Company
37-0211050
 (Illinois Corporation) 
 300 Liberty Street 
 Peoria, Illinois 61602 
 (309) 677-5271 
   
1-3004
Illinois Power Company
37-0344645
 (Illinois Corporation) 
 370 South Main Street 
 Decatur, 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 non-accelerated filer.smaller reporting company. See definitions of “accelerated filer,” “large accelerated filerfiler” and large accelerated filer“smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.

 Large Accelerated Filer
Accelerated
Filer
Non-Accelerated Filer
Smaller Reporting
Company
Ameren 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 CorporationYes(   )No(X)
Union Electric CompanyYes(   )No(X)
Central Illinois Public Service CompanyYes(   )No(X)
Ameren Energy Generating CompanyYes(   )No(X)
CILCORP Inc.Yes(   )No(X)
Central Illinois Light CompanyYes(   )No(X)
Illinois Power CompanyYes(  )No(X)


The number of shares outstanding of each registrant’s classes of common stock as of November 1, 2007,April 30, 2008, was as follows:

Ameren CorporationCommon stock, $.01 par value per share – 208,009,159209,474,844
  
Union Electric Company
Common stock, $5 par value per share, held by Ameren
Corporation (parent company of the registrant) – 102,123,834
  
Central Illinois Public Service Company
Common stock, no par value, held by Ameren
Corporation (parent company of the registrant) – 25,452,373
  
Ameren Energy Generating Company
Common stock, no par value, held by Ameren Energy
DevelopmentResources Company, LLC (parent company of the
registrant and indirect subsidiary of Ameren
Corporation) – 2,000
  
CILCORP Inc.
Common stock, no par value, held by Ameren
Corporation (parent company of the registrant) – 1,000
  
Central Illinois Light Company
Common stock, no par value, held by CILCORP Inc.
(parent company of the registrant and subsidiary of
Ameren Corporation) – 13,563,871
  
Illinois Power Company
Common stock, no par value, held by Ameren
Corporation (parent company of the registrant) – 23,000,000
 



OMISSION OF CERTAIN INFORMATION
 
OMISSION OF CERTAIN INFORMATION

Ameren Energy Generating Company and CILCORP Inc. meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this form with the reduced disclosure format allowed under that General Instruction.
 

This combined Form 10-Q is separately filed by Ameren Corporation, Union Electric Company, Central Illinois Public Service Company, Ameren Energy Generating Company, CILCORP Inc., Central Illinois Light Company, and Illinois Power Company. Each registrant hereto is filing on its own behalf all of the information contained in this quarterly report that relates to such registrant. Each registrant hereto is not filing any information that does not relate to such registrant, and therefore makes no representation as to any such information.




TABLE OF CONTENTS
 
Page
Glossary of Terms and Abbreviations ..................................................................................................................................................................................................................GLOSSARY OF TERMS AND ABBREVIATIONS.....................................................................................................................................................................................................5
  
Forward-looking Statements ...................................................................................................................................................................................................................................Statements..........................................................................................................................................................................................................................................67
  
PART I   Financial Information
 
  
Item 1.     Financial Statements (Unaudited) 
Ameren Corporation
 
Consolidated Statement of Income ................................................................................................................................................................................................8
                Consolidated Balance Sheet ...........................................................................................................................................................................................................Income...............................................................................................................................................................................................................9
Consolidated Balance Sheet..........................................................................................................................................................................................................................10
Consolidated Statement of Cash Flows ........................................................................................................................................................................................Flows.......................................................................................................................................................................................................1011
Union Electric Company
 
Consolidated Statement of Income ................................................................................................................................................................................................Income...............................................................................................................................................................................................................1112
Consolidated Balance Sheet ...........................................................................................................................................................................................................Sheet..........................................................................................................................................................................................................................1213
Consolidated Statement of Cash Flows ........................................................................................................................................................................................Flows.......................................................................................................................................................................................................1314
Central Illinois Public Service Company
 
Statement of Income ........................................................................................................................................................................................................................Income.......................................................................................................................................................................................................................................1415
Balance Sheet ...................................................................................................................................................................................................................................Sheet..................................................................................................................................................................................................................................................1516
Statement of Cash Flows ................................................................................................................................................................................................................Flows................................................................................................................................................................................................................................1617
Ameren Energy Generating Company
 
Consolidated Statement of Income ...............................................................................................................................................................................................Income...............................................................................................................................................................................................................1718
Consolidated Balance Sheet ..........................................................................................................................................................................................................Sheet..........................................................................................................................................................................................................................1819
Consolidated Statement of Cash Flows .......................................................................................................................................................................................Flows.......................................................................................................................................................................................................1920
CILCORP Inc.
 
Consolidated Statement of Income ...............................................................................................................................................................................................Income...............................................................................................................................................................................................................2021
Consolidated Balance Sheet ..........................................................................................................................................................................................................Sheet..........................................................................................................................................................................................................................2122
Consolidated Statement of Cash Flows .......................................................................................................................................................................................Flows.......................................................................................................................................................................................................2223
Central Illinois Light Company
 
Consolidated Statement of Income ...............................................................................................................................................................................................Income..............................................................................................................................................................................................................2324
Consolidated Balance Sheet ..........................................................................................................................................................................................................Sheet.........................................................................................................................................................................................................................2425
Consolidated Statement of Cash Flows .......................................................................................................................................................................................Flows.......................................................................................................................................................................................................2526
Illinois Power Company
 
Consolidated Statement of Income ..............................................................................................................................................................................................Income..............................................................................................................................................................................................................2627
Consolidated Balance Sheet .........................................................................................................................................................................................................Sheet..........................................................................................................................................................................................................................2728
Consolidated Statement of Cash Flows ......................................................................................................................................................................................Flows.......................................................................................................................................................................................................2829
  
Combined Notes to Financial Statements ...........................................................................................................................................................................................Statements....................................................................................................................................................................................................2930
  
Item 2.    Management’s Discussion and Analysis of Financial Condition and Results of Operations ....................................................................................................Operations............................................................................................................5758
Item 3.    Quantitative and Qualitative Disclosures About Market Risk .........................................................................................................................................................Risk.................................................................................................................................................................8378
Item 4.4 and
Item 4T.  Controls and Procedures ........................................................................................................................................................................................................................Procedures...............................................................................................................................................................................................................................8782
  
PART II Other Information
 
  
Item 1.    Legal Proceedings ..................................................................................................................................................................................................................................Proceedings...........................................................................................................................................................................................................................................8783
Item 1A.Risk Factors ..............................................................................................................................................................................................................................................1A. Risk Factors......................................................................................................................................................................................................................................................8883
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds .........................................................................................................................................................Proceeds.................................................................................................................................................................9183
Item 6.    Exhibits ......................................................................................................................................................................................................................................................Exhibits..............................................................................................................................................................................................................................................................9184
  
Signatures ................................................................................................................................................................................................................................................................Signatures.........................................................................................................................................................................................................................................................................9387

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. Forward-looking statements should be read with the cautionary statements and important factors included on page 6 of this Form 10-Q under the heading “Forward-looking Statements.”
 
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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 DevelopmentResources Company subsidiary that procures fuel and natural gas and manages the related risks for the Ameren Companies.
Ameren – Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.
Ameren Companies – The individual registrants within the Ameren consolidated group.
Ameren Energy – Ameren Energy, Inc., an Ameren Corporation subsidiary that is a power marketing and risk management agent for UE.
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 various non-rate-regulated subsidiaries.
CIPS – Central Illinois Public Service Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS.
CIPSCO –CIPSCO Inc., the former parent of CIPS.
CO2 – Carbon dioxide.
CT – Combustion turbine electric generation equipment used primarily for peaking capacity.
CUB – Citizens Utility Board.
Development Company – Ameren Energy Development Company, which is awas an Ameren Energy Resources Company subsidiary, and parent of Genco, Marketing Company, AFS, and AFS.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 (40% owned by UE and 40% owned by Development Company) 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.
ELPC – Environmental Law and Policy Center.
EPA – Environmental Protection Agency, a U.S. government agency.
Equivalent availability factor – A measure that indicates the percentage of time an electric power generating unit was available for service during a 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, 2006,2007, filed by the Ameren Companies with the SEC.
FSP– FASB Staff Position, which 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 DevelopmentResources Company subsidiary that operates a non-rate-regulated electric generation business in Illinois and Missouri.
Gigawatthour – One thousand megawatthours.
Heating degree-days – The summation of negative differences between the mean daily temperature and a 65- degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter space heating for residential and commercial customers.
ICC – Illinois Commerce Commission, a state agency that regulates the Illinois utility businesses and the rate-regulated operations of CIPS, CILCO and IP.
Illinois Customer Choice Law – Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which
5
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
5
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. IP SPT is a variable-interest entity, as the equity investment is not sufficient to permit IP SPT to finance its activities without additional subordinated debt.
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.
IP LLCKilowatthour– Illinois Power Securitization Limited Liability Company, which is a special-purpose Delaware limited-liability company. Under FIN 46R, Consolidation of Variable-interest Entities, IP LLC was no longer consolidated within IP’s financial statements as of December 31, 2003.
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. Pursuant to FIN 46R, IP SPT is a variable-interest entity, as the equity investment is not sufficient to permit IP SPT to finance its activities without additional subordinated debt.
JDA – The joint dispatch agreement among UE, CIPS, and Genco under which UE and Genco jointly dispatched electric generation prior to its termination on December 31, 2006.
Kilowatthour–A measure of electricity consumption equivalent to the use of 1,000 watts of power over a period of one hour.
Marketing Company –Ameren Energy Marketing Company, a DevelopmentResources Company subsidiary that markets power for Genco, AERG and EEI.
Medina Valley– AmerenEnergyMedina Valley Cogen (No. 4) LLC and its subsidiaries, all DevelopmentL.L.C., a Resources Company subsidiaries,subsidiary, which indirectly ownowns 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 all the operations of UE’s business, except for UE’s 40% interest in EEI and other non-rate-regulated activities.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 are maintained for rate-regulated and non-rate-regulated businesses. Thesebusiness are referred to as the utility money pool and the non-state-regulated subsidiary money pool, respectively.
Moody’s –Moody’s Investors Service Inc., a credit rating agency.
MoPSC – Missouri Public Service Commission, a state agency that regulates the Missouri utility business and operations of UE.
Non-rate-regulated Generation – A financial reporting segment consisting of the operations or activities of Genco, CILCORP holding company, AERG, EEI and Marketing Company.
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 non-nativenonnative load sales.
PGA – Purchased Gas Adjustment tariffs, which allow the passing through of the actual cost of natural gas to utility customers.
PUHCA 1935 – The Public Utility Holding Company Act of 1935, which was repealed effective February 8, 2006, by the Energy Policy Act of 2005 that was enacted on August 8, 2005.
PUHCA 2005– The Public Utility Holding Company Act of 2005, 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 Development Company, 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.
RTO – Regional Transmission Organization.
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.
TFN– Transitional Funding Trust Notes issued by IP SPT as allowed under the Illinois Customer Choice Law. IP must designate a portion of cash received from customer billings to pay the TFNs. The proceeds received by IP are remitted to IP SPT. The proceeds are restricted for the sole purpose of making payments of principal and interest on, and paying other fees and expenses related to, the TFNs. Since the application of FIN 46R, IP does not consolidate IP SPT. Therefore, the obligation to IP SPT appears on IP’s balance sheet.
TVAUE – Tennessee Valley Authority, a public power authority.
UE –Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated
6
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
6
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 pending UE, CIPS, CILCO and IP rate proceedings 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 thea new power procurement process in Illinois for 2008 and 2009;that began in 2008;
·  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 availability of fuel such as coal, natural gas, and enriched uranium used to produce electricity; the availability of purchased power and natural gas for distribution; and the level and volatility of future market prices for such commodities, including the ability to recover the costs for such commodities;
·  the effectiveness of our risk management strategies and the use of financial and derivative instruments;
·  prices for power in the Midwest;Midwest, including forward prices;
·  business and economic conditions, including their impact on interest rates;
·  disruptions of the capital markets or other events that make the Ameren Companies’ access to necessary capital more difficult or costly;
·  the impact of the adoption of new accounting standards and the application of appropriate technical accounting rules and guidance;
·  actions of credit rating agencies and the effects of such actions;
·  weather conditions and other natural phenomena;
·  the impact of system outages caused by severe weather conditions or other events;
·  generation plant construction, installation and performance, including costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident and 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.

 
78
PART I.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS.
 
AMEREN CORPORATION 
CONSOLIDATED STATEMENT OF INCOME 
(Unaudited) (In millions, except per share amounts) 
      
 
Three Months Ended
March 31,
 
 2008  2007 
Operating Revenues:     
Electric$1,467  $1,463 
Gas 612   561 
Total operating revenues 2,079   2,024 
Operating Expenses:       
Fuel 302   263 
Purchased power 287   373 
Gas purchased for resale 459   421 
Other operations and maintenance 423   389 
Depreciation and amortization 176   183 
Taxes other than income taxes 113   102 
Total operating expenses 1,760   1,731 
Operating Income 319   293 
Other Income and Expenses:       
Miscellaneous income 21   16 
Miscellaneous expense (4)  (5)
Total other income 17   11 
Interest Charges 100   100 
Income Before Income Taxes, Minority Interest, and       
Preferred Dividends of Subsidiaries 236   204 
Income Taxes 87   71 
Income Before Minority Interest and Preferred Dividends of Subsidiaries 149   133 
Minority Interest and Preferred Dividends of Subsidiaries 11   10 
Net Income$138  $123 
Earnings per Common Share – Basic and Diluted$0.66  $0.59 
Dividends per Common Share$0.635  $0.635 
Average Common Shares Outstanding 208.7   206.6 
        
The accompanying notes are an integral part of these consolidated financial statements.
AMEREN CORPORATION           
CONSOLIDATED STATEMENT OF INCOME           
(Unaudited) (In millions, except per share amounts)           
            
            
 
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
 
2007
  
2006
  
2007
  
2006
 
Operating Revenues:
           
Electric$
1,872
  $1,767  $
4,844
  $4,356 
Gas 
125
   143   
895
   904 
Total operating revenues 
1,997
   1,910   
5,739
   5,260 
                
Operating Expenses:
               
Fuel 
338
   277   
864
   776 
Purchased power 
419
   346   
1,106
   896 
Gas purchased for resale 
68
   84   
622
   641 
Other operations and maintenance 
427
   395   
1,249
   1,141 
Depreciation and amortization 
169
   162   
514
   485 
Taxes other than income taxes 
97
   99   
295
   302 
Total operating expenses 
1,518
   1,363   
4,650
   4,241 
                
Operating Income
 
479
   547   
1,089
   1,019 
                
Other Income and Expenses:
               
Miscellaneous income 
20
   12   
54
   29 
Miscellaneous expense (6)  (3)  (10)  (4)
Total other income 
14
   9   
44
   25 
                
Interest Charges
 
110
   89   
316
   254 
                
Income Before Income Taxes, Minority Interest
               
   and Preferred Dividends of Subsidiaries
 
383
   467   
817
   790 
                
Income Taxes
 
130
   161   
279
   273 
Income Before Minority Interest and Preferred
               
Dividends of Subsidiaries
 
253
   306   
538
   517 
                
Minority Interest and Preferred Dividends of Subsidiaries
 
9
   13   
28
   31 
Net Income
$
244
  $293  $
510
  $486 
                
Earnings per Common Share – Basic and Diluted
$
1.18
  $1.42  $
2.46
  $2.37 
                
Dividends per Common Share
$
0.635
  $0.635  $
1.905
  $1.905 
Average Common Shares Outstanding
 
207.6
   205.9   
207.1
   205.4 

9


AMEREN CORPORATION 
CONSOLIDATED BALANCE SHEET 
(Unaudited) (In millions, except per share amounts) 
      
 March 31,  December 31, 
 2008  2007 
ASSETS     
Current Assets:     
Cash and cash equivalents$186  $355 
Accounts receivable – trade (less allowance for doubtful       
accounts of $38 and $22, respectively) 656   570 
Unbilled revenue 318   359 
Miscellaneous accounts and notes receivable 315   280 
Materials and supplies 556   735 
Other current assets 272   181 
Total current assets 2,303   2,480 
Property and Plant, Net 15,294   15,069 
Investments and Other Assets:       
Nuclear decommissioning trust fund 291   307 
Goodwill 831   831 
Intangible assets 189   198 
Regulatory assets 1,149   1,158 
Other assets 701   685 
Total investments and other assets 3,161   3,179 
TOTAL ASSETS$20,758  $20,728 
        
LIABILITIES AND STOCKHOLDERS' EQUITY       
Current Liabilities:       
Current maturities of long-term debt$823  $221 
Short-term debt 1,617   1,472 
Accounts and wages payable 443   687 
Taxes accrued 88   84 
Other current liabilities 539   438 
Total current liabilities 3,510   2,902 
Long-term Debt, Net 5,066   5,691 
Preferred Stock of Subsidiary Subject to Mandatory Redemption 16   16 
Deferred Credits and Other Liabilities:       
Accumulated deferred income taxes, net 1,989   2,046 
Accumulated deferred investment tax credits 106   109 
Regulatory liabilities 1,328   1,240 
Asset retirement obligations 569   562 
Accrued pension and other postretirement benefits 856   839 
Other deferred credits and liabilities 346   354 
Total deferred credits and other liabilities 5,194   5,150 
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption 195   195 
Minority Interest in Consolidated Subsidiaries 23   22 
Commitments and Contingencies (Notes 2, 8, 9, and 10)       
Stockholders' Equity:       
Common stock, $.01 par value, 400.0 shares authorized –       
shares outstanding of 209.4 and 208.3, respectively 2   2 
Other paid-in capital, principally premium on common stock 4,656   4,604 
Retained earnings 2,115   2,110 
Accumulated other comprehensive income (loss) (19)  36 
Total stockholders’ equity 6,754   6,752 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY$20,758  $20,728 
 
The accompanying notes are an integral part of these consolidated financial statements.

10



AMEREN CORPORATION 
CONSOLIDATED STATEMENT OF CASH FLOWS 
(Unaudited) (In millions) 
      
      
 
Three Months Ended
March 31,
 
 2008  2007 
Cash Flows From Operating Activities:     
Net income$138  $123 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Gain on sales of emission allowances (2)  (4)
Mark-to-market (gain) loss on derivatives (16)  4 
Depreciation and amortization 180   182 
Amortization of nuclear fuel 11   9 
Amortization of debt issuance costs and premium/discounts 5   5 
Deferred income taxes and investment tax credits, net 23   (12)
Minority interest 8   7 
Other (1)  6 
Changes in assets and liabilities:       
Receivables (78)  (193)
Materials and supplies 179   158 
Accounts and wages payable (106)  (81)
Taxes accrued 4   77 
Assets, other (25)  19 
Liabilities, other (16)  37 
Pension and other postretirement benefit obligations 22   21 
Net cash provided by operating activities 326   358 
Cash Flows From Investing Activities:       
Capital expenditures (420)  (357)
Nuclear fuel expenditures (102)  (23)
Purchases of securities – nuclear decommissioning trust fund (89)  (47)
Sales of securities – nuclear decommissioning trust fund 86   43 
Purchases of emission allowances (2)  (5)
Sales of emission allowances -   2 
Other -   1 
Net cash used in investing activities (527)  (386)
Cash Flows From Financing Activities:       
Dividends on common stock (133)  (131)
Short-term debt, net 145   341 
Dividends paid to minority interest holder (7)  (5)
Redemptions, repurchases, and maturities:       
Long-term debt (19)  (174)
Issuances:       
Common stock 46   21 
Net cash provided by financing activities 32   52 
Net change in cash and cash equivalents (169)  24 
Cash and cash equivalents at beginning of year 355   137 
Cash and cash equivalents at end of period$186  $161 

The accompanying notes are an integral part of these consolidated financial statements.
8
AMEREN CORPORATION     
CONSOLIDATED BALANCE SHEET     
(Unaudited) (In millions, except per share amounts)     
      
 
September 30,
  
December 31,
 
 
2007
  
2006
 
ASSETS
     
Current Assets:
     
Cash and cash equivalents$
170
  $137 
Accounts receivable – trade (less allowance for doubtful       
accounts of $26 and $11, respectively) 
691
   418 
Unbilled revenue 
263
   309 
Miscellaneous accounts and notes receivable 
258
   160 
Materials and supplies 
757
   647 
Other current assets 
202
   203 
Total current assets 
2,341
   1,874 
Property and Plant, Net
 
14,729
   14,286 
Investments and Other Assets:
       
Nuclear decommissioning trust fund 
301
   285 
Goodwill 
831
   831 
Intangible assets 
197
   217 
Other assets 
683
   654 
Regulatory assets 
1,323
   1,431 
Total investments and other assets 
3,335
   3,418 
TOTAL ASSETS
$
20,405
  $19,578 
        
LIABILITIES AND STOCKHOLDERS' EQUITY
       
Current Liabilities:
       
Current maturities of long-term debt$
203
  $456 
Short-term debt 
1,202
   612 
Accounts and wages payable 
415
   671 
Taxes accrued 
136
   58 
Other current liabilities 
548
   406 
Total current liabilities 
2,504
   2,203 
Long-term Debt, Net
 
5,486
   5,285 
Preferred Stock of Subsidiary Subject to Mandatory Redemption
 
16
   17 
Deferred Credits and Other Liabilities:
       
Accumulated deferred income taxes, net 
2,055
   2,144 
Accumulated deferred investment tax credits 
111
   118 
Regulatory liabilities 
1,241
   1,234 
Asset retirement obligations 
571
   549 
Accrued pension and other postretirement benefits 
1,058
   1,065 
Other deferred credits and liabilities 
392
   169 
Total deferred credits and other liabilities 
5,428
   5,279 
Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption
 
195
   195 
Minority Interest in Consolidated Subsidiaries
 
20
   16 
Commitments and Contingencies (Notes 2, 8, and 9)
       
Stockholders' Equity:
       
Common stock, $.01 par value, 400.0 shares authorized –       
shares outstanding of 208.0 and 206.6, respectively 
2
   2 
Other paid-in capital, principally premium on common stock 
4,579
   4,495 
Retained earnings 
2,134
   2,024 
Accumulated other comprehensive income 
41
   62 
Total stockholders’ equity 
6,756
   6,583 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
20,405
  $19,578 
The accompanying notes are an integral part of these consolidated financial statements.
9
AMEREN CORPORATION     
CONSOLIDATED STATEMENT OF CASH FLOWS     
(Unaudited) (In millions)     
      
 
Nine Months Ended
 
 
September 30,   
 
 
2007
  
2006
 
Cash Flows From Operating Activities:
     
Net income$
510
  $486 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Gain on sales of emission allowances (7)  (25)
Depreciation and amortization 
537
   507 
Amortization of nuclear fuel 
26
   26 
Amortization of debt issuance costs and premium/discounts 
14
   12 
Deferred income taxes and investment tax credits, net 
18
   7 
Loss on sale of noncore properties 
-
   4 
Minority interest 
20
   23 
Other 
10
   17 
Changes in assets and liabilities:       
Receivables (320)  157 
Materials and supplies (110)  (136)
Accounts and wages payable (113)  (260)
Taxes accrued 
75
   148 
Assets, other (20)  (87)
Liabilities, other 
193
   101 
Pension and other postretirement benefit obligations 
87
   89 
Net cash provided by operating activities 
920
   1,069 
        
Cash Flows From Investing Activities:
       
Capital expenditures (1,035)  (693)
CT acquisitions 
-
   (292)
Nuclear fuel expenditures (39)  (37)
Proceeds from sale of noncore properties 
-
   11 
Purchases of securities – nuclear decommissioning trust fund (110)  (78)
Sales of securities – nuclear decommissioning trust fund 
98
   68 
Purchases of emission allowances (12)  (38)
Sales of emission allowances 
5
   12 
Other 
-
   3 
Net cash used in investing activities (1,093)  (1,044)
        
Cash Flows From Financing Activities:
       
Dividends on common stock (395)  (391)
Capital issuance costs (3)  (4)
Short-term debt, net 
590
   158 
Dividends paid to minority interest (16)  (21)
Redemptions, repurchases, and maturities:       
Long-term debt (465)  (138)
Preferred stock (1)  (1)
Issuances:       
Common stock 
71
   78 
Long-term debt 
425
   232 
Net cash provided by (used in) financing activities 
206
   (87)
Net change in cash and cash equivalents 
33
   (62)
Cash and cash equivalents at beginning of year 
137
   96 
Cash and cash equivalents at end of period$
170
  $34 
        
The accompanying notes are an integral part of these consolidated financial statements.
10
UNION ELECTRIC COMPANY           
CONSOLIDATED STATEMENT OF INCOME           
(Unaudited) (In millions)           
            
 
Three Months Ended
  
Nine Months Ended
 
 
September 30,   
  
September 30,   
 
 
2007
  
2006
  
2007
  
2006
 
Operating Revenues:
           
Electric - excluding off-system$
835
  $746  $
1,865
  $1,759 
Electric - off-system 
92
   90   
303
   331 
Gas 
18
   20   
123
   111 
Other 
-
   1   
1
   2 
Total operating revenues 
945
   857   
2,292
   2,203 
                
Operating Expenses:
               
Fuel 
179
   150   
447
   399 
Purchased power 
71
   64   
140
   199 
Gas purchased for resale 
9
   10   
73
   66 
Other operations and maintenance 
218
   214   
667
   581 
Depreciation and amortization 
81
   82   
252
   243 
    Taxes other than income taxes 
70
   66   
187
   184 
Total operating expenses 
628
   586   
1,766
   1,672 
                
Operating Income
 
317
   271   
526
   531 
                
Other Income and Expenses:
               
Miscellaneous income 
9
   9   
28
   22 
Miscellaneous expense (5)  (3)  (9)  (7)
Total other income 
4
   6   
19
   15 
                
Interest Charges
 
49
   42   
146
   123 
                
Income Before Income Taxes and Equity
               
in Income of Unconsolidated Investment
 
272
   235   
399
   423 
                
Income Taxes
 
93
   92   
132
   161 
                
Income Before Equity in Income
               
of Unconsolidated Investment
 
179
   143   
267
   262 
                
Equity in Income of Unconsolidated Investment,
               
Net of Taxes
 
14
   23   
40
   47 
                
Net Income
 
193
   166   
307
   309 
                
Preferred Stock Dividends
 
1
   1   
4
   4 
Net Income Available to Common Stockholder
$
192
  $165  $
303
  $305 
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
 
 
11
 


UNION ELECTRIC COMPANY     
 CONSOLIDATED BALANCE SHEET     
(Unaudited) (In millions, except per share amounts)     
      
 
September 30,
  
December 31,
 
 
2007
  
2006
 
ASSETS
     
Current Assets:
     
Cash and cash equivalents$
-
  $1 
Accounts receivable – trade (less allowance for doubtful       
accounts of $6 and $6, respectively) 
242
   145 
Unbilled revenue 
127
   120 
Miscellaneous accounts and notes receivable 
207
   128 
Advances to money pool 
13
   18 
Accounts receivable – affiliates 
32
   33 
Materials and supplies 
285
   236 
Other current assets 
58
   45 
Total current assets 
964
   726 
Property and Plant, Net
 
8,078
   7,882 
Investments and Other Assets:
       
Nuclear decommissioning trust fund 
301
   285 
Intangible assets 
60
   58 
Other assets 
476
   526 
Regulatory assets 
784
   810 
Total investments and other assets 
1,621
   1,679 
TOTAL ASSETS
$
10,663
  $10,287 
        
LIABILITIES AND STOCKHOLDERS' EQUITY
       
Current Liabilities:
       
Current maturities of long-term debt$
152
  $5 
Short-term debt 
92
   234 
Intercompany note payable – Ameren 
57
   77 
Accounts and wages payable 
172
   313 
Accounts payable – affiliates 
143
   185 
Taxes accrued 
206
   66 
Other current liabilities 
226
   191 
Total current liabilities 
1,048
   1,071 
Long-term Debt, Net
 
3,212
   2,934 
Deferred Credits and Other Liabilities:
       
Accumulated deferred income taxes, net 
1,279
   1,293 
Accumulated deferred investment tax credits 
86
   89 
Regulatory liabilities 
850
   827 
Asset retirement obligations 
511
   491 
Accrued pension and other postretirement benefits 
375
   374 
Other deferred credits and liabilities 
83
   55 
Total deferred credits and other liabilities 
3,184
   3,129 
Commitments and Contingencies (Notes 2, 8 and 9)
       
Stockholders' Equity:
       
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding 
511
   511 
Preferred stock not subject to mandatory redemption 
113
   113 
Other paid-in capital, principally premium on common stock 
744
   739 
Retained earnings 
1,843
   1,783 
Accumulated other comprehensive income 
8
   7 
Total stockholders' equity 
3,219
   3,153 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
10,663
  $10,287 
     
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
12
UNION ELECTRIC COMPANY     
CONSOLIDATED STATEMENT OF CASH FLOWS     
(Unaudited) (In millions)     
      
 
Nine Months Ended   
 
 
September 30,   
 
 
2007
  
2006
 
Cash Flows From Operating Activities:
     
Net income$
307
  $309 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Gain on sales of emission allowances (5)  (2)
Depreciation and amortization 
252
   243 
Amortization of nuclear fuel 
26
   26 
Amortization of debt issuance costs and premium/discounts 
4
   4 
Deferred income taxes and investment tax credits, net 
19
   (10)
Other 
1
   - 
Changes in assets and liabilities:       
Receivables (182)  (34)
Materials and supplies (49)  (35)
Accounts and wages payable (97)  (110)
Taxes accrued 
140
   174 
Assets, other 
60
   (42)
Liabilities, other 
16
   62 
Pension and other postretirement obligations 
27
   35 
Net cash provided by operating activities 
519
   620 
        
Cash Flows From Investing Activities:
       
Capital expenditures (493)  (341)
CT acquisitions 
-
   (292)
Nuclear fuel expenditures (39)  (37)
Changes in money pool advances 
5
   - 
Proceeds from intercompany note receivable – CIPS 
-
   67 
Purchases of securities – nuclear decommissioning trust fund (110)  (78)
Sales of securities – nuclear decommissioning trust fund 
98
   68 
Sales of emission allowances 
4
   2 
Net cash used in investing activities (535)  (611)
        
Cash Flows From Financing Activities:
       
Dividends on common stock (246)  (154)
Dividends on preferred stock (4)  (4)
Capital issuance costs (3)  - 
Short-term debt, net (142)  128 
Intercompany note payable – Ameren, net (20)  - 
Issuances of long-term debt 
425
   - 
Capital contribution from parent 
5
   3 
Net cash provided by (used in) financing activities 
15
   (27)
Net change in cash and cash equivalents (1)  (18)
Cash and cash equivalents at beginning of year 
1
   20 
Cash and cash equivalents at end of period$
-
  $2 
        
UNION ELECTRIC COMPANY 
CONSOLIDATED STATEMENT OF INCOME 
(Unaudited) (In millions) 
      
      
 
Three Months Ended
March 31,
 
 2008  2007 
Operating Revenues:     
Electric – excluding off-system$490  $451 
Electric – off-system 151   122 
Gas 83   76 
Other -   1 
Total operating revenues 724   650 
Operating Expenses:       
Fuel 147   125 
Purchased power 53   40 
Gas purchased for resale 55   49 
Other operations and maintenance 217   224 
Depreciation and amortization 81   87 
    Taxes other than income taxes 60   57 
Total operating expenses 613   582 
Operating Income 111   68 
Other Income and Expenses:       
Miscellaneous income 14   10 
Miscellaneous expense (2)  (2)
Total other income 12   8 
Interest Charges 41   48 
Income Before Income Taxes and Equity       
   in Income of Unconsolidated Investment 82   28 
Income Taxes 29   9 
Income Before Equity in Income       
   of Unconsolidated Investment 53   19 
Equity in Income of Unconsolidated Investment,       
Net of Taxes 11   14 
Net Income 64   33 
Preferred Stock Dividends 1   1 
Net Income Available to Common Stockholder$63  $32 
 
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.

 
12


UNION ELECTRIC COMPANY 
CONSOLIDATED BALANCE SHEET 
(Unaudited) (In millions, except per share amounts) 
      
 March 31,  December 31, 
 2008  2007 
ASSETS     
Current Assets:     
Cash and cash equivalents$-  $185 
Accounts receivable – trade (less allowance for doubtful       
accounts of $8 and $6, respectively) 205   191 
Unbilled revenue 102   118 
Miscellaneous accounts and notes receivable 246   213 
Advances to money pool 36   15 
Accounts receivable – affiliates 17   90 
Materials and supplies 302   301 
Other current assets 85   50 
Total current assets 993   1,163 
Property and Plant, Net 8,339   8,189 
Investments and Other Assets:       
Nuclear decommissioning trust fund 291   307 
Intangible assets 54   56 
Regulatory assets 711   697 
Other assets 374   491 
Total investments and other assets 1,430   1,551 
TOTAL ASSETS$10,762  $10,903 
        
LIABILITIES AND STOCKHOLDERS' EQUITY       
Current Liabilities:       
Current maturities of long-term debt$381  $152 
Short-term debt 208   82 
Intercompany note payable – Ameren 122   - 
Accounts and wages payable 135   315 
Accounts payable – affiliates 75   212 
Taxes accrued 49   78 
Other current liabilities 204   209 
Total current liabilities 1,174   1,048 
Long-term Debt, Net 2,979   3,208 
Deferred Credits and Other Liabilities:       
Accumulated deferred income taxes, net 1,281   1,273 
Accumulated deferred investment tax credits 84   85 
Regulatory liabilities 883   865 
Asset retirement obligations 482   476 
Accrued pension and other postretirement benefits 303   297 
Other deferred credits and liabilities 41   50 
Total deferred credits and other liabilities 3,074   3,046 
Commitments and Contingencies (Notes 2, 8, 9 and 10)       
Stockholders' Equity:       
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding 511   511 
Preferred stock not subject to mandatory redemption 113   113 
Other paid-in capital, principally premium on common stock 1,119   1,119 
Retained earnings 1,799   1,855 
Accumulated other comprehensive income (loss) (7)  3 
Total stockholders' equity 3,535   3,601 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY$10,762  $10,903 
        
 
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.
13
 
UNION ELECTRIC COMPANY 
CONSOLIDATED STATEMENT OF CASH FLOWS 
(Unaudited) (In millions) 
      
 
Three Months Ended
March 31,
 
 2008  2007 
Cash Flows From Operating Activities:     
Net income$64  $33 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Gain on sales of emission allowances (1)  (3)
Mark-to-market (gain) on derivatives (12)  (2)
Depreciation and amortization 81   87 
Amortization of nuclear fuel 11   9 
Amortization of debt issuance costs and premium/discounts 1   1 
Deferred income taxes and investment tax credits, net 15   9 
Other (4)  2 
Changes in assets and liabilities:       
Receivables 52   (50)
Materials and supplies (1)  2 
Accounts and wages payable (252)  (188)
Taxes accrued (29)  29 
Assets, other 83   55 
Liabilities, other (50)  (41)
Pension and other postretirement benefit obligations 11   7 
Net cash used in operating activities (31)  (50)
Cash Flows From Investing Activities:       
Capital expenditures (197)  (200)
Nuclear fuel expenditures (102)  (23)
Changes in money pool advances (21)  4 
Purchases of securities – nuclear decommissioning trust fund (89)  (47)
Sales of securities – nuclear decommissioning trust fund 85   43 
Sales of emission allowances -   2 
Net cash used in investing activities (324)  (221)
Cash Flows From Financing Activities:       
Dividends on common stock (77)  (80)
Dividends on preferred stock (1)  (1)
Short-term debt, net 126   214 
Intercompany note payable – Ameren, net 122   137 
Net cash provided by financing activities 170   270 
Net change in cash and cash equivalents (185)  (1)
Cash and cash equivalents at beginning of year 185   1 
Cash and cash equivalents at end of period$-  $- 
        
The accompanying notes as they relate to UE are an integral part of these consolidated financial statements.


CENTRAL ILLINOIS PUBLIC SERVICE COMPANY           
STATEMENT OF INCOME           
(Unaudited) (In millions)           
            
 
Three Months Ended
  
Nine Months Ended
 
 
September 30,   
  
September 30,   
 
 
2007
  
2006
  
2007
  
2006
 
Operating Revenues:
           
Electric$
201
  $228  $
605
  $569 
Gas 
22
   23   
159
   150 
Other 
1
   3   
3
   4 
Total operating revenues 
224
   254   
767
   723 
                
Operating Expenses:
               
Purchased power 
142
   125   
416
   355 
Gas purchased for resale 
12
   11   
107
   99 
Other operations and maintenance 
40
   41   
124
   117 
Depreciation and amortization 
16
   16   
49
   47 
Taxes other than income taxes 
6
   9   
24
   30 
Total operating expenses 
216
   202   
720
   648 
                
Operating Income
 
8
   52   
47
   75 
                
Other Income and Expenses:
               
Miscellaneous income 
5
   4   
13
   13 
Miscellaneous expense (1)  -   (2)  (1)
Total other income 
4
   4   
11
   12 
                
Interest Charges
 
10
   8   
28
   23 
                
Income Before Income Taxes
 
2
   48   
30
   64 
                
Income Taxes
 
1
   19   
11
   21 
                
Net Income
 
1
   29   
19
   43 
                
Preferred Stock Dividends
 
1
   1   
2
   2 
                
Net Income Available to Common Stockholder
$
-
  $28  $
17
  $41 
                
14
 

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY 
STATEMENT OF INCOME 
(Unaudited) (In millions) 
      
      
 
Three Months Ended
March 31,
 
 2008  2007 
Operating Revenues:     
Electric$180  $211 
Gas 110   101 
Other -   2 
Total operating revenues 290   314 
Operating Expenses:       
Purchased power 123   148 
Gas purchased for resale 80   74 
Other operations and maintenance 50   43 
Depreciation and amortization 17   17 
Taxes other than income taxes 12   9 
Total operating expenses 282   291 
Operating Income 8   23 
Miscellaneous Income 3   3 
Interest Charges 7   8 
Income Before Income Taxes 4   18 
Income Taxes 1   6 
Net Income 3   12 
Preferred Stock Dividends 1   1 
Net Income Available to Common Stockholder$2  $11 
        

The accompanying notes as they relate to CIPS are an integral part of these financial statements.
14
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY     
 BALANCE SHEET     
(Unaudited) (In millions)     
      
 
September 30,
  
December 31,
 
 
2007
  
2006
 
ASSETS
     
Current Assets:
     
Cash and cash equivalents$
1
  $6 
Accounts receivable – trade (less allowance for doubtful       
accounts of $6 and $2, respectively) 
66
   55 
Unbilled revenue 
36
   43 
Accounts receivable – affiliates 
50
   10 
Current portion of intercompany note receivable – Genco 
39
   37 
Current portion of intercompany tax receivable – Genco 
9
   9 
Advances to money pool 
95
   1 
Materials and supplies 
78
   71 
Other current assets 
53
   46 
Total current assets 
427
   278 
Property and Plant, Net
 
1,167
   1,155 
Investments and Other Assets:
       
Intercompany note receivable – Genco 
87
   126 
Intercompany tax receivable – Genco 
107
   115 
Other assets 
32
   27 
Regulatory assets 
132
   146 
Total investments and other assets 
358
   414 
TOTAL ASSETS
$
1,952
  $1,847 
        
LIABILITIES AND STOCKHOLDERS' EQUITY
       
Current Liabilities:
       
Short-term debt$
135
  $35 
Accounts and wages payable 
36
   36 
Accounts payable – affiliates 
51
   81 
Taxes accrued 
4
   10 
Other current liabilities 
71
   36 
Total current liabilities 
297
   198 
Long-term Debt, Net
 
471
   471 
Deferred Credits and Other Liabilities:
       
Accumulated deferred income taxes and investment tax credits, net 
274
   297 
Regulatory liabilities 
229
   224 
Accrued pension and other postretirement benefits 
83
   90 
Other deferred credits and liabilities 
38
   24 
Total deferred credits and other liabilities 
624
   635 
Commitments and Contingencies (Notes 2 and 8)
       
Stockholders' Equity:
       
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding 
-
   - 
Other paid-in capital 
191
   190 
Preferred stock not subject to mandatory redemption 
50
   50 
Retained earnings 
319
   302 
Accumulated other comprehensive income 
-
   1 
Total stockholders' equity 
560
   543 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
1,952
  $1,847 
        
The accompanying notes as they relate to CIPS are an integral part of these financial statements.

15


CENTRAL ILLINOIS PUBLIC SERVICE COMPANY 
BALANCE SHEET 
(Unaudited) (In millions) 
      
 March 31,  December 31, 
 2008  2007 
ASSETS     
Current Assets:     
Cash and cash equivalents$18  $26 
Accounts receivable – trade (less allowance for doubtful       
accounts of $9 and $5, respectively) 101   62 
Unbilled revenue 48   66 
Accounts receivable – affiliates 24   9 
Current portion of intercompany note receivable – Genco 39   39 
Current portion of intercompany tax receivable – Genco 9   9 
Materials and supplies 20   66 
Other current assets 55   35 
Total current assets 314   312 
Property and Plant, Net 1,179   1,174 
Investments and Other Assets:       
Intercompany note receivable – Genco 87   87 
Intercompany tax receivable – Genco 103   105 
Regulatory assets 109   113 
Other assets 54   69 
Total investments and other assets 353   374 
TOTAL ASSETS$1,846  $1,860 
        
LIABILITIES AND STOCKHOLDERS' EQUITY       
Current Liabilities:       
Current maturities of long-term debt$50  $15 
Short-term debt 85   125 
Accounts and wages payable 36   44 
Accounts payable – affiliates 15   19 
Taxes accrued 14   8 
Other current liabilities 63   47 
Total current liabilities 263   258 
Long-term Debt, Net 421   456 
Deferred Credits and Other Liabilities:       
Accumulated deferred income taxes and investment tax credits, net 266   269 
Regulatory liabilities 280   265 
Accrued pension and other postretirement benefits 67   67 
Other deferred credits and liabilities 30   28 
Total deferred credits and other liabilities 643   629 
Commitments 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   191 
Preferred stock not subject to mandatory redemption 50   50 
Retained earnings 278   276 
Total stockholders' equity 519   517 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY$1,846  $1,860 
 
CENTRAL ILLINOIS PUBLIC SERVICE COMPANY     
STATEMENT OF CASH FLOWS     
(Unaudited) (In millions)     
      
 
Nine Months Ended
 
 
September 30,   
 
 
2007
  
2006
 
Cash Flows From Operating Activities:
     
Net income$
19
  $43 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Depreciation and amortization 
49
   47 
Amortization of debt issuance costs and premium/discounts 
1
   1 
Deferred income taxes and investment tax credits, net (13)  (27)
Other 
-
   1 
Changes in assets and liabilities:       
Receivables (36)  60 
Materials and supplies (7)  (7)
Accounts and wages payable (27)  (5)
Taxes accrued (6)  8 
Assets, other (8)  - 
Liabilities, other 
34
   - 
Pension and other postretirement obligations 
5
   6 
Net cash provided by operating activities 
11
   127 
        
Cash Flows From Investing Activities:
       
Capital expenditures (58)  (63)
Proceeds from intercompany note receivable – Genco 
37
   34 
Changes in money pool advances (94)  (18)
Net cash used in investing activities (115)  (47)
        
Cash Flows From Financing Activities:
       
Dividends on common stock 
-
   (50)
Dividends on preferred stock (2)  (2)
Capital issuance costs 
-
   (1)
Short-term debt, net 
100
   - 
Changes in money pool borrowings 
-
   (2)
Redemptions, repurchases, and maturities:       
Long-term debt 
-
   (20)
Intercompany note payable – UE 
-
   (67)
Issuances of long-term debt 
-
   61 
Capital contribution from parent 
1
   1 
Net cash provided by (used in) financing activities 
99
   (80)
Net change in cash and cash equivalents (5)  - 
Cash and cash equivalents at beginning of year 
6
   - 
Cash and cash equivalents at end of period$
1
  $- 
        
The accompanying notes as they relate to CIPS are an integral part of these financial statements.
 
16
AMEREN ENERGY GENERATING COMPANY          
 
CONSOLIDATED STATEMENT OF INCOME          
 
(Unaudited) (In millions)          
 
            
 
Three Months Ended
  
Nine Months Ended
 
 
September 30,   
  
September 30,   
 
 
2007
  
2006
  
2007
  
2006
 
Operating Revenues
$
221
  $259  $
649
  $744 
                
Operating Expenses:
               
Fuel 
102
   86   
257
   216 
Purchased power 
1
   84   
23
   269 
Other operations and maintenance 
39
   34   
122
   113 
Depreciation and amortization 
18
   18   
54
   53 
Taxes other than income taxes 
5
   3   
15
   14 
Total operating expenses 
165
   225   
471
   665 
                
Operating Income
 
56
   34   
178
   79 
                
Miscellaneous Income
 
-
   -   
1
   - 
                
Interest Charges
 
15
   15   
43
   45 
                
Income Before Income Taxes
 
41
   19   
136
   34 
                
Income Taxes
 
16
   -   
52
   7 
                
Net Income
$
25
  $19  $
84
  $27 
 

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY 
STATEMENT OF CASH FLOWS 
(Unaudited) (In millions) 
      
      
 
Three Months Ended
March 31,
 
 2008  2007 
Cash Flows From Operating Activities:     
Net income$3  $12 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Depreciation and amortization 17   17 
Deferred income taxes and investment tax credits, net (5)  (2)
Other -   (1)
Changes in assets and liabilities:       
Receivables (34)  (39)
Materials and supplies 46   38 
Accounts and wages payable (10)  (31)
Taxes accrued 6   4 
Assets, other 21   9 
Liabilities, other 9   3 
Pension and other postretirement benefit obligations 2   - 
Net cash provided by operating activities 55   10 
Cash Flows From Investing Activities:       
Capital expenditures (22)  (20)
Changes in money pool advances -   (14)
Net cash used in investing activities (22)  (34)
Cash Flows From Financing Activities:       
Dividends on preferred stock (1)  (1)
Short-term debt, net (40)  65 
Net cash provided by (used in) financing activities (41)  64 
Net change in cash and cash equivalents (8)  40 
Cash and cash equivalents at beginning of year 26   6 
Cash and cash equivalents at end of period$18  $46 
        
The accompanying notes as they relate to CIPS are an integral part of these financial statements.

17

AMEREN ENERGY GENERATING COMPANY 
CONSOLIDATED STATEMENT OF INCOME 
(Unaudited) (In millions) 
       
       
  
Three Months Ended
March 31,
 
  2008  2007 
       
Operating Revenues $231  $243 
Operating Expenses:        
Fuel  88   81 
Purchased power  -   21 
Other operations and maintenance  40   34 
Depreciation and amortization  16   18 
Taxes other than income taxes  6   6 
Total operating expenses  150   160 
Operating Income  81   83 
Miscellaneous Income  2   - 
Interest Charges  9   14 
Income Before Income Taxes  74   69 
Income Taxes  28   26 
Net Income $46  $43 

The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
18

AMEREN ENERGY GENERATING COMPANY 
CONSOLIDATED BALANCE SHEET 
(Unaudited) (In millions, except shares) 
      
 March 31,  December 31, 
 2008  2007 
ASSETS     
Current Assets:     
Cash and cash equivalents$2  $2 
Accounts receivable – affiliates 107   93 
Accounts receivable – trade 13   12 
Materials and supplies 97   93 
Other current assets 9   4 
Total current assets 228   204 
Property and Plant, Net 1,700   1,683 
Intangible Assets 58   63 
Other Assets 5   18 
TOTAL ASSETS$1,991  $1,968 
        
LIABILITIES AND STOCKHOLDER'S EQUITY       
Current Liabilities:       
Short-term debt$150  $100 
Current portion of intercompany note payable – CIPS 39   39 
Borrowings from money pool 9   54 
Accounts and wages payable 39   61 
Accounts payable – affiliates 45   57 
Current portion of intercompany tax payable – CIPS 9   9 
Taxes accrued 29   15 
Other current liabilities 56   30 
Total current liabilities 376   365 
Long-term Debt, Net 474   474 
Intercompany Note Payable – CIPS 87   87 
Deferred Credits and Other Liabilities:       
Accumulated deferred income taxes, net 163   161 
Accumulated deferred investment tax credits 7   7 
Intercompany tax payable – CIPS 103   105 
Asset retirement obligations 48   47 
Accrued pension and other postretirement benefits 32   32 
Other deferred credits and liabilities 34   42 
Total deferred credits and other liabilities 387   394 
Commitments 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   503 
Retained earnings 189   167 
Accumulated other comprehensive loss (25)  (22)
Total stockholder's equity 667   648 
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY$1,991  $1,968 
        

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


19
AMEREN ENERGY GENERATING COMPANY 
CONSOLIDATED STATEMENT OF CASH FLOWS 
(Unaudited) (In millions) 
      
      
 
Three Months Ended
March 31,
 
 2008  2007 
Cash Flows From Operating Activities:     
Net income$46  $43 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Gain on sales of emission allowances (1)  (1)
Mark-to-market (gain) loss on derivatives (5)   - 
Depreciation and amortization 23   26 
Deferred income taxes and investment tax credits, net 8   2 
Other -   1 
Changes in assets and liabilities:       
Receivables (9)  18 
Materials and supplies (4)  - 
Accounts and wages payable (8)  (42)
Taxes accrued, net 14   16 
Assets, other 9   (2)
Liabilities, other 5   7 
Pension and other postretirement benefit obligations 1   1 
Net cash provided by operating activities 79   69 
Cash Flows From Investing Activities:       
Capital expenditures (58)  (37)
Purchases of emission allowances (2)  - 
Net cash used in investing activities (60)  (37)
Cash Flows From Financing Activities:       
Dividends on common stock (24)  (39)
Short-term debt, net 50   - 
Changes in money pool borrowings (45)  7 
Net cash used in financing activities (19)  (32)
Net change in cash and cash equivalents -   - 
Cash and cash equivalents at beginning of year 2   1 
Cash and cash equivalents at end of period$2  $1 

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
March 31,
 
  2008  2007 
Operating Revenues:      
Electric $194  $180 
Gas  151   135 
Total operating revenues  345   315 
Operating Expenses:        
Fuel  28   23 
Purchased power  78   76 
Gas purchased for resale  115   103 
Other operations and maintenance  45   40 
Depreciation and amortization  23   21 
Taxes other than income taxes  9   8 
Total operating expenses  298   271 
    Operating Income  47   44 
Other Income and Expenses:        
Miscellaneous income  -   2 
Miscellaneous expense  -   (1)
Total other income  -   1 
Interest Charges  15   14 
Income Before Income Taxes  32   31 
Income Taxes  12   10 
Net Income $20  $21 

The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
 
1721
 

AMEREN ENERGY GENERATING COMPANY     
CONSOLIDATED BALANCE SHEET     
(Unaudited) (In millions, except shares)     
      
 
September 30,
  
December 31,
 
 
2007
  
2006
 
ASSETS
     
Current Assets:
     
Cash and cash equivalents$
2
  $1 
Accounts receivable – affiliates 
114
   96 
Accounts receivable – trade 
15
   19 
Materials and supplies 
97
   96 
Other current assets 
17
   5 
Total current assets 
245
   217 
Property and Plant, Net
 
1,594
   1,539 
Intangible Assets
 
57
   74 
Other Assets
 
18
   20 
TOTAL ASSETS
$
1,914
  $1,850 
        
LIABILITIES AND STOCKHOLDER'S EQUITY
       
Current Liabilities:
       
Short-term debt$
75
  $- 
Current portion of intercompany note payable – CIPS 
39
   37 
Borrowings from money pool 
108
   123 
Accounts and wages payable 
36
   52 
Accounts payable – affiliates 
49
   66 
Current portion of intercompany tax payable – CIPS 
9
   9 
Taxes accrued 
15
   22 
Other current liabilities 
31
   22 
Total current liabilities 
362
   331 
Long-term Debt, Net
 
474
   474 
Intercompany Note Payable – CIPS
 
87
   126 
Deferred Credits and Other Liabilities:
       
Accumulated deferred income taxes, net 
153
   165 
Accumulated deferred investment tax credits 
8
   9 
Intercompany tax payable – CIPS 
107
   115 
Asset retirement obligations 
31
   31 
Accrued pension and other postretirement benefits 
41
   34 
Other deferred credits and liabilities 
45
   2 
Total deferred credits and other liabilities 
385
   356 
Commitments and Contingencies (Notes 2 and 8)
       
Stockholder's Equity:
       
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding 
-
   - 
Other paid-in capital 
503
   428 
Retained earnings 
127
   156 
Accumulated other comprehensive loss (24)  (21)
Total stockholder's equity 
606
   563 
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY
$
1,914
  $1,850 
        
The accompanying notes as they relate to Genco are an integral part of these consolidated financial statements.
CILCORP INC. 
CONSOLIDATED BALANCE SHEET 
(Unaudited) (In millions, except shares) 
      
 March 31,  December 31, 
 2008  2007 
      
ASSETS     
Current Assets:     
Cash and cash equivalents$42  $6 
Accounts receivable – trade (less allowance for doubtful       
accounts of $6 and $2, respectively) 88   52 
Unbilled revenue 50   54 
Accounts receivable – affiliates 58   47 
Advances to money pool 2   2 
Materials and supplies 61   110 
Other current assets 43   40 
Total current assets 344   311 
Property and Plant, Net 1,517   1,494 
Investments and Other Assets:       
Goodwill 542   542 
Intangible assets 40   41 
Regulatory assets 30   32 
Other assets 40   39 
Total investments and other assets 652   654 
TOTAL ASSETS$2,513  $2,459 
        
LIABILITIES AND STOCKHOLDER'S EQUITY       
Current Liabilities:       
Current maturities of long-term debt$19  $- 
Short-term debt 530   520 
Borrowings from money pool, net 3   2 
Accounts and wages payable 57   75 
Accounts payable – affiliates 40   34 
Taxes accrued 11   3 
Other current liabilities 67   54 
Total current liabilities 727   688 
Long-term Debt, Net 517   537 
Preferred Stock of Subsidiary Subject to Mandatory Redemption 16   16 
Deferred Credits and Other Liabilities:       
Accumulated deferred income taxes, net 185   193 
Accumulated deferred investment tax credits 6   6 
Regulatory liabilities 113   92 
Accrued pension and other postretirement benefits 127   127 
Other deferred credits and liabilities 69   66 
Total deferred credits and other liabilities 500   484 
Preferred Stock of Subsidiary Not Subject to Mandatory Redemption 19   19 
Commitments 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   627 
Retained earnings 78   58 
Accumulated other comprehensive income 29   30 
Total stockholder's equity 734   715 
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY$2,513  $2,459 
        
 
18
AMEREN ENERGY GENERATING COMPANY     
CONSOLIDATED STATEMENT OF CASH FLOWS     
(Unaudited) (In millions)     
      
 
Nine Months Ended   
 
 
September 30,   
 
 
2007
  
2006
 
Cash Flows From Operating Activities:
     
Net income$
84
  $27 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Gain on sales of emission allowances (1)  (1)
Depreciation and amortization 
79
   78 
Deferred income taxes and investment tax credits, net 
28
   7 
Other (1)  1 
Changes in assets and liabilities:       
Receivables (14)  (30)
Materials and supplies (1)  (30)
Accounts and wages payable (12)  16 
Taxes accrued, net (7)  (9)
Assets, other (12)  (16)
Liabilities, other 
5
   2 
Pension and other postretirement obligations 
5
   4 
Net cash provided by operating activities 
153
   49 
        
Cash Flows From Investing Activities:
       
Capital expenditures (131)  (58)
Purchases of emission allowances (7)  (26)
Sales of emission allowances 
1
   1 
Net cash used in investing activities (137)  (83)
        
Cash Flows From Financing Activities:
       
Dividends on common stock (113)  (93)
Short-term debt, net 
75
   - 
Changes in money pool borrowings (15)  13 
Intercompany notes payable – CIPS (37)  (34)
Capital contribution from parent 
75
   150 
Net cash provided by (used in) financing activities (15)  36 
Net change in cash and cash equivalents 
1
   2 
Cash and cash equivalents at beginning of year 
1
   - 
Cash 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.
19
CILCORP INC.           
CONSOLIDATED STATEMENT OF INCOME           
(Unaudited) (In millions)           
            
            
 
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
 
2007
  
2006
  
2007
  
2006
 
Operating Revenues:
           
Electric$
170
  $119  $
507
  $309 
Gas 
36
   38   
231
   236 
Other 
-
   1   
1
   1 
Total operating revenues 
206
   158   
739
   546 
                
Operating Expenses:
               
Fuel 
21
   26   
58
   79 
Purchased power 
74
   17   
206
   25 
Gas purchased for resale 
21
   24   
166
   175 
Other operations and maintenance 
48
   41   
135
   134 
Depreciation and amortization 
20
   18   
58
   55 
Taxes other than income taxes 
3
   5   
17
   18 
Total operating expenses 
187
   131   
640
   486 
                
Operating Income
 
19
   27   
99
   60 
                
Other Income and Expenses:
               
Miscellaneous income 
2
   -   
4
   1 
Miscellaneous expense (2)  (2)  (5)  (4)
Total other expenses 
-
   (2)  (1)  (3)
                
Interest Charges
 
17
   13   
46
   38 
                
Income Before Income Taxes and Preferred
               
Dividends of Subsidiaries
 
2
   12   
52
   19 
                
Income Taxes (Benefit)
 
1
   (1)  
17
   (4)
                
Income Before Preferred Dividends of Subsidiaries
 
1
   13   
35
   23 
                
Preferred Dividends of Subsidiaries
 
-
   -   
1
   1 
                
Net Income
$
1
  $13  $
34
  $22 
                
The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.

 
2022
 

CILCORP INC.     
CONSOLIDATED BALANCE SHEET     
(Unaudited) (In millions, except shares)     
      
 
September 30,
  
December 31,
 
 
2007
  
2006
 
      
ASSETS
     
Current Assets:
     
Cash and cash equivalents$
84
  $4 
Accounts receivable – trade (less allowance for doubtful       
accounts of $3 and $1, respectively) 
51
   47 
Unbilled revenue 
29
   45 
Accounts receivable – affiliates 
66
   10 
Advances to money pool 
-
   42 
Materials and supplies 
111
   93 
Other current assets 
50
   42 
Total current assets 
391
   283 
Property and Plant, Net
 
1,401
   1,277 
Investments and Other Assets:
       
Goodwill 
542
   542 
Intangible assets 
42
   48 
Other assets 
22
   16 
Regulatory assets 
55
   75 
Total investments and other assets 
661
   681 
TOTAL ASSETS
$
2,453
  $2,241 
        
LIABILITIES AND STOCKHOLDER'S EQUITY
       
Current Liabilities:
       
Current maturities of long-term debt$
-
  $50 
Short-term debt 
540
   215 
Intercompany note payable – Ameren 
-
   73 
Accounts and wages payable 
31
   54 
Accounts payable – affiliates 
44
   60 
Taxes accrued 
2
   3 
Other current liabilities 
80
   58 
Total current liabilities 
697
   513 
Long-term Debt, Net
 
538
   542 
Preferred Stock of Subsidiary Subject to Mandatory Redemption
 
16
   17 
Deferred Credits and Other Liabilities:
       
Accumulated deferred income taxes, net 
189
   201 
Accumulated deferred investment tax credits 
6
   7 
Regulatory liabilities 
74
   73 
Accrued pension and other postretirement benefits 
154
   171 
Other deferred credits and liabilities 
57
   27 
Total deferred credits and other liabilities 
480
   479 
Preferred Stock of Subsidiary Not Subject to Mandatory Redemption
 
19
   19 
Commitments and Contingencies (Notes 2 and 8)
       
Stockholder's Equity:
       
Common stock, no par value, 10,000 shares authorized – 1,000 shares outstanding 
-
   - 
Other paid-in capital 
627
   627 
Retained earnings 
45
   11 
Accumulated other comprehensive income 
31
   33 
Total stockholder's equity 
703
   671 
TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY
$
2,453
  $2,241 
        
CILCORP INC. 
CONSOLIDATED STATEMENT OF CASH FLOWS 
(Unaudited) (In millions) 
      
      
 
Three Months Ended
March 31,
 
 2008  2007 
Cash Flows From Operating Activities:     
Net income$20  $21 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Mark-to-market (gain) loss on derivatives (1)   - 
Depreciation and amortization 23   20 
Deferred income taxes and investment tax credits 4   (2)
Other -   (1)
Changes in assets and liabilities:       
Receivables (42)  (39)
Materials and supplies 49   48 
Accounts and wages payable 24   (30)
Taxes accrued 8   2 
Assets, other 7   11 
Liabilities, other 13   10 
Pension and postretirement benefit obligations (2)  2 
Net cash provided by operating activities 103   42 
Cash Flows From Investing Activities:       
Capital expenditures (79)  (43)
Changes in money pool advances -   42 
Other 1   - 
Net cash used in investing activities (78)  (1)
Cash Flows From Financing Activities:       
Short-term debt, net 10   74 
Changes in money pool borrowings -   31 
Intercompany note payable – Ameren, net 1   (73)
Redemptions, repurchases, and maturities:       
Long-term debt -   (50)
Net cash provided by (used in) financing activities 11   (18)
        
Net change in cash and cash equivalents 36   23 
Cash and cash equivalents at beginning of year 6   4 
Cash and cash equivalents at end of period$42  $27 

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


2123

CILCORP INC.      
CONSOLIDATED STATEMENT OF CASH FLOWS      
(Unaudited) (In millions)      
      
      
 
Nine Months Ended   
 
 
September 30,   
 
 
2007
  
2006
 
Cash Flows From Operating Activities:
     
Net income$
34
  $22 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Depreciation and amortization 
60
   74 
Amortization of debt issuance costs and premium/discounts 
1
   - 
Deferred income taxes and investment tax credits 
2
   8 
Loss on sale of noncore properties 
-
   4 
Other 
-
   1 
Changes in assets and liabilities:       
Receivables (38)  49 
Materials and supplies (18)  (22)
Accounts and wages payable (29)  (47)
Taxes accrued (3)  (9)
Assets, other (16)  24 
Liabilities, other 
22
   (4)
Pension and postretirement benefit obligations 
5
   4 
Net cash provided by operating activities 
20
   104 
        
Cash Flows From Investing Activities:
       
Capital expenditures (183)  (75)
Proceeds from note receivable – Resources Company 
-
   42 
Proceeds from sale of noncore properties 
-
   11 
Changes in money pool advances 
42
   - 
Purchases of emission allowances 
-
   (12)
Sales of emission allowances 
-
   1 
Net cash used in investing activities (141)  (33)
        
Cash Flows From Financing Activities:
       
Dividends on common stock 
-
   (50)
Capital issuance costs 
-
   (2)
Short-term debt, net 
325
   - 
Changes in money pool borrowings 
-
   (92)
Intercompany note payable – Ameren, net (73)  (30)
Borrowings from credit facility 
-
   40 
Redemptions, repurchases, and maturities:       
Long-term debt (50)  (32)
Preferred stock (1)  (1)
Issuances of long-term debt 
-
   96 
Net cash provided by (used in) financing activities 
201
   (71)
        
Net change in cash and cash equivalents 
80
   - 
Cash and cash equivalents at beginning of year 
4
   3 
Cash and cash equivalents at end of period$
84
  $3 
        
CENTRAL ILLINOIS LIGHT COMPANY 
CONSOLIDATED STATEMENT OF INCOME 
(Unaudited) (In millions) 
      
 
Three Months Ended
March 31,
 
 2008  2007 
Operating Revenues:     
Electric$194  $180 
Gas 151   135 
Total operating revenues 345   315 
        
Operating Expenses:       
Fuel 27   22 
Purchased power 78   76 
Gas purchased for resale 115   103 
Other operations and maintenance 48   41 
Depreciation and amortization 20   18 
Taxes other than income taxes 9   8 
Total operating expenses 297   268 
Operating Income 48   47 
Other Income and Expenses:       
Miscellaneous income -   1 
Miscellaneous expense -   (1)
Total other income -   - 
Interest Charges 6   6 
Income Before Income Taxes 42   41 
Income Taxes 16   14 
Net Income$26  $27 

The accompanying notes as they relate to CILCORP are an integral part of these consolidated financial statements.
22
CENTRAL ILLINOIS LIGHT COMPANY           
CONSOLIDATED STATEMENT OF INCOME           
(Unaudited) (In millions)           
            
 
Three Months Ended
September 30,
  
Nine Months Ended
September 30,
 
 
2007
  
2006
  
2007
  
2006
 
Operating Revenues:
           
Electric$
170
  $119  $
507
  $309 
Gas 
36
   38   
231
   236 
Other 
-
   -   
1
   1 
Total operating revenues 
206
   157   
739
   546 
                
Operating Expenses:
               
Fuel 
18
   22   
52
   70 
Purchased power 
74
   17   
206
   25 
Gas purchased for resale 
21
   24   
166
   175 
Other operations and maintenance 
46
   41   
133
   134 
Depreciation and amortization 
18
   18   
54
   52 
Taxes other than income taxes 
4
   4   
17
   17 
Total operating expenses 
181
   126   
628
   473 
                
Operating Income
 
25
   31   
111
   73 
                
Other Income and Expenses:
               
Miscellaneous income 
2
   -   
4
   - 
Miscellaneous expense (2)  (2)  (5)  (4)
Total other expenses 
-
   (2)  (1)  (4)
                
Interest Charges
 
8
   4   
19
   13 
                
Income Before Income Taxes
 
17
   25   
91
   56 
                
Income Taxes
 
7
   6   
33
   12 
                
Net Income
 
10
   19   
58
   44 
                
Preferred Stock Dividends
 
-
   -   
1
   1 
                
Net Income Available to Common Stockholder
$
10
  $19  $
57
  $43 
                
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
 
2324

CENTRAL ILLINOIS LIGHT COMPANY 
CONSOLIDATED BALANCE SHEET 
(Unaudited) (In millions) 
      
 March 31,  December 31, 
 2008  2007 
ASSETS     
Current Assets:     
Cash and cash equivalents$42  $6 
Accounts receivable – trade (less allowance for doubtful       
accounts of $6 and $2, respectively) 88   52 
Unbilled revenue 50   54 
Accounts receivable – affiliates 55   45 
Materials and supplies 61   110 
Other current assets 42   27 
Total current assets 338   294 
Property and Plant, Net 1,516   1,492 
Investments and Other Assets:       
Intangible assets 1   1 
Regulatory assets 30   32 
Other assets 44   43 
TOTAL ASSETS$1,929  $1,862 
        
LIABILITIES AND STOCKHOLDERS' EQUITY       
Current Liabilities:       
Current maturities of long-term debt$19  $- 
Short-term debt 355   345 
Accounts and wages payable 57   75 
Accounts payable – affiliates 40   34 
Taxes accrued 17   3 
Other current liabilities 50   45 
Total current liabilities 538   502 
Long-term Debt, Net 129   148 
Preferred Stock Subject to Mandatory Redemption 16   16 
Deferred Credits and Other Liabilities:       
Accumulated deferred income taxes, net 155   155 
Accumulated deferred investment tax credits 6   6 
Regulatory liabilities 241   220 
Accrued pension and other postretirement benefits 127   127 
Other deferred credits and liabilities 69   66 
Total deferred credits and other liabilities 598   574 
Commitments 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   19 
Other paid-in capital 429   429 
Retained earnings 198   172 
Accumulated other comprehensive income 2   2 
Total stockholders' equity 648   622 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY$1,929  $1,862 
 
CENTRAL ILLINOIS LIGHT COMPANY      
CONSOLIDATED BALANCE SHEET      
(Unaudited) (In millions)      
      
      
 
September 30,
  
December 31,
 
 
2007
  
2006
 
ASSETS
     
Current Assets:
     
Cash and cash equivalents$
72
  $3 
Accounts receivable – trade (less allowance for doubtful       
accounts of $3 and $1, respectively) 
51
   47 
Unbilled revenue 
29
   45 
Accounts receivable – affiliates 
59
   9 
Advances to money pool 
-
   42 
Materials and supplies 
111
   93 
Other current assets 
45
   32 
Total current assets 
367
   271 
Property and Plant, Net
 
1,400
   1,275 
Intangible Assets
 
1
   2 
Other Assets
 
25
   18 
Regulatory Assets
 
55
   75 
TOTAL ASSETS
$
1,848
  $1,641 
        
LIABILITIES AND STOCKHOLDERS' EQUITY
       
Current Liabilities:
       
Current maturities of long-term debt$
-
  $50 
Short-term debt 
365
   165 
Accounts and wages payable 
30
   54 
Accounts payable – affiliates 
44
   47 
Taxes accrued 
2
   3 
Other current liabilities 
63
   47 
Total current liabilities 
504
   366 
Long-term Debt, Net
 
148
   148 
Preferred Stock Subject to Mandatory Redemption
 
16
   17 
Deferred Credits and Other Liabilities:
       
Accumulated deferred income taxes, net 
156
   166 
Accumulated deferred investment tax credits 
6
   7 
Regulatory liabilities 
204
   206 
Accrued pension and other postretirement benefits 
154
   171 
Other deferred credits and liabilities 
57
   25 
Total deferred credits and other liabilities 
577
   575 
Commitments and Contingencies (Notes 2 and 8)
       
Stockholders' Equity:
       
Common stock, no par value, 20.0 shares authorized – 13.6 shares outstanding 
-
   - 
Preferred stock not subject to mandatory redemption 
19
   19 
Other paid-in capital 
429
   415 
Retained earnings 
155
   99 
Accumulated other comprehensive income 
-
   2 
Total stockholders' equity 
603
   535 
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY
$
1,848
  $1,641 
        
The accompanying notes as they relate to CILCO are an integral part of these consolidated financial statements.
 
2425
CENTRAL ILLINOIS LIGHT COMPANY     
CONSOLIDATED STATEMENT OF CASH FLOWS     
(Unaudited) (In millions)     
      
 
Nine Months Ended   
 
 
September 30,   
 
 
2007
  
2006
 
Cash Flows From Operating Activities:
     
Net income$
58
  $44 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Depreciation and amortization 
55
   61 
Amortization of debt issuance costs and premium/discounts 
1
   - 
Deferred income taxes and investment tax credits, net 
4
   15 
Loss on sale of noncore properties 
-
   6 
Changes in assets and liabilities:       
Receivables (32)  51 
Materials and supplies (18)  (20)
Accounts and wages payable (17)  (30)
Taxes accrued (3)  (17)
Assets, other (21)  14 
Liabilities, other 
16
   (6)
Pension and postretirement benefit obligations 
5
   9 
Net cash provided by operating activities 
48
   127 
        
Cash Flows From Investing Activities:
       
Capital expenditures (183)  (75)
Proceeds from sale of noncore properties 
-
   11 
Changes in money pool advances 
42
   - 
Purchases of emission allowances 
-
   (12)
Sales of emission allowances 
-
   1 
Net cash used in investing activities (141)  (75)
        
Cash Flows From Financing Activities:
       
Dividends on common stock 
-
   (65)
Dividends on preferred stock (1)  (1)
Capital issuance costs 
-
   (2)
Short-term debt, net 
200
   - 
Changes in money pool borrowings 
-
   (99)
Borrowings from credit facility 
-
   40 
Redemptions, repurchases, and maturities:       
Long-term debt (50)  (20)
Preferred stock (1)  (1)
Issuances of long-term debt 
-
   96 
Capital contribution from parent 
14
   - 
Net cash provided by (used in) financing activities 
162
   (52)
Net change in cash and cash equivalents 
69
   - 
Cash and cash equivalents at beginning of year 
3
   2 
Cash and cash equivalents at end of period$
72
  $2 
 
CENTRAL ILLINOIS LIGHT COMPANY 
CONSOLIDATED STATEMENT OF CASH FLOWS 
(Unaudited) (In millions) 
      
 
Three Months Ended
March 31,
 
 2008  2007 
Cash Flows From Operating Activities:     
Net income$26  $27 
Adjustments to reconcile net income to net cash       
provided by operating activities:       
Mark-to-market (gain) loss on derivatives  (1)  - 
Depreciation and amortization 20   19 
Deferred income taxes and investment tax credits, net 3   (3)
Other -   (1)
Changes in assets and liabilities:       
Receivables (41)  (35)
Materials and supplies 49   48 
Accounts and wages payable 24   (17)
Taxes accrued 14   11 
Assets, other 4   2 
Liabilities, other 5   5 
Pension and postretirement benefit obligations 1   2 
Net cash provided by operating activities 104   58 
Cash Flows From Investing Activities:       
Capital expenditures (79)  (43)
Changes in money pool advances -   42 
Other 1   - 
Net cash used in investing activities (78)  (1)
Cash Flows From Financing Activities:       
Short-term debt, net 10   (30)
Changes in money pool borrowings -   31 
Redemptions, repurchases, and maturities:       
Long-term debt -   (50)
Capital contribution from parent -   14 
Net cash provided by (used in) financing activities 10   (35)
Net change in cash and cash equivalents 36   22 
Cash and cash equivalents at beginning of year 6   3 
Cash and cash equivalents at end of period$42  $25 
        

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

 
2526
 

ILLINOIS POWER COMPANY
ILLINOIS POWER COMPANY
ILLINOIS POWER COMPANY 
CONSOLIDATED STATEMENT OF INCOME
CONSOLIDATED STATEMENT OF INCOME
CONSOLIDATED STATEMENT OF INCOME 
(Unaudited) (In millions)
(Unaudited) (In millions)
(Unaudited) (In millions) 
                
Three Months Ended
  
Nine Months Ended
      
September 30,   
  
September 30,   
 
Three Months Ended
March 31,
 
2007
  
2006
  
2007
  
2006
 2008  2007 
Operating Revenues:
                
Electric$
307
  $375  $
859
  $888 $238  $272 
Gas 
49
   59   
375
   381  264   241 
Other 
-
   1   
2
   2  1   2 
Total operating revenues 
356
   435   
1,236
   1,271  503   515 
                      
Operating Expenses:
                      
Purchased power 
211
   213   
573
   561  153   185 
Gas purchased for resale 
26
   35   
267
   272  205   185 
Other operations and maintenance 
74
   68   
197
   188  66   54 
Depreciation and amortization 
20
   20   
60
   57  25   26 
Amortization of regulatory assets 
4
   -   
12
   -  4   4 
Taxes other than income taxes 
13
   14   
50
   52  23   21 
Total operating expenses 
348
   350   
1,159
   1,130  476   475 
                      
Operating Income
 
8
   85   
77
   141  27   40 
                      
Other Income and Expenses:
                      
Miscellaneous income 
4
   2   
9
   4  3   2 
Miscellaneous expense (2)  (1)  (3)  (3) (1)  (1)
Total other income 
2
   1   
6
   1  2   1 
                      
Interest Charges
 
19
   13   
55
   37  24   16 
                      
Income (Loss) Before Income Taxes (Benefit)
 (9)  73   
28
   105 
Income Before Income Taxes 5   25 
                      
Income Taxes (Benefit)
 (5)  30   
10
   42 
Income Taxes 2   10 
                      
Net Income (Loss)
 (4)  43   
18
   63 
Net Income 3   15 
                      
Preferred Stock Dividends
 
1
   1   
2
   2  1   1 
                      
Net Income (Loss) Available to Common Stockholder
$(5) $42  $
16
  $61 
Net Income Available to Common Stockholder$2  $14 
                      
 
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
 
 
2627
 

ILLINOIS POWER COMPANY 
CONSOLIDATED BALANCE SHEET 
(Unaudited) (In millions) 
      
 March 31,  December 31, 
 2008  2007 
ASSETS     
Current Assets:     
Cash and cash equivalents$1  $6 
Accounts receivable - trade (less allowance for doubtful       
accounts of $16 and $9, respectively) 208   137 
Unbilled revenue 78   118 
Accounts receivable – affiliates 11   17 
Materials and supplies 47   134 
Other current assets 74   38 
Total current assets 419   450 
Property and Plant, Net 2,230   2,220 
Investments and Other Assets:       
Investment in IP SPT 11   10 
Goodwill 214   214 
Other assets 117   109 
Regulatory assets 298   316 
Total investments and other assets 640   649 
TOTAL ASSETS$3,289  $3,319 
        
LIABILITIES AND STOCKHOLDERS’ EQUITY       
Current Liabilities:
       
Current maturities of long-term debt$337  $ - 
Current maturities of long-term debt payable to IP SPT 36   54 
Short-term debt 150   175 
Accounts and wages payable 74   85 
Accounts payable – affiliates 28   36 
Taxes accrued 10   7 
Other current liabilities 90   80 
Total current liabilities 725   437 
Long-term Debt, Net 675   1,014 
Long-term Debt Payable to IP SPT -   2 
Deferred Credits and Other Liabilities:       
Regulatory liabilities 166   129 
Accrued pension and other postretirement benefits 192   189 
Accumulated deferred income taxes 141   148 
Other deferred credits and liabilities 96   92 
Total deferred credits and other liabilities 595   558 
Commitments 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   1,194 
Preferred stock not subject to mandatory redemption 46   46 
Retained earnings 50   64 
Accumulated other comprehensive income 4   4 
Total stockholders’ equity 1,294   1,308 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY$3,289  $3,319 
        
ILLINOIS POWER COMPANY     
CONSOLIDATED BALANCE SHEET     
(Unaudited) (In millions)     
      
 
September 30,
  
December 31,
 
 
2007
  
2006
 
ASSETS
     
Current Assets:
     
Cash and cash equivalents$
-
  $- 
Accounts receivable - trade (less allowance for doubtful       
accounts of $10 and $3, respectively) 
125
   105 
Unbilled revenue 
71
   101 
Accounts receivable – affiliates 
61
   1 
Materials and supplies 
156
   122 
Other current assets 
52
   27 
Total current assets 
465
   356 
Property and Plant, Net
 
2,190
   2,134 
Investments and Other Assets:
       
Investment in IP SPT 
9
   8 
Goodwill 
214
   214 
Other assets 
52
   62 
Regulatory assets 
353
   401 
Total investments and other assets 
628
   685 
TOTAL ASSETS
$
3,283
  $3,175 
        
LIABILITIES AND STOCKHOLDERS’ EQUITY
       
Current Liabilities:
       
Current maturities of long-term debt payable to IP SPT$
51
  $51 
Short-term debt 
200
   75 
Borrowings from money pool 
95
   43 
Accounts and wages payable 
82
   119 
Accounts payable – affiliates 
41
   67 
Taxes accrued 
6
   7 
Other current liabilities 
117
   72 
Total current liabilities 
592
   434 
Long-term Debt, Net
 
766
   772 
Long-term Debt Payable to IP SPT
 
24
   92 
Deferred Credits and Other Liabilities:
       
Regulatory liabilities 
93
   110 
Accrued pension and other postretirement benefits 
217
   230 
Accumulated deferred income taxes 
135
   138 
Other deferred credits and other noncurrent liabilities 
94
   53 
Total deferred credits and other liabilities 
539
   531 
Commitments and Contingencies (Notes 2 and 8)
       
Stockholders’ Equity:
       
Common stock, no par value, 100.0 shares authorized – 23.0 shares outstanding 
-
   - 
Other paid-in-capital 
1,194
   1,194 
Preferred stock not subject to mandatory redemption 
46
   46 
Retained earnings 
117
   101 
Accumulated other comprehensive income 
5
   5 
Total stockholders’ equity 
1,362
   1,346 
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY
$
3,283
  $3,175 
        

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

2728
 
ILLINOIS POWER COMPANY
ILLINOIS POWER COMPANY
ILLINOIS POWER COMPANY 
CONSOLIDATED STATEMENT OF CASH FLOWS
CONSOLIDATED STATEMENT OF CASH FLOWS
CONSOLIDATED STATEMENT OF CASH FLOWS 
(Unaudited) (In millions)
(Unaudited) (In millions)
(Unaudited) (In millions) 
          
Nine Months Ended   
      
September 30,   
 
Three Months Ended
March 31,
 
2007
  
2006
 2008  2007 
Cash Flows From Operating Activities:
          
Net income$
18
  $63 $3  $15 
Adjustments to reconcile net income to net cash              
provided by operating activities:              
Depreciation and amortization 
63
   18  26   22 
Amortization of debt issuance costs and premium/discounts 
6
   3  2   2 
Deferred income taxes 
8
   58  2   5 
Other  (1)  -  (1)  - 
Changes in assets and liabilities:              
Receivables (50)  60  (25)  (40)
Materials and supplies (34)  (34) 87   70 
Accounts and wages payable (45)  (62) (15)  (38)
Assets, other (16)  (1) (16)  17 
Liabilities, other 
54
   (5) 24   3 
Pension and other postretirement benefit obligations 
20
   8  2   2 
Net cash provided by operating activities 
23
   108  89   58 
              
Cash Flows From Investing Activities:
              
Capital expenditures (132)  (128) (33)  (46)
Changes in money pool advances -   (16)
Other (1)  (1) (1)  - 
Net cash used in investing activities (133)  (129) (34)  (62)
              
Cash Flows From Financing Activities:
              
Dividends on common stock (15)  - 
Dividends on preferred stock (2)  (2) (1)  (1)
Capital issuance costs 
-
   (1)
Short-term debt, net 
125
   -  (25)  115 
Changes in money pool borrowings, net 
52
   35  -   (43)
IP SPT maturities (65)  (69) (21)  (22)
Issuance of long-term debt 
-
   75 
Overfunding of TFNs 
-
   (17) 2   (2)
Net cash provided by financing activities 
110
   21 
Net cash provided by (used in) financing activities (60)  47 
Net change in cash and cash equivalents 
-
   -  (5)  43 
Cash and cash equivalents at beginning of year 
-
   -  6   - 
Cash and cash equivalents at end of period$
-
  $- $1  $43 
       
 
The accompanying notes as they relate to IP are an integral part of these consolidated financial statements.
 
 
2829
 
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, 2007March 31, 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 which are separate, independent legal entities with separate businesses, assets and liabilities,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 and natural gas transmission and distribution business, and a non-rate-regulated electric generation business (through its subsidiary, AERG), all 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-termshort- 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, throughwhich until February 29, 2008, was held 40% by UE and 40% by Development Company, which each own 40% of EEI.Company. Ameren consolidates EEI for financial reporting purposes, while UE reports its interest inreported EEI under the equity method. 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 and nine months ended September 30, 2007March 31, 2008 and 2006.2007.

Three Months
  
Nine Months
 Three Months 
2007
  
2006
  
2007
  
2006
 2008  2007 
Operating revenues$
117
  $
105
  $
324
  $
290
 $110  $97 
Operating income 
53
  
93
   
158
  
191
  64  54 
Net income 
34
  
56
   
99
  
117
  39  34 

The financial statements of the Ameren, Companies (except CIPS)Genco, CILCORP and CILCO are prepared on a consolidated basisbasis. CIPS has no subsidiaries and therefore includeis not consolidated. UE had a subsidiary in 2007 (Union Electric Development Corporation) but in January 2008, this subsidiary was transferred to Ameren in the accountsform of their majority-owned subsidiaries. All significant intercompany transactions have been eliminated. All tabular dollar amounts area stock dividend and in millions, unless otherwise indicated.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 at 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. Certain reclassifications have been made to the prior year’s financial statements to conform to our 2007 reporting presentation. These financial statements should be read in conjunction with the financial statements and the notes thereto included in the Form 10-K. All UE, CIPS, CILCORP, CILCO and IP financial information as of and for the three months ended March 31, 2007, included in this quarterly report reflects the correction of an error. During the third quarter of 2007, we identified and corrected a misallocation of first quarter 2007 purchased power expense
30
among Ameren subsidiaries. The error resulted in an understatement of UE purchased power expense of approximately $7 million and an overstatement of CIPS, CILCORP, CILCO and IP purchased power expense of approximately $2 million, $1 million, $1 million, and $4 million, respectively, during the three months ended March 31, 2007. The error resulted in an overstatement of UE net income of  $5 million, and an understatement of CIPS, CILCORP, CILCO and IP net income of approximately $1 million, $1 million,  $1 million, and $3 million, respectively, during the three months ended March 31, 2007. The error did not have a significant impact on previously reported subsidiary balance sheets or statements of cash flows, and the error had no impact on Ameren’s previously reported consolidated financial position, results of operations or cash flows.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts for the three and nine months ended September 30, 2007March 31, 2008 and 2006, due to an immaterial2007. The number of stock options, restricted stock shares, and performance share units outstanding.

29
outstanding was immaterial.
 
Long-term Incentive Plan of 1998 and 2006 Omnibus Incentive Compensation Plan

A summary of nonvested shares as of September 30, 2007, and changes during the nine-month period ended September 30, 2007,March 31, 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 Shares
  Performance Share Units  Restricted Shares
Shares
  
Weighted-average
Fair Value Per Unit  
Shares
Weighted-average
Fair Value Per Share 
 
Shares
  Weighted-average Fair Value Per Unit 
Shares
 
 Weighted-average
Fair Value Per Share
Nonvested at January 1, 2007  338,516  $
56.07
  377,776  $
45.79
 
Nonvested at January 1, 2008  669,403  $57.88  316,768  $46.23 
Granted(a)
 357,573  
59.60
  -  
-
  495,847  47.57  -  - 
Dividends -  
-
  11,567  
50.62
  -  -  2,900  43.71 
Forfeitures  (13,711) 
56.64
  (5,841) 
46.47
  -  -  (3,543) 47.11 
Vested(b)
 (12,975) 
59.14
  (70,391) 
43.84
  (40,575) 53.48  (113,640) 44.05 
Nonvested at September 30, 2007  669,403  $
57.88
  313,111  $
46.23
 
Nonvested at March 31, 2008  1,124,675  $53.50  202,485  $47.46 

(a)  Includes performance share units (share units) granted to certain executive and non-executive officers and other eligible employees in February 20072008 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 20072008 under the 2006 Plan was determined to be $59.60$47.57 based on Ameren’s closing common share price of $53.99$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 4.735%2.264%, dividend yields of 2.3% to 5.2%5.4% for the peer group, volatility of 12.91%14.43% to 18.33%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 $4$7 million and $3$5 million for the quartersquarter ended September 30,March 31, 2008 and 2007, and 2006, respectively, and a related tax benefit of $2$3 million and $1$2 million for the quartersquarter ended September 30,March 31, 2008 and 2007, and 2006, respectively. Ameren recorded compensation expense of $13 million and $8 million for the nine-month periods ended September 30, 2007 and 2006, respectively, and a related tax benefit of $5 million and $3 million for the nine-month periods ended September 30, 2007 and 2006, respectively. As of September 30, 2007,March 31, 2008, total compensation cost of $25$35 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of three years.25 months.

Accounting Changes and Other Matters

SFAS No. 157, Fair Value Measurements

FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of SFAS No. 109 (FIN 48)

FIN 48 addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, Ameren may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition of income tax assets and liabilities, classification of current and deferred income tax assets and liabilities, accounting for interest and penalties on income taxes, accounting for income taxes in interim periods, and requires expanded disclosures.

The Ameren Companies adopted the provisions of FIN 48 on January 1, 2007. The amount of unrecognized tax benefits as of January 1, 2007, was $155 million, $58 million,
$15 million, $36 million, $18 million, $18 million and $12 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. Of these unrecognized tax benefits on January 1, 2007, $20 million, $6 million, less than $1 million, less than $1 million, and less than $1 million for Ameren, UE, CIPS, Genco, and CILCORP, respectively, would impact the respective company’s effective tax rate, if recognized.

As of January 1, 2007, the Ameren Companies adopted a policy of recognizing interest and penalties accrued on tax liabilities on a gross basis as interest expense or penalty expense in the statements of income. Prior to January 1, 2007, the Ameren Companies recognized such items in the provision for taxes on a net-of-tax basis. As of January 1, 2007, Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP had recorded a liability of $12 million, $5 million, less than $1 million, $4 million, $1 million, less than $1 million, and less than
$1 million, respectively, for the payment of interest with respect to unrecognized tax benefits and no amount for penalties with respect to unrecognized tax benefits.

All of the Ameren Companies’ federal income tax returns are closed through 2001. The Ameren Companies are currently under federal income tax return examination for years 2002 through 2005. State income tax returns are generally subject to examination for a period of three years
30
after filing of the respective returns. 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. The Ameren Companies do not have state income tax returns in the process of examination. The Ameren Companies also do not have material state income tax issues in the process of administrative appeals or litigation.

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.

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. SFAS No. 157 clarifies that fair value is a market-based measurement that should be determined basedSee Note 7 – Fair Value Measurements for additional information on the assumptions that market participants would use in pricing an asset or liability. This standard is effective as of the beginning of our 2008 fiscal year. We are still determining the impact the adoption of SFAS No. 157 will have on our resultsin the first quarter of operations, financial position, and liquidity, if any; however, at this time, we do not expect the impact to be material.2008.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of SFAS No. 115
 
In February 2007, the FASB issued SFAS No. 159, which permits companies to choose to measure at fair value many financial instruments and certain assets and liabilities at fair value that are not currently required to be measured at fair value on an instrument-by-instrument basis. Entities electing the fair value option will bewere required to recognize changes in fair value in earnings and to expense upfront cost and fees associated with the item for which the fair value option is elected. SFAS No. 159 iswas effective as of the beginning of our 2008 fiscal
31
year. At this time, we doWe did not expect to elect the fair value option for any of our eligible financial instruments or other items.

FSP FIN 39-1, Amendment of FASB Interpretation No. 39

In April 2007, the FASB issued FSP FIN 39-1, effective for us as of the beginning of our 2008 fiscal year. FSP FIN 39-1 permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. We are currently evaluating whether we willdid not elect to applyadopt FSP FIN 39-1 for any of our eligible financial instruments or other items.

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

In March 2008, the accounting policies permitted under this pronouncement.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 FSP FIN 39-1SFAS No. 161 will not have noa material impact on net income, and we do not expect the impact to be material to our results of operations, financial position.position or liquidity since it only provides enhanced disclosure requirements.

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 asset 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, 20072008 to September 30, 2007,March 31, 2008, there were no changes in the carrying amount of goodwill.

Intangible Assets.At September 30, 2007, Ameren’s, UE’s, Genco’s, CILCORP’s and CILCO’s intangible assets consisted of emission allowances of $197 million at Ameren, $60 million at UE, $57 million at Genco, $42 million at CILCORP and $1 million at CILCO. 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.the following:

 
Ameren(a)
UEGenco
CILCORP(b)
CILCO
March 31, 2008     
Emission allowances(c)
$    189$    54$    58$    40$    1

(a)  Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)  Includes fair market value adjustments recorded in connection with Ameren’s acquisition of CILCORP.
(c)  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.

The following table presents the net book value of emission allowances consumed or (sold) for Ameren, UE, Genco, CILCORP and CILCO during the three and nine months ended September 30, 2007March 31, 2008 and 2006.2007.

Three Months
  
Nine Months
  Three Months 
2007
  
2006
  
2007
  
2006
  2008  2007 
Ameren(a)
$
7
  $(7) $
27
  $
18
  $7  $7 
UE (2) 
-
  (5) (2) (1) (3)
Genco 
8
  
9
  
23
  
24
  7  7 
CILCORP(b)
 
3
  
7
  
6
  
18
  -  2 
CILCO 
-
  
2
  
-
  
8
  -  1 

(a)  Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)  Includes allowances consumed that were recorded through purchase accounting.

31
Excise Taxes

Excise taxes imposed on us are reflected on Missouri electric, Missouri gas, and Illinois gas customer bills are imposed on us.bills. They are recorded on a gross basis 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 and nine months ended September 30, 2007March 31, 2008 and 2006:2007:

  Three Months 
  2008  2007 
Ameren $49  $42 
UE  25   23 
CIPS  6   5 
CILCORP  5   4 
CILCO  5   4 
IP  13   11 

32
 
Three Months
  
Nine Months
 
 
2007
  
2006
  
2007
  
2006
 
Ameren$
46
  $
43
  $
128
  $
129
 
UE 
38
   
35
   
88
   
87
 
CIPS 
2
   
2
   
11
   
11
 
CILCORP 
2
   
2
   
8
   
8
 
CILCO 
2
   
2
   
8
   
8
 
IP 
4
   
4
   
21
   
23
 
 
Uncertain Tax Positions

In the first quarter of 2008, Ameren settled the Internal Revenue Service’s examination of the 2002 through 2004 federal income tax returns. The settlement resulted in decreases to unrecognized tax benefits of $19 million,  $9 million, less than $1 million, $9 million, $1 million, $1 million and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. The settlement did not have a material effect on the results of operations of the Ameren Companies. The amount of unrecognized tax benefits as of March 31, 2008, was $102 million, $15 million, less than $1 million, $34 million, $19 million, $19 million and less than $1 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively.

Ameren is currently under federal income tax return examination for years 2005 and 2006. 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, Ameren does not believe such increases or decreases would be material to its financial condition or results of operations.

Asset Retirement Obligations

AROs at Ameren and UE increased compared to December 31, 2006,2007, to reflect the accretion of obligations to their fair values.

Prior Period Adjustment

During the third quarter of 2007, we identified a misallocation of first quarter 2007 purchased power expense among Ameren subsidiaries. The error resulted in an understatement of UE and Genco purchased power expense of approximately $7 million and $2 million, respectively, and an overstatement of CIPS, CILCORP, CILCO and IP purchased power expense of approximately $4 million, $1 million, $1 million, and $4 million, respectively, during both the three months ended March 31, 2007, and the six months ended June 30, 2007. The error resulted in an overstatement of UE and Genco net income of $5 million and $1 million, respectively, and an understatement of CIPS, CILCORP, CILCO and IP net income of approximately $3 million, $1 million, $1 million, and $3 million, respectively, during both the three months ended March 31, 2007, and the six months ended June 30, 2007. The error did not have a significant impact on previously reported subsidiary balance sheets or statements of cash flows, and the error had no impact on Ameren’s previously reported consolidated financial position or results of operations or cash flows.

All UE, CIPS, Genco, CILCORP, CILCO and IP financial information as of and for the nine months ended September 30, 2007, included in this quarterly report reflects the correction of the error. Previously-issued quarterly financial statements have not been restated, as management does not believe that the impact of these errors is material to the financial statements of UE, CIPS, Genco, CILCORP, CILCO  and IP as of and for the quarter ended March 31, 2007, and as of and for the six months ended June 30, 2007.
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

With the expiration of an electric rate moratorium that provided for no changes in UE’s electric rates before July 1, 2006, UE filed in July 2006 a request with the MoPSC in April 2008 to increase its annual revenues for a proposedelectric service by $251 million. The electric rate increase request proposes an average increase in electric rates of 17.7%, or $361 million,12.1% and is based on a requested10.9% return on equity, a capital structure composed of 12.0%. This51% common equity, a rate increase filing was based onbase of $5.9 billion and a test year ended June 30, 2006, and was updatedMarch 31, 2008, with updates for known and measurable itemschanges through January 1, 2007.June 30, 2008. In May 2007,the filing, UE has also requested that the MoPSC issued an order, as clarified, granting UEapprove implementation of a $43 million increase in base rates forfuel and purchased power cost recovery mechanism.

 The MoPSC proceeding relating to the proposed electric service based onrate changes will take place over a return on equityperiod of 10.2%up to 11 months, and a capital structure of 52% common equity. New electric rates became effective June 4, 2007. The MoPSC order also included the following significant provisions:
·  Acceptance without rate adjustment of the expiration of UE’s cost-based power supply contract with EEI, which expired in December 2005.
·  Allowance of the full cost of certain CTs purchased or built in the past few years to be included in UE’s rate base.
·  
Establishment of a regulatory tracking mechanism, through the use of a regulatory liability account, for gains on sales of SO2 emission allowances, net of SO2 premiums incurred under the terms of coal procurement contracts, plus any SO2discounts received under such contracts. These deferred amounts will be addressed as part of UE’s next rate case. The MoPSC allowed an annual base level of SO2 emission allowance sales of up to $5 million, which UE can recognize in its statement of income.
·  Approval of a regulatory tracking mechanism for pension and postretirement benefit costs.
·  Change of income tax method associated with the cost of property removal, net of salvage, to the normalization method of accounting, which reduced income tax expense in the calculation of UE’s electric rates and for financial reporting purposes.
·  Establishment of off-system sales base level of $230 million used in determining UE’s revenue requirement.

32
·  Extension of UE’s Callaway nuclear plant and fossil generation plant lives used in calculating depreciation expense for electric rates and financial reporting purposes.
·  MoPSC staff directed to review a possible loss in capacity sales as a result of the breach of the upper reservoir of the Taum Sauk pumped-storage hydroelectric facility.
·  Establishment of a requirement to fund low-income energy assistance and energy conservation programs; half of such funding will be recoverable through rates to customers.
·  Denial of UE’s request to implement a fuel and purchased power cost recovery mechanism.
In June 2007, the MoPSC denied UE’s and other intervenors’ applications for rehearing with respect to certain aspects of the MoPSC rate order. In July 2007, UE appealed certain aspects of the MoPSC decision principally the 10.2% return on equity granted by the MoPSC toin such proceeding is required by March 2009. UE cannot predict the Circuit Courtlevel of Cole County in Jefferson City, Missouri. The Office of Public Counsel and the Missouri attorney general, who were both intervenors in theany electric service rate case, also appealed certain aspects ofchange the MoPSC decisionmay approve, when any rate change may go into effect, whether the fuel and purchased power 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 Circuit Court of Cole County.increase goes into effect.

Taum Sauk
In June 2007, the MoPSC opened an investigation of the breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility in December 2005. In October 2007, the MoPSC staff issued its report on the Taum Sauk incident, and in November 2007 UE provided its response to the report.  The MoPSC is expected to issue an order on the investigation by the end of 2007.  See Note 8 – Commitments and Contingencies for additional information.

January 2007 Ice Storm Cost Recovery

UE submitted a filing to the MoPSC in November 2007 requesting that operations and maintenance expenses that 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'sUE’s next rate proceeding. UE incurred approximately $25 million of operations and maintenance expenses in the first quarter of 2007 as a result of the January storm.
Illinois In January 2008, the MoPSC staff recommended that the MoPSC grant UE’s request with the amortization to commence on January 15, 2007. On April 30, 2008, the MoPSC issued an accounting order that will give 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. We are currently evaluating this order.  UE may record a regulatory asset 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.

ElectricIllinois

New electric rates for Electric and Natural Gas Delivery Service Rate Cases

CIPS, CILCO and IP went into effect on January 2,filed requests with the ICC in November 2007 reflectingto increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million and IP - $139 million). The Ameren Illinois Utilities pledged in 2007 to keep the overall residential electric bill increase to less than 10% for each utility in their next rate filings. These filings are consistent with that pledge. Accordingly, the requested rate increase for IP residential customers is to be capped at the 10% increase level in the first year of the increase, even if the final
33
authorized rate increase exceeds that amount. This rate increase limit could result in approximately $30 million of the requested increase not being phased in until the second year. The amount of CIPS’ and CILCO’s requested increases did not require inclusion of similar limits, as they were within the scope of the pledge. The electric rate increase requests are based on an 11% return on equity, a capital structure composed of 51% to 53% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.1 billion and a test year ended December 31, 2006, with certain prospective updates.

CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS - $15 million increase, CILCO - $4 million decrease and IP - $56 million increase). The natural gas rate change requests are based on an 11% return on equity, a capital structure composed of 51% to 53% equity, an aggregate rate base for the Ameren Illinois Utilities of $0.9 billion and a test year ended December 31, 2006, with certain prospective updates.

In their filings, the Ameren Illinois Utilities have also requested that the ICC approve implementation of mechanisms that would permit the reconciliation and adjustment of actual bad debt expenses to those established in rates set by the ICC for electric and gas customers. The filings also seek a more timely recovery of investments in existing electric distribution plant. Because general rate adjustment proceedings require up to 11 months in Illinois, these mechanisms would allow current revenues to better match current costs. In addition, the Ameren Illinois Utilities are seeking approval of a revenue decoupling rate adjustment mechanism as a part of their natural gas delivery service rate change requests. This mechanism would separate each utility’s fixed cost recovery from the volume of gas it sells by providing a periodic true-up of revenues. The periodic true-up would result in adjustments to a utility’s ICC-approved tariffs approvedbased on increases or decreases in demand for natural gas.

In March 2008, the ICC staff filed direct testimony in response to the Ameren Illinois Utilities electric and natural gas delivery service rate increase filings. The ICC staff recommended in their testimony a net increase in revenues for electric delivery service for the Ameren Illinois Utilities of $38 million in the aggregate (CIPS - $2 million decrease, CILCO - $12 million decrease, and IP - $52 million increase) and a net increase in revenues for natural gas delivery service of $9 million in the aggregate (CIPS - $3 million increase, CILCO - $14 million decrease, and IP - $20 million increase). The ICC staff in their direct testimony also opposed the Ameren Illinois Utilities’ requests to implement cost recovery mechanisms for bad debt expenses and electric infrastructure investments that are being proposed to reduce regulatory lag. In their direct testimony, the ICC staff offered limited support for the Ameren Illinois Utilities’ request to implement a rate adjustment mechanism for the decoupling of natural gas revenues from sales volumes. Other parties also made recommendations through direct testimony in the rate cases.

In April 2008, the Ameren Illinois Utilities revised their revenue requirement requests in rebuttal testimony filed with the ICC. CIPS, CILCO and IP revised their requests to an increase in annual revenues for electric delivery service of $163 million in the aggregate (CIPS - $28 million, CILCO - $4 million, and IP - $131 million) and an increase in annual revenues for natural gas delivery service of $57 million in the aggregate (CIPS - $11 million increase, CILCO - $4 million decrease, and IP - $50 million increase). The Ameren Illinois Utilities revised their requested annual revenues for electric and natural gas delivery service because they accepted some of the positions proposed by the ICC staff and intervenors. The Ameren Illinois Utilities also withdrew their requests to implement a cost recovery mechanism for bad debt expense as a part of their rebuttal testimony.

The ICC proceedings relating to the proposed electric and natural gas delivery service rate changes will take place over a period of up to 11 months, and decisions by the ICC in November 2006 and full cost recoverysuch proceedings are required by the end of power purchased on behalf ofSeptember 2008. The Ameren Illinois Utilities’ customers inUtilities cannot predict the September 2006 auction in accordance with a January 2006level of any delivery service rate change the ICC order. As a result of these new electric rates goingmay approve, when any rate change may go into effect, whether any rate adjustment mechanism will be approved, or whether any rate increase that may eventually be approved will be sufficient for the estimated average annual residential rate overallAmeren Illinois Utilities to recover their costs and earn a reasonable return on their investments when the increase in 2007 was expected to be 40% to 55% over 2006 rates. The estimated average annual residential rate overall increase for electric heat customers was expected to be 60% to 80% over 2006 rates.goes into effect.

Due to the magnitude of these rate increases, various legislators supported legislation that would have reduced and frozen the electric rates of CIPS, CILCO and IP to the rates that were in effect prior to January 2, 2007, and would have imposed a tax on electric generation in Illinois to help fund customer assistance programs. The Illinois governor also supported rate rollback and freeze legislation. Electric Settlement Agreement

In July 2007, an agreement was reached among key stakeholders in Illinois designed to avoid suchrate 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 which includesinclude a comprehensive rate relief and customer assistance program, were set forth in a letter dated July 24, 2007, to the leaders of the Illinois General Assembly and the Illinois attorney general, in a release and settlement agreement with the Illinois attorney general, in funding agreements among the parties contributing to the rate relief and assistance programs and in legislation, which became effective on August 28, 2007.program. The following is a discussion of this agreement, including its impact on future power procurement for the Ameren Illinois Utilities, and outstanding significant regulatory and related legal matters affecting our Illinois electric operations.

Electric Settlement Agreement

The settlement agreement was the result of many months of negotiations among leaders of the House of Representatives and Senate in Illinois, the office of the Illinois attorney general, Ameren, on behalf of its affiliates, including Marketing Company, Genco and AERG, the Ameren Illinois Utilities, Exelon Corporation (Exelon), on behalf of Exelon Generation Company LLC, Commonwealth Edison Company, Exelon’s Illinois electric utility subsidiary, Dynegy Holdings Inc., Midwest Generation, LLC, and MidAmerican Energy Company. The comprehensive program 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 comprehensive program,Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG have 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 $28 million from AERG. Below is a summary ofSee Note 9 – Commitments and Contingencies for information on the total customer relief and assistanceremaining contributions to be provided to the customersmade as of the Ameren Illinois Utilities, the Ameren Illinois Utilities’, Genco’s and AERG’s portion of the funding
33
that is expected to be disbursed, and the expected charges to earnings as a result of the program and agreement.
 
Total
Relief/Assistance
to Ameren
Illinois
Customers
  
Ameren
Subsidiaries’
Funding(a)
  
Estimated
Ameren Earnings
Per Share
Impact(b)
 
2007$
253,000,000
  $
86,000,000
  $
0.26
 
2008 132,000,000   
37,000,000
   
0.11
 
2009 
97,000,000
   
25,000,000
   
0.07
 
2010 
6,000,000
   
2,000,000
   
0.01
 
Total$
488,000,000
  $
150,000,000
  $
0.45
 

(a)  Includes a $4.5 million contribution in 2007 towards funding of a newly-created IPA.
(b)  Includes estimated cost of proposed forgiveness of outstanding customer late payment fees.
March 31, 2008.

The Ameren Illinois Utilities, Genco and AERGCILCO (AERG) will recognize in their financial statements the costs of their
34
respective rate relief contributions and program funding in a manner corresponding with the timing of the funding included in the above table.funding. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues, of $59 million, $8 million, $5 million, $11 million,  $24$2 million, $1 million, $2 million, $4 million, and $11$2 million, respectively, under the terms of the Illinois electric settlement agreement during the quarter ended September 30, 2007. At September 30, 2007, Ameren, CIPS, CILCO and IP (Illinois Regulated) had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $108 million, $37 million, $21 million and $50 million, respectively.March 31, 2008.

Other electric generators and utilities in Illinois have 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 willsend a bill, due in 30 days, to the Generators and utilities for their proportionate share of that month’s rate relief and assistance, which will be due in 30 days.assistance. If any escrow funds have been provided by the Generators, these funds will be drawn prior to seeking reimbursement from the Generators. At March 31, 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.

The settlement agreement preserves existing rates and rate structures, andIn early 2008, the Ameren Illinois Utilities retain the right to file new electric delivery service rate cases with the ICC at the respective utility’s discretion. See Electric Delivery Service Rate Cases belowcontracted for information on electric delivery service rate increase requests recently filed by the Ameren Illinois Utilities. The settlement agreement provides that if legislation is enacted in Illinois before August 1, 2011, freezing or reducing retail electric rates, or imposing or authorizing a new tax, special assessment or fee on the generationmost of electricity, then thetheir remaining commitments under this agreement would expire,power and any funds set aside in support of the commitments would be refunded to the utilities and Generators.

As part of the settlement agreement, the current reverse auction used for power procurement in Illinois was discontinued and replaced with a new power procurement process. In 2008, Illinois utilities will contract for their necessary baseload, intermediate and peaking powerenergy requirements through a request-for-proposal process, subject to ICC review and approval. Also as part of the agreement, existing supply contracts from the September 2006 reverse auction remain in place. In October 2007, CIPS, CILCO and IP filed a proposal with the ICC to formalize the structure of the power procurement process and related products for the period June 1, 2008 through May 31, 2009.2009 through request-for-proposal processes, which were approved by the ICC in March and April 2008. See Note 9 – Commitments and Contingencies for additional information.

As partRedesigned 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 the settlement agreement,electricity. The redesigned rates will not change total annual revenue collected by the Ameren Illinois Utilities enteredin 2008 or in subsequent years.

Federal

Regional Transmission Organization

UE, CIPS, CILCO and IP are transmission-owning members of MISO, which is a FERC-regulated RTO that provides transmission tariff administration services for electric transmission systems. In early 2004, UE received authorization from the MoPSC to participate in MISO for a five-year period, with further participation subject to approvals by the MoPSC. The MoPSC required UE to file a study evaluating the costs and benefits of its participation in MISO prior to the end of the five-year period. The MoPSC also directed UE to enter into financial contractsa service agreement for MISO to provide transmission service to UE’s bundled retail customers. 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 particular, the service agreement provided that UE would not pay MISO for transmission service to UE’s bundled retail customers. FERC approved the service agreement in the form that was acceptable to the MoPSC.
Due to recent changes to MISO’s allocation of transmission revenues to transmission owners, UE believed it should receive incremental annual transmission revenues of $60 million as of February 2008 based on its service agreement with Marketing Company (forMISO. Numerous transmission owners in MISO, along with MISO itself as the benefittariff administrator, filed with FERC in December 2007 requesting changes to the MISO tariff to prevent UE from collecting these additional transmission revenues. In December 2007, UE filed a protest to these proposed MISO tariff changes as unauthorized and improper in light of Gencothe MoPSC’s requirement for the service agreement between UE and AERG),MISO discussed above. In February 2008, FERC issued an order accepting the MISO tariff changes proposed by MISO and transmission owners in MISO. In March 2008, UE filed a request with FERC for a rehearing of its order. UE is unable to lock-in energy pricespredict if or when FERC may issue a further order in this proceeding.

In a separate proceeding filed with FERC in March 2008, UE joined the other MISO transmission owners (including CIPS, CILCO and IP) and the MISO in proposing a mechanism to implement the tariff changes approved in the February 2008 order. In joining this proposal, UE preserved its right to continue to pursue its arguments in the underlying proceeding, including UE’s pending request for 400rehearing.
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 discussed above. If some of these uncertainties are ultimately resolved in a manner adverse to 1,000 megawatts annuallyUE, it could call into question whether it is cost-effective for UE to remain in MISO.  UE has advised MISO of their around-the-clock power requirements during the period June 1, 2008its intent to withdraw from MISO as of December 31, 2012, at relevant market prices. These financial contracts do not include capacity, are not load-following products and do not involve the physical delivery of energy. These financial contracts became effective on August 28, 2007, when legislation2008, in connection with the settlement agreement became law. Below are the contracted volumes and prices per megawatthour.

Period
Volume
Price per
Megawatthour
June 1, 2008 – December 31, 2008400 MW
$47.45
January 1, 2009 – May 31, 2009400 MW
49.47
June 1, 2009 – December 31, 2009800 MW
  49.47
January 1, 2010 – May 31, 2010800 MW
51.09
June 1, 2010 – December 31, 20101,000 MW
51.09
January 1, 2011 – December 31, 20111,000 MW
52.06
January 1, 2012 – December 31, 20121,000 MW
53.08

The financial contracts provide that if any one of the following events occurs during their term, the Ameren Illinois Utilities and Marketing Company will meet as soon as practicable, but no later than 30 days after the date such event occurs, to identify and discuss its effect on the terms and conditions of, and prices under the financial contracts: a) a state tax on electric generation; b) a state or federal tax on and/or regulation of greenhouse gas emissions (e.g., a carbon tax); or c) if the state of Illinois enacts a law that eliminates retail electric supplier choice for the residential and small commercial customers of the Ameren Illinois Utilities. The financial contracts also provide that if any one of these events occurs, the parties to the financial contracts will negotiate to determine in a commercially reasonable manner whether the affected terms, conditions and prices can be revised so asorder to preserve the economic benefitsoption to withdraw based on the outcome of the financial contracts for all parties andpending MoPSC proceeding. It is uncertain when or how the MoPSC will rule on UE’s MISO cost-benefit study or, if UE were to revisewithdraw from MISO, what the financial contracts accordingly. In the event the parties to the financial contracts are not able to agree oneffect of such revisions, Marketing Company may terminate the financial contracts by written notice no earlier than 60 days and no later than 90 days after such event occurs, with the termination being effective when
34
notice is given. Under the terms of the settlement agreement and the legislation, these financial contracts are deemed prudent, and the Ameren Illinois Utilities are permitted full recovery of their costs in rates.

Beginning in June 2009 and thereafter, power procurement will be accomplished through competitive requests for proposals to supply the separate baseload, intermediate and peaking power needs of the utility instead of the full requirements, load-following supply contracts previously procured through the reverse auction. The power procurement process that is expected to be implemented would require the IPA to develop an annual Procurement Plan (Plan) for the Ameren Illinois Utilities and Commonwealth Edison. Each Plan would govern a utility’s procurement of power to meet the expected load requirements that are not met by pre-existing contracts or generation facilities. Subject to ICC approval, the Ameren Illinois Utilitieswithdrawal would be allowed to lease, or invest in, generation facilities. The objective of each Plan would be to ensure adequate, reliable, affordable, efficient, and environmentally sustainable electric service at the lowest total cost over time, taking into account any benefits of price stability for the utilities’ eligible retail customers. The power procurement process provides that each Plan be submitted to the ICC for initial approval; if approved, the final design and implementation of a Plan would be overseen by an independent procurement administrator selected by the IPA and a procurement monitor selected by the ICC. The IPA has broad authority to assist in the procurement of electric power for residential and nonresidential customers beginning in June 2009. Winning proposals will be selected on the basis of price, compared for reasonableness to benchmarks developed by the procurement administrator and procurement monitor, and approved by the ICC.UE.

The power procurement process provides for the subject electric utility in Illinois to file proposed tariffs with the ICC, which will be designed to pass-through to customers the costs of procuring electric power supply with no mark-up on the price paid by the utility, plus any reasonable costs that the utility incurred in arranging and providing for the supply of electric power. All such procurement costs will be deemed to have been prudently incurred and recoverable through rates.

The settlement agreement and the legislation provide that the Ameren Illinois Utilities have a right to maintain membership in a FERC-approved regional transmission organization of their choice for a period of at least 15 years.
The settlement agreement and the legislation also include a commitment to energy conservation programs designed to reduce energy consumption through increased energy efficiency and demand response. In addition, 2% of the Illinois utilities’ electricity is to be procured from renewable sources beginning June 1, 2008, with that percentage increasing in subsequent years, subject to limits on customer rate impacts. The provision for full and timely recovery of the cost of these commitments is also included in the settlement agreement and the legislation.

Pursuant to the settlement agreement, all previously pending litigation and regulatory actions by the office of the Illinois attorney general relating to the reverse auction procurement process, which was used to determine market-based rates effective January 1, 2007, and the electric space heating marketing practices of the Ameren Illinois Utilities have been withdrawn with prejudice. The litigation and regulatory actions included those filed by the office of the attorney general with the FERC, the ICC, the United States Court of Appeals for the District of Columbia Circuit and the Circuit Court of the First Judicial Circuit Jackson County, Illinois and the Appellate Court of Illinois, Second Judicial Circuit.

Finally, the settlement agreement establishes the authority to obtain accelerated review by the ICC of a merger or combination of the three Ameren Illinois Utilities, if requested in the future.

Appeals of 2006 ICC Procurement Order

The Illinois attorney general, CUB, and ELPC, appealed to Illinois district appellate courts the ICC’s denial of rehearing requests with respect to its January 2006 order, which approved the power procurement auction and related tariffs. In August 2006, the Supreme Court of Illinois ordered that the appeals be consolidated in the appellate court for the Second Judicial Circuit in Illinois. The Illinois attorney general’s appeal at the Second Judicial Circuit appellate court was withdrawn as part of the agreement discussed above. CUB’s and ELPC’s appeals at the Second Judicial Circuit appellate court are still pending. The Ameren Illinois Utilities filed a motion to dismiss the appeals in September 2007.

Power Procurement Auction Lawsuits

Ameren, CIPS, CILCO, IP, Commonwealth Edison Company and its parent company, Exelon, and 15 electricity suppliers, including Marketing Company, which are selling power to the Illinois utilities pursuant to contracts entered into as a result of the September 2006 power procurement auction, were named as defendants in two similar lawsuits seeking class action status filed in the Circuit Court of Cook County, Illinois in March 2007. The classes have yet to be certified. The asserted class seeks to represent all customers who purchased electric service from Commonwealth Edison Company or the Ameren Illinois Utilities. Both lawsuits allege, among other things, that the Illinois utilities and the power suppliers illegally manipulated prices in the September 2006 power procurement auction. The relief sought in both lawsuits is actual damages to be determined at trial and legal costs,
 
35
 
including attorneys’ fees. One of the lawsuits also seeks punitive damages and recovery of illegal profits and excludes the Ameren Illinois Utilities from the requests for relief. In April 2007, the defendants in these lawsuits filed notices removing these cases to the U.S. District Court for the Northern District of Illinois. The defendants have pending motions to dismiss.  These two lawsuits are not affected by the settlement agreement discussed above.

Redesigned Rates

In October 2007, the ICC issued an order authorizing redesigned electric rates for CIPS, CILCO and IP to be implemented December 1, 2007. These rates were designed to reduce seasonal fluctuations for residential customers who use large amounts of electricity while allowing utilities to fully recover costs. The ICC subsequently issued a rehearing order in late October 2007, granting CIPS’, CILCO’s and IP’s rehearing request to change the implementation date of the rate redesign for certain customers to January 1, 2008. The ICC granted the change in effective date to ensure the implementation of redesigned rates was revenue neutral to the Ameren Illinois Utilities in 2007 and subsequent calendar years.

Electric and Natural Gas Delivery Service Rate Cases
CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million and IP - $139 million).  The Ameren Illinois Utilities pledged earlier this year to keep the overall residential electric bill increases to less than 10% per year for each utility in their next rate filings.  These filings are consistent with that pledge.  Accordingly, the requested rate increase for IP residential customers is proposed to be capped in the first year of the increase if the amount of the final authorized rate increase exceeds the first year capped rate level.  This rate increase limit could result in approximately $30 million of the requested increase not being phased in until the second year.  The amount of CIPS' and CILCO's requested increases did not require inclusion of similar limits as they were within the scope of the pledge.  The electric rate increase requests are based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $2.1 billion, and a test year ended December 31, 2006, with certain prosective updates.
CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS - 
$15 million increase, CILCO - $4 million decrease and IP - $56 million increase).  The natural gas rate change requests are based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $0.9 billion and a test year ended December 31, 2006, with certain prospective updates.
In their filings, the Ameren Illinois Utilities have also requested ICC approval to implement mechanisms that would permit the reconciliation and adjustment of actual bad debt expenses to those established in rates by the ICC for electric and gas customers and the more timely recovery of investments in existing electric distribution plant. Since general rate adjustment proceedings require up to 11 months in Illinois, these mechanisms would allow current revenues to better match current costs. In addition, the Ameren Illlinois Utilities are seeking approval of a revenue decoupling rate adjustment mechanism as a part of their natural gas delivery service rate change requests.  This mechanism would separate each utility's fixed cost recovery from the volume of gas it sells by providing a periodic true-up of revenues.  The periodic true-up would result in adjustments to a utility's ICC-approved tariffs based on increases or decreases in demand for natural gas.
The ICC proceedings relating to the proposed electric and natural gas delivery service rate changes will take place over a period of up to 11 months, and decisions by the ICC in such proceedings are required by October 2008.  The Ameren Illinois Utilities cannot predict the level of any delivery service rate change the ICC may approve, when any rate change may go into effect, whether any rate adjustment mechanism discussed above will be approved or whether any rate increase that may eventually be approved will be sufficient for the Ameren Illinois Utilities to recover their costs and earn a reasonable return on their investments when the increase goes into effect.  
Federal

FERC Order – MISO Charges

In May 2007, Ameren Services, on behalf of UE, CIPS, CILCO and IP, filed with the United States Court of Appeals for the District of Columbia Circuit, an appeal of the 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 the FERC’s motion to hold the appeal in abeyance pending completion of the underlying proceedings at the FERC. Other MISO participants also filed appeals. On November 5, 2007, the FERC issued orders relative to these allocation matters.  We are evaluating the impact of these orders and cannot determine their ultimate impact at this time.

UE Power Purchase Agreement with Entergy Arkansas, Inc.

In July 2007, as a consequence of a series of orders issued by the FERC addressing a complaint filed by the Louisiana Public Service Commission against Entergy

36
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. These additionalAdditional charges to UE are expected to approximate $13 million for 2007 and additional amounts continue during the remainder of the term of the power purchase agreement, which terminatesexpires effective August 25, 2009. Although UE was not a party to the FERC proceedings that gave rise to these additional charges, UE intervened in August 2007 in a related FERC proceeding forand filed a complaint with the purpose of challengingFERC against Entergy and Entergy Services, Inc. in April 2008 to challenge the additional charges. UE is unable to predict whether the FERC will grant any relief.
 
NOTE 3 – CREDIT FACILITIES 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, 2007,March 31, 2008, under the $1.15 billion credit facility and the 2007 and 2006
$500 $500 million credit facilities:

$1.15 Billion Credit Facility(a)
Ameren (Parent)
  
UE
  
Genco
  
Ameren Total
 
September 30, 2007:
           
Average daily borrowings outstanding during 2007$
164
  $
350
  $
6
  $
520
 
Outstanding short-term debt at period end 
250
   
92
   
75
   
417
 
Weighted-average interest rate during 2007 5.90%  5.70%  5.26%  5.76%
Peak short-term borrowings during 2007$
350
  $
506
  $
75
  $
856
 
Peak interest rate during 2007 8.25%  8.25%  5.75%  8.25%
$1.15 Billion Credit Facility Ameren (Parent) UE  Genco  Total 
March 31, 2008:            
Average daily borrowings outstanding during 2008 $530  $127  $118  $775 
Outstanding short-term debt at period end  550   208(a)  150   908(a)
Weighted-average interest rate during 2008  4.41%  3.79%  4.18%  4.27%
Peak short-term borrowings during 2008 $675  $283  $150  $983 
Peak interest rate during 2008  7.25%  5.65%  5.53%  7.25%

(a)  Includes issuances under a commercial paper programsprogram of $58 million at Ameren and UE supported by this credit facility.facility as of March 31, 2008.

2007 $500 Million Credit Facility CIPS  CILCORP (Parent)  
CILCO
(Parent)
  
IP
  AERG  
Total
 
March 31, 2008:                  
Average daily borrowings outstanding during 2008 $-  $125  $58  $179  $82  $444 
Outstanding short-term debt at period end  -   125   75   150   100   450 
Weighted-average interest rate during 2008  -   5.35%  5.02%  4.99%  4.82%  5.06%
Peak short-term borrowings during 2008 $-  $125  $75  $200  $100  $490 
Peak interest rate during 2008  -   6.66%  6.47%  6.15%  6.22%  6.66%
2006 $500 Million Credit Facility                        
March 31, 2008:                        
Average daily borrowings outstanding during 2008 $106  $50  $18  $6  $186  $366 
Outstanding short-term debt at period end  85   50   -   -   180   315 
Weighted-average interest rate during 2008  4.91%  5.36%  5.29%  6.50%  4.96%  5.03%
Peak short-term borrowings during 2008 $135  $50  $40  $100  $190  $465 
Peak interest rate during 2008  6.31%  7.01%  5.98%  6.50%  7.01%  7.01%
2007 $500 Million Credit Facility
 
CIPS
  
CILCORP (Parent)
  
CILCO
(Parent)
  
IP
  
AERG
  
Total
 
September 30, 2007:
                  
Average daily borrowings outstanding during 2007 $-  $98  $23  $120  $
73
  $314 
Outstanding short-term debt at period end  -   
125
   75   200   100   
500
 
Weighted-average interest rate during 2007  
-
   6.87%  6.31%  6.53%  6.84%  6.69%
Peak short-term borrowings during 2007 $-  $125  $75  $200  $
100
  $500 
Peak interest rate during 2007  
-
   8.63%  6.47%  6.64%  7.02%  8.63%
2006 $500 Million Credit Facility
                        
September 30, 2007:
                        
Average daily borrowings outstanding during 2007 $92  $
48
  $62  $79  $
95
  $376 
Outstanding short-term debt at period end  135   50   
75
   -   115   375 
Weighted-average interest rate during 2007  6.52%  6.82%  6.28%  6.59%  6.89%  6.62%
Peak short-term borrowings during 2007 $135  $
50
  $75  $125  $
115
  $500 
Peak interest rate during 2007  8.25%  7.04%  6.47%  6.64%  8.25%  8.25%

At September 30, 2007,March 31, 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 $1.15 billion, $500 million and $500 million maturing in July 2010, January 2010 and January 2010, respectively.

Effective July 12, 2007, Under the $1.15 billion facility, the termination date for UE’sUE and Genco’s direct borrowing sublimits under the $1.15 billion credit facility was extended toGenco is July 10, 2008, pursuantsubject to thean annual 364-day renewal provisions ofprovision in the facility. The $1.15 billion credit facility will terminate on July 14, 2010, with respect to Ameren.

The $1.15 billion credit facility was used to support the commercial paper programs that included $92 million of outstanding commercial paper of UE as of September 30, 2007.

The 2007 $500 million credit facility was entered into in February 2007, by CIPS, CILCORP, CILCO, IP and AERG.

The obligations of IP under the 2007 $500 million credit facility were secured by the issuance of mortgage bonds in the amount of $200 million. CIPS and CILCO cannot utilize any amount of their borrowing authority under the 2007 $500 million credit facility until they reduce their borrowing authority by an equal amount under the 2006 $500 million credit facility. If CIPS or CILCO elect to transfer borrowing authority from the 2006 $500 million credit facility to the 2007 $500 million credit facility, that company must retire an appropriate amount of first mortgage bonds issued with respect to the 2006 $500 million credit facility and issue new bonds in an equal amount to secure its obligations under the 2007 $500 million credit facility. In July 2007, CILCO permanently reduced its $150 million of borrowing authority under the 2006 $500 million credit facility by $75 million and shifted that amount of capacity to the 2007 $500 million credit

37

facility. CILCO is now considered a borrower under both credit facilities and is subject to the covenants of both.

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 currently limited in their access to the commercial paper market as a result of downgrades in their short-term credit ratings.

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

CIPS, CILCO and IP borrow from each other through the utility money pool agreement subject to applicable regulatory short-term borrowing authorizations. AERG may make loans to, but may not borrow from, the utility money pool. Although UE and Ameren Services are parties to the utility money pool agreement, they are not currently borrowing or lending under the agreement. The average interest rate for borrowing under the utility money pool for the three and nine months ended September 30, 2007, was 5.4% and 5.7%, respectively (2006 – 5.4% and 5.0%, respectively).

Non-state-regulated Subsidiaries

Ameren Services, Resources Company, Genco, AERG, Marketing Company, AFS, Ameren Energy 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 funding from Ameren’s $1.15 billion credit facility through a non-state-regulated subsidiary money pool agreement. At September 30, 2007, $728 million was available through the non-state-regulated subsidiary money pool, excluding additional funds available through excess cash balances. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three and nine months ended September 30, 2007, was 5.6% and 5.1%, respectively (2006 – 4.8% and 4.6%, respectively).

See Note 7 – Related Party Transactions for the amount of interest income (expense) from the money pool arrangements recorded by the Ameren Companies for the three and nine months ended September 30, 2007 and 2006.

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 54 – Credit Facilities and Liquidity in the Form 10-K, for a detailed description of those provisions.

The Ameren Companies’ bank credit facilities contain provisions that, among other things, place restrictions on the ability to incur liens, sell assets, and merge with other entities. The $1.15 billion credit facility contains provisions that limit total indebtedness of each of Ameren, UE and Genco to 65% of total consolidated capitalization pursuant to a calculation defined in the facility. Exceeding these debt levels would result in a default under the $1.15 billion credit facility.

36
The $1.15 billion credit facility also contains provisions for default, provisions, including cross defaults, with respect to a borrower under the facility thatborrower. Defaults can result from the occurrence of an event of default under any other facility covering indebtedness of that borrower or certain of its subsidiaries in excess of $50 million in the aggregate. The obligations of Ameren, UE and Genco under the facility are several and not joint, and except under limited circumstances, the obligations of UE and Genco are not guaranteed by Ameren or any other subsidiary. CIPS, CILCORP, CILCO, AERG and IP are not considered subsidiaries for purposes of the cross-default or other provisions.

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

Both the 2007 $500 million credit facility and the 2006 $500 million credit facility entered into by CIPS, CILCORP, CILCO, IP and AERG, discussed above, limit the indebtedness of each borrower to 65% of consolidated total capitalization pursuant to a calculation set forth in the facilities. Events of default under these facilities apply separately to each borrower (and, except in the case of CILCORP, to their subsidiaries), and an event of default under these facilities does not constitute an event of default under the $1.15 billion credit facility and vice versa. In addition, 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-gradebelow investment-grade credit rating byfrom either Moody’s or S&P. With respect to AERG, which currently is not rated by Moody's or S&P, then such borrower will be limited to capitalthe common and preferred stock dividend paymentsrestriction will not apply if its ratio of $10 million per year each, while such below-investment-grade credit ratingconsolidated total debt to consolidated operating cash flow, pursuant to a calculation defined in the facilities, is in effect. On July 26, 2006, Moody’s downgradedless than or equal to 3.0 to 1.0. CILCORP’s
38
senior unsecured long-term debt credit rating tofrom Moody’s is below investment-grade, causing it to be subject to this dividend payment limitation. A similar restriction does not apply to AERG, which is currently not rated by Moody’s or S&P, if its debt-to-operating cash flow ratio, as set forth in these facilities, is less than or equal to a 3.0 to 1.0 ratio. As of September 30, 2007,March 31, 2008, AERG was in compliance with thisthe debt-to-operating cash flow ratio test in the 2007 $500 millionand 2006 credit facility and the 2006 $500 million credit facility.facilities. CIPS, CILCO and IP are not currently limited in their dividend payments by this provision of the 2007 $500 million or 2006 $500 million credit facilities. Ameren’s access to dividends from CILCO and AERG iswould be limited by dividend restrictions at CILCORP.

The 2007 $500 million credit facility and the 2006 $500 million credit facility also limit the amount of other secured indebtedness issuable by each borrower thereunder. For CIPS, CILCO and IP, other secured debt is limited to that permitted under their respective mortgage indentures. For CILCORP, other debt secured debtby the pledge of CILCO common stock is limited (a) under the 2007 $500 million credit facility to $425 million (including the principal amount of CILCORP’s outstanding senior notes and senior bonds)bonds, but excluding amounts drawn under the 20072006 $500 million credit facility) and (b) under the 2006 $500 million credit facility andto $550 million (including the principal amount of CILCORP’s outstanding senior notes and senior bonds as well asand amounts drawn underon the 2007 $500 million credit facility) under the 2006 $500 million credit facility, secured in each case by the pledge of CILCO common stock.. For AERG, other secured debt is limited to $100 million under the 2007 $500 million credit facility and $200 million under the 2006 $500 million credit facility secured on an equal basis with its obligations under the facilities.facilities is limited to $100 million by the 2007 $500 million credit facility (excluding amounts drawn by AERG under the 2006 $500 million credit facility) and $200 million by the 2006 $500 million credit facility. The limitations on other secured debt at CILCORP and AERG in the 2007 $500 million credit facility are subject to adjustment based on the borrowing sublimits of these entities under this facility or under the 2006 $500 million credit facility. In addition, the 2007 $500 million credit facility and the 2006 $500 million credit facility prohibit CILCO from issuing any preferred stock if, after giving effect to such issuance, the aggregate liquidation value of all CILCO preferred stock issued after February 9, 2007 and July 14, 2006, respectively, would exceed $50 million.

TheUnder the 2007 $500 million and 2006 $500 million credit facility provides thatfacilities, each of CIPS, CILCO and IP will agreehad been required to reserve future bonding capacity under their respective mortgage indentures (that is, agreethey agreed to forego the issuance of additional mortgage bonds otherwise permitted under the terms of each mortgage indenture) in the following amounts (subject to, in the case of CIPS and CILCO, their then current borrowing sublimits under the facility and similar provisions in the 2006 facility): CIPS, prior to December 31, 2007 - $50 million, on and after December 31, 2007, but prior to December 31,. On March 26, 2008, - $100 million, on and after December 31, 2008, but prior to December 31, 2009 - $150 million, on and after December 31, 2009 - $200 million; CILCO, prior to December 31, 2007 - $25 million, on and after December 31, 2007, but prior to December 31, 2008 - $50 million, on and after December 31, 2008, but prior to December 31, 2009 - $75 million, on and after December 31, 2009 - $150 million; and IP, prior to December 31, 2008 - $100 million, on and after December 31, 2008, but prior to December 31, 2009 - $200 million, on and after December 31, 2009 - $350 million.

The 2006 $500 million credit facility provides that CIPS, CILCO and IP will agreeand other parties to reserve future bonding capacity under their respective mortgage indentures in the following amounts: CIPS, priorcredit facilities entered into amendments to December 31, 2007 - $50 million, on and after December 31, 2007, but prior to Decemberthe credit facilities, which eliminated this requirement.

As of March 31, 2008, - $100 million, on and after December 31, 2008 - $150 million; CILCO - $25 million; and IP - $100 million.

As of September 30, 2007, the ratioratios of total indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the $1.15 billion credit facility, for Ameren, UE and Genco was 50%53%, 50%49% and 48%46%, 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 53%, 59%57%, 46%44%, 46%48% and 39%43%, respectively.

None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At September 30, 2007,March 31, 2008, the Ameren Companies were in compliance with their credit facility 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
37
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 the committed credit facilities. CIPS, CILCO and IP borrow from each other through the utility money pool agreement subject to applicable regulatory short-term borrowing authorizations. Ameren and AERG may participate in the utility money pool only as lenders. Although UE and Ameren Services are parties to the utility money pool agreement, they are not currently borrowing or lending under the agreement. The average interest rate for borrowing under the utility money pool for the three months ended March 31, 2008 was 4.1% (2007 – 6.1%).

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 funding from Ameren’s $1.15 billion credit facility through a non-state-regulated subsidiary money pool. At March 31, 2008, $233 million was available through the non-state-regulated subsidiary money pool, excluding additional funds available through excess cash balances. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the three months ended March 31, 2008, was 4.4% (2007 – 4.7%).

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 ended March 31, 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) plans,plan, pursuant to an effective SEC Form S-8 registration statements,statement, Ameren issued a total of 0.51.0 million new shares of common stock valued at $23 million and 1.4 million new shares valued at  $71$46 million in the three and nine months ended September 30, 2007, respectively.March 31, 2008.

In February 2007, $100 million of Ameren’s 2002 5.70% notes matured and were retired.UE

In May 2007,April 2008, UE issued $250 million of Ameren’s senior notes related to its 2002 equity security units matured and were retired.

UE

In June 2007, UE issued, pursuant to an effective SEC Form S-3 shelf registration statement, $425 million of 6.40%6.00% senior secured notes due June 15, 2017,April 1, 2018, with interest payable semi-annuallysemiannually on June 15April 1 and December 15October 1 of each year,
39
beginning in December 2007.October 2008. UE received net proceeds of $422$248 million, which were used to redeem UE’s outstanding auction-rate environmental improvement revenue refunding bonds discussed below and to repay short-term debt.

In connection with UE’s June 2007this issuance of $425$250 million of senior secured notes, UE agreed, for so long as thosethese senior secured notes are outstanding, that it wouldwill not, prior to June 15, 2012, optionally redeem, purchase or otherwise retire in full its outstanding first mortgage bonds not subject to release provisions thus causingmaturity, cause a first mortgage bond release date to occur. SuchThe 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 ranking equally with any other outstanding senior unsecured indebtedness of UE. UE further agreed that the interest rate for these $425indebtedness.

In April 2008, $63 million of senior secured notes will be subject to an increase of up to a maximum of 2.00% if such release date occurs between June 15, 2012 and June 15, 2017 (the maturity date of the $425 million senior secured notes) and Moody's or S&P downgrades the rating assigned to these senior secured notes below investment grade as a result of the occurrence of the release within 30 days of such release date (subject to extension if and for so long as the rating for such senior secured notes is under consideration for possible downgrade). Any interest rate increase on these senior secured notes will take effect on the first day of the interest period during which such rating downgrade requires an increase in the interest rate.UE’s Series 2000B auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest.

CIPSIn 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.

CIPS

See Note 5 – Credit Facilities and Liquidity in the Form 10-K regardingIn April 2008, $35 million of CIPS’ agreement under the 2007 $500 million credit facility and the 2006 $500 million credit facility to reserve future bonding capacity under its mortgage indenture.Series 2004 auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest.

Genco

In April 2008, Genco issued $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 future capital expenditures, repay short-term debt and for general corporate purposes.

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 (2006 -$1 million) and $4 million (2006(2007 - $4$1 million) for the three and nine months ended September 30, 2007, respectively,March 31, 2008, and was included as a reduction to interest expense in the Consolidated Statements of Income of Ameren and CILCORP. See Note 54 – Credit Facilities and Liquidity in the Form 10-K regarding CILCORP’s pledge of the common stock of CILCO as security for CILCORP’sits obligations under the 2007 $500 million credit facility and the 2006 $500 million credit facility.

CILCO

In January 2007, $50April 2008, $19 million of CILCO’s 7.50% first mortgageSeries 2004 auction-rate environmental improvement revenue refunding bonds matured and were retired.redeemed at par value plus accrued interest.

See Note 5 – Credit Facilities and Liquidity in the Form 10-K regarding CILCO’s agreement under the 2007 $500 million credit facility and the 2006 $500 million credit facility to reserve future bonding capacity under its mortgage indenture.
38
 
In July 2007, CILCO redeemed 11,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. The redemption satisfied CILCO’s mandatory sinking fund redemption requirement for this series of preferred stock for 2007.

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
(2006 (2007 - $3 million) and $9 million (2006 - $10 million) for the three and nine months ended September 30, 2007, respectively,March 31, 2008, and was included as a reduction to interest expense in the Consolidated Statements of Income of Ameren and IP.

See Note 5 – Credit FacilitiesIn April 2008, IP issued and Liquiditysold, 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 will be used to redeem all of IP’s outstanding auction-rate-pollution control revenue refunding bonds during May and June 2008. 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 Form 10-K regardingdate at which the security provided by the pledge under IP’s agreement under the 2007 $500 million credit facilityfirst mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and the 2006 $500 million credit facility to reserve future bonding capacity under its mortgage indenture.such indebtedness would become senior unsecured indebtedness.
 
Indenture Provisions and Other Covenants

The information below presents a summary of the Ameren Companies’ compliance with indenture provisions and other covenants. See Note 65 – 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 indenture provisionsindentures 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, 2007,March 31, 2008, at an assumed interest and dividend rate of 7%.

 
 
Required Interest Coverage Ratio(a)(b)
 
Actual Interest
Coverage Ratio
 
Bonds
Issuable(c)(d)
 
Required Dividend Coverage Ratio(e)
Actual
Dividend
Coverage Ratio
Preferred
Stock
Issuable
UE≥2.04.2
$     2,232
≥2.549.21,584
CIPS≥2.01.8-≥1.5  1.3-
CILCO
≥2.0(f)
  11.0 84≥2.532.1
319(g)
IP≥2.01.8-≥1.5  1.1-
  
 
 
Required Interest Coverage Ratio(a)
 
Actual Interest
Coverage Ratio
 
Bonds(b)
Issuable
 
Required Dividend Coverage Ratio(c)
Actual
Dividend
Coverage Ratio
Preferred
Stock
Issuable
UE≥ 2.0                       4.0$   2,270≥ 2.553.3$   1,725
CIPS≥ 2.0                       1.4-≥ 1.5  1.1-
CILCO
≥ 2.0(d)
                     14.1108≥ 2.540.7
404(e)
IP≥ 2.0                       2.9339≥ 1.5  1.1-

(a)  Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued.
(b)   Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(c)(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 $16$15 million, $3 million, $175 million and $914$664 million, respectively, for which no earnings coverage test is required.
(d)  Amounts are net of future bonding capacity restrictions agreed to by CIPS, CILCO and IP under the 2007 $500 million credit facility and the 2006 $500 million credit facility entered into by these companies. See Note 3 – Credit Facilities and Liquidity for further discussion.
(e)(c)  Coverage required on the annual interest charges on all long-term debt (CIPS-only)(CIPS only) and the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation. For CILCO, this ratio must be met for a period of 12 consecutive calendar months within the 15 months immediately preceding the issuance.
(f)(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 three and nine months ended September 30, 2007,March 31, 2008, CILCO had earnings equivalent to at least 38%43% of the principal amount of all mortgage bonds outstanding.
(g)(e)  See Note 3 – Credit Facilities and Liquidity for a discussion regarding a restriction on the issuance of preferred stock by CILCO under the 20072006 $500 million credit facility and the 20062007 $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 $1.8 billion of free and unrestricted retained earnings at September 30, 2007.March 31, 2008.

Genco’s and CILCORP’s indentures include provisions that require the companies to maintain certain debt service coverage and debt-to-capital ratios in order for the companies to pay dividends, to make certain principal or interest payments, to make certain loans to affiliates, or to incur additional indebtedness. The following table summarizes these ratios for the 12 months ended September 30, 2007:March 31, 2008:
 

Required
Interest
Coverage Ratio
Actual
Interest
Coverage Ratio
Required
Debt–to-
Capital
Ratio
Actual
Debt–to-
Capital
Ratio
Required
Interest
Coverage
Ratio
Actual
Interest
Coverage
Ratio
Required
Debt–to-
Capital
Ratio
Actual
Debt–to-
Capital
Ratio
Genco (a)
≥1.75(b)
6.3≤60%44%
≥ 1.75(b)
7.1≤ 60%37%
CILCORP(c)
≥2.23.0≤67%27%≥ 2.23.3≤ 67%27%

(a)  Interest coverage ratio relates to covenants regarding certain dividend, principal and interest payments on certain subordinated intercompany borrowings. The debt-to-capital ratio relates to a debt incurrence covenant, which requires an interest coverage ratio of 2.5 for the most recently ended four fiscal quarters.
(b)  Ratio excludes amounts payable under Genco’s intercompany note to CIPS and must be met for both the prior four fiscal quarters and for the succeeding four succeeding six-month periods.
(c)  CILCORP must maintain the required interest coverage ratio and debt-to-capital ratio in order to make any payment of dividends or intercompany loans to affiliates other than to its direct or indirect subsidiaries.
 

39
Genco’s debt incurrence-related ratio restrictions 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, 2007,March 31, 2008, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were B+,BB, Ba2, and BB+, respectively. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior notes and bonds and credit facility obligations.

In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.

Off-Balance-Sheet Arrangements

At September 30, 2007,March 31, 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.


41


NOTE 5 – OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the three and nine months ended September 30, 2007March 31, 2008 and 2006:2007:

  Three Months 
  2008  2007 
Ameren:(a)
      
Miscellaneous income:      
Interest and dividend income                                                                                      
 $12  $14 
Allowance for equity funds used during construction                                                                                      
  6   - 
Other 
  3   2 
Total miscellaneous income                                                                              
 $21  $16 
Miscellaneous expense:        
Other                                                                                      
 $(4) $(5)
Total miscellaneous expense                                                                              
 $(4) $(5)
UE:        
Miscellaneous income:        
Interest and dividend income                                                                                      
 $8  $10 
Allowance for equity funds used during construction 
  6   - 
Total miscellaneous income                                                                              
 $14  $10 
Miscellaneous expense:        
Other                                                                                      
 $(2) $(2)
Total miscellaneous expense                                                                              
 $(2) $(2)
CIPS:        
Miscellaneous income:        
Interest and dividend income                                                                                      
 $3  $3 
Total miscellaneous income                                                                              
 $3  $3 
Genco:        
Miscellaneous income:        
Other                                                                                      
 $2  $- 
Total miscellaneous income                                                                              
 $2  $- 
CILCORP:        
Miscellaneous income:        
Interest income                                                                                      
 $-  $2 
Total miscellaneous income                                                                              
 $-  $2 
Miscellaneous expense:        
Other                                                                                      
 $-  $(1)
Total miscellaneous expense                                                                              
 $-  $(1)
CILCO:        
Miscellaneous income:        
Interest income                                                                                      
 $-  $1 
Total miscellaneous income                                                                              
 $-  $1 
Miscellaneous expense:        
Other                                                                                      
 $-  $(1)
Total miscellaneous expense                                                                              
 $-  $(1)
40
  
Three Months
  
Nine Months
 
  
2007
  
2006
  
2007
  
2006
 
Ameren:(a)
            
Miscellaneous income:            
Interest and dividend income
 $
16
  $
9
  $
41
  $
21
 
Allowance for equity funds used during construction
  
2
   
1
   
2
   
2
 
Other 
  
2
   
2
   
11
   
6
 
Total miscellaneous income
 $
20
  $
12
  $
54
  $
29
 
Miscellaneous expense:                
Other
 $(6) $(3) $(10) $(4)
Total miscellaneous expense
 $(6) $(3) $(10) $(4)
UE:
                
Miscellaneous income:                
Interest and dividend income
 $
8
  $
7
  $
24
  $
18
 
Allowance for equity funds used during construction 
  
1
   
1
   
1
   
1
 
Other
  
-
   
1
   
3
   
3
 
Total miscellaneous income
 $
9
  $
9
  $
28
  $
22
 
Miscellaneous expense:                
Other
 $(5) $(3) $(9) $(7)
Total miscellaneous expense
 $(5) $(3) $(9) $(7)
CIPS:
                
Miscellaneous income:                
Interest and dividend income
 $
4
  $
4
  $
12
  $
12
 
Other
  
1
   
-
   
1
   
1
 
Total miscellaneous income
 $
5
  $
4
  $
13
  $
13
 
Miscellaneous expense:                
Other
 $(1) $
-
  $(2) $(1)
Total miscellaneous expense
 $(1) $
-
  $(2) $(1)
Genco:
                
Miscellaneous income:                
Other
 $
-
  $
-
  $
1
  $
-
 
Total miscellaneous income
 $
-
  $
-
  $
1
  $
-
 
CILCORP:
                
Miscellaneous income:                
Interest and dividend income
 $
1
  $
-
  $
3
  $
1
 
Other
  
1
   
-
   
1
   
-
 
Total miscellaneous income
 $
2
  $
-
  $
4
  $
1
 
Miscellaneous expense:                
Other
 $(2) $(2) $(5) $(4)
Total miscellaneous expense
 $(2) $(2) $(5) $(4)
CILCO:
                
Miscellaneous income:                
Interest and dividend income
 $
1
  $
-
  $
3
  $
-
 
Other
  
1
   
-
   
1
   
-
 
Total miscellaneous income
 $
2
  $
-
  $
4
  $
-
 
Miscellaneous expense:                
Other
 $(2) $(2) $(5) $(4)
Total miscellaneous expense
 $(2) $(2) $(5) $(4)
IP:
                
Miscellaneous income:                
Interest and dividend income
 $
2
  $
1
  $
5
  $
2
 
Other
  
2
   
1
   
4
   
2
 
Total miscellaneous income
 $
4
  $
2
  $
9
  $
4
 
Miscellaneous expense:                
Other
 $(2) $(1) $(3) $(3)
Total miscellaneous expense
 $(2) $(1) $(3) $(3)
  Three Months 
  2008  2007 
IP:        
Miscellaneous income:        
Interest income                                                                                      
 $2  $1 
Other                                                                                      
  1   1 
Total miscellaneous income                                                                              
 $3  $2 
Miscellaneous expense:        
Other                                                                                      
 $(1) $(1)
Total miscellaneous expense                                                                              
 $(1) $(1)

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


42
NOTE 6 – DERIVATIVE FINANCIAL INSTRUMENTS

The following table presents the pretax net gain (loss) for the three and nine months ended September 30,March 31, 2008 and 2007, and 2006, of power hedges included in Operating Revenues – Electric. This pretax net gain (loss) represents the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, and the reversal of amounts previously recorded in OCI due to transactions being delivered or settled:

 
Three Months
  
Nine Months
  Three Months 
Gains (Losses)
 
2007
  
2006
  
2007
  
2006
  2008  2007 
Ameren  $
22
  $
2
  $
35
  $
-
  $(8) $4 
UE   
2
  
2
   
-
  
5
  (1) 2 
Genco   
-
  
1
   
-
  
2
 
IP   
-
  (1)  
-
  (7)

The following table presents the carrying value of all derivative instruments and the amount of pretax net gains (losses) on derivative instruments in Accumulated OCI, for cash flow hedgesregulatory assets, or regulatory liabilities as of September 30, 2007:March 31, 2008:

 
Ameren(a)
  
UE
  
CIPS
  
Genco
  
CILCORP/
CILCO
  
IP
 
Ameren(a)
  
UE
  
CIPS
  
Genco
  
CILCORP/
CILCO
  
IP
 
Derivative instruments carrying value:                                   
Other current assets
 $
52
  $
11
  $
1
  $
-
  $
3
  $1 $129  $46  $18  $2  $18  $35 
Other assets
 
24
  
-
  
2
  
-
  
3
  
3
  35  3  42  -  23  69 
Other current liabilities
 
9
  
2
  1  
2
  1  1  140  50  1  16  1  1 
Regulatory liabilities
 
25
  -  
6
  
-
  
5
  
19
 
Other deferred credits and liabilities
 4  -  -  
-
  -  -  11  -  1  -  -  1 
Gains (losses) deferred in Accumulated OCI:                                               
Power forwards(b)
 
54
  
12
  
-
  
-
  
-
  
-
  (71) (16) -  -  -  - 
Interest rate swaps(c)
 
3
  
-
  
-
  
3
  
-
  
-
 
Gas swaps and futures contracts(d)
 
1
  
-
  
-
  
-
  
2
  
-
 
Interest rate swaps(c)(d)
 (13) -  -  (13) -  - 
Gas swaps and futures contracts(e)
 3  1  -  -  -  - 
SO2 futures contracts
 (1) 
-
  
-
  (1) 
-
  
-
  -  -  -  -  -  - 
Coal options
 4  4  -  -  -  - 
Gains deferred in regulatory assets or liabilities:                       
Gas swaps and futures contracts(e)
 74  8  12  -  19  35 
Financial contracts(f)
 -  -  46  -  23  66 

(a)  Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)  Represents the mark-to-market value for the hedged portion of electricity price exposure for periods of up to fourthree years, including $43losses of $67 million over the next year.12 months.
(c)  RepresentsIncludes 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 March 31, 2008, was $2 million.
(d)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 future debt issuances. The cumulative loss on the interest rate swaps will be amortized over a 10-year period that began in April 2008. The carrying value at March 31, 2008 was a loss of $15 million.
(e)  Represents gains associated with natural gas swaps and futures contracts. The swaps and futures contracts are a partial hedge of our natural gas requirements through MarchOctober 2011.
(f)  Current amounts of $8 million at CIPS, $4 million at CILCO, and $11 million at IP were recorded in other current assets and other current liabilities at March 31, 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 the Ameren Illinois Utilities and 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'sAmeren’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
41
Form 10-K for additional information on these financial contracts.

Other Derivatives

The following table presents the net change in market value for the three and nine months ended September 30,March 31, 2008 and 2007, and 2006, of option and swap transactions used to manage our positions in SO2 allowances, coal, heating oil, FTRs and nonhedge power and gas trading activity. Certain of these transactions are treatedhave not been designated as nonhedge transactionscash flow hedges under
SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. 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 swapstransactions are recorded in Operating Revenues – Electric and Operating Revenues – Gas.

 Three Months 
Gains (Losses)2008  2007 
SO2 options and swaps:
     
Ameren
$(1) $4 
UE
 -   4 
Coal options:       
Ameren
 -   1 
UE
 -   1 
Heating oil options:       
Ameren
 19   3 
UE
 10   - 
Genco
 5   - 
CILCORP/CILCO
 1   - 
Nonhedge power swaps and forwards:       
Ameren
 5   - 
UE
 2   - 
Nonhedge gas forwards:       
Ameren
 (5)  - 
UE
 (1)   - 
FTRs:       
Ameren
 5   - 
UE
 2   - 

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 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 and/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, which are held in UE’s Nuclear Decommissioning Trust Fund.

Level 2: Observable market-based inputs or unobservable inputs that are corroborated by 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. Derivative instruments classified as Level 2 are valued using corroborated observable inputs including from pricing services or prices from similar instruments that trade in liquid markets.

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.

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
42
  
Three Months
  
Nine Months
 
Gains (Losses)
 
2007
  
2006
  
2007
  
2006
 
SO2 options and swaps:
            
Ameren
 $
-
  $
1
  $
6
  $(2)
UE
  
-
   
1
   
5
   
3
 
Genco
  
-
   
1
   
1
   (4)
Coal options:
                
Ameren
  
-
   (1)  
2
   (2)
UE
  
-
   (1)  
2
   (2)
Heating oil options:
                
Ameren
  
-
   (2)  
3
   (2)
Nonhedge power swaps and forwards:
                
Ameren
  
3
   
-
   (2)  
-
 
UE
  
2
   
1
   (2)  
1
 
Nonhedge gas futures:
                
Ameren
  (2)  
-
   
-
   
-
 
UE
  (2)  
-
   
-
   
-
 
our counterparties and considering any counterparty credit enhancements (e.g. collateral). SFAS No. 157 also requires that the fair value measurement of liabilities should reflect the nonperformance risk of the entity, where 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.
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 March 31, 2008:

  
Quoted Prices in
Active Markets for Identified Assets
(Level 1)
 
Significant Other Observable Inputs
(Level 2)
 
Significant Other
Unobservable Inputs
(Level 3)
 
 
 
Total
 
Assets:            
Ameren(a)
Derivative assets(b)                            
$2  $45  $117  $164 
 Nuclear Decommissioning               
 Trust Fund 233   56   2   291 
UEDerivative assets -   29   20   49 
 Nuclear Decommissioning               
 Trust Fund231 233   56   2   291 
CIPS
Derivative assets(b)
 -   -   60   60 
Genco
Derivative assets(b)
 -   -   2   2 
CILCORP/CILCO
Derivative assets(b)
(c)
   -   41   41 
IP
Derivative assets(b)
 -   -   104   104 
Liabilities:                
Ameren(a)
Derivative liabilities(b)
$19  $74  $58  $151 
UE
Derivative liabilities(b)
 1   44   5   50 
CIPS
Derivative liabilities(b)
 -   -   2   2 
Genco
Derivative liabilities(b)
 15   -   1   16 
CILCORP/CILCO
Derivative liabilities(b)
 -   -   1   1 
IP
Derivative liabilities(b)
 -   -   2   2 

(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)  Less than $1 million.

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 March 31, 2008:

               Change in
       Total       Unrealized
    
Realized and Unrealized Gains (Losses)
 Realized Purchases,     Gains (Losses)
   Beginning      Included in and Issuances, Net Ending related to
   Balance at      Regulatory Unrealized and Other Transfers In Balance at assets/liabilities
   January 1, Included in Included  Assets/ Gains Settlements, and/or (Out) March 31, still held at
   2008 
Earnings(a)
 In OCI  Liabilities (Losses) Net of Level 3 2008 March 31, 2008
Net DerivativeAmeren                  $19  $6  $(34) $69  $41  $10  $(11) $59  $18 
ContractsUE                   3   2   7   7   16   (5)  1   15   11 
 CIPS                   38   -   -   19   19   1   -   58   12 
 Genco                   1  
(b)
  
(b)
   -  
(b)
  (b)   -   1  
(b)
 
 CILCORP/CILCO  21  
(b)
  
(b)
   20   20   (1)  -   40   15 
 IP                   55   -   -   43   43   4   -   102   31 
NuclearAmeren                  $5  $-  $-  $-  $-  $(3) $-  $2  $- 
DecommissioningUE                   5   -   -   -   -   (3)  -   2   - 
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.

Transfers in and/or out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. 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.

 
43
NOTE 78 – 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 1312 – Related Party Transactions under Part II, Item 8 of the Form 10-K. Below are updates to several of these related party agreements.

Illinois Electric Rate Settlement Agreement

See Note 2 – Rate and Regulatory Matters and Note 8 – Commitments and Contingencies for information on an electric settlement agreement reached in July 2007 among key stakeholders in Illinois and reflected in legislation, enacted on August 28, 2007, that addresses electric rate increases and the future power procurement process in Illinois. As part of the Illinois electric settlement agreement, in Illinois, the Ameren Illinois Utilities, Genco and AERG agreed to make contributions of $150 million 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, 2007,March 31, 2008, CIPS, CILCO and IP had receivable balances from Genco for reimbursement of customer rate relief of $7$1 million, $4less than $1 million and $10$1 million, respectively. Also at September 30, 2007,March 31, 2008, CIPS, CILCO and IP had receivable balances from AERG for reimbursement of customer rate relief of $3less than $1 million, less than $1 million, and $4less than $1 million, respectively. 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, when2007. See also Note 6 – Derivative Financial Instruments for additional information on the legislation in connection with the agreement became law.financial contracts.

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 and nine months ended September 30, 2007March 31, 2008 and 2006:
 
Three Months
  
Nine Months
 
 
2007
  
2006
  
2007
  
2006
 
Genco sales to
   Marketing Company(a)
 
-
   5,820   
-
   16,707 
Marketing Company
   sales to CIPS(a)
 
-
   3,424   
-
   9,500 
Genco sales to
   Marketing Company(b)
 
4,754
   -   
12,711
   - 
AERG sales to
   Marketing Company(b)
 
1,270
   -   
3,912
   - 
Marketing Company
   sales to CIPS(c)
 
671
   -   
1,852
   - 
Marketing Company
   sales to CILCO(c)
 
349
   -   
922
   - 
Marketing Company
   sales to IP(c)
 
1,016
   -   
2,716
   - 
(a)  These agreements expired or terminated on December 31, 2006.
(b)  In December 2006, Genco and Marketing Company, and AERG and Marketing Company, entered into new power supply agreements whereby Genco and AERG sell and Marketing Company purchases all the capacity available from Genco’s and AERG’s generation fleets and such amount of associated energy commencing on January 1, 2007.
(c)  In accordance with the January 2006 ICC order, discussed in Note 2 – Rate and Regulatory Matters, an auction was held in September 2006 to procure power for CIPS, CILCO and IP after their previous power supply contracts expired on December 31, 2006. Through the auction, Marketing Company contracted with CIPS, CILCO and IP to provide power for their customers. See also Note 3 – Rate and Regulatory Matters under Part II, Item 8 of the Form 10-K for further details of the power procurement auction in Illinois. See Note 2 – Rate and Regulatory Matters for a discussion of future changes in the Illinois power procurement process as a result of the electric settlement agreement reached among key stakeholders in July 2007 and the related legislation enacted into law in August 2007.

Joint Dispatch Agreement2007:

UE, CIPS
 Three Months 
 2008  2007 
Genco sales to Marketing Company 4,412   4,119 
AERG sales to Marketing Company 1,702   1,488 
Marketing Company sales to CIPS 623   619 
Marketing Company sales to CILCO 257   288 
Marketing Company sales to IP 804   826 

In December 2006, Genco and Marketing Company entered into a new power supply agreement (Genco PSA) whereby Genco mutually consentedagreed to waive the one-year termination notice requirementsell and Marketing Company to purchase all of the JDAcapacity available from Genco’s generation fleet and all the associated energy. On March 28, 2008, Genco and Marketing Company entered into an amendment, effective immediately, of the Genco PSA. Under the amendment, Genco will be 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 terminate it on December 31, 2006. The terminationsell and Marketing Company to purchase all of the JDA was acceptedcapacity available from AERG’s generation fleet and all the associated energy. On March 28, 2008, AERG and Marketing Company entered into an amendment, effective immediately, of the AERG PSA that is substantially identical to the amendment to the Genco PSA described above. Under the amendment, AERG will be 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. 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 FERCAERG, acting in September 2006.a commercially reasonable manner, to resell the unreceived energy, less any reasonable related transmission, ancillary service, or brokerage costs.

The following table presentsOne-third of the amountAmeren Illinois Utilities’ supply contracts that serve the load needs of gigawatthour sales under the JDA for the three and nine months ended September 30, 2006:their fixed-price
 
Three Months  
Nine Months 
UE sales to Genco2,0737,507
Genco sales to UE   8982,615


44

The following table presentsresidential and small commercial customers expire on May 31, 2008. To replace a portion of these expiring supply contracts, the short-term power sales margins underAmeren Illinois Utilities used request-for-proposal (RFP) processes in early 2008, pursuant to the JDA for UE and GencoIllinois electric settlement agreement, to contract for the threenecessary power and nine months ended September 30, 2006:energy requirements for the period from June 1, 2008 through May 31, 2009. Marketing Company was a winning supplier in the Ameren Illinois Utilities’ energy and capacity RFPs. Marketing Company entered into financial instruments, which will fix the price that the Ameren Illinois Utilities will pay for approximately 2 million megawatthours at approximately $60 per megawatthour. Marketing Company also 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.

  
Three Months
  
Nine Months
 
UE $15  $73 
Genco    5   22 
Total $20  $95 
In April 2008, the Ameren Illinois Utilities filed with FERC an electric resource sharing agreement for capacity. The purpose of the agreement is to allocate among the Ameren Illinois Utilities, in an equitable manner, the costs of acquiring their joint capacity needs. The Ameren Illinois Utilities requested that FERC accept the agreement effective June 1, 2008.

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 - Credit Facilities and Liquidity for a discussion of affiliate borrowing arrangements.

Intercompany Promissory NotesBorrowings

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 (2006for the three months ended March 31, 2008 (2007 - -  $3 million) and $7 million (2006 - $10 million) for the three and nine months ended September 30, 2007 and 2006, respectively..

CILCORP had no outstanding borrowings directly from Ameren of $3 million and zero at September 30, 2007. CILCORP had $156 million of outstanding borrowings from Ameren at September 30, 2006, withMarch 31, 2008 and March 31, 2007, respectively. The average interest rates of 4.8% and 4.5%rate on these borrowings was 4.4% for the three and nine months ended September 30, 2006, respectively.March 31, 2008 (2007 – 6.1%). CILCORP recorded interest expense of less than $1 million
(2006 - $2 million) and less than $1 million (2006 - $6 million) for these borrowings for the three and nine months ended September 30,March 31, 2008 (2007 - $1 million).

UE had outstanding borrowings directly from Ameren of $122 million and zero at March 31, 2008 and March 31, 2007, respectively. The average interest rate on these borrowings was 3.3% for the three months ended March 31, 2008. UE recorded interest expense of less than $1 million for these borrowings for the three months ended March 31, 2008 (2007 - $1 million).
 
The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the three and nine months ended September 30, 2007March 31, 2008 and 2006. The table2007. It is based primarily on the agreements discussed above and in Note 13 –12 - Related Party Transactions under Part II, Item 8 of the Form 10-K, and the money pool arrangements discussed above in Note 3 - Credit Facilities and Liquidity of this report.

   
Three Months
  
Nine Months
 
Agreement
  
UE
  
CIPS
  
Genco
  
CILCORP(a)  
IP
  
UE
  
CIPS
  
Genco
  
CILCORP(a)  
IP
 
Operating Revenues:
                               
Genco and AERG power supply
2007
 $(b) $(b) $
222
  $
73
  $(b) $(b) $(b) $
615
  $
207
  $(b)
agreements with Marketing Company                                         
Ancillary service agreement
2007
  
5
  
(b
) 
(b
) 
(b
)  
(b
)   
13
  
(b
)  
(b
) 
(b
) 
(b
) 
with CIPS, CILCO and IP                                          
Power supply agreement with Marketing Company – expired2006 
(b
)  
(b
)   
216
  
(c
)  (b)  
(b
) 
(b
)   
605
   
5
  
(b
) 
December 31, 2006                                   
UE and Genco gas
2007 
(c
) 
(b
)  
(b
) 
(b
)  
(b
) 
(c
) 
(b
)  
(b
)  
(b
)  
(b
) 
transportation agreement2006 (c)  
(b
) 
(b
)  
(b
)  (b)  (c)  
(b
)  (b)  
(b
)  (b) 
JDA – terminated December 31, 20062006  35  
(b
)  
23
  
(b
) (b)   156  
(b
)   69  
(b
) (b) 
Total Operating Revenues
2007
 $
5
  $(b) $
222
  $
73
  $(b) $
13
  $(b) $
615
  $
207
  $(b)
 2006  
35
  
(b
)  
239
  
(c
)  (b)   
156
  
(b
)   
674
   
5
  
(b
) 
Fuel and Purchased Power:
                                         
CIPS, CILCO and IP agreements
2007
 $(b) $
42
  $(b) $
22
  $
64
  $(b) $
120
  $(b) $
60
  $
176
 
with Marketing Company(auction)                                         
Ancillary service agreement with UE
2007
 
(b
)  
2
  
(b
)  
1
   
2
  
(b
)  
5
  
(b
)  
2
   
6
 
Ancillary service agreement with Marketing Company
2007
 
(b
)  
1
  
(b
)  
-
   
2
  
(b
)  
3
  
(b
)  
1
   
4
 
JDA – terminated December 31, 20062006  23  
(b
)  35  
(b
) (b)  69  (b)  156  (b) (b)
Power supply agreement with Marketing Company – expired2006 (b)  118  (b)  
1
  (b) (b)  337  (b)  1  (b)
December 31, 2006                                         
Executory tolling agreement 
2007
 
(b
) 
(b
) 
(b
)  
8
  
(b
) 
(b
) 
(b
) 
(b
)  
28
  
(b
)
with Medina Valley2006 (b) 
(b
) (b)  
9
  (b) (b) (b) (b)  29  (b)
UE and Genco gas
2007
 
(b
) 
(b
) 
(c
) 
(b
) 
(b
) 
(b
) 
(b
) 
(c
) 
(b
) 
(b
)
transportation agreement2006 (b) 
(b
) 
(c
)  
(b
) (b)  (b) (b) (c) (b) (b)
Total Fuel and Purchased
2007
 $(b) $
45
  $(c) $
31
  $
68
  $(b) $
128
  $(c) $
91
  $
186
 
Power2006  23   118   
35
   
10
  (b)  
69
   
337
   
156
   
30
  
(b
)
  Three Months
Agreement UECIPSGenco
CILCORP(a)
IP
       
Operating Revenues:      
Genco and AERG power supply2008$                     (b)    $                     (b)$                      226  $                        83  $                        (b)
agreements with Marketing Company2007
(b)
(b)
211
72
(b)
       
Ancillary service agreement with CIPS,2008
3
(b)
(b)
(b)
(b)
CILCO and IP2007
4
(b)
(b)
(b)
(b)
       
UE and Genco gas transportation2008(c)
(b)
(b)
(b)
(b)
agreement2007(c)
(b)
(b)
(b)
(b)
 
 
45
 
 
  
Three Months
  
Nine Months               
 Agreement
   UE    CIPS    Genco    CILCORP(a)    IP    UE    CIPS    Genco    CILCORP (a)   IP  
Other Operating Expense:
                                         
Ameren Services support
2007
 $
34
  $
12
  $
6
  $
12
  $
18
  $
102
  $
35
  $
18
  $
37
  $
54
 
services agreement2006  
34
   
12
   
7
   
12
   
18
   103   
36
   
18
   
37
   
54
 
Ameren Energy support
2007
  
2
  
(b
) 
(c
) 
(b
) 
(b
)  
7
  
(b
) 
(c
) 
(b
) 
(b
)
services agreement2006  2  
(b
)  1  
(b
) (b)  
6
  
(b
)  
2
  
(b
) 
(b
)
AFS support services
2007
  
2
   
-
   
1
   
1
   
-
   
5
   
1
   
2
   
2
   
1
 
agreement 2006  1  
(c
) (c) 
(c
)  
1
   
3
   
1
   
1
   
1
   
2
 
Insurance premiums(d)
2007
  
7
  
(b
)  
1
   
-
  
(b
)  
16
  
(b
)  
3
   
1
  
(b
)
Total Other Operating
2007
 $
45
  $
12
  $
8
  $
13
  $
18
  $
130
  $
36
  $
23
  $
40
  $
55
 
Expenses2006  
37
   
12
   
8
   
12
   
19
   112   
37
   
21
   
38
   
56
 
Interest expense (income) from
2007
 $
-
  $(c) $
3
  $(c) $(c) $
-
  $(c) $
7
  $(c) $(c)
money pool borrowings(advances)2006 
(c
)  (1)  
3
   
1
   
1
  
(c
)  (2)  
8
   
4
   
2
 
  Three Months
Agreement UECIPSGenco
CILCORP(a)
IP
       
Total Operating Revenues
2008$                       3$                     (b)
  $                      226
$                        83
$                        (b)
 2007
4
(b)
211
72
(b)
       
Fuel and Purchased Power:      
CIPS, CILCO and IP agreements with2008$                     (b)$                     41
$                         (b)
$                        17
$                        53
Marketing Company (2006 auction)2007
(b)
42
(b)
19
55
       
Ancillary service agreement with UE2008
(b)
1
(b)
(c)
1
 2007
(b)
1
(b)
1
2
       
Ancillary service agreement with2008(b)
2
(b)
1
3
Marketing Company2007(b)
1
(b)
(c)
1
       
Executory tolling agreement with2008(b)
(b)
(b)
13
(b)
Medina Valley2007(b)
(b)
(b)
12
(b)
       
UE and Genco gas transportation2008(b)
(b)
(c)
(b)
(b)
agreement2007(b)
(b)
(c)
(b)
(b)
       
Total Fuel and Purchased Power
2008    $                     (b)$                     44
$                          (c)
$                        31
$                        57
 2007(b)
44
(c)
32
58
       
Other Operating Expense:      
Ameren Services support services2008  $                     33$                     12
$                             7
$                       12
$                        18
agreement2007
36
12
6
13
19
       
Ameren Energy, Inc. support services2008(e)
(b)
(e)
(b)
(b)
agreement20073
(b)
(c)
(b)
(b)
       
AFS support services agreement20082
(c)
1
(c)
(c)
 20072
(c)
1
1
(c)
       
Insurance premiums(d)
2008
9
(b)
4
4
(b)
 2007
4
(b)
1
(c)
(b)
       
Total Other Operating Expenses
2008$                    44  $                     12
$                          12
$                        16
$                        18
 2007
45
12
8
14
19
       
Interest expense (income) from2008   $                       - $                     (c)
$                            2
$                        (c)
$                        (c)
money pool borrowings (advances)2007-
(c)
2
(c)
(c)

(a)   Amounts represent CILCORP and CILCO activity.
(b)  Not applicable.
(c)   Amount less than $1 million.  
(d)Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage. 
(e)Ameren Energy, Inc. was eliminated December 31, 2007 through an internal reorganization. 
 
NOTE 89 – 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 32 – Rate and Regulatory Matters, Note 1312 – Related Party Transactions, and Note 1413 – 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, and Note 78 – Related Party Transactions and Note 10 – Callaway Nuclear Plant in this report.


46
Callaway Nuclear Plant

The following table presents insurance coverage at UE’s Callaway nuclear plant at September 30, 2007.March 31, 2008. The property coverage and the nuclear liability coverage were renewed on October 1, 2007 and January 1, 2007,2008, respectively.

Type and Source of Coverage
Maximum Coverages
Maximum Assessments for Single Incidents
Public liability:
American Nuclear Insurers
$                                     300
$                                         -
Pool participation
                             10,461(a)
                                 101(b)
$                                10,761(c)
$                                     101
Nuclearliability and nuclear worker liability:  
American Nuclear Insurers
$                                 300(d)(a)
$                                      4-
Pool participation
                     10,461
                              101(b)
$                            10,761(c)
$                                  101
Property damage:  
Nuclear Electric Insurance Ltd.Ltd
$                              2,750(e)(d)
$                                    24
Replacement power:  
Nuclear Electric Insurance Ltd.Ltd
$                                 490(f)(e)
$                                      9
Energy Risk Assurance Company
$                                   64(g)(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 $15 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)  Industry limit for potential liability for worker tort claims filed for bodily injury caused by a nuclear energy accident. Effective January 1, 1998, this program was modified to provide coverage to all workers whose nuclear-related employment began on or after the commencement date of reactor operations.
(e)  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.
(f)(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.
(g)(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 78 – Related Party Transactions for more information on this affiliate transaction.

46
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. 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.

Subsequent toAfter the terrorist attacks on September 11, 2001, both American Nuclear Insurers and Nuclear Electric Insurance Ltd. confirmed that losses resulting from terrorist attacks would be covered under their policies, subject to applicable policy limits. Both companies, however, revised their policy terms to include an industry aggregate for all “non-certified” terrorist acts as defined by the Terrorism Risk Insurance Act of 2002, which was renewed in 2005. The non-certified American Nuclear Insurers nuclear liability cap is a $300 million shared industry aggregate for all facilities licensed in the United States during the policy period. The aggregate for allits policies. However, Nuclear Electric Insurance Ltd. policies, which apply to non-certified property claimsltd. imposed an industry-wide aggregate policy limit of $3.24 billion within a 12-month period is $3.2 billion, plus any amounts available through reinsurance or indemnity from an outside source.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 occurred,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

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas and nuclear fuel. In addition, we have entered into various long-term commitments for the purchase of electricity and natural gas for distribution. For a complete listing of our obligations and commitments, see Note 1413 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K.

AsThe Illinois electric settlement agreement provides approximately $1 billion of September 30,funding over a four-year period that commenced in 2007 our commitmentsfor rate relief for certain electric customers in Illinois. Funding for the procurementsettlement will come from electric generators in Illinois and certain Illinois electric utilities. The Ameren Illinois Utilities, Genco and AERG agreed to fund an aggregate of coal and related transportation have changed from amounts previously disclosed as$150 million, of Decemberwhich the following contributions remain to be made at March 31, 2006. The following table presents our total estimated coal and related transportation purchase commitments at September 30, 2007:
 
2007
  
2008
  
2009
  
2010
  
2011
 
Ameren(a)
$
145
  $
552
  $
380
  $
186
  $
121
 
UE 
78
   
294
   
256
   
142
   
103
 
Genco 
43
   
143
   
66
   
20
   
8
 
CILCORP/CILCO 
9
   
37
   
21
   
8
   
4
 
(a)       Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
2008:

As of September 30, 2007, our commitments for the procurement of natural gas have materially changed from amounts previously disclosed as of December 31, 2006. The following table presents our total estimated natural gas purchase commitments at September 30, 2007:
 
2007
  
2008
  
2009
  
2010
  
2011
  
Thereafter(a)
 
Ameren(b)
$
173
  $
591
  $
369
  $
263
  $
213
  $
1,964
 
UE 
20
   
85
   
58
   
37
   
27
   
56
 
CIPS 
29
   
111
   
81
   
64
   
42
   
73
 
Genco 
9
   
30
   
8
   
8
   
8
   
13
 
CILCORP/CILCO 
53
   
162
   
97
   
59
   
58
   838(c)
IP 
57
   
192
   
123
   
95
   
77
   983(c)
  
 
Ameren
  CIPS  
CILCO
(Illinois
Regulated)
  IP  Genco  
CILCO
(AERG)
 
2008(a)
 $31.9  $4.7  $2.3  $6.4  $12.8  $5.7 
2009(a)
  26.5   3.9   1.9   4.9   10.9   4.9 
2010(a)
  1.7   0.2   0.1   0.4   0.7   0.3 
Total $60.1  $8.8  $4.3  $11.7  $24.4  $10.9 

(a)  Commitments for natural gas are until 2031.
(b)  Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(c)  Commitments for natural gas purchases for CILCO and IP include projected natural gas purchases pursuant to a 20-year supply contract beginning in April 2011. Purchases under this contract will be passed through to utility customers under the PGA.
(a)  Estimated.

AsOne-third of September 30, 2007, the commitments forAmeren Illinois Utilities’ supply contracts that serve the procurementload needs of nuclear fuel have materially changed from amounts previously disclosed astheir fixed-price residential and small commercial customers expire on May 31, 2008. To replace a portion of December 31, 2006. The following table presentsthese expiring supply contracts, the total estimated nuclear fuel purchase commitments at September 30, 2007:
  
    2007
  
  2008
  
  2009
  
   2010
  
  2011
  
   Thereafter(a)
 
Ameren/UE $52  $71  $63  $74  $51  $
292
 

(a)  Commitments for nuclear fuel are until 2020.
Ameren Illinois Utilities used RFP processes
 
47
At this time, UE does not expect to require new baseload generation capacity until at least 2018. However, due
in early 2008, pursuant 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. During the second quarter of 2007, UE entered into a commitment to purchase heavy forgings needed to construct a nuclear plant. This commitment does not mean a decision has been made to build a nuclear plant. The purpose of entering into the forgings purchase commitment was to secure access to heavy forgings, which are long lead-time materials, in the event that UE decides to build a nuclear plant. As of September 30, 2007, UE’s commitments to purchase heavy forgings totaled $88 million through 2010 ($3.5 million in 2007, $6.5 million in 2008, $7.5 million in 2009 and $70.5 million in 2010).

As part of theIllinois electric settlement agreement in Illinois,agreement. Specifically, the Ameren Illinois Utilities Gencoused RFPs to procure energy swaps, capacity, and AERG, committedrenewable energy credits for the period June 1, 2008 through May 31, 2009. In March 2008, the ICC approved the results of the Ameren Illinois Utilities’ energy RFP that was used to make aggregate contributionsprocure financial energy swap products. The Ameren Illinois Utilities contracted to purchase approximately two million megawatthours of $150 million overenergy swaps at an average price of approximately $60 per megawatthour. In April 2008, the ICC approved the results of the Ameren Illinois Utilities’ capacity and renewable energy credits RFPs. As a four-year period, with $60 million coming fromresult of the capacity RFP, the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco and $28 million from AERG. Also as partcontracted to purchase approximately 1,800 megawatts of the electric settlement agreementcapacity at an average price of approximately $50 per MW-day. The renewable energy credits RFP resulted in Illinois, the Ameren Illinois Utilities entered into financial contracts with Marketing Companycontracting to lock-in energy prices for 400 to 1,000 megawatts annuallypurchase 415,000 credits at an average price of their around-the-clock power requirements from 2008 to 2012. See Note 2 – Rate and Regulatoryapproximately $17 per credit.
Environmental Matters for additional information regarding the electric settlement agreement in Illinois.

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 we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or our operations, as required.operations. The more significant matters are discussed below.

Clean Air Act

Clean Air Act

In May 2005, theThe EPA issued final SO2, NOx and mercury emission regulations with respect to SO2 and NOx emissions (thein May 2005. The Clean Air Interstate Rule)Rule and mercury emissions (thethe Clean Air Mercury Rule) from coal-fired power plants. These rulesRule require significant reductions in these emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. States are required to finalizehave finalized rules to implement the federal Clean Air Interstate Rule and Clean Air Mercury Rule. Although the federal rules mandate a specific cap for SO2, NOx and mercury emissions by state from utility boilers, the states have considerable flexibility in allocating emission allowances to individual utility boilers. In addition, a state may choose to hold back certain emission allowances for growth or other reasons, and it may implement a more stringent program than the federal program. Illinois has finalized rules to implement the federal Clean Air Interstate Rule program that will reduce the number of NOx allowances automatically allocated to Genco’s, AERG’s and EEI’s plants. As a result of the Illinois rules, Genco, AERG and EEI will need to procure allowances and install pollution control equipment in order to continue to operate. We currently plan to installequipment. Current plans include the installation of scrubbers for SO2 reduction and selective catalytic reduction (SCR) systems for NOx reduction at our largecertain coal-fired plants in Illinois.

Missouri rules, which substantially follow the federal regulations and became effective in April 2007, and approved by the EPA in December 2007, are expected to reduce mercury emissions 81% by 2018, and reduce NOx emissions 30% and SO2 emissions 75% by 2015. As a result of the Missouri rules, UE will manage allowances and install pollution control equipment. Current plans include the installation of scrubbers for SO2 reduction and co-benefit reduction of mercury and pollution control equipment designed to reduce mercury emissions at certain coal-fired plants in Missouri.

Illinois has adopted rules for mercury emissions that are significantly stricter than the federal regulations. In 2006, Genco, CILCO, EEI, and the Illinois EPA entered into an agreement that was incorporated into Illinois’ mercury emission regulations. Under the regulations, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NOx and SO2 controls. In 2009, Genco, AERG and EEI willexpect to begin putting into service equipment designed to reduce mercury emissions. These rules, when fully implemented, are expected to reduce mercury emissions 90%, NOx emissions 50%, and SO2 emissions 70% by 2015 in Illinois.

In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that effectively 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 court decision impacts the Missouri plan to implement the federal Clean Air Mercury Rule. The Illinois mercury rule will continue to be implemented and is not significantly impacted by the court decision. The EPA and a group representing the electric utility industry have filed petitions for rehearing. At this time, we are unable to determine the impact that this action would have on our estimated expenditures for compliance with environmental rules, our results of operations, financial position, or liquidity.
48

The table below presents estimated capital costs based on current technology to comply with both the federal Clean Air Interstate Rule and Clean Air MercuryRule through 2016 and related state implementation plans.plans through 2017. The estimates described below could change depending upon additional federal or state requirements, the ultimate outcome of the petition for rehearing at the U.S. Court of Appeals relative to the Clean Air Mercury Rule decision, 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 the proposed rules, thereby deferring capital investment.


48
 
2007
2008
20082009 – 2012
2013 - 20112017
2012 - 2016
Total
UE(a)
$   110255$    630-    830215-  $    295$ 910- 1,1801,300-  $ 1,700$  1,650- 2,1201,770-  $ 2,250
Genco  110300                         820- 1,060
955-     1,210
                              180-    26045-          70                              1,110- 1,4301,300-     1,580
CILCO (AERG)  100                         185-    240                                95-    140170                          380-        480500                            70-          90
  620-        760
EEI    1030
                        260-        350
                            185-    24020-          30                              165-    220                                 360-    470
  310-        410
Ameren$   330755                    $ 1,810-  $ 2,355$ 1,820- 2,3701,435-  $ 1,890$   1,350- 1,8004,000-  $ 3,500- 4,5005,000

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

Illinois and Missouri must also develop attainment plans to meet the existing federal eight-hour ozone ambient standard, the federal fine particulate ambient standard, and the Clean Air Visibility rule. Both states have filed ozone attainment plans for the St. Louis area. The stateIllinois and Missouri are finalizing their attainment plans for fine particulate must be submittedmatter for submission to the EPA by April 2008,EPA. The Illinois and theMissouri plans for the Clean Air Visibility rule must bewere submitted to the EPA byin December 2007. The costs in the table above assume that emission controls required for the Clean Air Interstate Rule regulations will be sufficient to meet these new standards in the St. Louis region. Should Missouri develop an alternative plan to comply with these standards, the cost impact could be material to UE, but we would expect these costs to be recoverable from ratepayers. Illinois is planning to impose additional requirements beyond the Clean Air Interstate Rule as part of the attainment plans for the existing ozone and fine particulate.particulate matter standards. 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. 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 impact of future initiatives related to greenhouse gas emissions and global warming on us are unknown and therefore not included in the estimated environmental expenditures. 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.

Emission Allowances
 
Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act, under the Acid Rain Program and 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 the beginning of 2004; it was applied to the eastern third of Missouri, where UE’s coal-fired power plants are located, beginning in 2007. Our generating facilities are expected to comply with the 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.

The following table presents the SO2 and NOx emission allowances held and the related SO2 and NOx emission allowance book values that are carried as intangible assets as of September 30, 2007.March 31, 2008.

SO2(a)
NOx(b)
Book Value
SO2 (a)
  
NOx (b)
  Book Value 
Ameren 3.191  33,240  $189(c)
UE  1.59115,948$                        60 1.757  15,818  54 
Genco  0.62411,841
57
 0.745  11,891  58 
CILCORP 0.351  2,147  40 
CILCO (AERG)  0.300  2,147
1
 0.351  2,147  1 
EEI  0.293  3,397 
9
 0.338  3,384  9 
Ameren  2.80833,333
197(c)

(a)  
Vintages are from 20072008 to 2016.2018. Each company possesses additional allowances for use in periods beyond 2016.2018. Units are in millions of SO2 allowances (currently one allowance equals one ton emitted).
(b)  
Vintages are from 20072008 to 2008.2009. Units are in NOx allowances (one allowance equals one ton emitted). NOx allowances for 2009 and beyond have not yet been allocated by the EPA; however, UE, Genco, AERG and EEI expect to be allocated allowances in future years.
(c)  Includes value assigned to AERG and EEI allowances as a result of purchase accounting of $70$27 million.

UE, Genco, CILCO and EEI expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. New environmentalEnvironmental regulations, including the Clean Air Interstate Rule, the timing of the installation
49
of pollution control equipment, and the level of operations will have a significant impact on the amount of allowances actually required for ongoing operations. The Clean Air Interstate Rule requires a reduction in SO2 emissions by increasing the ratio of Acid Rain Program allowances surrendered. The current Acid Rain Program requires the surrender of one SO2 allowance for every ton of SO2 that is emitted. The Clean Air Interstate Rule program will require that SO2 allowances of vintages 2010 through 2014 be surrendered at a ratio of two allowances for every ton of emission in 2010 through 2014. Beginning inemission. SO2 allowances with vintages of 2015 the Clean Air Interstate Rule programand beyond will require SO2 allowancesbe required to be surrendered at a ratio of 2.86 allowances for every ton of emission. In order to accommodate this change in surrender ratio and to comply with the federal and state regulations, UE, Genco, AERG, and EEI expect to install control technology designed to further reduce SO2 emissions, as discussed above.

Global ClimateThe Clean Air Interstate Rule will have both an annual program and an ozone season program for regulating NOx emissions, with separate allowances issued for each program. Both sets of allowances for the years 2009 through 2014 were issued by the Missouri Department of Natural Resources in December 2007. Allocations for UE’s Missouri generating facilities were 11,665 tons per ozone season and 26,842 tons annually. Allocations for Genco’s generating facility in Missouri were one ton for the ozone season and three tons annually. UE, Genco, AERG and EEI expect to be allocated NOx allowances for both programs in Illinois in 2008.

Global Climate
Future initiatives regarding greenhouse gas emissions and global warming continueare subject to active consideration in the U.S. Congress. It is anticipated that this summer the U.S. Senate will take up legislation proposed by Senators Lieberman and Warner, and passed out of the Senate Environment and Public Works Committee earlier this year, that would set up a “cap and trade” program for greenhouse gas emissions.  In the U.S. House of Representatives, the Energy and Commerce Committee is also expected to issue proposed greenhouse gas legislation this year.

In addition, President Bush has proposed climate legislation 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 legislation currently under consideration in the Senate.

The outcome of these initiatives cannot be determined at this time. However, presidential candidates Senators Clinton, McCain, and Obama have all expressed support for a greenhouse gas cap and trade program. Therefore, the subjectlikelihood that some form of much debate.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. Coal-firedfacilities, but coal-fired power plants however, are significant sources of carbon dioxide,CO2, a principal greenhouse gas. Six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member,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 TVA, signedMidwest economy because of the region's reliance on electricity generated by coal-fired power plants. Natural gas emits about half the amount of CO2 as coal. As a Memorandumresult, 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 federal and state legislation or regulations that mandate limits on the emission of Understanding (MOU) with the DOEgreenhouse gases would result in December 2004 calling for a 3% to 5% voluntary decreasesignificant increases in carbon intensity by the utility sector between 2002capital expenditures and 2012. Currently, Ameren is considering various initiativesoperating costs. The costs to comply with the MOU, including increased generation at nuclearfuture legislation or regulations could be so expensive that Ameren and hydroelectricother similarly situated electric power plants, increased efficiency
49
measures at ourgenerators may be forced to close some coal-fired units,facilities. Mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and investments in renewable energy and carbon sequestration projects.EEI’s results of operations, financial position, or liquidity.

InWith 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 carbon dioxideCO2 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.” Unless the U.S. Congress enacts legislation directing otherwise,As a result, the EPA could begin to regulate such emissions.

 Ameren has taken actions to address the global climate issue. These include implementing efficiency improvements at our power plants; participating in the
50
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 “Missouri Schools Going Solar,” a project that will install photovoltaic solar arrays on school grounds; and partnering with other utilities, the Electric Power Research Institute, and the Illinois State Geological Survey in the DOE Illinois Basin Initiative, which will examine the feasibility and methods of storing CO2 within deep unused coal seams, mature oil fields, and saline reservoirs.
The impact on us of future initiatives related to greenhouse gas emissions and global warming on us areis unknown. Although compliance costs are unlikely in the near future, our costs of complying with any mandated federal or state including Illinois, greenhouse gas programsprogram could have a material impact on our future results of operations, financial position, or liquidity.
Clean Water Act

AmerenIn 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 preparing a report to addressalso the environmental planning process and actions of Ameren relativepossibility that the rules may lead to the climate change issue.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 reportSupreme Court is expected to hear the case this fall. In the meantime, the EPA is expected to reissue the rules early in 2009. Until the Supreme Court case, the new rules and the studies on the power plants are completed, we will be issued in mid-December 2007.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 utilities 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 2007, the U.S. Supreme Court in Environmental Defense v. Duke Energy Corp., issued a decision that effectively reduced the statutory defenses available to NSR and Prevention of Significant Deterioration (PSD) claims. The key issue before the Supreme Court was whether EPA requirements to obtain permits under the NSR and PSD programs are triggered when a “modification” at an industrial facility results in an increase in an hourly emissions rate, as upheld by the U.S. Court of Appeals for the Fourth Circuit, or in total annual emissions, as asserted by environmental groups. The U.S. Supreme Court found that the NSR and PSD regulations can be triggered by either an hourly or annual increase in the emissions. The Supreme Court decision did not address other potential defenses or potential exceptions under the NSR and PSD programs.

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. 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.

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, increased operations and maintenance expenses, and fines or penalties. We believe that any potential resolution would likely require the installation of control technology, some of which is already planned for compliance with other regulatory requirements such as the Clean Air Interstate Rule and the Illinois mercury rules.

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. SeveralSome 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.

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As of September 30, 2007,March 31, 2008, CIPS, CILCO and IP owned or were otherwise responsible for 14, four, and 25several former MGP sites respectively, 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 theirits former MGP sites in Illinois from theirits 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, 2007,March 31, 2008, estimated obligations were:  CIPS - $22 million to $42 million, CILCO - $5 million to $8 million, and IP - $77 million to $171 million. CIPS, CILCO and IP hadalso recorded liabilities of $25$22 million, $5 million and $76$77 million, respectively, to represent estimated minimum obligations.obligations as no other amount within the range is a better estimate at this time.

50
CIPS is also responsible for the cleanup of a former landfill in Coffeen, Illinois. As of March 31, 2008, CIPS estimated its obligation at $0.5 million to $6 million. CIPS recorded $0.5 million to represent its estimated minimum obligation for this site as no other amount within the range is a better estimate at this time. IP is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of March 31, 2008, IP estimated its obligation at $1 million to $4 million. IP recorded $1 million to represent its estimated minimum obligation for these sites as no other amount within the range is a better estimate at this time.

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. Because of the unknown and unique characteristics of each site (such as amount and type of residues present, physical characteristics of the site, and the environmental risk) and uncertain regulatory requirements, we are not able to determine the maximum liability for the remediation of these sites. As of   September 30, 2007,March 31, 2008, UE hadestimated its obligation at $5 million to $13 million. UE recorded $5 million to represent its estimated minimum obligation for its MGP sites.sites as no other amount within the range is a better estimate at this time. UE also is responsible for four electric sites in Missouri that have corporate cleanup liability, most as a result of federal agency mandates. As of September 30, 2007,March 31, 2008, UE hadestimated its obligation at $4 million to $17 million. UE recorded $4 million to represent its estimated minimum obligation for these sites. Atsites as no other amount within the range is a better estimate at this time, we are unable to determine what portion of these costs, if any, will be eligible for recovery from insurance carriers.time.

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 of such activities will be submitted to the EPA by the endthird quarter of 2007.2008. Following this submission, the EPA will ultimately select a remedy alternative and begin negotiations with various PRPs to implement the selected alternative.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 of Solutia related to Solutia’s former chemical waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection.

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.

In December 2004, AERG submitted a comprehensive package to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have a liability of $3.9$2 million at September 30, 2007,March 31, 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 BiphernalsBiphenyls Information Request

Polychlorinated biphernalsbiphenyls (PCBs) are a blend of chemical compounds that were historically used in a variety of industrial products because of their chemical and
52
thermal stability. In natural gas systems, PCBs were used as a compressor lubricant and a valve sealant before thetheir sale of PCBs 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 itstheir experiences with PCBs in itstheir gas distribution system.systems. The Ameren Illinois Utilities have 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 of this matter 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. At the FERC’s direction, outside experts were hired by UE to review the cause of the incident. Their reports and reports by FERC staff indicated design, construction, and human error as causes of the breach. In their report, UE’s outside experts concluded that restoration of the upper reservoir, if undertaken, will require a complete rebuild of the entire dam with a completely different design concept, not simply a repair of the breached area. FERC agreed with this conclusion and rejected repair as an option.

The FERC investigation ofUE has settled all state and federal issues associated with the incident has been completed. In October 2006, the FERC approved a stipulation and consent agreement between UE and the FERC’s Office of Enforcement that resolves all issues arising from an investigation that the FERC’s Office of Enforcement conducted into alleged violations of license conditions and FERC regulations by UE as the licensee of theDecember 2005 Taum Sauk hydroelectric facility that may have contributed to the breach of the upper reservoir. As part of the stipulation and consent agreement, UE agreed, among other things, (1) to pay a civil penalty of $10 million, (2) to pay $5 million into an interest-bearing escrow account to fund project enhancements at or near the Taum Sauk facility, and (3) to implement and comply
51
with a new dam safety program developed in connection with the settlement.
incident. In February 2007, UE submitted plans and an environmental report to FERC to rebuild the upper reservoir at its Taum Sauk plant, assuming successful resolution of outstanding issues with authorities of the state of Missouri.addition, UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant in August 2007 and hired a contractorcontractor. The estimated cost to rebuild the upper reservoir is in November 2007.  Shouldthe range of $450 million. UE expects the Taum Sauk plant be rebuilt, UE would expect it to be out of service through at least the fall of 2009, if not longer.early 2010.

UE has accepted responsibility forIn December 2006, 10 business owners filed a lawsuit regarding the effectsTaum 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 incident. 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.

At this time, UE believes that substantially all damages and liabilities (but not penalties) 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 clean up,cleanup, damage and liabilities, excluding costs to rebuild the facility, resulting from the Taum Sauk incident toreservoir will range from $188$200 million to $208$220 million. As of September 30, 2007,March 31, 2008, UE had paid $89$157 million and accrued a $99$43 million liability, including costs resulting from the FERC-approved stipulation and consent agreement, discussed above, while expensing $31$32 million and recording a $157$168 million receivable due from insurance companies. As of September 30, 2007,March 31, 2008, UE hashad received $35$89 million from insurance companies, which has reduced the insurance receivable balance to $122 million as of such date.$79 million. As of September 30, 2007,March 31, 2008, UE had a $57$144 million receivable due from insurance companies related to the rebuilding of the facility. 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 2006,2007, FERC granted intervention, denied rehearing, and dismissed the staterequest 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. We are unable to predict how or when the Court of Appeals will rule on this appeal.

In December 2007, the Missouri through its attorney general,Parks Association filed a lawsuit in the U.S. District Court for the District of Columbia against UE and 10 business owners filed separate lawsuits regardingFERC to stop the reconstruction of the upper reservoir at the Taum Sauk breachplant. The Missouri Parks Association claims that are currently pending inFERC failed to adequately study the Circuitenvironmental effect of reopening the hydroelectric plant or alternatives to rebuilding it. In January 2008, UE filed a motion to dismiss the lawsuit, arguing that the U.S. District Court of Reynolds County, Missouri. The attorney general’s suit alleges negligence, violationslacks jurisdiction over the subject matter of the Missouri Clean Water Act and various other statutory and common law claims. The business owners’ suit contains similar allegations and seeks damages relating to business losses and lost profit. Both suits seek unspecified punitive damages.case. In May 2007,March 2008, the U.S. District Court dismissed the lawsuit filed by the Missouri Department of Natural Resources’ petition to intervene as a plaintiff in the attorney general’s lawsuit was denied.  UE is currently in discussions with authorities of the state of Missouri to resolve outstanding issues associated with this incident.Parks Association.

See Note 2 – Rate and Regulatory Matters for information on the MoPSC’s Taum Sauk investigation.

Until the reviews conducted by state authorities have concluded, litigation has been resolved and the insurance review is completed, and future regulatory treatment for the facility is determined, 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.

Asbestos-related LitigationMechanics’ Liens

Approximately 20 mechanics’ liens were filed by various subcontractors who provided labor or material for a 2007 planned maintenance outage at the Duck Creek facility of CILCO subsidiary, AERG. The total lien claim amount was $26 million plus interest at March 31, 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. AERG believes it has paid the general contractor the amount due in full (less a contract-allowed holdback of $4 million), and since this arose out of a contract dispute between the general contractor and the primary subcontractor, AERG is currently considering its potential remedies against the general contractor. In February 2008, AERG filed its answer in the lawsuit denying the validity of the liens. At this time, we are unable
53
 to predict the impact of these liens and lawsuit on CILCO’s or AERG’s future 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 189 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, 2007,March 31, 2008, the average number of parties was 71.65.

The claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and 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 JulyJanuary 1, 2007,2008, through September 30, 2007, nineMarch 31, 2008, eight additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois. FourThree lawsuits were settled.settled and nine lawsuits were dismissed. The following table presents the status as of September 30, 2007,March 31, 2008, of the asbestos-related lawsuits that have been filed against the Ameren Companies:

 
Specifically Named as Defendant 
 Specifically Named as Defendant
Total(a)
Ameren
UE
CIPS
Genco
CILCO
IP
Total(a)
AmerenUECIPSGencoCILCOIP
Filed34331188145249164357                   32198151250172
Settled116  -  59  51-18  60126                     -  67  56-19  64
Dismissed15127  99  51210  70160                   29105  58217  78
Pending  76 4  30  43-21  34  71                     3  26  37-14  30

(a)   AdditionTotals do not equal to the sum of the numbers in the individual columns does not equal the total columnsubsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.
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As of September 30, 2007, eightMarch 31, 2008, ten 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. Beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates will beare recovered by IP from a $20 million trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy. At March 31, 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 910 – CALLAWAY NUCLEAR PLANT

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or 1/10 of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2017. UE has sufficient installed storage capacity at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.

Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in
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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 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 2005 and 2004.2005. 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 study was filed in 2005. Minor tritium contamination was discovered on the Callaway nuclear plant site in the summer of 2006. Existing facts and regulatory requirements indicate that this discovery will not cause any significant increase in a decommissioning cost estimate when the next study is conducted.conducted and filed on September 1, 2008. 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 andrestricted. 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.asset or regulatory liability, as appropriate.

NOTE 1011 – 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 and nine months ended September 30,March 31, 2008 and 2007, and 2006, is shown below for the Ameren Companies:

  
Three Months
  
Nine Months
 
  
2007
  
2006
  
2007
  
2006
 
Ameren:(a)
            
Net income $
244
  $
293
  $
510
  $
486
 
Unrealized gain on derivative hedging instruments, net of taxes of $8, $6,
$6 and $1, respectively
  
15
   
14
   
10
   
5
 
Reclassification adjustments for (gain) included in net income, net of
taxes of $9, $1, $19 and $3, respectively
  (17)  (1)  (33)  (4)
 
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Three Months     
   
Nine Months    
 
   
2007 
   
2006 
   
2007 
   
2006 
 
Adjustment to pension and benefit obligation, net of taxes (benefit) of $1,
$-, $(2) and $-, respectively
  
1
   
-
   
2
   
-
 
Total comprehensive income, net of taxes $
243
  $
306
  $
489
  $
487
 
Three Months 
2008  2007 
Ameren:(a)
     
Net income $138  $123 
Unrealized net (loss) on derivative hedging instruments, net of taxes (benefit) of $(36) and $(15), respectively (63) (28)
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $(3) and $7, respectively 6  (13)
Adjustment to pension and benefit obligation, net of taxes (benefit) of $(2) and $(1), respectively 2  2 
Total comprehensive income, net of taxes
$83  $84 
UE:
                       
Net income $
193
  $
166
  $
307
  $
309
 $64  $33 
Unrealized gain on derivative hedging instruments, net of taxes of $3, $5,
$3 and $2, respectively
  
5
  
8
   
4
  
4
 
Reclassification adjustments for (gain) included in net income, net of
taxes of $1, $3, $2 and $3, respectively
  (1) (5)  (3) (4)
Unrealized net (loss) on derivative hedging instruments, net of taxes (benefit) of $(7) and $(3), respectively (11) (5)
Reclassification adjustments for derivative (gain) loss included in net income, net of taxes (benefit) of $(1) and $2, respectively 1  (3)
Total comprehensive income, net of taxes $
197
  $
169
  $
308
  $
309
 $54  $25 
CIPS:
                       
Net income $
1
  $
29
  $
19
  $
43
 $3  $12 
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit)
of $-, $-, $- and $(3), respectively
  
-
  (1)  
-
  (5)
Reclassification adjustments for (gain) included in net income, net of
taxes of $-, $-, $1 and $1, respectively
  (1) 
-
   (1) (1)
Unrealized net gain on derivative hedging instruments, net of taxes of $- and $-, respectively -  1 
Total comprehensive income, net of taxes $
-
  $
28
  $
18
  $
37
 $3  $13 
Genco:
                       
Net income $
25
  $
19
  $
84
  $
27
 $46  $43 
Unrealized gain (loss) on derivative hedging instruments, net of taxes
(benefit) of $-, $2, $(1) and $2, respectively
  
-
  
3
   (2) 
3
 
Reclassification adjustments for (gain) included in net income, net of
taxes of $-, $2, $- and $1, respectively
  
-
  (2)  
-
  (1)
Adjustment to pension and benefit obligation, net of taxes (benefit) of $1,
$-, $(1) and $-, respectively
  
1
  
-
   (1) 
-
 
Unrealized net (loss) on derivative hedging instruments, net of taxes (benefit) of $(4) and $(1), respectively (6) (2)
Adjustment to pension and benefit obligation, net of taxes (benefit) of $(2) and $-, respectively 3  1 
Total comprehensive income, net of taxes $
26
  $
20
  $
81
  $
29
 $43  $42 
CILCORP:
                       
Net income $
1
  $
13
  $
34
  $
22
 $20  $21 
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit)
of $(1), $(3), $- and $(13), respectively
  (1) (4)  (1) (19)
Reclassification adjustments for (gain) included in net income, net of
taxes of $-, $-, $1 and $-, respectively
  
-
  
-
   (2) (1)
Adjustment to pension and benefit obligation, net of taxes of $-, $-, $- and
$-, respectively
  
-
  
-
   
1
  
-
 
Unrealized net gain on derivative hedging instruments, net of taxes of $- and $2, respectively -  3 
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $1 and $2, respectively (1) (3)
Adjustment to pension and benefit obligation, net of taxes (benefit) of $(1) and $-, respectively -  1 
Total comprehensive income, net of taxes $
-
  $
9
  $
32
  $
2
 $19  $22 
CILCO:
                       
Net income $
10
  $
19
  $
58
  $
44
 $26  $27 
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit)
of $-, $(3), $- and $(13), respectively
  
-
  (4)  
-
  (19)
Reclassification adjustments for (gain) included in net income, net of
taxes of $-, $-, $1 and $-, respectively
  
-
  
-
   (2) 
-
 
Unrealized net gain on derivative hedging instruments, net of taxes of $- and $2, respectively -  3 
Reclassification adjustments for derivative (gain) included in net income, net of taxes of $- and $2, respectively -  (3)
Total comprehensive income, net of taxes $
10
  $
15
  $
56
  $
25
 $26  $27 
IP:
                       
Net income (loss) $(4) $
43
  $
18
  $
63
 
Unrealized (loss) on derivative hedging instruments, net of taxes (benefit)
of $-, $(4), $- and $(1), respectively
  
-
  (6)  
-
  (2)
Reclassification adjustments for loss included in net income, net of taxes
(benefit) of $-, $(4), $- and $(1), respectively
  
-
  
6
   
-
  
2
 
Total comprehensive income (loss), net of taxes $(4) $
43
  $
18
  $
63
 
Net income$3  $15 
Total comprehensive income, net of taxes
$3  $15 

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

55
NOTE 1112 – RETIREMENT BENEFITS

Ameren’sAmeren's pension plans are funded in compliance with income tax regulations and federal funding requirements. We previously did not expect future contributions to be required until 2009, at which time we had expected a required contribution of $75 million to $125 million, to maintain minimum funding levels for Ameren’s pension plans. 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. Consequently, Ameren expects to fund its pension plans at a level equal to the pension expense. Based on Ameren's assumptions at December 31, 2006,2007, and reflecting this pension funding policy, Ameren now expects annual voluntary contributions of $45$40 million to $70 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.
 
54
Ameren made a contribution to its postretirement benefit plan of $26 million during the nine months ended September 30, 2007 as compared to $37 million during the nine months ended September 30, 2006.
The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans for the three and nine months ended September 30, 2007March 31, 2008 and 2006:2007:

Pension Benefits(a)
  
Postretirement Benefits(a)
  
Pension Benefits(a)
  
Postretirement Benefits(a)
 
Three Months
  
Nine Months
  
Three Months
  
Nine Months
  Three Months  Three Months 
2007
  
2006
  
2007
  
2006
  
2007
  
2006
  
2007
  
2006
  2008  2007  2008  2007 
Service cost $
16
  $
16
  $
47
  $
47
  $
5
  $5  $
15
  $16  $15  $16  $5  $6 
Interest cost  
45
  
43
   
135
  
129
   
18
  
18
   
54
  
51
  47  45  19  19 
Expected return on plan assets (51) (49)  (154) (147)  (13) (12)  (39) (35) (53) (52) (14) (13)
Amortization of:                                               
Transition obligation
 
-
  
-
   
-
  
-
   
1
  
-
   
2
  
1
  -  -  -  - 
Prior service cost (benefit)
 
3
  
3
   
9
  
8
   (2) (2)  (6) (5) 3  3  (2) (2)
Actuarial loss
 
5
  
10
   
16
  
31
   
6
  
9
   
18
  
26
  1  6  4  7 
Net periodic benefit cost$
18
  $
23
  $
53
  $
68
  $
15
  $18  $
44
  $54  $13  $18  $12  $17 

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

UE, CIPS, Genco, CILCORP, CILCO IP and EEIIP 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 and nine months ended September 30, 2007March 31, 2008 and 2006:2007:

Pension Costs
  
Postretirement Costs
  Pension Costs  Postretirement Costs 
Three Months
  
Nine Months
  
Three Months
  
Nine Months
  Three Months  Three Months 
2007
  
2006
  
2007
  
2006
  
2007
  
2006
  
2007
  
2006
  2008  2007  2008  2007 
Ameren(a)$
18
  $23  $
53
  $
68
  $
15
  $18  $
44
  $
54
  $13  $18  $12  $17 
UE 
10
  
13
   
30
  
39
   
7
  
9
   
22
  
28
  9  10  6  9 
CIPS 
2
  
3
   
6
  
9
   
2
  
2
   
5
  
6
  2  2  1  2 
Genco 
2
  
2
   
4
  
6
   
1
  
1
   
3
  
3
  1  1  1  1 
CILCORP 
2
  
3
   
7
  
8
   
2
  
3
   
5
  
7
  -  3  1  2 
IP 
1
  
2
   
4
  
6
   
2
  
3
   
8
  
10
  1  2  3  3 
EEI 
1
  
-
   
2
  
-
   
1
  
-
   
1
  
-
 

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

As discussed above and in Note 2
NOTE 13 – Rate and Regulatory Matters, the MoPSC issued an order that included approval of a regulatory tracking mechanism for pension and postretirement benefit costs. The difference between the level of pension and postretirement benefit costs incurred by UE under GAAP and the level of such costs built into rates effective June 4, 2007, will be tracked by means of a regulatory asset or liability, as applicable. The resulting regulatory asset or liability will be included in rate base for purposes of setting new rates in UE’s next electric rate case and amortized over five years beginning with the effective date of electric rates approved in UE’s next rate case. As of September 30, 2007, the regulatory liability was $6 million.SEGMENT INFORMATION

NOTE 12 – 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 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 consists 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 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
56
business of AERG. Other forFor CILCORP and CILCO, Other comprises leveraged lease investments, parent company activity and minor activities not reported in the Illinois Regulated or Non-rate-regulated Generation segments for CILCORP.

55

The following table presents information about the reported revenues and specified items included in net income of Ameren for the three and nine months ended September 30,March 31, 2008 and 2007, and 2006, and total assets as of September 30, 2007March 31, 2008 and December 31, 2006.2007.

Three Months
 
Missouri
Regulated
  
Illinois
Regulated
  
Non-rate-regulated Generation
  
Other
  
Intersegment Eliminations
  
Consolidated
 Missouri Regulated  
Illinois
Regulated
  Non-rate-regulated Generation  Other  Intersegment Eliminations  Consolidated 
2007:
                  
2008:                 
External revenues  $
934
  $
702
  $
372
  $(11) $
-
  $
1,997
 $715  $1,046  $316  $2  $-  $2,079 
Intersegment revenues   
11
   
21
   
122
   
10
   (164)  
-
  9  11  132  4  (156) - 
Net income (loss)(a)
  
179
   (9)  
73
   
1
   
-
   
244
  52  16  78  (8) -  138 
2006:
                        
External revenues  $
811
  $
836
  $
256
  $
7
  $
-
  $
1,910
 
Intersegment revenues  
46
  
4
  
212
  (1) (261) 
-
 
Net income(a)
 
142
  
83
  
62
  
6
  
-
  
293
 
Nine Months
                        
2007:
                                               
External revenues  $
2,258
  $
2,503
  $
980
  $(2) $
-
  $
5,739
 $638  $1,059  $318  $9  $-  $2,024 
Intersegment revenues   
34
   
34
   
379
   
30
   (477)  
-
  12  7  133  10  (162) - 
Net income(a)
  
264
   
45
   
197
   
4
   
-
   
510
  18  33  70  2  -  123 
2006:
                        
External revenues  $
2,021
  $
2,501
  $
703
  $
35
  $
-
  $
5,260
 
Intersegment revenues  
182
  
12
  
594
  
17
  (805) 
-
 
Net income(a)
 
255
  
125
  
102
  
4
  
-
  
486
 
As of September 30, 2007:
                        
As of March 31, 2008:                       
Total assets $
10,611
  $
6,487
  $
3,938
  $
1,131
  $(1,762) $
20,405
 $10,762  $6,333  $4,184  $897  $(1,418) $20,758 
As of December 31, 2006:
                        
As of December 31, 2007:                       
Total assets $
10,251
  $
6,226
  $
3,612
  $
1,161
  $(1,672) $
19,578
 $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 and nine months ended September 30,March 31, 2008 and 2007, and 2006, and total assets as of September 30, 2007March 31, 2008 and December 31, 2006.2007.

Three Months
 Missouri Regulated  
Other (a)
  
Consolidated
UE
 Missouri Regulated
Other (a)
  
Consolidated
UE
 
2008:        
Revenues $724  $-  $724 
Net income(b)
 52  11  63 
2007:
                    
Revenues  $
945
  $
-
  $
945
 $650  $-  $650 
Net income(b)
  
179
   
13
   
192
  18  14  32 
2006:
            
Revenues  $
857
  $
-
  $
857
 
Net income(b)
 
142
  
23
  
165
 
Nine Months
            
2007:
            
Revenues  $
2,292
  $
-
  $
2,292
 
Net income(b)
  
264
   
39
   
303
 
2006:
            
Revenues  $
2,203
  $
-
  $
2,203
 
Net income(b)
 
255
  
50
  
305
 
As of September 30, 2007:
            
As of March 31, 2008:           
Total assets  $
10,611
  $
52
  $
10,663
 $10,762  $-  $10,762 
As of December 31, 2006:
            
As of December 31, 2007:           
Total assets  $
10,251
  $
36
  $
10,287
 $10,852  $51  $10,903 

(a)   IncludesIncluded 40% interest in EEI.EEI through February 29, 2008.
(b)  Represents net income available to the common shareholder (Ameren).
(b)  Represents net income available to the common shareholder (Ameren).

The following table presents information about the reported revenues and specified items included in net income of CILCORP for the three and nine months ended September 30,March 31, 2008 and 2007, and 2006, and total assets as of September 30, 2007March 31, 2008 and December 31, 2006.2007.

Three Months
 
Illinois
Regulated
  
Non-rate-regulated Generation
  
CILCORP
Other
  
Intersegment
Eliminations
  
Consolidated
CILCORP
 
Illinois
Regulated
  Non-rate-regulated Generation  
CILCORP
Other
  
Intersegment
Eliminations
  
Consolidated
CILCORP
 
2008:              
External revenues $266  $79  $-  $-  $345 
Intersegment revenues  -  1  -  (1)    
Net income(a)
 12  8  -  -  20 
2007:
                                  
External revenues  $
142
  $
64
  $
-
  $
-
  $
206
 $239  $76  $-  $-  $315 
Intersegment revenues   
-
   
1
   
-
   (1)  
-
  -  1  -  (1) - 
Net income (loss)(a)
  (4)  
5
   
-
   
-
   
1
 
Net income(a)
 8  13  -  -  21 
As of March 31, 2008:                   
Total assets(b)
$1,200  $1,502  $2  $(191) $2,513 
As of December 31, 2007:        -         
Total assets(b)
$1,202  $1,455  $1  $(199) $2,459 
56
 
 
Three Months
 
Illinois
Regulated
  
Non-rate-regulated Generation
  
CILCORP
Other
  
Intersegment
Eliminations
  
Consolidated
CILCORP
 
2006:
                    
External revenues                                              $
153
  $
5
  $
-
  $
-
  $
158
 
Intersegment revenues                                       
-
   
54
   
-
   (54)  
-
 
Net income (loss)(a)                                           
  
12
   
2
   (1)  
-
   
13
 
Nine Months
                    
2007:
                    
External revenues                                              $
537
  $
202
  $
-
  $
-
  $
739
 
Intersegment revenues                                               
-
   
3
   
-
   (3)  
-
 
Net income(a)                                             
  
11
   
23
   
-
   
-
   
34
 
2006:
                    
External revenues                                              $
523
  $
23
  $
-
  $
-
  $
546
 
Intersegment revenues                                               
-
   
139
   
-
   (139)  
-
 
Net income (loss)(a)                                            
  
23
   
3
   (4)  
-
   
22
 
As of September 30, 2007:
                    
Total assets(b)
 $
1,253
  $
1,390
  $
4
  $(194) $
2,453
 
As of December 31, 2006:
                    
Total assets(b)
 $
1,208
  $
1,246
  $
4
  $(217) $
2,241
 

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


57

The following table presents information about the reported revenues and specified items included in net income of CILCO for the three and nine months ended September 30,March 31, 2008 and 2007, and 2006, and total assets as of September 30, 2007March 31, 2008 and December 31, 2006.2007.

Three Months
 
Illinois
Regulated
  
Non-rate-regulated Generation
  
CILCO
Other
  
Intersegment
Eliminations
  
Consolidated
CILCO
 
Illinois
Regulated
  Non-rate-regulated Generation  
CILCO
Other
  
Intersegment
Eliminations
  
Consolidated
CILCO
 
2007:
               
2008:              
External revenues  $
142
  $
64
  $
-
  $
-
  $
206
 $266  $79  $-  $-  $345 
Intersegment revenues   
-
   
1
   
-
   (1)  
-
  -  1  -  (1) – 
Net income (loss)(a)
  (4)  
14
   
-
   
-
   
10
 
2006:
                    
External revenues  $
153
  $
5
  $(1) $
-
  $
157
 
Intersegment revenues  
-
  
54
  
-
  (54) 
-
 
Net income (loss)(a)
 
12
  
8
  (1) 
-
  
19
 
Nine Months
                    
Net income(a)
 12  14  -  -  26 
2007:
                                       
External revenues  $
537
  $
202
  $
-
  $
-
  $
739
 $239  $76  $-  $-  $315 
Intersegment revenues   
-
   
3
   
-
   (3)  
-
  -  1  -  (1) - 
Net income(a)
  
11
   
46
   
-
   
-
   
57
  8  19  -  -  27 
2006:
                    
External revenues  $
523
  $
23
  $
-
  $
-
  $
546
 
Intersegment revenues  
-
  
139
  
-
  (139) 
-
 
Net income (loss)(a)
 
23
  
24
  (4) 
-
  
43
 
As of September 30, 2007:
                    
As of March 31, 2008:                   
Total assets  $
1,063
  $
785
  $
1
  $(1) $
1,848
 $1,011  $919  $-  $(1) $1,929 
As of December 31, 2006:
                    
As of December 31, 2007:                   
Total assets  $
1,020
  $
642
  $
1
  $(22) $
1,641
 $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.

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

OVERVIEWAmeren Executive Summary

Ameren Executive Summary

Ameren’s earnings in the thirdfirst quarter of 2008 exceeded its earnings in the 2007 comparable period principally because of the net impact of the following items:

·  Severe ice storms reduced Ameren’s first quarter 2007 net income by $18 million.
·  A FERC order that resettled costs among market participants, retroactive to 2005, reduced Ameren’s first quarter 2007 net income by $10 million.
·  The net costs associated with the Illinois electric settlement agreement reduced Ameren net income by  $6 million in the first quarter of 2008, while the reversal of a 2006 charge related to funding commitments for the Illinois Customer Elect electric rate increase phase-in plan benefited first quarter 2007 net income by $10 million.
·  Net mark-to-market gains from nonqualifying hedges increased Ameren’s first quarter 2008 net income by   $10 million, as compared to losses of $4 million in the first quarter of 2007.

Excluding these items, Ameren’s earnings in the first quarter of 2008 were below its earnings in the same period in 2007 principally because of higher fuel prices, increased distribution system reliability spending and the first nineimpact of electric rate redesign in Illinois. In late 2007, the ICC authorized redesigned electric rates to reduce seasonal fluctuations for residential customers who use electricity to heat their homes. The effect of these redesigned rates will shift some revenues from winter to summer months with no impact on full-year earnings. The earnings impact of 2007 werethese unfavorable items was reduced by, among other things, improved generation levels, higher power sales prices, the impact of colder weather on natural gas and power demand, and the benefit of the 2007 Missouri electric and natural gas rate orders.

Rising costs, associatedcoupled with significant levels of investment in Ameren’s Illinois and Missouri regulated business segments, continued to negatively impact the earnings of these segments. This is because current utility rate levels are not sufficient to recover costs and provide reasonable returns. To address this issue, rate adjustment requests have been filed by all of Ameren’s utilities. In November 2007, electric and gas delivery service rate adjustment requests were filed in Illinois for CIPS, CILCO and IP, which, as amended, requested a total annual increase in revenues of $220 million in the aggregate. In April 2008, a $251 million electric rate increase request was filed in Missouri by UE. These cases are progressing, and final decisions are expected by the end of September 2008 for the Illinois electric settlement agreement, whichrate cases and by March 2009 for the Missouri rate case. Achieving constructive regulatory outcomes in these cases is discussed below, changescritical to UE's, CIPS', CILCO's and IP’s ability to invest in their energy infrastructure in order to meet customers’ expectations and deliver safe reliable service.

Since the beginning of 2008, UE, Genco, and IP have been very active in the capital markets as nearly $900 million of debt has been issued to refinance outstanding insured auction-rate tax-exempt bonds and short-term debt as well as to fund construction programs. Early this year the insured auction-rate tax-exempt securities market effectively collapsed. UE and the Ameren Illinois Utilities’ electric rate structure andUtilities moved quickly to obtain the rising costsnecessary regulatory approvals to refinance $621 million of operating and investing in our Missouri and Illinois rate-regulated segments, including increased reliability expenditures. During the third quarter of 2007, these factors more than offset higher margin in the Missouri and Illinois rate-regulated business segments from warmertheir $828 million insured auction-rate tax-exempt debt outstanding at March 31, 2008. The remaining 
5758
 
summer weather, the implementation$207 million of the June 2007 Missouri electric rate order and higher electric margin in Non-rate-regulated Generation due to the replacement of below-market power sales contracts that expired in 2006.

Ameren’s earningsauction-rate securities currently have reasonable interest rates in the first nine months of 2007 were reduced by $19 million (after taxes), or 9 cents per share, as a result of the cost of restoration efforts associated with a severe ice storm January 2007. Storm-related costs in the first nine months of 2006 reduced net income by an estimated $25 million (after taxes), or 13 cents per share. In addition, costs related to participation in the MISO Day Two Energy Market were $10 million (after taxes), or 5 cents per share, higher in the first nine months of 2007 over the same period in 2006 becauseevent of a March 2007 FERC order that resettled such costs among market participants retroactive to 2005. Ameren’s net income in the first quarter of 2007 benefited from the reversal of a $10 million charge (after taxes), or 5 cents per share, originally recorded in 2006 related to funding for low-income energy assistance and energy efficiency programs in Illinois. These commitments were terminated in the first quarter of 2007 as a result of credit rating downgrades resulting from Illinois legislative actions during that period.auction failure.

In late August 2007, the Illinois governor signed into law the enabling legislation for the Illinois electric settlement agreement that was reached among key stakeholders in Illinois deigned to address the increase in electric rates that occurred after the state’s electric rate freeze ended on January 1, 2007, and to address the future power procurement process in Illinois. As part of the Illinois settlement agreement, the electric customers of the Ameren Illinois Utilities will receive $488 million in bill credits and refunds and other relief through 2010 as part of an approximately $1 billion state-wide relief package. The Ameren Illinois Utilities, Genco and AERG will be funding $150 million, in the aggregate, of this program over a four-year period. The total impact to Ameren’s earnings per share is expected to be about 45 cents per share spread across four years, including 26 cents per share in 2007. The Ameren Illinois Utilities began sending checks and providing bill credits to customers in September 2007.  Ameren recorded 18 cents per share of these costs in the third quarter of 2007. Other key aspects of the settlement agreement are currently being implemented including those related to power procurement in the future.

Ameren’s Illinois Regulated business segment experienced a significant earnings decline during the third quarter and first nine months of 2007 compared with 2006 due to, among other things, its current levels of electric and gas delivery service rates being insufficient to recover its current costs of providing service to its customers. In early November 2007, the Ameren Illinois Utilities filed requests with the ICC for a combined $247 million increase in electric and gas rates. As the Illinois Regulated business segment’s recent earnings results indicate, these rate increase requests are clearly needed by the Ameren Illinois Utilities and are consistent with the Ameren Illinois Utilities’ need to recover their costs of providing safe and reliable service to their customers and earning a reasonable return on their investments. Earlier this year, the Ameren Illinois Utilities pledged to keep the overall annual residential electric bill increases in Illinois to less than 10 percent per year for each utility in their next rate filings. These Illinois rate filings are consistent with that pledge. This self-imposed rate increase limit could result in approximately $30 million of the increase request not being phased-in until the second year of implementation if the full request is granted by the ICC. The Ameren Illinois Utilities’ also requested rate mechanisms for bad debt expenses, electric infrastructure investments and the decoupling of natural gas revenues from volumes. The ICC has eleven months to make a decision on these filings. With rising costs, including fuel and related transportation, purchased power, labor and material 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. As a result, Ameren, UE, CIPS, CILCO and IP expect to be entering a period where more frequent rate cases will be necessary.

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 which are separate, independent legal entities with separate businesses, assets and liabilities,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, as discussed below. 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.

58
·  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. About 90%The vast majority of Ameren’s 2006 revenues were directlyare subject to state or federal regulation. This regulation can havehas 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 orand purchased power cost recovery mechanismsmechanism 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 pending and recently-decided rate cases and the Illinois electric settlement agreement in Illinois.agreement. Fluctuations in interest rates affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity 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 decreasedincreased to $244$138 million, or $1.18 per share, in the third quarter of 2007 from $293 million, or $1.42 per share, in the third quarter of 2006. Net income in the Missouri Regulated and Non-rate-regulated Generation segments in the three months ended September 30, 2007, increased by $37 million and $11 million, respectively, from the prior-year period, while net earnings in the Illinois Regulated segment declined by $92 million.

Ameren’s net income increased to $510 million, or $2.4666 cents per share, in the first nine monthsquarter of 20072008 from $486$123 million, or $2.3759 cents per share, in the first nine monthsquarter of 2006.2007. Net income increased in the Missouri Regulated and Non-rate-regulated Generation segments by $9$34 million and $95$8 million, respectively, in the first ninethree months of 20072008 compared to the prior-year period, while net income in the Illinois Regulated segment decreased by $80 million.$17 million from the same period in 2007.

Earnings were favorably impacted in the thirdfirst quarter and first nine months of 20072008 as compared with the same periodsperiod in 20062007 by:

·  higherincreased plant availability and margins on interchange sales in the Non-rate-regulated Generation segment due to the replacement of below-market power sales contracts, which expired in 2006, with higher-priced contracts;Missouri Regulated segment;
·  favorable weather conditions;increased plant availability in the Non-rate-regulated Generation segment;
·  
the absence of costs in the current-year periods2008 that were incurred in the prior-year periods related to the reservoir breach at UE’s Taum Sauk plant (4January 2007 associated with electric outages caused by a severe ice storm (9 cents per share and
9 cents per share, respectively)share);
·  net mark-to-market gains on energy and fuel-related transactions (7 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 (9(6 cents per share and 11 cents per share, respectively)share); and
·  the absence of costs associated with outages caused by severe storms in the current year periods2008 that were incurred in the prior-year periods (102007 as a result of a March 2007 FERC order that resettled costs among market participants retroactive to 2005  (5 cents per shareshare); and 13
59
·  favorable weather conditions (estimated at 3 cents per share, respectively)share).

Earnings were negatively impacted in the thirdfirst quarter and first nine months of 20072008 as compared with the same periodsperiod in 20062007 by:

·  higher fuel and related transportation prices (9 cents per share);
·   increased distribution system reliability expenditures (6 cents per share);
·  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);
·  the implementation of new seasonal delivery service tariffs at the Ameren Illinois Utilities, which will have no impact on total annual revenues (5 cents per share); and
·  electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities’Utilities electric customers under the Illinois electric settlement agreement (18 cents per share) described in Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report;
·  the elimination of bundled tariffs and the rate redesign in Illinois;
59

·    higher fuel and related transportation prices (9 cents per share and 23 cents per share, respectively);
·  higher labor and employee benefit costs (4 cents per share and 12 cents per share, respectively);
·  increased depreciation and amortization expense (4 cents per share and 11 cents per share, respectively);
·  higher financing costs (5 cents per share and 13 cents per share, respectively); and
·  lower emission allowance sales (4 cents per share and 5 cents per share, respectively).

In addition to the above items affecting both periods, earnings were impacted in the first nine months of 2007 as compared with the first nine months of 2006 by the following items:
Earnings were favorably impacted by:
·  the reversal of an accrual originally recorded in 2006 in the Illinois Regulated segment for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan (5 cents per share). The commitment to make these contributions was terminated in 2007 as a result of credit rating agency downgrades resulting from Illinois legislative actions; and
·  the lack of FERC fees related to UE’s Osage hydroelectric plant in the current-year period that were incurred in the prior-year period and the capitalization of fees, pursuant to a May 2007 MoPSC order, in the current-year period (2 cents per share).
Earnings were negatively impacted by:
·  costs associated with electric outages caused by a severe ice storm in January 2007 (9 cents per share);
·  a FERC order in March 2007 that reallocated costs related to participation in the MISO Day Two Energy Market among market participants retroactive to 2005 (5 cents per share); and
·  the cost of UE’s Callaway nuclear plant refueling and maintenance outage in the second quarter of 2007 exceeding the cost of the unplanned outage at the Callaway plant in the second quarter of 2006 (9(3 cents per share).

An increase in the number of common shares outstanding reduced Ameren’s earningsThe cents per share in the 2007 periods compared with the 2006 periods. Per share information presented above is based on average shares outstanding in 2006.the first quarter of 2007.

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 and nine months ended September 30, 2007March 31, 2008 and 2006:2007:

 
Three Months
  
Nine Months
 Three Months 
 
2007
  
2006
  
2007
  
2006
 2008  2007 
Net income (loss):            
Net income:     
UE(a)
 $
192
  $
165
  $
303
  $
305
 $63  $32 
CIPS  
-
  
28
   
17
  
41
  2  11 
Genco  
25
  
19
   
84
  
27
  46  43 
CILCORP  
1
  
13
   
34
  
22
  20  21 
IP  (5) 
42
   
16
  
61
  2  14 
Other(b)
  
31
  
26
   
56
  
30
 
Other(b)
 5  2 
Ameren net income $
244
  $
293
  $
510
  $
486
 $138  $123 

(a)  Includes earnings from a non-rate-regulated 40% interest in EEI.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 and nine months ended September 30, 2007March 31, 2008 and 2006:2007:

 
Missouri
Regulated
  
Illinois
Regulated
  
Non-rate-
regulated Generation
  
Other / Intersegment
Eliminations
  
Total
 
Missouri Regulated
  
Illinois
Regulated
  Non-rate-regulated Generation  
Other / Intersegment
Eliminations
  
 
Total
 
Three Months 2008:              
Electric margin $441  $178  $272  $(13) $878 
Gas margin  28  126  -  (1) 153 
Other operations and maintenance  (217) (143) (78) 15  (423)
Depreciation and amortization  (81) (60) (28) (7) (176)
Taxes other than income taxes  (60) (43) (8) (2) (113)
Other income  12  4  1  -  17 
Interest expense  (41) (35) (21) (3) (100)
Income taxes  (29) (9) (52) 3  (87)
Minority interest and preferred dividends (1) (2) (8) -  (11)
Net income (loss) $52  $16  $78  $(8) $138 
Three Months 2007:
                                  
Electric margin  $
677
  $
185
  $
267
  $(14) $
1,115
 $408  $179  $250  $(10) $827 
Gas margin   
9
   
48
   
-
   
-
   
57
  27  115  -  (2) 140 
Other revenues   
2
   
2
   
-
   (4)  
-
  1  2  -  (3) - 
Other operations and maintenance   (222)  (142)  (79)  
16
   (427) (223) (121) (68) 23  (389)
                    
Depreciation and amortization  (87) (60) (27) (9) (183)
Taxes other than income taxes  (57) (36) (8) (1) (102)
Other income and (expenses)  9  3  1  (2) 11 
Interest expense  (48) (29) (25) 2  (100)
Income taxes  (11) (18) (46) 4  (71)
Minority interest and preferred dividends (1) (2) (7) -  (10)
Net income $18  $33  $70  $2  $123 

 
60
 
Margins
  
Missouri
Regulated
  
Illinois
Regulated
  
Non-rate-regulated Generation
  
Other / Intersegment
Eliminations
  
Total
 
Three Months 2007:
               
Depreciation and amortization                                                 (82)  (54)  (26)  (7)  (169)
Taxes other than income taxes                                                 (69)  (23)  (6)  
1
   (97)
Other income and (expenses)                                                 
8
   
5
   
1
   
-
   
14
 
Interest expense                                                 (49)  (36)  (28)  
3
   (110)
Income taxes                                                 (94)  
8
   (49)  
5
   (130)
Minority interest and preferred dividends  (1)  (2)  (7)  
1
   (9)
Net income (loss)                                                $
179
  $(9) $
73
  $
1
  $
244
 
Three Months 2006:
                    
Electric margin                                                $
622
  $
319
  $
221
  $(18) $
1,144
 
Gas margin                                                 
10
   
52
   
-
   (3)  
59
 
Other revenues                                                 
1
   
2
   
1
   (4)  
-
 
Other operations and maintenance                                                 (214)  (133)  (65)  
17
   (395)
Depreciation and amortization                                                 (82)  (49)  (26)  (5)  (162)
Taxes other than income taxes                                                 (66)  (29)  (5)  
1
   (99)
Other income and (expenses)                                                 
7
   
3
   
-
   (1)  
9
 
Interest expense                                                 (43)  (25)  (26)  
5
   (89)
Income taxes                                                 (93)  (55)  (27)  
14
   (161)
Minority interest and preferred dividends  
-
   (2)  (11)  
-
   (13)
Net income                                                $
142
  $
83
  $
62
  $
6
  $
293
 
Nine Months 2007:
                    
Electric margin                                                $
1,579
  $
573
  $
766
  $(44) $
2,874
 
Gas margin                                                 
50
   
227
   
-
   (4)  
273
 
Other revenues                                                 
2
   
3
   
-
   (5)  
-
 
Other operations and maintenance                                                 (668)  (398)  (239)  
56
   (1,249)
Depreciation and amortization                                                 (253)  (162)  (80)  (19)  (514)
Taxes other than income taxes                                                 (186)  (89)  (20)  
-
   (295)
Other income and (expenses)                                                 
25
   
15
   
3
   
1
   
44
 
Interest 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                                                $
264
  $
45
  $
197
  $
4
  $
510
 
Nine Months 2006:
                    
Electric margin                                                $
1,492
  $
668
  $
570
  $(46) $
2,684
 
Gas margin                                                 
45
   
222
   
-
   (4)  
263
 
Other revenues                                                 
2
   
1
   
1
   (4)  
-
 
Other operations and maintenance                           ��                     (581)  (381)  (216)  
37
   (1,141)
Depreciation and amortization                                                 (243)  (144)  (79)  (19)  (485)
Taxes other than income taxes                                                 (184)  (99)  (19)  
-
   (302)
Other income and (expenses)                                                 
16
   
9
   
1
   (1)  
25
 
Interest expense                                                 (123)  (70)  (77)  
16
   (254)
Income taxes                                                 (165)  (76)  (56)  
24
   (273)
Minority interest and preferred dividends  (4)  (5)  (23)  
1
   (31)
Net income                                                $
255
  $
125
  $
102
  $
4
  $
486
 

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins for the three and nine months ended September 30, 2007,March 31, 2008, compared with the same periodsperiod in 2006.2007. 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
  
IP
 
Electric revenue change:                     
Effect of weather on native load (estimate) $59  $
46
  $
3
  $
-
  $
2
  $
2
  $
8
 
UE electric rate increase  15   
15
   
-
   
-
   
-
   
-
   
-
 
Storm-related outages  
3
   
2
   
2
   (2)  
-
   
-
   
1
 
JDA- terminated December 31, 2006  
-
   (35)  
-
   (23)  
-
   
-
   
-
 
Interchange revenues  
36
   
36
   
-
   
-
   
-
   
-
   
-
 
                             
61
Three Months
Ameren(a)
  UE  CIPS  Genco  CILCORP  CILCO  IP 
Electric revenue change:                    
Effect of weather (estimate)$4  $1  $1  $-  $1  $1  $1 
UE electric rate increase 9   9   -   -   -   -   - 
Interchange revenues, excluding estimated
   weather impact of $(3) million
 32   32   -   -   -   -   - 
Illinois electric settlement agreement - net                           
  of reimbursement (11)  -   (2)  (4)  (3)  (3)  (2)
FERC-ordered MISO resettlements –
  March 2007
 (13)  -   -   (8)  (4)  (4)  - 
Illinois rate redesign (38)  -   (14)  -   (6)  (6)  (18)
Net mark-to-market gains on energy
  contracts
 12   4   -   -   -   -   - 
Growth and other 9   22   (16)  -   26   26   (15)
Total electric revenue change$4  $68  $(31) $(12) $14  $14  $(34)
Fuel and purchased power change:                           
Fuel:                           
Generation and other$(19) $(8) $-  $(4) $(5) $(5) $- 
Emission allowance sales (costs) -   (2)  -   1   1   1   - 
Net mark-to-market gains on fuel
  contracts
 11   6   -   5   1   1   - 
Price (31)  (18)  -   (9)  (2)  (2)  - 
Purchased power 33   (26)  13   21   (8)  (8)  10 
Illinois rate redesign 21   -   8   -   3   3   10 
FERC-ordered MISO resettlements –
   March 2007
 32   13   4   -   3   3   12 
Total fuel and purchased power change$47  $(35) $25  $14  $(7) $(7) $32 
Net change in electric margins$51  $33  $(6) $2  $7  $7  $(2)
Net change in gas margins$13  $1  $3  $-  $4  $4  $3 

Three Months
 
Ameren(a)
  
UE
  
CIPS
  
Genco
  
CILCORP
  
CILCO
  
IP
 
Elimination of CILCO/AERG intra-company                            
power supply agreement  
30
   
-
   
-
   
-
   
30
   
30
   
-
 
Illinois settlement agreement-net of                            
 reimbursement  (53)  
-
   (8)  (20)  (14)  (14)  (11)
Illinois rate redesign, generation repricing,
growth and other
  
15
   
27
   (24)  
7
   
33
   
33
   (66)
Total $
105
  $
91
  $(27) $(38) $
51
  $
51
  $(68)
Fuel and purchased power change:                            
Fuel:                         ��  
Generation and other $(21) $(9) $
-
  $(17) $
2
  $
2
  $
-
 
Emission allowance sales (costs)  (16)  
5
   
-
   
-
   
4
   
3
   
-
 
Mark-to-market gains (losses)  
4
   (1)  
-
   
-
   
-
   
-
   
-
 
Price  (30)  (25)  
-
   
-
   (1)  (1)  
-
 
JDA-terminated December 31, 2006  
-
   
23
   
-
   
35
   
-
   
-
   
-
 
Purchased power  (35)  (22)  (17)  
48
   (27)  (27)  
2
 
Power purchase agreement -
Entergy Arkansas, Inc.
  (8)  (8)  
-
   
-
   
-
   
-
   
-
 
Elimination of CILCO/AERG intra-                            
company power supply agreement  (30)  
-
   
-
   
-
   (30)  (30)  
-
 
Storm-related energy costs  
2
   
1
   
-
   
1
   
-
   
-
   
-
 
Total fuel and purchased power change $(134) $(36) $(17) $
67
  $(52) $(53) $
2
 
Net change in electric margins
 $(29) $
55
  $(44) $
29
  $(1) $(2) $(66)
Net change in gas margins
 $(2) $(1) $(2) $
-
  $
1
  $
1
  $(1)
Nine Months
                            
Electric revenue change:                            
Effect of weather on native load (estimate) $
105
  $
67
  $
14
  $
-
  $
8
  $
8
  $
16
 
UE electric rate increase  
20
   
20
   
-
   
-
   
-
   
-
   
-
 
Storm-related outages  
9
   
8
   
2
   (2)  
-
   
-
   
1
 
JDA - terminated December 31, 2006  
-
   (156)  
-
   (69)  
-
   
-
   
-
 
Interchange revenues  
128
   
128
   
-
   
-
   
-
   
-
   
-
 
Elimination of CILCO/AERG intra-company                            
power supply agreement  
83
   
-
   
-
   
-
   
83
   
83
   
-
 
Illinois settlement agreement - net of                            
reimbursement  (53)  
-
   (8)  (20)  (14)  (14)  (11)
FERC-ordered MISO resettlements -                            
March 2007  
16
   
-
   
-
   
12
   
3
   
3
   
-
 
Illinois rate redesign, generation repricing,
growth and other
  
180
   
11
   
28
   (16)  
118
   
118
   (35)
Total $
488
  $
78
  $
36
  $(95) $
198
  $
198
  $(29)
Fuel and purchased power change:                            
Fuel:                            
Generation and other $(16) $
12
  $
-
  $(45) $
15
  $
16
  $
-
 
Emission allowance sales (costs)  (10)  
3
   
-
   
-
   
12
   
8
   
-
 
Mark-to-market gains (losses)  
11
   (1)  
-
   
5
   
1
   
1
   
-
 
Price  (72)  (60)  
-
   (2)  (7)  (7)  
-
 
JDA - terminated December 31, 2006  
-
   
69
   
-
   
156
   
-
   
-
   
-
 
Purchased power  (77)  
14
   (53)  
90
   (94)  (94)  2 
Power purchase agreement -
Entergy Arkansas, Inc.
  (12)  (12)  
-
   
-
   
-
   
-
   
-
 
Elimination of CILCO/AERG intra-company                            
power supply agreement  (83)  
-
   
-
   
-
   (83)  (83)  
-
 
FERC-ordered MISO resettlements -                            
March 2007  (38)  (12)  (8)  
-
   (4)  (4)  (14)
Storm-related energy costs  (1)  (2)  
-
   
1
   
-
   
-
   
-
 
Total fuel and purchased power change $(298) $
11
  $(61) $
205
  $(160) $(163) $(12)
Net change in electric margins
 $
190
  $
89
  $(25) $
110
  $
38
  $
35
  $(41)
Net change in gas margins
 $
10
  $
5
  $
1
  $
-
  $
4
  $
4
  $(1)
(a)  Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

62
Ameren

Ameren’s electric margin decreasedincreased by $29$51 million, or 6%, for the three months and increased by $190 million for the nine months ended September 30, 2007, respectively,March 31, 2008, compared with the same periodsperiod in 2006.2007. The following items had a favorable impact on electric margin for the thirdfirst quarter and first nine months of 20072008 as compared to the year-ago periods:
period:
·  Non-rate-regulated Generation selling more power at market-based prices in the third quarterNet mark-to-market gains of $23 million on energy and first nine months of 2007 compared with sales at below-market prices pursuant to cost-based power supply agreements, which expired on December 31, 2006;fuel-related transactions.
·  favorable weather conditionsAn increase in margin on interchange sales of $22 million due to a 12% increase in average sales prices and a 13% increase in sales volume supported by increased native load electric margin by an estimated $33 million and  $54 million for the three and nine months ended September 30, 2007, respectively;hydroelectric generation due to improved water levels.
·  
Increased plant availability, primarily in the Non-rate-regulated Generation segment. Ameren’s baseload nuclear and coal-fired generating plants’ average capacity and equivalent availability factors were approximately 82% and 88%, respectively, in the first quarter of 2008 compared with 79% and 86%, respectively, in the first quarter of 2007.
·  Reduced net MISO purchased power costs of $19 million due to the absence of the March 2007 FERC order that resettled costs in 2007 among market participants retroactive to 2005.
·  Other MISO purchased power costs, excluding the effect of the March 2007 FERC order, declined $16 million.
·  UE’s electric rate increase that went into effect June 4, 2007, which increased electric margin by an estimated $15 million and $20 million for the three and nine months ended September 30, 2007, respectively;$9 million.
·  an increase in margin on interchange sales primarily becauseGrowth and other, including the effect of the termination of the JDA on December 31, 2006. This termination of the JDA provided UE with the ability to sell its excess power, originally obligated to Genco under the JDA at cost, in the spot market at higher purchased power prices. This increase was partially offset by higher purchased power costs of $8 million and $12 million for the three and nine months ended September 30, 2007, respectively, associated with Entergy Arkansas, Inc. See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report, for more information on the UE power purchase agreement with Entergy Arkansas, Inc. In addition, increased native load demand, because of warmer weather, reduced excess power available for sale;
·  increased revenues as a result of lower than expected line losses at UE;
·  increased hydroelectric generation, which favorably impacted purchased power cost;
·  severe storm-related outages that occurred in 2006, which negatively impacted electric sales and resulted in an estimated net reduction in overall electric margin of  $5 million and $8 million for the three and nine months ended September 30, 2006, respectively;
·  unrealized mark-to-market net gains on fuel and energy contracts not yet settled increased electric margin by $4 million and $11 million for the three and nine months ended September 30, 2007, respectively; and
·  decreased fuel costs due to the lack of $4 million in fees levied by the FERC in the nine months ended September 30, 2006, upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant, and the May 2007 MoPSC rate order, which directed UE to transfer $4 million of the total fees to an asset account, which is being amortized over 25 years.2008 leap year day.

The following items had an unfavorable impact on electric margin for the thirdfirst quarter and first nine months of 20072008 as compared to the year-ago periods:period:

·  
A 13% increase in fuel prices.

61
·  the combined effectThe implementation of the elimination ofnew seasonal delivery service tariffs at the Ameren Illinois Utilities’ bundled tariffs, implementation of new delivery service tariffs including changes in seasonal ratesUtilities, effective January 2, 2007, and the expiration of  power supply contracts;2008, decreased electric margin by $17 million.
·  a 15% and 12% increase in coal and related transportation prices for the three and nine months ended September 30, 2007, respectively;
·  
rate relief and customer assistance programs under theThe Illinois electric settlement agreement, which reduced electric margin by $53$11 million. Illinois customer refund payments and credits, including the forgiveness of late payment charges, provided to certain Ameren Illinois Utilities’ electric customers of $159 million for the three and nine months ended
September 30, 2007, decreased electric revenue. As part of the settlement agreement, Ameren expects to receive reimbursements from non-affiliated generators in Illinois totaling $106 million for the three and nine months ended September 30, 2007;
·  MISO purchased power costs were $18 million and $29 million higher for the three and nine months ended September 30, 2007, respectively. Costs related to participation in the MISO Day Two Energy Market were higher for the year because of a March 2007 FERC order that resettled costs among market participants retroactive to 2005; and
·  decreased emission allowance sales of $20 million and $22 million offset by lower emission allowance costs of $4 million and $12 million for the three and nine months ended September 30, 2007, respectively.
 
Ameren’s gas margin was comparable in the three months ended September 30, 2007, with the same period in 2006. Ameren’s gas margin increased by $10$13 million, or 4%9%, for the ninethree months ended September 30, 2007,March 31, 2008, compared with the same period in 20062007 due primarily because ofto favorable weather conditions as evidenced by a 14%an 11% increase in heating degree-days for the nine months ended  September 30, 2007.degree-days.

Missouri Regulated

UE

UE’s electric margin increased $55$33 million, and $89 millionor 8%, for the three and nine months ended September 30, 2007, respectively,March 31, 2008, compared towith the same periodsperiod in 2006.2007. The following items had a favorable impact on electric margin
63
for the thirdfirst quarter and first nine months of 20072008 as compared to the year-ago periods:period:

·  anAn increase in margin on interchange sales primarily because of the termination of the JDA on December 31, 2006. This termination of the JDA provided UE with the ability$22 million due to sell its excess power, originally obligated to Genco under the JDA at cost,a 12% increase in the spot market at higher market prices. Thisaverage sales prices and a 13% increase was partially offsetin sales volume supported by increased purchased power costs of $8 million and $12 million for the three and nine months ended September 30, 2007, respectively, associated with an agreement with Entergy Arkansas, Inc. See Note 2 – Rate and Regulatory Mattershydroelectric generation due to our financial statements under Part I, Item 1, of this report, for more information on the UE power purchase agreement with Entergy Arkansas, Inc. In addition, increased native load demand, because of warmer weather, reduced excess power available for sale;improved water levels.
·  favorable weather conditions increased native load electric margin by an estimated $31Reduced MISO purchased power costs of $13 million and $44 million fordue to the three and nine months ended September 30,absence of the March 2007 respectively;FERC order.
·  Net mark-to-market gains of $10 million on energy and fuel-related transactions.
the
·  The electric rate increase that went into effect June 4, 2007, which increased electric margin by an estimated $15 million and $20 million for the three and nine months ended
September 30, 2007, respectively;
$9 million.
·  increased revenues as a result of lower than expected line losses;
·  increased hydroelectric generation, which favorably impacted purchased power costs;
·  severe storm-related outages in 2006, which reduced electric margin by $3 millionGrowth and $6 million for the three and nine months ended September 30, 2006, respectively; and
·  decreased fuel costs due to the lack of $4 million in fees levied by the FERC in the nine months ended September 30, 2006, upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant, and the May 2007 MoPSC rate order, which directed UE to transfer $4 million of the total fees to an asset account, which is being amortized over 25 years.
Factors that had an unfavorable impact on electric margin for the three and nine months ended September 30, 2007, as compared to the same periods in the prior year, were as follows:

·  a 24% and 17% increase in coal and related transportation prices for the three- and nine-month periods ended September 30, 2007, respectively;
·  MISO costs were $12 million higher for the nine months ended September 30, 2007, compared to the same period in 2006, due to the March 2007 FERC order;
·  other, MISO purchased power costs, excludingincluding the effect of the March 2007 FERC order, were $18 million higher for the third quarter of 2007 and $9 million higher for the nine months ended September 30, 2007, compared to the same periods in 2006; and2008 leap year day.
·  reduced power plant availability because of planned maintenance activities.
 
UE’s gas margin was comparable in the three months ended September 30, 2007, with the same period in 2006. UE’s gas margin increased by $5 million, or 11%, for the nine months ended September 30, 2007, compared with the same period in 2006 primarily because of favorable weather conditions as evidenced by a 15% increase in heating degree-days for the nine months ended September 30, 2007.

Illinois Regulated

Illinois Regulated’s electric margin declined by $134 million, or 42%, and $95 million, or 14%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. Illinois Regulated’s gas margin decreased by $4 million in the third quarter of 2007 and increased by $5 million, or 2%, for the nine months ended September 30, 2007, compared with the same periods in 2006.

CIPS

CIPS’ electric margin decreased by $44 million, or 43%, and $25 million, or 12%, for the three and nine months ended September 30, 2007, respectively, compared to the same periods in 2006. The following items had an unfavorable impact on electric margin for the third quarter and first ninethree months of 2007ended March 31, 2008, as compared to the year-ago periods:period:

·  the combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs, including changesA 14% increase in seasonal rates effective January 2, 2007, and the expiration of power supply contracts;fuel prices.
·  the Illinois settlement agreement reduced electric margin by $8Higher purchased power prices of $7 million. Customer refund payments and credits, including the forgiveness of late payment charges, totaled $54 million for the three and nine months ended September 30, 2007, which were reduced by expected reimbursements of $36 million due from non-affiliated generators and $10 million due from affiliated generators in Illinois; and
·  MISO costs increased $8 million for the nine months ended September 30, 2007, compared to the same period in 2006, becauseReduced emission allowance sales of a March 2007 FERC order that resettled costs among market participants retroactive to 2005.$2 million.
 
64
The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:
·  
MISO purchased power costs, excluding the effect of the March 2007 FERC order discussed above, were $4 million and $16 million lower for the three and nine
months ended September 2007, respectively, compared to the same periods in 2006;
·  severe storm-related outages in 2006, which reduced electric margin by $2 million for the three and nine months ended September 30, 2006; and
·  favorable weather conditions, which increased electric margin by an estimated $5 million for the nine months ended September 30, 2007.
CIPS’ gas margin decreased by $2 million for the three months ended September 30, 2007, compared with the same period in 2006 primarily because of reduced transportation service revenues. CIPS’UE’s gas margin increased by $1 million, or 2%4%, for the ninethree months ended September 30,March 31, 2008, compared with the same period in 2007 due to the gas rate increase that went into effect in April 2007 and favorable weather conditions as evidenced by a 10% increase in heating-degree days.

Illinois Regulated

Illinois Regulated’s electric margin decreased by $1 million, or 1%, for the three months ended March 31, 2008, compared with the same period in 2007. Illinois Regulated’s gas margin increased by $11 million, or 10%, in the first quarter of 2008, compared with the same period in 2007.

CIPS

CIPS’ electric margin decreased by $6 million, or 10%, for the three months ended March 31, 2008, compared with the same period in 2007. The following items had an unfavorable impact on electric margin for the first quarter of 2008 as compared to the year-ago period:
·  The implementation of new seasonal delivery service tariffs decreased electric margin by $6 million.
·  The Illinois electric settlement agreement, which reduced electric margin by $2 million.
These unfavorable variances were partially offset by reduced MISO purchased power costs of $4 million due to the absence of the March 2007 FERC order.

CIPS’ gas margin increased by $3 million, or 11%, for the three months ended March 31, 2008, compared with the same period in 2007 primarily because of favorable weather conditions as evidenced by a 15% inrease10% increase in heating degree-days for the nine months ended September 30, 2007.
degree-days.

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, 2007,March 31, 2008, as compared with the same periodsperiod in 2006:2007:

 
Three Months
  
Nine Months
  Three Months 
CILCO (Illinois Regulated) $(24) $(29) $7 
CILCO (AERG)  
22
   
64
  
   -
 
Total change in electric margin $(2) $
35
  $7 
 
CILCO’s (Illinois Regulated) electric margin decreasedincreased by $24$7 million, or 45%, and $29 million, or 23%24%, for the three and nine months ended September 30, 2007, respectively,March 31, 2008, compared to the same periodsperiod in 2006. 2007 primarily as a result of reduced MISO purchased power costs of $3 million due to the absence of the March 2007 FERC order.
The following items had an unfavorable impact on electric margin for the thirdfirst quarter and first nine months of 20072008 as compared to the year-ago periods:period:

·  the combined effect of the elimination of bundled tariffs,The implementation of new seasonal delivery service tariffs including changes in seasonal rates effective January 2, 2007, and the expiration of power supply contracts;decreased electric margin by $3 million.
·  theThe Illinois electric settlement agreement, which reduced electric margin by $5$1 million. Customer refund payments and credits, including the forgiveness of late payment charges, totaled $32 million for the three and nine months ended September 30, 2007, which were reduced by expected reimbursements of $21 million from non-affiliated generators and by $6 million from affiliated generators in Illinois; and
·  MISO costs increased $4 million for the nine months ended September 30, 2007, because of the March 2007 FERC order noted above.

The decrease in electric margin was reduced by favorable weather conditions, which increased electric margin by an estimated $2 million for the nine months ended September 30, 2007.

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, 2007,March 31, 2008, as compared with the same periodsperiod in 2006.2007.
 
CILCO’s (Illinois Regulated) gas margin was comparable for the three months ended September 30, 2007, with the same period in 2006.
62
CILCO’s (Illinois Regulated) gas margin increased by   $4$5 million, or 7%15%, for the ninethree months ended September 30, 2007,March 31, 2008, compared with the same period in 2006 primarily2007 because of favorable weather conditions as evidenced by a 12%an 8% increase in heating degree-days in the first nine months of 2007 and growth in the industrial sector.increased growth.

IP

IP’s electric margin decreased by $66$2 million, or 41%, and $41 million, or 13%2%, for the three and nine months ended September 30, 2007, respectively,March 31, 2008, compared with the same periodsperiod in 2006.2007. The following items had an unfavorable impact on electric margin for the thirdfirst quarter and first nine months of 2007 as compared to the year-ago periods:period:

·  the combined effect of the elimination of bundled tariffs,The implementation of new seasonal delivery service tariffs including changesdecreased electric margin by $8 million.
·  The Illinois electric settlement agreement, which reduced electric margin by $2 million.

These unfavorable variances were partially offset by reduced MISO purchased power costs of $12 million due to the absence of the March 2007 FERC order.
IP’s gas margin increased by $3 million, or 5%, for the three months ended March 31, 2008, compared with the same period in 2007 primarily because of favorable weather conditions as evidenced by a 13% increase in heating degree-days.

Non-rate-regulated Generation

Non-rate-regulated Generation’s electric margin increased by $22 million, or 9%, for the three months ended March 31, 2008, compared with the same period in 2007.

Genco

Genco’s electric margin increased by $2 million, or 1%, for the three months ended March 31, 2008, compared with the same period in 2007. The following items had a favorable impact on electric margin for the first quarter of 2008 as compared to the year-ago period:
· 
Increased plant availability. Genco’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were 79% and 86%, respectively, in seasonal rates effective January 2, 2007,the first quarter of 2008 compared with 73% and 81%, respectively, in the expirationfirst quarter of 2007.
·  MISO purchased power supply contracts;costs decreased $3 million.
·  the Illinois settlement agreement reduced electric margin by $11Replacement power cost insurance recoveries of $6 million. Customer refund payments and credits, including the forgiveness of late payment charges, totaled $73 million for the three and nine months ended September 30, 2007, which were reduced by expected reimbursements of $49 million from non-affiliated generators and by $13 million from affiliated generators in Illinois; and
·  Net mark-to-market gains of $5 million on fuel-related transactions.

The following items had an unfavorable impact on electric margin for the first quarter of 2008 as compared to the year-ago period:
·  A 9% increase in fuel prices.
·  Reduced MISO-related revenues of $8 million due to the absence of the March 2007 FERC order, referenced above,order.
·  The Illinois electric settlement agreement, which reduced IP’s electric margin by $14$4 million.

CILCO (AERG)

For the three months ended March 31, 2008, AERG’s electric margin was comparable with the same period in 2007. The following items had an unfavorable impact on electric margin for the first quarter of 2008 as compared with the year-ago period:
·  
A 10% increase in coal prices together with greater oil consumption during plant startups.
·  Reduced MISO-related revenues of $4 million for the nine months ended September 30, 2007, compareddue to the same period a year ago.absence of the March 2007 FERC order.
·  The Illinois electric settlement agreement, which reduced electric margin by $2 million.

The following items had a favorable impact on electric margin for the thirdfirst quarter and first nine months of 20072008 as compared to the year-ago periods:period:

 
65

·  favorable weather conditions, which increased electric margin by an estimated $2 millionIncreased plant availability. AERG’s baseload coal-fired generating plants’ average capacity and $4 million forequivalent availability factors were 72% and 77%, respectively, in the threefirst quarter of 2008 compared with 62% and nine months ended September 30, 2007, respectively; and70%, respectively, in the first quarter of 2007.
·  severe storm-related outages in 2006, which reduced electric margin byEmission allowance expenses decreased $1 million for the three and nine months ended September 30, 2006.
IP’s gas margin was comparable for the three and nine months ended September 30, 2007, compared with the same periods in 2006, primarily because of reduced transportation service revenues, partially offset by favorable weather conditions as evidenced by a 13% increase in heating degree-days for the nine months ended September 30, 2007.

Non-rate-regulated Generation

Non-rate-regulated Generation’s electric margin increased by $46 million, or 21%, and $196 million, or 34%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.

Genco

Genco’s electric margin increased by $29 million, or 33%, and $110 million, or 42%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·  selling power at market-based prices for the three and nine months ended September 30, 2007, compared with selling power at below-market prices pursuant to a cost-based power supply agreement, which expired on December 31, 2006. This was offset, in part, by the loss of margin on sales supplied with power acquired through the JDA;million.
·  reduced purchased power costs due to the expirationNet mark-to-market gains of the JDA;$1 million on fuel-related transactions.
·  increased power plant availability due to fewer planned outages this year reduced purchased power costs;
·  a reduction of mark-to-market losses on fuel contracts in 2007, which amounted to $5 million for the nine months ended September 30, 2006; and
·  MISO costs were $12 million lower for the nine months ended September 30, 2007, compared with the same period in 2006, as a result of the March 2007 FERC order.
EEI

EEI’s electric margin increased by $11 million, or 16%, for the three months ended March 31, 2008, compared with the same period in 2007 primarily because of a 17% increase in the market price of power realized by EEI.
The following items had an unfavorable impact on electric margin for the thirdfirst quarter and first nine months of 20072008 as compared towith the year-ago periods:period:

·  costs of $20 million for the three and nine months ended September 30, 2007, pursuant to the Illinois electric settlement agreement discussed above; andAn 8% increase in fuel prices.
·  a 3% increaseDecreased plant availability. EEI’s baseload coal-fired generating plant’s average capacity and equivalent availability factors were both 90% in coal and related transportation prices for the three and nine months ended September 30, 2007, respectively.first quarter 2008 compared with 93% in the first quarter 2007.
 
CILCO (AERG)

For the three and nine months ended September 30, 2007, AERG’s electric margin increased by $22 million, or 82%, and $64 million, or 72%, respectively, compared with the same periods in 2006. The following items had a favorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·  increased revenues due to selling power at market-based prices in the third quarter of 2007 compared with sales at below-market prices in 2006 pursuant to a cost-based power supply agreement, which expired on December 31, 2006; and
·  reduced emission costs of $3 million and $8 million for the three and nine months ended September 30, 2007, respectively, compared with the same prior-year periods.

The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared with the year-ago periods:

·  costs of $9 million for the three and nine months ended September 30, 2007, pursuant to the Illinois electric settlement agreement discussed above;
·  revenues and fuel costs decreased due to reduced plant availability because of an extended plant outage; and
·  a 12% increase in coal and related transportation prices for the nine months ended September 30, 2007.
EEI

EEI’s electric margin decreased by $36 million, or 35%, and $28 million, or 12%, for the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The following items had an unfavorable impact on electric margin for the third quarter and first nine months of 2007 as compared to the year-ago periods:

·  the lack of emissions allowance sales in 2007, which increased the electric margin by $30 million for the three and nine months ended September 30, 2006;
·  a 5% increase in coal and related transportation prices for the three and nine months ended September 30, 2007; and
·  revenues and fuel costs decreased due to reduced plant availability due to increased unit outages in the three and nine months ended September 30, 2007.


6663
Marketing Company
An increase in nonaffiliated net mark-to-market energy-related gains of $8 million at Marketing Company for the three months ended March 31, 2008, compared with the first quarter of 2007 also contributed to Non-rate-regulated Generation’s higher electric margin.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren

Ameren
Three months – Other operations and maintenance expenses increased $32$34 million in the thirdfirst quarter of 20072008 compared with the thirdfirst quarter of 20062007, primarily because of higher distribution system reliability expenditures of $12 million, increased plant maintenance expenditures of $12$5 million, due to outages at coal-fired plants, increased distribution system reliability and maintenance expenditures, higher labor and employee benefits costs of $5 million, and increased injuries and damages expenses.bad debt expense. Additionally, as part of the Illinois electric settlement agreement, we paid $4 million to the IPA in the third quarter of 2007. The amount of the increase in expenses in the thirdfirst quarter of 2007, over 2006 was lower than it otherwise would have been because in the third quarter of 2006, we experienced severe storms in our service territory resulting in expenses of $23a $15 million while there were no major storms in our service territory during the third quarter ended September 30, 2007. Additionally, in the third quarter of 2006, Ameren recorded $7 million of costs related to the December 2005 reservoir breach at UE’s Taum Sauk plant with no similar costs recorded in the third quarter of 2007.

Nine months - Other operations and maintenance expenses increased $108 million in the first nine months of 2007 compared with the first nine months of 2006.  Maintenance and labor costs associated with the Callaway refueling and maintenance outage in the second quarter of 2007 added $35 million to other operations and maintenance expenses in the period. Higher non-Callaway labor costs, bad debt reserves, maintenance at coal-fired plants, the IPA payment described above, and distribution system reliability expenditures also increased other operations and maintenance expenses in the first nine months of 2007 compared to the year-ago period. Reducing the effect of these items was the reversal of an accrual of  $15 million established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan. Additionally,plan was reversed due to the termination of the plan, with no similar item in the prior-yearfirst quarter of 2008. This plan was replaced with the Illinois electric settlement agreement in August 2007.

The decreased impact of ice storms in the first quarter of 2008, as compared with the same period in 2007, reduced the effect of these unfavorable items. In January 2007, we recognized costs related to the Taum Sauk reservoir breach of $17 million and noncore property sale losses of $7 million at a subsidiary of AERG, items which did not recur in 2007. Increased other operations and maintenance expenses resulting fromexperienced a severe ice storm in January 2007 in UE’s and CIPS’ service territories were offset by the absenceresulting in 2007system repair expenditures of severe summer$28 million, as compared with $10 million in expenditures for minor storms such as those that occurred in the summerfirst quarter of the prior year.2008, primarily in CIPS’ service territory.

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 and nine months ended September 30, 2007,March 31, 2008, compared with the same periodsperiod in 20062007 were as follows:

Missouri Regulated

UE

Three months – Other operations and maintenance expenses were comparable in the third quarter of 2007 with the third quarter of 2006. Increased plant maintenance at coal-fired plants from scheduled outages, increased distribution system reliability and maintenance expenditures, and insurance premiums paid to an affiliate for replacement power coverage in the current year third quarter were offset by the absence of costs related to the Taum Sauk reservoir breach. In addition, there were no severe summer storms in 2007, which resulted in expenses of $16 million in the third quarter of 2006.

Nine months - Other operations and maintenance expenses increased $86 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of ice storm repair expenditures of approximately $25 million and costs associated with the Callaway refueling and maintenance outage of $35 million. Increased plant maintenance at coal-fired plants, increased distribution system reliability and maintenance expenditures, higher labor costs, and insurance premiums for replacement power coverage of $14 million paid to an affiliate also increasedUE’s other operations and maintenance expenses decreased $7 million in the first nine monthsquarter of 20072008 compared with the prior year period.first quarter of 2007, primarily because of the decreased impact of ice storms in the first quarter of 2008 as compared with the same period in 2007. Storm repair expenditures in the first quarter of 2008 were $4 million as compared with repair expenditures of $25 million in the first quarter of 2007. Reducing the effectbenefit of these items was the absencedecreased storm expenditures were increased distribution system reliability expenditures of  $6 million and higher labor and employee benefit costs in the current year periodfirst quarter of costs related to the Taum Sauk reservoir breach and the absence of severe summer storms in 2007 such as those that occurred in the prior year period.2008.

Illinois Regulated

Other operations and maintenance expenses increased $9 million and $17$22 million in the Illinois Regulated segment in the three and nine months ended September 30, 2007, respectively,March 31, 2008, compared with the same periodsperiod in 2006.2007.

CIPS

Three months – Other operations and maintenance expenses were comparable between periods as the absence of severe summer storms in 2007, such as those that occurred in the summer of the prior year, was offset by increased distribution system reliability and maintenance expenditures and by higher injuries and damages expenses.

Nine months - Other operations and maintenance expenses increased $7 million in the first nine monthsquarter of 20072008 compared with the first nine months of 2006same period in 2007. The increase was primarily because of increased bad debt reserves as a result of the transition to higher electric rates in Illinois, and increased distribution system reliability expenditures. The reversal in the first quarter of 2007 of the customer assistance programan accrual of $4 million
67
established in 2006 as noted above, reducedfor contributions to assist customers through the effect of these increases. The impact of a severe ice storm in January 2007 was offset by the absence in 2007 of severe summer storms such as those that occurredIllinois Customer Elect electric rate increase phase-in plan, with no similar item in the summerfirst quarter of 2008. Storm repair expenditures in the prior year.first quarter of 2008 exceeded the cost of storm repairs in the prior-year quarter by $2 million.

CILCO (Illinois Regulated)

ThreeOther operations and maintenance expenses increased $3 million in the first quarter of 2008 compared with the same period in 2007. 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 the first quarter of 2008.  Additionally, bad debt expense increased in the first quarter of 2008 compared with the same period in the prior year.

IP

Other operations and maintenance expenses increased $12 million in the first quarter of 2008 compared with the same period in 2007. The increase was primarily because of the reversal in the first quarter of 2007 of an accrual of $8 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 the first quarter of 2008. Additionally, distribution system reliability expenditures increased $5 million and bad debt expense increased $2 million over the prior-year quarter.

Non-rate-regulated Generation

Other operations and maintenance expenses increased $10 million in the Non-rate-regulated Generation segment in the three months – ended March 31, 2008, compared with the same period in 2007.
64

Genco and CILCO (AERG)

Other operations and maintenance expenses increased $6 million at Genco and $4 million at CILCO (AERG) in the first quarter of 2008 as compared with the first quarter of 2007, primarily because of higher plant maintenance costs due to scheduled outages.

CILCORP (Parent Company Only) and EEI

Other operations and maintenance expenses were comparable between periods.

Nine months – Other operationsDepreciation and maintenance expenses were comparable between periods as an increase in bad debt reserves was offset by the reversal of the customer assistance program accrual of $3 million established in 2006 as noted above.Amortization

IPAmeren

Three months – Other operations and maintenance expenses increased $6 million in the third quarter of 2007 compared with the third quarter of 2006 primarily because of higher employee benefit costs and increased injuries and damages expenses. Reducing the unfavorable impact of these items was the absence of severe summer storms in 2007 such as those that occurred in the summer of 2006.

Nine months - Other operations and maintenance expenses increased $9 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of higher employee benefit costs and increased bad debt reserves. Reducing the effect of these items was the reversal of the customer assistance program accrual of $8 million, established in 2006 as noted above, and the absence of severe summer storms in 2007 such as those that occurred in the summer of the prior year.

Non-rate-regulated Generation

Other operations and maintenance expenses increased $14 million and $23 million in the Non-rate-regulated Generation segment in the three and nine months ended
September 30, 2007, respectively, compared with the same periods in 2006.
Genco

Three months – Other operations and maintenance expenses increased $5 million in the third quarter of 2007 compared with the third quarter of 2006 primarily because of higher plant maintenance costs due to scheduled outages. Additionally, as part of the Illinois electric settlement agreement, Genco paid $3 million to the IPA in the third quarter of 2007.

Nine months - Other operations and maintenance expenses increased $9 million in the first nine months of 2007 compared with the first nine months of 2006 primarily because of higher labor costs, the IPA payment, and insurance premiums for replacement power coverage paid to an affiliate.

CILCORP (Parent Company Only)

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

Nine months - Other operations and maintenance expenses were comparable between periods as increased employee benefit costs in the current year period were offset by the absence of a write-off in 2007, as occurred in the prior year period, of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP.

CILCO (AERG)

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 2007 compared with the first nine months of 2006 primarily because of higher plant maintenance costs due to an extended plant outage.

EEI

Three and nine months - Other operations and maintenance expenses increased $2 million and $5 million in the three and nine months ended September 30, 2007, respectively, compared to the prior year periods primarily because of higher plant maintenance costs.

Depreciation and Amortization

Ameren

Three and nine months – Ameren’s depreciation and amortization expenses increaseddecreased $7 million and $29 million in the three and nine months ended September 30, 2007, respectively,March 31, 2008, compared with the same periodsperiod in 2006. The increases were2007, primarily because of changes in the useful lives of UE’s plants as discussed below. Increased capital additions in 2006 andover the startpast year reduced the benefit of amortization of a regulatory asset in 2007 associated with acquisition integration costs at IP, as required by an ICC order.this item.

Variations in depreciation and amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007,March 31, 2008, compared with the same periodsperiod in 20062007 were as follows:

68
Missouri Regulated

UE

Three months - Depreciation and amortization expenses were comparabledecreased $6 million between periods as increased depreciation expenses from capital additions were offset by decreased expenses resulting fromprimarily because of the extension of UE’s nuclear and coal-fired plants’ useful lives for purposes of calculating depreciation expense in connection with a MoPSC electric rate order issued in Mayeffective June 2007. See Note 2 – Rate and Regulatory Matters under Part I, Item 1,Reducing the benefit of this report for additional information on UE’s electric rate order.item was an increase in capital additions over the past year.

Nine months – Depreciation and amortization expenses increased $9 million in the nine months ended September 30, 2007, primarily because of capital additions in 2006 and early 2007, including CTs purchased in the second quarter of 2006, and storm-related expenditures in 2006.

Illinois Regulated

Depreciation and amortization expenses increased $5 million and $18 million in the Illinois Regulated segment in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.
 
CIPS & CILCO (Illinois Regulated)

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

IP

Three and nine months – Depreciation and amortization expenses increased $4 million and $15 million in the three and nine months ended September 30, 2007, respectively, primarily because of amortization in 2007 of $4 million and $12 million for the three and nine months ended September 30, 2007, respectively, of a regulatory asset associated with acquisition integration costs, as required by an ICC order.

Non-rate-regulated Generation

Three and nine months - Depreciation and amortization expenses were comparable in the three months ended March 31, 2008, with the same period in 2007 in the Illinois Regulated segment and for CIPS, CILCO (Illinois Regulated) and IP.

Non-rate-regulated Generation

Depreciation and amortization expenses were comparable in the first quarter of 2008 with the same period in 2007 in the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEIEEI. Depreciation and amortization expenses decreased $2 million at Genco in the three and nine months ended September 30, 2007,first quarter of 2008 compared with the same period in 2007 as a result of modified depreciation rates pursuant to a depreciation study performed in September 2007. Depreciation and amortization expenses increased $2 million at CILCO (AERG) between periods in 2006.primarily because of capital additions over the past year.

Taxes Other Than Income Taxes

Ameren

Ameren

Three months – Ameren’s taxes other than income taxes were comparable between periods.
Nine months - Ameren’s taxes other than income taxes decreased $7increased $11 million in the first nine monthsquarter of 20072008 compared with the first nine monthsquarter of 20062007, primarily because of lowerhigher gross receipts and lower property tax expenses.taxes.

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 and nine months ended September 30, 2007,March 31, 2008, compared with the same periodsperiod in 20062007 were as follows:

Missouri Regulated
 
UE

Three and nine months – Taxes other than income taxes increased $4 million and $3 million in the third quarter and first nine months of 2007 compared with the same periods in the prior year primarily because of increased gross receipts taxes.
Illinois Regulated

Taxes other than income taxes increased $3 million at UE in the first quarter of 2008 compared with the first quarter of 2007, primarily because of higher gross receipts taxes.

Illinois Regulated

Taxes other than income taxes increased $7 million in the Illinois Regulated segment decreased $6 million and $10 million for the three and nine months ended September 30, 2007, respectively,March 31, 2008, compared with the same periodsperiod in 2006.

CIPS

Three and nine months – Taxes2007. Higher excise taxes in the first quarter of 2008 resulted in increased taxes other than income taxes decreased $3at CIPS, CILCO (Illinois Regulated) and IP. Additionally, higher property taxes of $2 million and $6 million forcontributed to the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006, primarily because of lower property tax expenses. The nine-month period was also impacted by lower gross receipts taxes in 2007.increase at CIPS.

CILCO (Illinois Regulated) & IPNon-rate-regulated Generation

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

Non-rate-regulated Generation

Three and ninein the three months - Taxes other than income taxes were comparableended March 31, 2008, with the same period in 2007 in the Non-rate-regulated Generation segment and for Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEI in the three and nine months ended September 30, 2007, with the same periods in 2006.EEI.

Other Income and Expenses

Ameren

Ameren

Three and nine months – Miscellaneous income increased $8 million and $25$5 million in the three and nine months ended September 30, 2007, respectively,March 31, 2008, compared with the same periodsperiod in 2006,2007, primarily because of increasedan increase in allowance
6965
interest income. Miscellaneous income in each period includes interest income on industrial development revenue bonds acquired by UE in conjunction with its purchase of CTs. These amounts are offset by an equivalent amount of interest expense associated with capital leases for the CTs recorded in interest charges on Ameren’s and UE’s statements of income.funds used during construction at UE. Miscellaneous expense increased $3 million and $6 million in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006, primarily as a result of contributions made to our charitable trust.was comparable between periods.

Variations in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007, compared with the same periods in 2006 were as follows:

Missouri Regulated
UE
Three and nine months – Miscellaneous income was comparable between the third quarter of 2007 and the third quarter of 2006. Miscellaneous income increased $6 million for the nine months ended September 30, 2007,March 31, 2008, compared with the same period in 2006, primarily2007 were as a result of increased interest income. As discussed above, miscellaneous income includes interest income related to industrial development revenue bonds that is offset in interest charges on UE’s statement of income. These interest amounts were $7 million for the third quarter in both 2007 and 2006 and $22 million and $16 million for the nine months ended September 30, 2007 and 2006, respectively. Miscellaneous expense was comparable for the three and nine months ended September 30, 2007, with the same periods in 2006.follows:

Missouri Regulated
 
Illinois RegulatedUE

Miscellaneous income increased $3 million and $7$4 million in the Illinois Regulated segmentfirst quarter of 2008 over the first quarter of 2007 primarily because of an increase in the threeallowance for funds used during construction. The increase resulted from higher rates and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.increased construction-in-progress balances. Miscellaneous expense was comparable for the three- and nine-month periods in 2007 compared with the same periods in 2006.
CILCO (Illinois Regulated) & IP
Three months – Miscellaneous income was comparable at CILCO (Illinois Regulated) in the third quarter of 2007 with the same period in the prior year. Miscellaneous income increased $2 million at IP in the three months ended September 30, 2007, compared with the same period in 2006 primarily because of increased interest income. Miscellaneous expense was comparable in the third quarter of 2007 with the same period in 2006.
Nine months - Miscellaneous income increased $2 million and $5 million at CILCO (Illinois Regulated) and IP in the nine months ended September 30, 2007, respectively, compared with the same period in 2006 primarily because of increased interest income. Miscellaneous expense was comparable at CILCO (Illinois Regulated) and IP between periods.

CIPS
Three and nine months - Other income and expenses were comparable between periods.
 
Non-rate-regulated GenerationIllinois Regulated
 
Other income and expenses were comparable in the three months ended March 31, 2008, with the same period in 2007, in the Illinois Regulated segment and for CIPS, CILCO (Illinois Regulated), and IP.

Non-rate-regulated Generation

Other income and expenses were comparable in the three months ended March 31, 2008, with the same period in 2007, in the Non-rate-regulated Generation segment and atfor Genco, CILCORP (Parent Company Only), CILCO (AERG) and EEIEEI.

Interest

Ameren

Interest expense was comparable in the three and nine months ended September 30, 2007,March 31, 2008, with the same periodsperiod in 2006.

Interest

Ameren

Three and nine months - Interest expense increased $21 million and $62 million2007. Increased short-term borrowings in the threefirst quarter of 2008 and nine months ended September 30, 2007, respectively,prior-year debt issuances noted below resulted in higher interest expense in the current-year period. Additionally, higher interest rates on auction-rate environmental improvement and pollution control revenue bonds resulted in increased interest expense in the first quarter of 2008 as compared with the same periods in 2006, primarily becauseperiod last year. See Insured Auction-Rate Tax-exempt Bonds under Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk of increased short-term borrowings and higher interest rates due to reduced credit ratings and other items noted below. Interest expense recognized on UE’s capital leases associated withthis report. These increases were mitigated by the purchasereversal of CTs is offset by an equivalent amount$11 million of interest income recorded in other income and expenses on Ameren’s and UE’s statement of income. With the adoption of FIN 48, we also began to record interest associated withreserves for uncertain tax positions as interest expense rather than incomeresulting from a federal tax expense. These interest charges were $2 million and $9 million forsettlement in the three and nine months ended September 30, 2007, respectively.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 and nine months ended September 30, 2007,March 31, 2008, compared with the same periodsperiod in 2006,2007 were as follows:

Missouri Regulated

UE

Three and nine months – Interest expense increaseddecreased $7 million and $23primarily because of the reversal of $8 million forof interest reserves resulting from the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006. The increase in the third quarterfederal tax settlement noted above. Partially offsetting this decrease was due primarily to increased interest expense related toon increased net borrowings resulting from the issuance
70
of $425 million senior secured notes in June 2007. 2007, the proceeds of which were used to reduce short-term borrowings between periods. Additionally, higher interest rates on auction-rate environmental improvement and pollution control revenue bonds resulted in increased interest expense.
Illinois Regulated
Interest expense increased $6 million in the nine-month periodIllinois Regulated segment and $8 million at IP primarily because of increased short-term borrowings andin the first quarter of 2008 compared with the year-ago period, higher interest rates due to reduced credit ratingson auction-rate environmental improvement and becausepollution control revenue bonds, and the issuance of increased interest expense related to the June 2007 debt issuance. As discussed above, interest charges include interest expense related to capital leases that is offset$250 million of senior secured notes at IP in other income and expenses on UE’s statement of income.November 2007. Interest expense recorded in conjunction with the adoption of FIN 48at CIPS and CILCO (Illinois Regulated) was $3 million for the nine months ended September 30, 2007.
comparable between periods.

Illinois RegulatedNon-rate-regulated Generation

Interest expense increased $11 million and $27decreased $4 million in the Illinois RegulatedNon-rate-regulated Generation segment and $5 million at Genco primarily because of the federal tax settlement noted above and reduced intercompany borrowings in the three and nine months ended September 30, 2007, respectively, compared with the same periods in 2006.
CIPS
Three months –first quarter of 2008. Interest expense was comparable between periods.
Nine months – Interest expense increased $5 million forin the ninethree months ended September 30,March 31, 2008, with the same period in 2007 at CILCORP (Parent Company Only), CILCO (AERG) and EEI.

Income Taxes

 Ameren

Ameren’s effective tax rate increased in the first quarter of 2008 as compared with the same period in 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings.
CILCO (Illinois Regulated)
Three and nine months – Interest expense was comparable between periods.
IP

Three months – Interest expense increased $6 million for the third quarter of 2007, compared with the same period in 2006, primarily because of increased short-term borrowings and higher interest rates resulting from reduced credit ratings.

Nine months – Interest expense increased $18 million for the nine months ended September 30, 2007, compared with the same period in 2006, primarily because of the issuance of  $75 million senior secured notes in June 2006 and because of increased short-term borrowings and higher interest rates due to reduced credit ratings.
Non-rate-regulated Generation

Interest expense was comparable in the Non-rate-regulated Generation segment in the third quarter of 2007 with the same period in 2006. Interest expense increased $4 million in the nine months ended September 30, 2007, compared with the same period in 2006.
CILCORP (Parent Company Only) & CILCO (AERG)
Three months – Interest expense was comparable between periods.
Nine months - Interest expense increased $2 million and $4 million at CILCORP (Parent Company Only) and CILCO (AERG) for the nine months ended September 30, 2007, respectively, compared with the same period in 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings.

Genco & EEI

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

Income Taxes

Ameren

Three and nine months - Ameren’s effective tax rate decreased between 2007 and 2006.2007.

Variations in effective tax rates infor Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies for the three and nine months ended September 30, 2007,March 31, 2008, compared with the same periodsperiod in 20062007 were as follows:

66
Missouri Regulated
 
UE

Three months – The effective tax rate decreasedincreased in the first quarter of 2008 as compared with the same period in 2007, from 2006 primarily because of an increase inlower reserves for uncertain tax positions in 2006 for tax returns filed in previous years, along with an increase in expenses deductible for tax purposes, which were not expensed for book purposes in 2007. These decreases were offset by lower favorable tax return-to-accrual adjustments in 2007 compared towith 2008, as well as decreased production activity deductions in the samefirst quarter of 2008 compared with the year-ago period in 2006.

Nine months – The effective tax rate decreased in 2007 from 2006, primarily because of theon higher pretax book income. Offsetting these unfavorable items detailed above, along withwas the implementation of changes ordered by the MoPSC in UE’s 2007 electric rate order. order, which reduced the unfavorable effect of the net amortization of property-related regulatory assets and liabilities in the first three months of 2008 compared to the first three months of 2007.

Illinois Regulated

The effective tax rate was comparable between the first quarter of 2008 and the first quarter of 2007 in the Illinois Regulated segment.  The effective tax rate variations for the nine-month periodIllinois Regulated entities are detailed below.
CIPS

The effective tax rate decreased, primarily because of the increased impact of the amortization of investment tax credit on lower pretax book income and lower reserves for uncertain tax positions in 2006 was increased by the effectfirst quarter of higher non-deductible expenses than2008 compared with the same period in 2007, offset by a lower permanent benefit for SFAS No. 106-2, as it relates to Medicare Part D provisions.

CILCO (Illinois Regulated)

The effective tax rate increased, primarily because of a decrease in the permanent benefit related to company-owned life insurance, a decrease in the favorable effect of net amortization of property-related regulatory assets and liabilities, and a decrease in the estimated benefit from state tax credits in the first three months of 2008 compared to the first three months of 2007.

IP
The effective tax rate was comparable between periods.

Non-rate-regulated Generation

The effective tax rate increased in the first quarter of 2008 in the Non-rate-regulated Generation segment compared with the first quarter of 2007, because of items detailed below.

Genco

The effective tax rate was comparable between periods.
CILCO (AERG)

The effective tax rate increased, primarily because of federal return audit adjustments recorded in the first quarter of 2008.

Illinois RegulatedCILCORP (Parent Company only)

The effective tax rate increased in the Illinois Regulated segment in the three months ended September 30, 2007, and decreased in the nine months ended September 30, 2007,
71
first quarter of 2008 compared with the same periodsyear-ago period primarily because of a change in 2006, duethe permanent benefit for SFAS No. 106-2, as it relates to items detailed below.
CIPSMedicare Part D provisions.

Three and nine months – The effective tax rate increased primarily because of unfavorable tax return-to-accrual adjustments in 2007 compared to favorable tax return-to-accrual adjustments in 2006.

CILCO (Illinois Regulated)

Three months – The effective tax rate increased primarily because of an increase in expenses deductible for tax purposes that were not expensed for book purposes on a pre-tax loss in 2007, along with a decrease in reserves for uncertain tax positions in 2006 for returns filed in previous years as compared to no change in reserves in 2007.

Nine months – The effective tax rate decreased primarily because of an increase in expenses deductible for tax, which were not expensed for book purposes, along with favorable tax return-to-accrual adjustments in 2007 compared with unfavorable tax return-to-accrual adjustments in 2006.

IP

Three months – The effective tax rate increased primarily because of favorable tax return-to-accrual adjustments on a pre-tax book loss in 2007 compared with unfavorable tax
return-to-accrual adjustments in 2006.

Nine months – The effective tax rate decreased primarily because of favorable tax return-to-accrual adjustments in 2007 compared with unfavorable tax return-to-accrual adjustments in 2006.

Non-rate-regulated GenerationEEI

The effective tax rate increased in the Non-rate-regulated Generation segment in the three and nine months ended September 30, 2007,first quarter of 2008 compared with the same periods in 2006, due to items detailed below.

Genco

Three and nine months – The effective tax rate increasedyear-ago period primarily because of lower reserves for uncertain tax positions in 2006 for tax returns filed in previous years as compared to 2007, a decrease in 2007 of expenses deductible for tax purposes but not expensed fordecreased production activity deductions on higher pretax book purposes when compared to 2006, and unfavorable tax return-to-accrual adjustments in 2007 compared with favorable tax return-to-accrual adjustments in 2006.income.
 
CILCO (AERG)

Three and nine months – The effective tax rate increased primarily because of lower reserves for uncertain tax positions in 2006 for tax returns filed in prior years, a decrease in expenses in 2007 that were deductible for tax purposes but not expensed for book purposes, and unfavorable tax return-to-accrual adjustments in 2007 compared to favorable tax return-to-accrual adjustments in 2006.

CILCORP (Parent Company Only)

Three and nine months – The effective tax rate decreased primarily because of lower favorable tax return-to-accrual adjustments in 2007 as compared to 2006.

EEI

Three and nine months – The effective tax rate decreased primarily because of an increase in expenses deductible for tax purposes, which were not expensed for book purposes.

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 principally rely on power sales to Marketing Company, which sold power through the September 2006 Illinois power procurement auction, in September 2006, and financial contracts that were part of 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 or credit facilities to support normal operations and other temporary capital requirements. The use of operating cash flows and short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit, as was the case at September 30, 2007,March 31, 2008, for Ameren, UE, Genco, CILCORP, CILCO, and IP. The Ameren Companies willmay reduce their short-term borrowings with cash from operations or discretionarily with long-term borrowings, andor in the case of Ameren subsidiaries, with equity infusions from Ameren. The Ameren Companies will 
 
7267
 
Ameren. The Ameren Companies will incur significant capital expenditures over the next five years for complianceas they comply with environmental regulations or toand 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. 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, thatwhich among other things, will change the process for power procurement in Illinois in the future and will impactaffect future cash flows of the Ameren Companies, except UE. The settlement resulted in customer refunds and credits during the thirdfirst quarter of 2007,2008, and it will result in further monthly credits to customers through 2010. The Ameren Illinois Utilities will receive reimbursement for a majoritymost of these refunds and credits from Illinois power generators, including Genco and CILCO (AERG).AERG.

The following table presents net cash provided by (used in) operating, investing and financing activities for the ninethree months ended September 30, 2007March 31, 2008 and 2006:2007:

 
Net Cash Provided By
Operating Activities
  
Net Cash Used In
Investing Activities
  
Net Cash Provided By
(Used In) Financing Activities
  
Net Cash Provided By
(Used In) Operating Activities
  
Net Cash Used In
Investing Activities
  
Net Cash Provided By
(Used In) Financing Activities
 
 
2007
  
2006
  
Variance
  
2007
  
2006
  
Variance
  
2007
  
2006
  
Variance
  2008  2007  Variance  2008  2007  Variance  2008  2007  Variance 
Ameren(a)
 $
920
  $1,069  $(149) $(1,093) $(1,044) $(49) $
206
  $(87) $293  $326  $358  $(32) $(527) $(386) $(141) $32  $52  $(20)
UE   
519
  620  (101)  (535) (611) 76   
15
  (27) 42  (31) (50) 19  (324) (221) (103) 170  270  (100)
CIPS   
11
  127  (116)  (115) (47) (68)  
99
  (80) 179  55  10  45  (22) (34) 12  (41) 64  (105)
Genco   
153
  49  104   (137) (83) (54)  (15) 36  (51) 79  69  10  (60) (37) (23) (19) (32) 13 
CILCORP   
20
  104  (84)  (141) (33) (108)  
201
  (71) 272  103  42  61  (78) (1) (77) 11  (18) 29 
CILCO   
48
  127  (79)  (141) (75) (66)  
162
  (52) 214  104  58  46  (78) (1) (77) 10  (35) 45 
IP   
23
  108  (85)  (133) (129) (4)  
110
  21  89  89  58  31  (34) (62) 28  (60) 47  (107)

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

Cash Flows from Operating Activities

Ameren’s cash from operating activities decreased in the first ninethree months of 2007,2008, as compared with the first ninethree months of 2006. The2007 because of several factors. Payments, net of insurance recoveries, related to the December 2005 Taum Sauk incident were $109 million in the first quarter of 2008 compared to $4 million in the first quarter of 2007. In addition, the first quarter of 2008 was colder than the year-ago period, which resulted in increased gas purchases and larger customer receivable balances at March 31, 2008. Other factors that reduced cash flows from operations included higher past-due accounts receivable, increased under-recovery of the PGA, increased collateral postings, and increased payments for income taxes and other taxes. Benefiting cash flows from operations compared to the prior-year period was a larger reduction of natural gas inventories as a result of higher natural gas sales. Cash flow from operations was also positively affected in the first quarter of 2008 by the Illinois electric settlement agreement, resulted in $45 million of customer refunds and program funding. Under the terms of the settlement agreement, the Ameren Illinois Utilities will receiveas reimbursements from Illinois electricity generators in future months for a majority of these expenditures. See Note 2 – Rate and Regulatory Matters under Part I, Item 1, of this report for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from Illinois electricexceeded credits provided to customers lagged payments for power purchases. A decrease in income taxes paid (net of refunds) of $59 million benefited cash flows from operations in the first nine months of 2007. Increases in electric and gas margins also benefited operating cash flows, but were reduced by higher operations and maintenance expenses as discussed in Results of Operations, primarily as a result of the Callaway nuclear plant refueling and maintenance outage and storm-related outage repairs.$21 million.

At UE, negative cash from operating activities decreased in the first ninethree months of 2007,2008, compared with the first ninethree months of 2006. Increased storm repair costs and increased other operations and maintenance expenses as a result of the Callaway nuclear plant refueling and maintenance outage were only partially offset by increased2007. Positive effects on operating cash flows included an increase in electric and gas margins, as discussed in Results of Operations. In addition, there was an increase in accounts receivable, primarily because of higher prices for interchange power sales and warmer summer weather. Compared to the prior-year period, decreases in cash paid for Taum Sauk-related costs (net of insurance recoveries) of $24 million,Operations, and a decrease in other operations and maintenance expenses, including reduced storm repair expenditures, compared to the year-ago period. Partially offsetting this benefit were payments, net of insurance recoveries, related to the December 2005 Taum Sauk incident of $109 million in the first quarter of 2008 compared to $4 million in the first quarter of 2007. In addition, there were higher past-due accounts receivable and increased income tax payments (net of refunds) of $97 million benefited cash flows from operations.in the current-year period.

At CIPS, cash from operating activities decreasedincreased in the first ninethree months of 2007,2008, compared with the first ninethree months of 2006. Operating cash flows were lower,2007, primarily because of $15a net $10 million increase in income tax refunds, a larger reduction of customer refundsnatural gas inventories as a result of higher natural gas sales and program funding related tochanges in working capital that occurred in the ordinary course of business. In addition, the Illinois electric settlement agreement had a positive effect on cash from operations in the first quarter of 2008 as generator reimbursements exceeded credits provided to customers. Included in the working capital changes was an increase in receivables due to past-due accounts, which reduced cash from operations.  Additionally, the Illinois rate redesign reduced cash flows and increased other operationsnet income in the first three months of 2008; however, the cash flows and maintenance expenses. Under the terms of the settlement agreement, CIPSnet income will receive reimbursements from Illinois electricity generatorsbe recouped in future months for a portion of these expenditures. See Note 2 – Rate and Regulatory Matters for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, and past due customer accounts increased due to higher rates and uncertainty about future rate relief programs. Income tax payments (net of refunds) decreased $26 million, benefiting cash flows from operations.quarters in 2008.

Genco’s cash from operating activities increased in the first ninethree months of 20072008 compared to the 20062007 period, primarily because of an increase in electric margins, as discussed in Results of Operations, and a reduction in cash spent for fuel inventory due to large cash outlays made in 2006 to replenish coal inventory after disruptions in rail deliveries caused by train derailments. Reducing these increases in cash from operating activities was an increasenet decrease in income tax payments (net of refunds) of $23$12 million.

Cash from operating activities decreasedincreased for CILCORP and CILCO in the ninethree months ended September 30, 2007,March 31, 2008, compared with the same period in 2007. An increase in electric margins benefited cash from operations compared to the year-ago period. In addition, the Illinois electric settlement agreement had a positive effect on cash from operations in the first quarter of 2008 as generator reimbursements exceeded credits provided to customers. Other increases in cash flow from operations were primarily due to fluctuations in
 
7368
compared withworking capital in the same periodnormal course of 2006. The positive cash effect of increased electric margins discussedbusiness, including a larger reduction in Results of Operations was more than offset by $9 million of customer refunds and program funding related to the Illinois electric settlement agreement. Under the terms of the settlement agreement, CILCO will receive reimbursements from Illinois electricity generators in future months fornatural gas inventories as a portion of these expenditures. See Note 2 – Rate and Regulatory Matters for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collectionresult of higher electric rates from customers lagged payments for power purchases, and past due customer accountsnatural gas sales. Accounts receivable increased due to higher ratespast-due accounts, which reduced cash from operations. Addtionally, the Illinois rate redesign reduced cash flows and uncertainty aboutnet income in the first three months of 2008; however, the cash flows and net income will be recouped in future rate relief programs. In addition, Income tax payments (net of refunds) increased $21 million and $18 million for CILCORP and CILCO, respectively.quarters in 2008.

IP’s cash from operating activities decreasedincreased in the ninethree months ended September 30, 2007,March 31, 2008, compared with the same period in 2006. The2007, primarily due to working capital changes in the ordinary course of business, including a larger reduction in gas inventories as a result of higher natural gas sales. In addition, the Illinois electric settlement agreement resultedhad a positive effect on cash from operations in $21 millionthe first quarter of customer refunds and program funding. Under2008 as generator reimbursements exceeded credits provided to customers. The following factors partially offset the terms ofaforementioned increases in cash from operations:  accounts receivable increased compared to the settlement agreement, IP will receive reimbursements from Illinois electricity generators in future months for a portion of these expenditures. See Note 2 – Rate and Regulatory Matters for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, and past due customer accountsyear-ago period, as natural gas sales increased due to higher rates and uncertainty about future rate relief programs. Storm repair costs increased $11 millioncolder weather in the current year period compared to the prior year,prior-year period and income tax payments (net of refunds) increased by $32 million, further reducingthere was an increase in past-due accounts. Additionally, the Illinois rate redesign reduced cash flows from operations.and net income in the first three months of 2008; however, the cash flows and net income will be recouped in future quarters in 2008.

Cash Flows from Investing Activities

Ameren had an increase inused more cash used infor investing activities in the first ninethree months of 2007 compared to2008 than in the first ninethree months of 2006.2007. Net cash used for capital expenditures increased in 20072008 as a result of increased storm repair costs, power plant scrubber projects and upgrades at various power plants. These expenditures were offset by the lack of CT acquisitionsAdditionally, increased purchases and higher prices resulted in 2007 as occurred in 2006. The absence in 2007 of $11a $79 million of proceeds from sales of non-core properties received in 2006 also contributed to the increase in cash used in investing activities. A decrease in purchases of emission allowances was partially offset by fewer sales of emission allowances resulting in a $19 million net benefit to investing cash flows.nuclear fuel expenditures.

UE’s cash used in investing activities decreased inincreased during the first nine monthsquarter of 2007,2008, compared to the same period in 2006,2007, principally because of the $292 million expended for CT purchases in 2006, partially offset by a $152$79 million increase in capitalnuclear fuel expenditures resulting from increased purchases for future refueling outages and higher prices. In 2008, UE contributed net money pool advances of $21 million compared with $4 million net receipts in 2007. Capital expenditures decreased $3 million. This decrease was a result of lower storm costs in the first nine monthsquarter of 2007 as2008 compared with the first nine monthsquarter of 2006. The2007 and was partially offset by increased capital expenditures in 2007 werespending related to storm repair costs, a power plant scrubber project, and other power plant upgrades. In the 2006 period, UE received proceeds of $67 million from an intercompany note related to the transfer of UE’s Illinois territory to CIPS, which had reducedproject.

CIPS’ cash used in investing activities indecreased during the same period in 2006.

CIPS had an increase in its net usefirst quarter of cash from investing activities during 20072008 as compared to the same period in 2006.2007. The net $68$12 million increasedecrease was primarily due to an increasechanges in money pool advances. In the 2007 year-ago period, CIPS made net advances of $94$14 million compared to $18 millionwhile there were no net advances in the 2006 period. Reducing this increase in net use of cash from investing activities, capital expenditures decreased by $5 million compared to the prior year.2008.

Genco’s cash used in investing activities increased in the first ninethree months of 20072008 compared with the 20062007 period. Capital expenditures increased $73$21 million, principally due to a power plant scrubber project at one of its power plants and various plant upgrades, whileplants. In addition, emission allowance purchases decreasedincreased by $19$2 million.

CILCORP’s and CILCO’s cash used in investing activities increased in the ninethree months ended September 30, 2007,March 31, 2008, compared with the same period in 2006.2007. Cash flow used in investing activities increased as a result of a $108$36 million increase in capital expenditures, primarily due to a power plant scrubber project and plant upgrades at AERG. The absence in 2007 of $11 million of proceeds received in 2006 from the sale of leveraged leases, and (for CILCORP only) the absence in 2007 of a 2006 note receivable payment from Resources Company in the amount of $42 million related to the 2005 transfer of leveraged leases from CILCORP to Resources Company also resulted in an increase in cash used in investing activities. The receipt of a $42 million net repayment of prior-year money pool advances and a $12 million reduction of emission allowance purchases reduced cash flows used in investing activities in the 2007 period compared to 2006.2008.

IP’s cash used in investing activities increaseddecreased in the first ninethree months of 20072008 compared to the same period in 2006 as2007. Capital expenditures decreased by $13 million in the first three months of 2008 from the year-ago period primarily because of a resultreduction in storm-related capital expenditures. In addition, net money pool advances decreased by $16 million in the first quarter of increased capital expenditures.2008 compared with the prior-year period.

See Note 89 – 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 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
74
may be purchased, among other things. Any changes that we may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material.

Cash Flows from Financing Activities

Cash provided by financing activities increaseddecreased for Ameren in the first ninethree months of 2007 from2008 compared with the year-ago period primarily due to a net reduction in short-term debt borrowings of $196 million. The prior-year period included the maturity of $100 million of Ameren’s 5.70% notes and the maturity of $50 million of CILCO’s 7.50% bonds. Current-year maturities of $19 million related to the IP SPT notes were consistent with the year-ago period. CashProceeds from financing activitiesthe issuance of common stock increased by $25 million as a result of a
$425 million debt issuance in June 2007 by UE, which was larger than the prior year’s issuances that totaled $232 million. The proceeds of the $425 million offering were used to reduce short-tem debt at UE. Overall, short-term debt increased $432 million year-over-year at Ameren. The increased short-term debt was used to pay maturing long-term notessales through Ameren’s 401(k) and to fund working capital requirements at Ameren’s subsidiaries. Cash was reduced by a $7 million decrease in common stock issuances and a $327 million increase in long-term debt redemptions, repurchases and maturities, including the maturity of $350 million in notes at Ameren CorporationDRPlus plans in the first nine monthsquarter of 2007.2008 compared with the year-ago period.

 
UE had a
69
UE’s net source of cash fromprovided by financing activities decreased in the first ninethree months of 2007,2008, compared to a net use of cash inwith the same period of the prior year. ContributingUE used existing cash balances to finance the increase was the issuancecurrent period’s investing activities resulting in a net reduction in short-term borrowings of $425$88 million in long-term debt in June 2007. The proceeds were used to reduce short-term debt. Overall, short-term debt decreased $142the first quarter of 2008 compared with the year-ago period and a $15 million in 2007 compared to an increasenet reduction of $128 million in 2006. Short-term borrowings were used in 2007 to fund working capital requirements and increased capital expenditures, and in 2006 principally to fund the acquisition of CTs. A $92 million increase in dividend payments and $20 million of net repayments onunder an intercompany borrowing arrangement with Ameren reduced cash provided by financing activities in the first nine months of 2007 compared to the same period in 2006.Ameren.

CIPS had a net source of cash from financing activities for the nine months ended September 30, 2007, compared to a net use of cash for the first nine months of 2006. Cash from financing activities increased as a result of a $100 million net increase in short-tem debt, a $50 million decrease in dividends paid, a $20 million reduction in long-term debt maturities, and the absence in 2007 of a 2006 intercompany note payment to UE in the amount of $67 million. Reducing these positive effects was the absence in 2007 of $61 million in proceeds from long-term debt issuances in 2006.

Genco had a net use of cash from financing activities forin the ninethree months ended September 30, 2007,March 31, 2008, compared towith a net source of cash in the first three months of 2007. This change was a result of $40 million net repayments of short-tem debt in the first three months of 2008 compared with net borrowings of $65 million in the first three months of 2007.

Genco had a decrease in cash used in financing activities for the three months ended March 31, 2008, compared with the first ninethree months of 2006.2007. The increasedecrease in cash used in financing activities in 2007the first quarter of 2008 was a result of a $20net repayments to the money pool of $45 million increaseduring the current year period compared with $7 million of net money pool advances during the first quarter of 2007. Cash benefited in dividend payments and a $75 million capital contribution received in 2007 compared to $150 million received in 2006. Reducing the net cash used in financing activities wasfirst quarter of 2008 by a net increase in short-term debt of $75 million$50 million. Additionally, dividends paid in the first ninethree months of 20072008 decreased $15 million compared towith the same period in 2006.year-ago period.

CILCORP and CILCO had a net source of cash from financing activities forin the ninethree months ended September 30, 2007,March 31, 2008, compared towith a net use of cash forin the first ninethree months of 2006. Short-term2007 as CILCORP and CILCO used existing cash to finance investing activities. CILCORP’s net short-term debt increased year-over-yeardecreased by $325$64 million, while CILCO had net borrowings of $10 million in the first quarter of 2008 compared with $30 million of net repayments in the same period in 2007. Cash used for redemptions, repurchases, and maturities of long-term debt decreased by $123 million at CILCORP and $50 million at CILCO. This included net repayments of a $73 million direct loan from Ameren and the maturity of $50 million of CILCO’s 7.50% bonds during the three months ended March 31, 2007. Net money pool borrowings totaled $31 million for CILCORP and $200 million for CILCO. Dividends were not paid by either companyCILCO in the first three months of 2007 compared to $50 million and $65 million paidwith no net borrowings in 2006 by CILCORP and CILCO, respectively. Also benefiting cash in 2007 compared to 2006 was the absencefirst three months of money pool repayments in 2007, compared to 2006 repayments of $92 million at CILCORP and $99 million at CILCO. In addition, there was a2008. A $14 million capital contribution received by CILCO in the first quarter of 2007 from CILCORP. Cash flows from financing activities were reduced byCILCORP resulted in a $43 million increase in CILCORP note repayments, a $96 million reduction in long-term debt proceedspositive impact on cash at both CILCORP and CILCO, and increased redemptions, repurchases, and maturities of long-term debt of $18 million and $30 million at CILCORP and CILCO, respectively.CILCO.

IP had a net increase inuse of cash from financing activities in the first ninethree months of 2008, compared with a net source of cash for the same period in 2007. In the first three months of 2007, IP had net money pool repayments of $43 million, compared towith no money pool repayments in 2008. In the same period of the prior year. Cash benefited by $125three months ended March 31, 2007, IP had $115 million of short-term debtnet borrowings inunder the 2007 comparedcredit facility to none in 2006, a $17 million net increase inrepay outstanding money pool borrowings and build liquidity during a period of legislative uncertainty. During the first quarter of 2008, IP reduced short-term debt by the lack$25 million and funded $15 million of $17 million in TFN overfunding. These benefits to cash were reduced by the lack of long-term debt proceeds in 2007, compared to $75 million in 2006.dividends.

Short-term Borrowings and Liquidity

Short-term borrowings typically consist of drawings under committed bank credit facilities and commercial paper issuances. ForSee Note 3 – Credit Facilities 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, see Note 3 – Credit Facilities and Liquidity to our financial statements under Part I, Item 1, of this report.arrangements.


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The following table presents the various committed bank credit facilities of the Ameren Companies and AERG, and their availability as of September 30, 2007:March 31, 2008:
Credit Facility
Expiration
Amount Committed
  
Amount Available
 Expiration Amount Committed  Amount Available 
Ameren, UE and Genco:
             
Multiyear revolving(a)
July 2010$
1,150
  $
728
 July 2010 $1,150  $233 
CIPS, CILCORP, CILCO, IP and AERG:
                 
2007 Multiyear revolving(b)
January 2010 
500
  
-
 
2006 Multiyear revolving(c)
January 2010 
500
  
125
 
2006 Multiyear revolving(b)(c)
January 2010    500  185 
2007 Multiyear revolving(b)(d)
January 2010    500   50 

(a)  Ameren Companies may access this credit facility through intercompany borrowing arrangements. The maximum amount directly available to Ameren, UE and Genco under the facility is $1.15 billion, $500 million and $150 million, respectively.
(b)See Note 3 - Credit Facilities and Liquidity to our financial statements under Part I, Item 1, of this report for discussion of the amendments to these facilities.
(c)  The maximum amount available to each borrower under this facility at September 30,March 31, 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 March 31, 2008, CILCO had a sublimit of $75 million under this facility and a $75 million sublimit under the 2007 credit facility.
(d)  The maximum amount available to each borrower under this facility at March 31, 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.
(c)  The maximum amount available to each borrower at September 30, 2007, including for issuance of letters of credit, was limited as follows: CIPS - $135 million, CILCORP - $50 million, CILCO - $150 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 October 31, 2007, CILCO had a sublimit of $75 million under this facility and a $75 million sublimit under the 2007 credit facility.

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In addition to committed credit facilities, a further source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents. At March 31, 2008, Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP had $186 million, $- million, $18 million, $2 million, $42 million,  $42 million, and $1 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 2006, FERC issued an order authorizing these utility subsidiaries to issue short-term debt securities subject to the following limits on outstanding balances: UE - $1 billion;billion, CIPS - $250 million;million, and CILCO - $250 million. The authorization was effective as of April 1, 2006, and terminates onwith an expiration date of March 31, 2008. In March 2008, FERC granted renewal of this authorization through March 31, 2010. IP has unlimited short-term debt authorization from FERC.

Genco iswas authorized by FERC in its March 2006 order to have up to $300 million of short-term debt outstanding at any time. This amount was increased to $500 million by FERC in its March 2008 order. AERG and EEI have unlimited short-term debt authorization from FERC.

With the repeal of PUHCA 1935, theThe issuance of short-term unsecured debt securities by Ameren and CILCORP which was previously subject to SEC approval under PUHCA 1935, is no longernot subject to approval by any regulatory body.

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) and preferred stock for the ninethree months ended September 30,March 31, 2008 and 2007, and 2006, 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.
   
Nine Months
 
 
Month Issued, Redeemed,
Repurchased or Matured
 
2007
  
2006
 
Issuances
       
Long-term debt
       
UE:
       
6.40% Senior secured notes due 2017
June $
425
  $
-
 
CIPS:
         
6.70% Senior secured notes due 2036
June  
-
   
61
 
CILCO:
         
6.20% Senior secured notes due 2016
June  
-
   
54
 
6.70% Senior secured notes due 2036
June  
-
   
42
 
IP:
         
6.25% Senior secured notes due 2016
June  
-
   
75
 
Total Ameren long-term debt issuances  $
425
  $
232
 

   Three Months 
 
Month Issued, Redeemed,
Repurchased or Matured
 
2008
  2007 
Issuances       
Common stock       
Ameren:       
DRPlus and 401(k)
Various $46  $21 
Total common stock issuances  $46  $21 
Redemptions, Repurchases and Maturities         
Long-term debt         
Ameren:         
2002 5.70% Notes due 2007February  -   100 
76
     
   
Nine Months
 
 
Month Issued, Redeemed,
Repurchased or Matured
 
2007
  
2006
 
Common stock
         
Ameren:
         
DRPlus and 401(k)
Various $
71
  $
78
 
Total common stock issuances  $
71
  $
78
 
Total Ameren long-term debt and common stock issuances  $
496
  $
310
 
Redemptions, Repurchases and Maturities
         
Long-term debt
         
Ameren:
         
2002 5.70% notes due 2007 
February $
100
  $
-
 
Senior notes due 2007
May  
250
   
-
 
CIPS:
         
7.05% First mortgage bonds due 2006
June  
-
   
20
 
CILCORP:
         
9.375% Senior notes due 2029 
March/April  
-
   
12
 
CILCO:
         
7.73% First Mortgage bonds due 2025                                                                     
July  
-
   
20
 
7.50% First mortgage bonds due 2007 
January  
50
   
-
 
IP:
         
Note payable to IP SPT:
         
5.65% Series due 2008
Various  
65
   
-
 
5.54% Series due 2007
Various  
-
   
86
 
Preferred Stock
         
CILCO:
         
5.85% Series
July  
1
   
1
 
Total Ameren long-term debt and preferred stock redemptions, repurchases and
maturities
  $
466
  $
139
 
CILCO:       
7.50% First Mortgage bonds due 2007                                                                        January  -   50 
IP:         
Note payable to IP SPT:         
5.65% Series due 2008Various  19   24 
Total Ameren long-term debt redemptions, repurchases and maturities  $19  $174 
 
The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for certain Ameren Companies as of September 30, 2007:March 31, 2008:

Effective
Date
 
Authorized
Amount
  
Issued
  
Available
 
Effective
Date
 
Authorized
Amount
  Issued  Available 
Ameren June 2004 $
2,000
  $
459
  $1,541 June 2004 $2,000  $459  $1,541 
UE(a)October 2005 1,000  
685
  
315
 October 2005 1,000  685  315 
CIPSMay 2001 
250
  
211
  
39
 May 2001 250  211  39 

(a)  In April 2008, UE issued $250 million principal amount of senior secured notes pursuant to its Form S-3 shelf registration statement, which leaves $65 million of securities currently available for issuance.

In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren in February 2004, authorizing the offering of 6 million additional shares of its common stock under 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 certain of its 401(k) plansplan pursuant to an effective SEC Form S-8 registration statements.statement. Under DRPlus and its 401(k) plans,plan (including a subsidiary plan that is now merged into the Ameren 401(k) plan), Ameren issued a total of 1.4 1.0
71
million new shares of common stock valued at $71$46 million in the ninethree months ended September 30, 2007.March 31, 2008.

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 3 – Credit Facilities and Liquidity to our financial statements under Part I, Item 1, of this report for a discussion of the covenants and provisions contained in our bank credit facilities and applicable cross-default provisions.  Also see Note 4 – Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ indenture agreements and articles of incorporation.

At September 30, 2007,March 31, 2008, the Ameren Companies were in compliance with their credit facility, indenture, and articles of incorporation provisions and covenants.

We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. 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 would increase our cost of
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capital and adversely affect our ability to access the capital markets.

Dividends

Dividends

The amount and timing of dividends payable on Ameren’sAmeren paid to its shareholders common stock are withindividends totaling $133 million, or 63.5 cents per share during the sole discretionfirst three months of 2008 (2007 - $131 million or 63.5 cents per share). On April 22, 2008, Ameren’s board of directors. The board of directors has not set specific targets or payout parameters when declaringdeclared a quarterly common stock dividends. However, the board considers various issues, including Ameren’s historical earnings and cash flow, projected earnings, projected cash flow and potential cash flow requirements, dividend payout rates at other utilities, returnof 63.5 cents per share payable on investments with similar risk characteristics, impactsJune 30, 2008, to shareholders of regulatory orders or legislation and overall business considerations.record on June 11, 2008.

See Note 3 – Credit Facilities and Liquidity and Note 4 – Long-term Debt and Equity Financings to our financial statements under Part I, Item 1, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ financial agreements and articles of incorporation that would restrict the Ameren Companies’ payment of dividends in certain circumstances. At September 30, 2007,March 31, 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. On July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured long-term debt credit rating tofrom Moody's is below investment-grade, causing it to be subject to this dividend payment limitation. As of September 30, 2007,March 31, 2008, AERG was in compliance with the debt-to-operating cash flow ratio test in the 2007 and 2006 $500 million credit facilities. 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 dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents for the ninethree months ended September 30, 2007March 31, 2008 and 2006.
  
Nine Months
 
  
2007
  
2006
 
UE $
246
  $
154
 
CIPS  
-
   
50
 
Genco  
113
   
93
 
CILCORP(a)
  
-
   
50
 
Nonregistrants  
36
   
44
 
Dividends paid by Ameren $
395
  $
391
 
2007.

(a)  CILCO paid to CILCORP dividends of $50 million for the nine months ended September 30, 2006.
  Three Months 
  2008  2007 
UE $77  $80 
Genco  24   39 
IP  15   - 
Nonregistrants  17   12 
Dividends paid by Ameren $133  $131 

Contractual Obligations

For a complete listing of our obligations and commitments, see Contractual Obligations under Part II, Item 7 and Note 1413 – Commitments and Contingencies under Part II, Item 8 of the Form 10-K, and Other Obligations in Note 89 – Commitments and Contingencies under Part I, Item 1, of this report. See Note 1112 – 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.
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Subsequent to December 31, 2006,Total other obligations, related toincluding the procurement of coal and related transportation, natural gas and nuclear fuel materially changed at Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP to $5,560 million, $1,759 million, $400 million, $356 million, $1,346 million, $1,346 million and $1,527 million, respectively, as of September 30, 2007. The Ameren Companies adopted the provisions of FIN 48 on January 1, 2007. The amount of unrecognized tax benefits, under the provisions of FIN 48 are $155 million, $58 million, $15 million, $36 million, $18 million, $18 million and $12 million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. UE also entered into a commitment to purchase heavy forgings during 2007. As of September 30, 2007, UE’s commitment to purchase heavy forgings totaled $88 million. Total obligations at September 30, 2007,March 31, 2008, for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP were $6,415$6,048 million, $2,301$2,032 million, $445$456 million, $392$243 million, $1,409$1,422 million, $1,409$1,422 million and $1,680$1,664 million, respectively.
 
As a result of the Illinois electric settlement agreement reached in July 2007 and the enactment of relatedreflected in legislation into law, which occurredenacted on August 28,26, 2007, 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
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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 of $59$11 million, $8$2 million, $5$1 million,
$11 $2 million, $24$4 million and $11$2 million, respectively, under the terms of the settlement agreement during the quarter ended September 30, 2007.March 31, 2008.  At September 30, 2007,March 31, 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 $108$15 million, $37$5 million, $21$3 million and $50$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
Fitch
Ameren:
   
Issuer/corporate credit ratingBaa2BBB-BBB+
UnsecuredSenior unsecured debtBaa2BB+BBB+
Commercial paperP-2A-3F2
UE:
   
Issuer/corporate credit ratingBaa1BBB-A-
Secured debtA3BBBA+
Commercial paperP-2A-3F2
CIPS:
   
Issuer/corporate credit ratingBa1BBBB+
Secured debtBaa3BBBBBB
Senior unsecured debt
Ba1BBB-BBB-
Genco:   
Issuer/corporate credit rating-BBB-BBB+
UnsecuredSenior unsecured debtBaa2BBB-BBB+
CILCORP:
   
Issuer/corporate credit rating-BBBB+
UnsecuredSenior unsecured debtBa2B+BBBB+
CILCO:
   
Issuer/corporate credit ratingBa1BBBB+
Secured debtBaa2BBBBBB
IP:
   
Issuer/corporate credit ratingBa1BBBB+
Secured debtBaa3BBB-BBB

During March and April of 2007, Moody’s, S&P, and Fitch downgraded various credit ratings of certain of the Ameren Companies. Depending on the specific credit rating agency action and the specific legal entities affected, the downgrade of these credit ratings was a result of the actions of various Illinois state legislators, including passage of forms of legislation that would have rolled back and frozen the electric rates of CIPS, CILCO and IP, and in the case of UE was prompted by higher costs, lower financial metrics and a continued challenging regulatory environment in Missouri.

On August 1, 2007, Fitch changed the rating outlook at Ameren to stable. In addition, Fitch revised the rating watch on CIPS, CILCORP, CILCO and IP to positive. The positive watch followed the announcement of the Illinois electric settlement agreement.  See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1 of this report for further discussion of the Illinois settlement agreement.

On August 29, 2007,February 12, 2008, Moody’s changed the rating outlook at Ameren and Genco to stable. The rating outlook of CIPS, CILCORP, CILCO, and IP was upgraded to positive. These actions were prompted by the Illinois electric settlement agreement. Moody’s stated that “the settlement significantly reduces the likelihood of a rate freeze being enacted in Illinois and provides the foundation for a potentially improving political and regulatory environment for investor-owned-utilities in the state.”

On August 29, 2007, S&P issued a research update in response to the Illinois settlement agreement, as discussed above. The outlook onaffirmed the ratings of Ameren UE and Genco wasbut changed their rating outlook to negative from stable. The outlook onMoody’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 upgradedprompted by declining cash flow coverage metrics, increased operating costs, higher capital expenditures for environmental 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 positive. 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 September 6, 2007,March 19, 2008, S&P upgradedraised its senior securedunsecured debt ratings of UE,for CIPS to BBB- from B+ and CILCOat CILCORP to BB from “BBB-” to “BBB” as a result of changes in its first mortgage bond rating methodology.B+.

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 as of the end of the thirdfirst quarter of 20072008 were $76$111 million, $4$6 million, $8$2 million, $27$2 million, $27$2 million, and $33$2 million at Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively, resulting from our reduced corporateissuer and issuer creditsenior unsecured debt ratings. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at September 30, 2007,March 31, 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 $160$210 million, $43$40 million, $16$15 million, $20$26 million, $22$35 million, $22$35 million, and $39$26 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.
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OUTLOOK

Below are some key events and trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 20072008 and beyond.

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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 materialfinancing 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. As a result, Ameren, UE, CIPS, CILCO and IP expect to be entering into a period where more frequent rate cases will be necessary. necessary in the future. UE agreed not to file a natural gas delivery rate case before March 15, 2010.
·  The Ameren Illinois Utilities filed delivery service rate cases with the ICC in November 2007 due to inadequate recovery of costs and low returns on equity beingof less than 5% experienced in 2007. CIPS, CILCO2007 and IP requested4% expected in 2008. In April 2008, the Ameren Illinois Utilities revised their requests to an increase theirin annual revenues for electric delivery service by $180of $163 million in the aggregate (CIPS - $31$28 million, CILCO - $10$4 million, and IP - $139$131 million). The electric rate increase requests were based on an 11% return on equity, a capital structure composed of 5151% to 53 percent53% equity, an aggregate rate base for the Ameren Illinois Utilities of $2.1 billion and a test year ended December 31, 2006, with certain prospective updates. In addition, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service. In April 2008, the Ameren Illinois Utilities revised their requests to an increase in annual revenues for natural gas delivery service by $67of $57 million in the aggregate (CIPS - $15$11 million increase, CILCO - $4 million decrease, and IP - $56$50 million increase). The natural gas rate change requests were based on an 11% return on equity, a capital structure composed of 5151% to 53 percent53% equity, an aggregate rate base for the Ameren Illinois Utilities of $0.9 billion and a test year ended December 31, 2006, with certain prospective updates. The ICC has until Octoberthe end of September 2008 to render a decision in these rate cases.
·  UE is actively considering the timing of its nextfiled an electric rate case filingwith the MoPSC in Missouri.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 June 30, 2008. 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 their electric and natural gas delivery service rate cases filed in November 2007, the Ameren Illinois Utilities requested ICC approval to implement rate adjustment mechanisms for bad debt expenses, electric infrastructure investments and the decoupling of natural gas revenues from sales volumes. The ICC staff in their direct testimony filed in March 2008 opposed the Ameren Illinois Utilities’ requests to implement a rate adjustment mechanism for electric infrastructure investments. The ICC staff offered limited support for the Ameren Illinois Utilities’ request to implement a rate adjustment mechanism for the decoupling of natural gas revenues from sales volumes. In July 2005, a law was enacted that enablesApril 2008, the Ameren Illinois Utilities withdrew their requests for bad debt expense rate adjustment mechanisms. In its electric rate case filed in April 2008, UE requested the MoPSC to put in place fuel, purchased power, and environmental cost recovery mechanisms for Missouri’s utilities. Rules for theapprove implementation of a fuel and purchased power cost recovery mechanism were approved by the MoPSC in September 2006. Detailed rules for the environmental cost recovery mechanism are being developed and expected to be effective in the first half of 2008.mechanism.
·  
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 electric delivery service rates. Due to the magnitude of these increases, a comprehensivethe Illinois electric settlement agreement was reached with key stakeholders in Illinois that2007 provides approximately $1 billion of funding forover a four-year period that began in 2007 to fund rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Funding for the settlement is coming from electric generators in Illinois and certain Illinois electric utilities. Pursuant to the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco and AERG agreed to makefund an aggregate contributions of $150 million, over a four-year period, with $60 million coming fromof which the Ameren Illinois Utilities (CIPS - $21 million; CILCO - $11 million; IP - $28 million), $62 million from Genco and $28 million from AERG. To fund thesefollowing contributions the Ameren Illinois Utilities, Genco and AERG willremain to be made as of March 31, 2008:
  
 
Ameren
  CIPS  
CILCO
(Illinois
Regulated)
  IP  Genco  
CILCO
(AERG)
 
2008(a)
 $31.9  $4.7  $2.3  $6.4  $12.8  $5.7 
2009(a)
  26.5   3.9   1.9   4.9   10.9   4.9 
2010(a)
  1.7   0.2   0.1   0.4   0.7   0.3 
Total $60.1  $8.8  $4.3  $11.7  $24.4  $10.9 
(a)  Estimated.
To fund these contributions, the Ameren Illinois Utilities, Genco and AERG may need to increase their respective borrowings.
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·  As part of the Illinois electric settlement agreement, the reverse auction used for power procurement in Illinois was discontinued. It will be replaced with a new power procurement process to be led by the IPA, beginning in 2009. In 2008, Illinois utilities contracted for necessary power and energy requirements primarily through a request-for-proposal process that was subject to ICC review and approval. In March and April 2008, the ICC approved the results of the Ameren Illinois Utilities’ energy and capacity requests-for-proposals for power needs during the period June 1, 2008 through May 31, 2009. Marketing Company was one of the winning bidders in both of these requests-for-proposals, and UE was one of the winning bidders in the capacity request-for-proposal. Existing supply contracts from the September 2006 reverse auction remain in place. The Ameren Illinois Utilities’ power procurement costs are passed directly to its customers. 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 related legislation, the reverse auction usedAERG), to lock-in energy prices for power procurement in Illinois was discontinued and replaced with a new power procurement process led by the IPA, beginning in 2009. In 2008, utilities will contract for necessary baseload, intermediate and peaking400 to 1,000 megawatts annually of their around-the-clock power requirements through a request-for-proposal process, subjectduring the period June 1, 2008 to ICC reviewDecember 31, 2012, at then relevant market prices. These financial contracts do not include capacity, are not load-following products and approval. Existing supply contracts fromdo not involve the September 2006 reverse auction will remain in place. The impactphysical delivery of the new procurement process in Illinois is uncertain.energy.
·  The MoPSC issued an order, as clarified, granting UE a $43 million increase in base rates for electric service with new electric rates effective June 4, 2007. This order included provisions to extend UE'sUE’s Callaway nuclear plant and fossil generation plant lives and to change the income tax method associated with the cost of property removal.removals. Such provisions are expected to decrease Ameren'sAmeren’s and UE'sUE’s expenses by $58 million annually.  The MoPSC also approved a stipulation and agreement authorizing an increase in UE’s annual natural gas delivery revenues of $6 million, effective April 1, 2007. UE agreed not to file a natural gas delivery rate case before March 15, 2010.
·  See Note 2 – Rate and Regulatory Matters to our financial statements under Part I, Item 1, of this report for a further discussion of Illinois and Missouri rate matters.
·  Very volatileVolatile 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. UE, Genco and CILCOAERG are seeking to raise the equivalent availability and capacity
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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 33 million megawatthours of baseload power in 2008 (Genco – 18 million, AERG – 7 million, EEI – 8 million), 31 million megawatthours in 2009 (Genco –  15 million, AERG - 8 million, EEI - 8 million) and 33 million megawatthours in 2010 (Genco - 18 million, AERG - 7 million, EEI - 8 million).
·  All but 5 million megawatthours of GencoGenco’s and AERG’s pre-2006 wholesale and retail electric power supply agreements expired during 2006. In 2007, 1 million megawatthours of these agreements, will expire and anotherwhich had an average embedded selling price of $35 per megawatthour, expired. Another 2 million contracted megawatthours will expire in 2008. These agreements hadlate 2008, which have an average embedded selling price of $36$33 per megawatthour. These agreements are being replaced with market-based sales. The Non-rate-regulated Generation segment expects to generate 31 million megawatthours of power in 2007 (Genco – 17 million, AERG – 6 million, EEI – 8 million).
·  
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, volatility, while capitalizingseeking to capitalize on its low-cost generation fleet to provide for 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, including contracts resulting fromMarketing Company targets to hedge Non-rate-regulated Generation’s expected output by 80% to 90% for the Illinois 2006 power procurement auctionfollowing year, 50% to 70% for two years out, and the Illinois electric settlement agreement, the Non-rate-regulated Generation segment has sold approximately 90% of its expected 2007 generation output at an average price of $51 per megawatthour (fiscal year 2008 - 75%, or 24 million megawatthours; fiscal year 2009 - 55%, or 18 million megawatthours). Expected sales in 2007 include an estimated 7.6 million megawatthours of power sold through the 2006 Illinois power procurement auction at about $65 per megawatthour (2008 - 6.8 million, 2009 - 4.3 million).
30% to 50% for three years out.
·  
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 transmissionprovider’s system. In February 2008, FERC conditionally accepted the ancillary services market tariff proposed by MISO. 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 based on their generation 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. MISO is currently in the process of developing a centralized regional wholesale ancillary services market, which is expected to begin during 2008. In September 2007, MISO filed a new proposed ancillary services market tariff with the FERC subject to normal FERC procedural review. We expect MISO will begin developmentcapacity and energy prices to strengthen from current levels because of aimproving market liquidity and decreasing reserve margins in MISO. Non-rate-regulated Generation’s capacity market oncerevenues are expected to increase to approximately $40 million in 2008 from $25 million in 2007. EEI receives payment for 100% of its ancillary services market iscapacity sales under its power supply agreement with Marketing Company. Capacity revenues are allocated to Genco and AERG based on their generation in place.accordance with their power supply agreements with Marketing Company. 
·  We expect continued economic growth in our service territory and market area to benefit energy demand in 2007
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2008 and beyond, but higher energy prices could result in reduced demand from customers, especially in Illinois. 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 2006, 85%2007, 84% of Ameren’s electric generation (UE - 77%76%, Genco - 97%96%, CILCOAERG - 99%, EEI –- 100%) was supplied by its coal-fired power plants. About 93%94% of the coal used by these plants (UE - 97%, Genco - 87%88%, CILCOAERG - 69%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. As of September 30, 2007,March 31, 2008, coal inventories for UE, Genco, AERG and EEI were adequate and consistent within excess of historical levels. UE’s coal inventories were at targeted levels, and Genco’s, AERG’s and EEI’s coal inventories were near targeted 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.
·  Ameren’s fuel costs (including transportation) are expected to increase in 2008 and beyond. Fuel costs for both Missouri Regulated and Non-rate-regulated Generation are expected to increase approximately 35% from 2007 to 2010, assuming Genco will be reimbursed for incremental fuel costs it is incurring to replace coal from an Illinois mine that was closed at the end of 2007. Genco’s supply contract with the mine owner went through 2009.  Under the Uniform Commercial Code, Genco should be entitled to the incremental increase in its coal costs for replacement coal in 2008 and 2009. Genco is currently in negotiations with the mine owner for reimbursement of replacement coal and related transportation costs are expected to increase 15% to 20% in 2007 over 2006 and 5% to 10% in 2008. Further increases are expected beyond 2008.  Ameren’s nuclear fuel costs are also expected to rise overcosts; however, we cannot predict the next few years. In addition, power generationoutcome of these negotations. Under the terms of the terminated contract, Genco could have purchased 2.5 million tons of coal annually from higher-cost, gas-fired plants is expected to increase in the next few years.this mine. See Item 3 - Quantitative and Qualitative Disclosures about Market Risk in Part I of this report for additional information about the percentage of fuel and transportation requirements that are price-hedged for 20072008 through 2011.2012.
·  Ameren’s coal and related transportation costs are expected to increase 15% to 20% in 2007 over 2006 and 5% to 10% in 2008. Further increases are expected beyond 2008.  Ameren’s nuclear fuel costs are also expected to rise over the next few years. In addition, power generation from higher-cost, gas-fired plants is expected to increase in the next few years. See Item 3 - Quantitative and Qualitative Disclosures about Market Risk in Part I of this report for information about the percentage of fuel and transportation requirements that are price-hedged for 2007 through 2011.

·  In 2007, Ameren and IP will experience higher year-over-year purchased power expenses as the amortization of certain favorable purchase accounting adjustments associated with the IP acquisition was completed in 2006.
·  In 2007, Ameren expects to reduce levels of emission allowance sales in order to retain remaining allowances for future environmental compliance needs.
Other Costs

·  In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. In FebruaryJanuary 2008, the Circuit Court of Reynolds County, Missouri, approved UE’s November 2007 UE submitted plans and an environmental report to FERC to rebuild the upper reservoir at its Taum Sauk plant, assuming successful resolution of outstanding issuessettlement agreement with authorities of the state of Missouri.Missouri resolving the state’s lawsuit and claims for damages and other relief related to the breach. In addition, pursuant to the settlement agreement, UE is required to replace the breached upper reservoir with a new reservoir, subject to FERC authorization. UE received approval from FERC to rebuild the upper reservoir in August 2007 and hired a contractor in November 2007. ShouldThe estimated cost to rebuild the upper reservoir is in the range of $450 million. UE expects the Taum Sauk plant be rebuilt, UE would expect itpumped-storage hydroelectric facility to be out of service through at least the fall of 2009, if not longer. UE has accepted responsibility for the effects of the incident. At this time,early 2010. UE believes that substantially all of the damagedamages and liabilities (but not penalties or lost electric margins)

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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 and by authorities in the state of Missouri. UE is currently in discussions with state authorities to resolve outstanding issues associated with this incident. The Taum Sauk incident is also under investigation at the MoPSC.parties. We are unable to determinepredict the impact the breach may havetiming or outcomes of this litigation, or its possible effect on Ameren’s and UE’s results of operations,operation, financial position or liquidity beyond those amounts already recognized.liquidity. See Note 2 – Rate and Regulatory Matters and Note 8 -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’s next scheduled refueling and maintenance outage is in the fall of 2008 and is expected to last 25 to 30 days. During ana 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 the Taum Sauk incident, among other things.
·  Bad debts expense and past-due accounts receivable may increase due to rising electric and gas rates.rates as well as statutory restrictions on collection activities.
·  Genco expects its annual depreciation expense will decrease by $12 million annually based on a depreciation study completed in September 2007.As we refinance our short-term and variable-rate debt into fixed-rate debt, financing costs may increase.
·  We are currently undertaking cost reduction and control initiatives associated with the strategic sourcing of purchases and streamlining of all aspects of our business.

Capital Expenditures

·  The EPA has issued more stringent emission limits on all coal-fired power plants. Between 20072008 and 2016,2017, Ameren expects that certain Ameren Companies will be
76
required to invest between $3.5$4 billion and $4.5$5 billion to retrofit their power plants with pollution control equipment. Costs for these types of projects continue to escalate. These investments will also result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 50%45% of this investment will be in Ameren’s regulated UE operations, and it is therefore expected to be recoverable from ratepayers. The recoverability of amounts expended in non-rate-regulated operations will depend on whether market prices for power adjust as a result of thismarket conditions reflecting increased investment.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. TheExcessive costs to comply with future legislation or regulations could be so expensive thatmight force Ameren and other similarly-situated electric power generators may be forced to close some coal-fired facilities. In December 2007, Ameren will provideissued a report on how it is responding to the rising regulatory, competitive, and public pressure to significantly reduce carbon dioxideCO2 and other emissions from current and proposed power plant operations. The report will includeincluded Ameren’s climate change strategy and activities, current greenhouse gas emissions, and analysis with respect to plausible future greenhouse gas scenarios. Ameren will issue this report in mid-December 2007.scenarios; it is available on Ameren’s Web site. Investments to control carbon emissions at Ameren’s coal-fired plants would significantly increase future capital expenditures and operationsoperation 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 at least 2018.2018 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 2007, UE signed an agreement with UniStar Nuclear to assist UE in the preparation of a combined construction and operating license application (COLA) for filing with the NRC. A COLA describes how a nuclear plant would be designed, constructed and operated. In addition, UE has also signed contracts for certain long lead-time equipment. Preparing athat COLA and entering into these contracts does not mean a decision has been made to build a nuclear plant. TheyThese are only the first steps in the regulatory licensing and procurement process. UE and UniStar Nuclear must submit the COLA to the NRC in 2008 to be eligible for incentives available under provisions of the 2005 Energy Policy Act. We cannot predict whether or when the NRC will approve the COLA.
·  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.
·  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. UE announced in July 2007 plans to spend $300 million over three years for underground cabling and reliability improvement, $135 million ($45 million per year) for tree-trimming, and $84 million over three years (approximately $28 million per year) for circuit and device inspection and repair. We would expect these costs or investments 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.
·  The Ameren Companies will incur significant capital expenditures over the next five years for compliance with environmental regulations and to make significant investments in their electric and gas utility infrastructure to improve overall system reliability. Expenditures are expected to be funded primarily with debt.

82
Affiliate TransactionsOther

·  As a result of the termination of the JDA on December 31, 2006, UE and Genco no longer have the obligation to provide power to each other. UE is able to sell any excess power it has at market prices, which we believe will most likely be higher than the prices paid to it by Genco. Genco will no longer receive the margins on sales that it made, which were fulfilled with power from UE. The electric rate order issued in May 2007required by the MoPSC, incorporatedUE filed a study in November 2007 with the net decreaseMoPSC evaluating the costs and benefits of UE’s participation in MISO. This case is currently pending. UE’s revenue requirementfiling noted that there were a number of uncertainties associated with the cost-benefit study, including issues associated with the UE-MISO service agreement. If some of these uncertainties are ultimately resolved in a manner adverse to UE, it could call into question whether it is cost-effective for UE to remain in MISO. UE has advised MISO of its intent to withdraw from increased margins expectedMISO as of December 31, 2008, in order to result frompreserve the terminationoption to withdraw based on the outcome of the JDA. See Note 7 - Related Party Transactionspending MoPSC proceeding.  It is uncertain when or how the MoPSC will rule on UE's MISO cost-benefit study or, if UE were to our financial statements under Part I, Item 1,withdraw from MISO, what the effect of this report forsuch a discussion of the effects of terminating the JDA.withdrawal would be on UE.

Other

·  
In 2006, Ameren realized gains on sales of noncore properties, including leveraged leases. The net benefit of these sales to Ameren in 2006 was 16 cents per share. Ameren continues to pursue the sale of its interests in its remaining three leveraged lease assets. Ameren does not expect to achieve similar sales levels of noncore properties in 2007.    

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.
 

77
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, 2007:March 31, 2008:

 
Interest Expense
  
Net Income(a)
  Interest Expense  
Net Income(a)
 
Ameren $
20
  $(13) $25  $(15)
UE 
6
  (4) 8  (5)
CIPS 
2
  (1) 1  (1)
Genco 
1
  (1) 1  (1)
CILCORP 
5
  (3) 6  (3)
CILCO 
4
  (2) 4  (2)
IP 
6
  (4) 5  (3)

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

Insured Auction-Rate Tax-exempt Bonds

83
 Our auction-rate tax-exempt environmental improvement and pollution control revenue bonds issued for the benefit of UE, CIPS, CILCO and IP through governmental authorities are 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 have placed some of the monoline bond insurers on review for a possible downgrade and/or have actually downgraded their credit ratings due to their insuring of such securities. As a result, since December 2007 our auction-rate bonds that are insured by the monoline bond insurers have similarly been placed on review for possible downgrade and/or have been downgraded. We have 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 have redeemed or provided notices of redemption with respect to 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 March 31, 2008, and interest rates ranging from 4.0% to 4.9% at March 31, 2008. In April 2008, UE and IP issued senior secured notes in the 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.

78
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 Ameren Illinois Utilities’ past-due accounts receivable balances have increased significantly due to the increase in electric rates in Illinois, effective January 2, 2007, and statutory restrictions on collection activities. The allowances for doubtful accounts of IP, CIPS, and CILCO have been increased to provide for the heightened credit risk associated with this increase in past-due accounts receivables. 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, 2007,March 31, 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 powerinterchange or wholesale purchase and sale activity with nonaffiliated companies. These companies also have credit exposure to affiliates. At September 30, 2007,March 31, 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 purchases and salescounterparties was each less than $1$3 million, net of collateral (2006(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 leases.lease. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $32$78 million at September 30, 2007 (2006March 31, 2008 (2007 - $35$22 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 will provide $488 million in rate relief over a four-year period 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 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, and in the amount of cash required to be contributed to the plans.

Commodity Price Risk
 
We are exposed to changes in market prices for electricity, fuel, and natural gas. UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are partially hedged through sales agreements. 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 our cumulative earnings might decrease if power prices were to decrease by 1% on unhedged economic generation for the remainder of 20072008 through 2010:
  
Net Income(a)
 
Ameren                                        $(23)
UE                                         (9)
Genco                                         (7)
CILCO (AERG)                                         (2)
EEI                                         (6)

  
Net Income(a)
 
Ameren                                        $(17)
UE                                         (8)
Genco                                         (5)
CILCO (AERG)                                         (2)
EEI                                         (6)
(a)  Calculations are based on an effective tax rate of 38%

Ameren also utilizesuses 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 negative material financial impact.

Similar techniques are used to manage risks associated with changing prices of fuel exposures 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
79
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
84
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. The naturalNatural gas transportation expenses for theAmeren’s gas distribution utility companies and the gas-fired generation units of UE, Genco, AERG and EEI are controlledregulated by FERC via publishedthrough approved tariffs withgoverning the rates, terms and conditions of transportation and storage services. Certain firm transportation and storage capacity agreements held by Ameren Companies include rights to extend the contracts from yearprior to year.the termination of the primary term. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariffstariff rates for our requirements.

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 20072008 through 2011:2012, as of March 31, 2008:

 
2007
  
2008
   
2009 – 2011
  2008  2009   2010 – 2012 
Ameren:
                    
Coal  100% 98% 51% 100% 87% 34%
Coal transportation  
100
  96  44  100  82  17 
Nuclear fuel  
100
  100  73  100  100  87 
Natural gas for generation  
100
  19  -  38  1  - 
Natural gas for distribution 
 (a)
  26  12 
Natural gas for distribution(a)
 23  14  15 
Purchased power for Illinois Regulated(b)
  
100
  91  60  97  80  51 
UE:
                        
Coal   100% 99% 54% 100% 87% 38%
Coal transportation  
100
  97  62  100  96  31 
Nuclear fuel  
100
  100  73  100  100  87 
Natural gas for generation  
100
  14  -  29  -  - 
Natural gas for distribution(a) 
(a)
  58  9  22  12  4 
CIPS:
                        
Natural gas for distribution 
(a)
  23% 14%
Natural gas for distribution(a)
 24% 16% 5%
Purchased power(b)
  100% 91  60  97  80  51 
Genco:
                        
Coal   100% 100% 47% 100% 88% 25%
Coal transportation  
100
  98  32  100  98  - 
Natural gas for generation  
100
  17  -  60  -  - 
CILCORP/CILCO:
                        
Coal (AERG)   100% 83% 41% 93% 82% 28%
Coal transportation (AERG)  
100
  79  24  100  69  - 
Natural gas for distribution 
(a)
  20  10 
Natural gas for distribution(a)
 21  12  21 
Purchased power(b)
  
100
  91  60  97  80  51 
IP:
                        
Natural gas for distribution 
(a)
  23% 13%
Natural gas for distribution(a)
 24% 16% 15%
Purchased power(b)
  100% 91  60  97  80  51 
EEI:
                        
Coal  100% 100% 55% 100% 88% 39%
Coal transportation  
100
  100  -  100  100  - 

(a)  The year 2007 is non-applicableRepresents the percentage of natural gas price hedged for this table.peak winter season of November through March. The year 2008 represents November 2007January 2008 through March 2008. The year 2009 represents November 2008 through March 2009. This continues each successive year through March 2011.2012.
(b)  Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than 1 megawatt of demand and includesdemand. 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.
 

 
8580
The following table shows how our totalcumulative 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 five-year period 20072008 through 2011:
2012. 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 March 31, 2008, Ameren had price-hedged approximately 100% of expected fuel surcharges in 2008.
 
Coal
  
Transportation
  Coal  Transportation 
 
Fuel
Expense
  
Net
Income(a)
  
Fuel
Expense
  
Net
Income(a)
  
Fuel
Expense
  
Net
Income(a)
  
Fuel
Expense
  
Net
Income(a)
 
Ameren(b)
 $
11
  $(7) $
15
  $(10) $31  $(19) $21  $(13)
UE 
4
  (3) 
6
  (4) 12  (8) 9  (6)
Genco 
4
  (2) 
3
  (2) 12  (7) 5  (3)
CILCORP 
2
  (1) 
2
  (1) 5  (3) 2  (1)
CILCO (AERG) 
2
  (1) 
2
  (1) 5  (3) 2  (1)
EEI 
1
  (1) 
4
  (3) 2  (1) 5  (3)

(a)  Calculations are based on an effective tax rate of 38%.
(b)  Includes amounts for Ameren registrant and nonregistrant subsidiaries.

In the event of a significant change in coal and coal transportation 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 89 – 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 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 and nine months ended September 30, 2007. TheMarch 31, 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 other external sources,(Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods.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(b)
  
CILCORP/
CILCO
  
IP
  
Ameren(a)
  UE  CIPS  
Genco
  
CILCORP/
CILCO
  IP 
Three Months
                                    
Fair value of contracts at beginning of period, net $
52
  $
5
  $-  $(2) $
3
  $(15)  $13  $7  $38  $(4) $21  $55 
Contracts realized or otherwise settled during the period (25) (1) 2  
-
  4  18  (5) (3) -  -  (1) 4 
Changes in fair values attributable to changes in valuation technique and assumptions  
-
  
-
  
-
  
-
  
-
  
-
  -  -  -  -  -  - 
Fair value of new contracts entered into during the period 
7
  
11
  
-
  (1) (1) 
-
  15  (1) -  1  -  (2)
Other changes in fair value 
4
  (6) 
(6
) 
1
  (6)  (19) (10) (4) 20  (11) 20  45 
Fair value of contracts outstanding at end of period, net $38  $
9
  $(4) $(2) $-  $
(16
)  $13  $(1) $58  $(14) $40  $102 
Nine Months
                        
Fair value of contracts at beginning of period, net $
41
  $
9
  $(7) $(1) $(3) $(34) 
Contracts realized or otherwise settled during the period (16) (4) 5  
-
  7  36 
Changes in fair values attributable to changes in valuation technique and assumptions  
-
  
-
  
-
  
-
  
-
  
-
 
Fair value of new contracts entered into during the period 
15
  6  
-
  (1) (4) (7) 
Other changes in fair value 
(2
)  
(2
)  (2)  
-
  -  (11)
Fair value of contracts outstanding at end of period, net $38  $
9
  $(4)  $(2) $-  $(16) 

(a)  Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b)  In conjunction with the new power supply agreement between Marketing Company and Genco that went into effect January 1, 2007, the mark-to-market value of hedges entered into during 2006 for Genco was transferred from Genco to Marketing Company.

The following table presents maturities of derivative contracts as of September 30, 2007:March 31, 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 Value
 
Ameren:
               
Prices actively quoted                                                      $8  $(1) $
-
  $
-
  $
7
 
Prices provided by other external sources(a)
  (23)   (1)   
-
   
-
   (24) 
Prices based on models and other valuation methods(b)
  
39
   
16
   
-
   
-
   
55
 
Total                                                      $
24
  $
14
  $
-
  $
-
  $38 
UE:
                    
Prices actively quoted                                                      $
-
  $
-
  $
-
  $
-
  $- 
Prices provided by other external sources(a)
  (1)   
-
   
-
   
-
   (1) 
Prices based on models and other valuation methods(b)
  
8
   
2
   
-
   
-
   10 
Total                                                      $
7
  $
2
  $
-
  $
-
  $
9
 
 
 
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 Value
 
Ameren:               
Level 1                                                      $(17) $-  $-  $-  $(17)
Level 2(a)                                                     
  (29)  -   -   -   (29)
Level 3(b)                                                     
  35   22   2   -   59 
Total                                                      $(11) $22  $2  $-  $13 
 
8681
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 Value
CIPS:
                    
Prices actively quoted                                                      $-  $
-
  $
-
  $
-
  $
-
 
Prices provided by other external sources(a)
  (2)   (1)   (1)   
-
   (4) 
Prices based on models and other valuation methods(b)
  
-
   
-
   
-
   
-
   
-
 
Total                                                      $(2)  $
(1
)  $(1)  $
-
  $(4) 
Genco:
                    
Prices actively quoted                                                      $(1) $
-
  $
-
  $
-
  $(1)
Prices provided by other external sources(a)
  (1)  
-
   
-
   
-
   (1)
Prices based on models and other valuation methods(b)
  
-
   
-
   
-
   
-
   
-
 
Total                                                      $(2) $
-
  $
-
  $
-
  $(2)
CILCORP/CILCO:
                    
Prices actively quoted                                                      $
1
  $
-
  $
-
  $
-
  $1 
Prices provided by other external sources(a)
  
(1
)   
-
   
-
   
-
   (1) 
Prices based on models and other valuation methods(b)
  
-
   
-
   
-
   
-
   
-
 
Total                                                      $-  $
-
  $
-
  $
-
  $
-
 
                
IP:
                    
Prices actively quoted                                                      $
-
  $
-
  $
-
  $
-
  $
-
 
Prices provided by other external sources(a)
  (17)   
1
   
-
   
-
   (16) 
Prices based on models and other valuation methods(b)
  
-
   
-
   
-
   
-
   
-
 
Total                                                      $(17)  $1  $
-
  $
-
  $(16) 
 
 
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 Value
 
UE:                    
Level 1                                                      $(2) $-  $-  $-  $(2)
Level 2(a)                                                     
  (14)  -   -   -   (14)
Level 3(b)                                                     
  12   3   -   -   15 
Total                                                      $(4) $3  $-  $-  $(1)
CIPS:                    
Level 1                                                      $-  $-  $-  $-  $- 
Level 2(a)                                                     
  -   -    -   -   - 
Level 3(b)                                                     
  17   21   20   -   58 
Total                                                      $17  $21  $20  $-  $58 
Genco:                    
Level 1                                                      $(15) $-  $-  $-  $(15)
Level 2(a)                                                     
  -   -   -   -   - 
Level 3(b)                                                     
  1   -   -   -   1 
Total                                                      $(14) $-  $-  $-  $(14)
CILCORP/CILCO:                    
Level 1                                                      $-  $-  $-  $-  $- 
Level 2(a)                                                     
  -   -   -   -   – 
Level 3(b)                                                     
  17   14   9   -   40 
Total                                                      $17  $14  $9  $-  $40 
IP:                    
Level 1                                                      $-  $-  $-  $-  $- 
Level 2(a)                                                     
  -   -   -   -   - 
Level 3(b)                                                     
  33   41   28   -   102 
Total                                                      $33  $41  $28  $-  $102 

(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 4.4 and Item 4T. CONTROLS AND PROCEDURES.

(a)  Evaluation of Disclosure Controls and Procedures

As of September 30, 2007,March 31, 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.

82
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 April 2008, The Boeing Company, in conjunction with other industrial customers as a coalition, intervened in the MoPSC proceeding relating to UE's pending request for an increase in its electric service rates.  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 78 – Related Party Transactions and Note 89 – Commitments and Contingencies to our financial statements under Part I, Item 1 and Item 1A, Risk Factors, below of this report.
 
87

ITEM 1A. RISK FACTORS.

There have been no material changes to the risk factors disclosed in Item 1A. Risk Factors in our Form 10-K.

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.

The electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are determined through regulatory proceedings and are subject to legislative actions which are largely outside of our control. Where these events result in the inability of UE, CIPS, CILCO or IP to recover their respective costs and earn an appropriate return on investment, it could have a material adverse effect on our future results of operations, financial position or liquidity.

The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, and liquidity of the Ameren Companies. The electric and gas utility industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental entities outside of our control, including the MoPSC, the ICC, and FERC. Decisions made by these entities could have a material adverse effect on our results of operations, financial position, or liquidity.

Increased costs and investments, when combined with rate reductions and moratoriums, have caused decreased returns in Ameren’s utility businesses. With rising costs, including fuel and related transportation, purchased power, labor and material 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 rate relief is granted from state regulators. As a result, Ameren, UE, CIPS, CILCO and IP expect to be entering a period where more frequent rate cases will be necessary.  Ameren remains subject to competitive, economic, political, legislative and regulatory pressures that could have a material adverse effect on our results of operations, financial position, or liquidity.

Illinois
A provision of the Illinois Customer Choice Law related to the restructuring of the Illinois electric industry put a rate freeze into effect through January 1, 2007, for CIPS, CILCO and IP. CIPS, CILCO and IP filed rate cases with the ICC in December 2005 requesting a modification of their electric delivery service rates effective January 2, 2007. In November 2006, the ICC issued an order that approved an aggregate revenue increase of $97 million effective January 2, 2007 (CIPS - an $8 million decrease, CILCO - a $21 million increase and IP - an $84 million increase) based on an allowed return on equity of 10%. In May 2007, the ICC issued an order disallowing the recovery of certain administrative and general expenses totaling $50 million. Because of the ICC’s cost disallowances and regulatory lag, the Ameren Illinois Utilities are not expected to earn their allowed return on equity of 10% in 2007. Most customers were taking service under a frozen bundled electric rate in 2006, which included the cost of power, so these delivery service revenue changes do not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery service rates that became effective January 2, 2007.
Due to inadequate recovery of costs and low returns on equity being experienced in 2007, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for electric delivery service by $180 million in the aggregate (CIPS - $31 million, CILCO - $10 million and IP - $139 million).  The electric rate increase requests were based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $2.1 billion and a test year ended December 31, 2006, with certain prospective updates.  In addition, CIPS, CILCO and IP filed requests with the ICC in November 2007 to increase their annual revenues for natural gas delivery service by $67 million in the aggregate (CIPS - $15 million increase, CILCO - $4 million decrease and IP - $56 million increase). The natural gas rate change requests were based on an 11% return on equity, a capital structure composed of 51 to 53 percent equity, an aggregate rate base for the Ameren Illinois Utilities of $0.9 billion and a test year ended December 31, 2006, with certain prospective updates. The ICC has until October 2008 to render a decision in these rate cases and could materially reduce the amount of the increase requested, or even reduce rates.

Electric Settlement Agreement
Consistent with the Illinois Customer Choice Law that froze electric rates for CIPS, CILCO and IP through January 1, 2007, these companies entered into power supply contracts that expired on December 31, 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers through an auction. It also approved the related tariffs to collect these costs from customers for the period commencing January 2, 2007. In accordance with the January 2006 ICC order, a power procurement auction was held in September 2006. New electric rates for CIPS, CILCO and IP went into effect on January 2, 2007, reflecting delivery service tariffs approved by the ICC in November 2006 and full cost recovery of power purchased
88
on behalf of Ameren Illinois Utilities’ customers in the September 2006 auction.

Due to the magnitude of these rate increases, various legislators supported legislation that would have reduced and frozen the electric rates of CIPS, CILCO and IP at the rates that were in effect prior to January 2, 2007, and would have imposed a tax on electric generation in Illinois to help fund customer assistance programs. The Illinois governor also supported rate rollback and freeze legislation. The rate rollback and freeze legislation would have prevented the Ameren Illinois Utilities from recovering from retail customers substantial portions of the cost of electric energy the Ameren Illinois Utilities are purchasing under wholesale contracts entered into as a result of the September 2006 auction, and would have caused the Ameren Illinois Utilities to under-recover their delivery service costs until the ICC could approve higher delivery service rates.

As a result of these concerns, in July 2007, an agreement was reached among key stakeholders in Illinois that addresses the increase in electric rates and the future power procurement process. The settlement agreement was subject to enactment of legislation into law, which occurred on August 28, 2007. Ameren, on behalf of Marketing Company, Genco and AERG, the Ameren Illinois Utilities, Exelon, on behalf of Exelon Generation Company LLC, Commonwealth Edison Company, Exelon’s Illinois electric utility subsidiary, Dynegy Holdings, Inc., Midwest Generation, LLC, and MidAmerican Energy Company agreed to contribute an aggregate of approximately $1 billion over four years to fund both rate relief programs and the IPA. The agreement provides that if legislation is enacted in Illinois before August 1, 2011 freezing or reducing retail electric rates or imposing or authorizing a new tax, special assessment or fee on generation of electricity, then the remaining funding commitments will expire and any funds set aside in support of those commitments will be refunded to the utilities and electric generators. Also pursuant to the agreement, all pending litigation and regulatory actions by the Illinois attorney general relating to the reverse auction procurement process, which was used to determine market-based rates effective January 1, 2007, and the electric space heating marketing practices of the Ameren Illinois utilities were withdrawn with prejudice.

Although we cannot fully predict the effect of the implementation of the settlement agreement and related comprehensive rate relief program on Ameren, the Ameren Illinois Utilities, Genco or AERG, we believe the settlement agreement significantly reduces the risk that legislation will be enacted into law that reduces and freezes electric rates of CIPS, CILCO and IP to rates that were in effect prior to January 2, 2007, or that imposes a tax on electric generation in Illinois. The following factors resulting from implementation of the Illinois electric settlement agreement could have a material adverse effect on the results of operations, financial position or liquidity of Ameren, the Ameren Illinois Utilities, Genco or AERG:

·  uncertainty as to the implementation of the new power procurement process in Illinois for 2008 and 2009, including ICC review and approval requirements, the role of the IPA, and the ability of the Ameren Illinois Utilities to lease, or invest in, generation facilities;
·  the increase in short-term or long-term borrowings by the Ameren Illinois Utilities, Genco and AERG to fund contributions under the settlement agreement;
·  the failure by the electric generators that are party to the settlement agreement to perform in a timely manner under their respective funding agreements, which permit the Ameren Illinois Utilities to seek reimbursement for a portion of the rate relief that will be provided to certain of their electric customers; and
·  the extent to which Genco and AERG will be successful in making future sales to supply a portion of Illinois’ total electric demand through the revised power procurement mechanism.
If, notwithstanding the Illinois settlement agreement, any decision is made or action occurs that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner, and such decision or action is not promptly enjoined, it could result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP.

Missouri

With the expiration of multiyear electric and gas rate moratoriums, effective July 1, 2006, UE filed requests with the MoPSC in July 2006 for an electric rate increase of $361 million and for a natural gas delivery rate increase of $11 million. In March 2007, a stipulation and agreement was approved by the MoPSC authorizing an increase in annual natural gas delivery revenues of $6 million, effective April 1, 2007. As part of this stipulation and agreement, UE agreed not to file a natural gas delivery rate case before March 15, 2010. This agreement does not prevent UE from filing to recover infrastructure costs through a statutory infrastructure system replacement surcharge (ISRS) during this three-year rate moratorium. The return on equity to be used by UE for purposes of any future ISRS tariff filing is 10.0%.

In May 2007, the MoPSC issued an order authorizing a $43 million increase in UE’s base rates for electric service based on a return on equity of 10.2%. The MoPSC denied UE’s and other intervenors’ applications for rehearing with respect to certain aspects of the MoPSC
89
rate order. In July 2007, UE appealed certain aspects of the MoPSC decision, principally the 10.2% return on equity granted by the MoPSC, to the Circuit Court of Cole County in Jefferson City, Missouri. The Office of Public Counsel and the Missouri attorney general, who were both intervenors in the electric rate case, also appealed certain aspects of the MoPSC decision to the Circuit Court of Cole County. We cannot predict the outcome of these appeals of the MoPSC rate order. Any change in electric or gas rates may not directly correspond to a change in UE’s earnings.

Increased federal and state environmental regulation will cause UE, Genco, CILCO (through AERG) and EEI to incur large capital expenditures and to incur increased operating costs. Future limits on greenhouse gas emissions would likely require UE, Genco, CILCO (through AERG) and EEI to incur significant additional increases in capital expenditures and operating costs and could result in the closures of coal-fired generating plants.
About 61% of Ameren’s generating capacity is coal-fired and about 85% of its electric generation was produced by its coal-fired plants in 2006. The remaining electric generation comes from nuclear, gas-fired, hydroelectric, and oil-fired power plants. In May 2005, the EPA issued final regulations with respect to SO2, NOx, and mercury emissions from coal-fired power plants. These regulations require significant additional reductions in the emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. Preliminary estimates of aggregate capital compliance expenditures for UE, Genco, and EEI range from $3.5 billion to $4.5 billion by 2016.
Missouri rules, which substantially follow the federal regulations and became effective in April 2007, are expected to reduce mercury emissions 81% by 2018 and reduce NOx emissions 30% and SO2 emissions 75% by 2015.
Illinois has adopted rules for mercury emissions that are significantly stricter than the federal regulations. In 2006, Genco, CILCO, EEI, and the Illinois EPA entered into an agreement that was incorporated into Illinois’ mercury emission regulations. Under the regulations, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NOx and SO2 controls. Genco, AERG and EEI will begin putting into service equipment designed to reduce mercury emissions in 2009. When fully implemented, it is estimated that these rules will reduce mercury emissions 90%, NOx emissions 50% and SO2 emissions 70% by 2015 in Illinois.
Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities. Coal-fired power plants, however, are significant sources of carbon dioxide, a principal greenhouse gas. Six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the TVA, signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% to 5% voluntary decrease in carbon intensity bythe utility sector between 2002 and 2012. Currently, Ameren is considering various initiatives to comply with the MOU, including increased generation at nuclear and hydroelectric power plants, increased efficiency measures at our coal-fired units, and investments in renewable energy and carbon sequestration projects.
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.

The EPA has been conducting an enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The EPA’s inquiries focus on whether the best available emission control technology was or should have been used at such power plants when major maintenance or capital improvements were made.

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. 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. Resolution of the matters could have a material adverse impact on the future results of operations, financial position, or liquidity of Ameren, Genco, AERG and EEI. A resolution could result in increased capital expenditures, increased operations and maintenance expenses, and fines or penalties. We believe that any potential resolution would likely require the installation of control technology, some of which is already
90
planned for compliance with other regulatory requirements such as the Clean Air Interstate Rule and the Illinois mercury emission rules.
New environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation could result in a significant increase in capital expenditures and operating costs, decreased revenues, increased financing requirements, penalties and closure of power plants for UE, Genco, CILCO (through AERG) and EEI. Although costs incurred by UE would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar mechanism for recovery of costs by Genco, AERG or EEI in Illinois. We are unable to predict the ultimate impact of these matters on our results of operations, financial position or liquidity.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

The following table presents Ameren Corporation’s purchases of equity securities reportable under Item 703 of Regulation S-K:
 
Period
 
(a) Total Number
of Shares
(or Units)
Purchased(a)
  
(b) Average Price
Paid per Share
(or Unit)
  
(c) Total Number of Shares
 (or Units) Purchased as Part
of Publicly Announced Plans
 or Programs
  
(d) Maximum Number (or
Approximate Dollar Value) of
Shares (or Units) that May Yet
Be Purchased Under the Plans
or Programs 
July 1 – July 31, 2007                                      2,950  $
49.11
   -   - 
August 1 – August 31, 2007                                      -   
-
   -   - 
September 1 – September 30, 2007  4,625   
53.58
   -   - 
Total                                      7,575  $
51.84
   -   - 
 
Period
 
(a) Total Number
of Shares
(or Units) Purchased(a)
  
(b) Average Price
Paid per Share
(or Unit)
  (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs  (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs 
January 1 – January 31, 2008  12,000  $53.29   -   - 
February 1 – February 29, 2008  -   -   -   - 
March 1 – March 31, 2008                                      40,683   42.70   -   - 
Total                                      52,683  $45.11   -   - 

(a)  TheseIncluded in January were 12,000 shares of Ameren common stock were purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligation uponobligations for director compensation awards. Included in March were 40,683 shares of Ameren common stock purchased by Ameren from employee participants to satisfy participants’ tax obligations incurred by the exercise by employeesrelease of options issuedrestricted shares of Ameren common stock under Ameren’s Long-term Incentive Plan of 1998, as amended.1998. Ameren does not have any publicly announced equity securities repurchase plans or programs.
 
The following table presents CILCO’s purchases of equity securities reportable under Item 703 of Regulation S-K:
 
Period
 
(a) Total Number
of Shares
(or Units)
Purchased(a)
  
(b) Average Price
Paid per Share
(or Unit)
  
(c) Total Number of Shares
(or Units) Purchased as Part of Publicly Announced Plans or Programs
  
(d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs 
July 1 – July 31, 2007                                     11,000  $
100.00
   -   - 
August 1 – August 31, 2007                                     -   
-
   -   - 
September 1 – September 30, 2007  -   
-
   -   - 
Total                                     11,000  $
100.00
   -   - 

(a)  CILCO redeemed these shares of its 5.85% Class A preferred stock to satisfy the mandatory sinking fund redemption requirement for this series of preferred stock for 2007. 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 JulyJanuary 1 to September 30, 2007March 31, 2008 period.

83
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 indicated.previously filed are filed herewith.

Exhibit
Designation
Registrant(s)
Nature of Exhibit
Previously Filed as Exhibit to:
Instruments Defining Rights of Securities Holders, Including Indentures
4.1
Ameren
UE
UE Company Order dated April 8, 2008, establishing the 6.00% Senior Secured Notes due 2018 (including the global note)April 8, 2008 Form 8-K, Exhibits 4.3 and 4.5, File No. 1-2967
4.2
Ameren
UE
Supplemental Indenture dated as of April 1, 2008 by and between UE and The Bank of New York, as Trustee under the Indenture of Mortgage and Deed of Trust dated June 15, 1937, as amended, relating to UE First Mortgage Bonds, Senior Notes Series LL securing UE 6.00% Senior Secured Notes due 2018April 8, 2008 Form 8-K, Exhibit 4.7, File No. 1-2967
4.3
Ameren
Genco
Fifth Supplemental Indenture dated as of April 1, 2008, between Genco and The Bank of New York Trust Company, N.A., as Trustee, under the Indenture dated as of November 1, 2000, relating to Genco 7.00% Senior Notes, Series G due 2018, (including the form of notes)April 9, 2008 Form 8-K, Exhibit 4.2, File No. 333-56594
4.4
Ameren
IP
IP Company Order dated April 8, 2008, establishing the 6.25% Senior Secured Notes due 2018 (including forms of global and definitive notes)April 8, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004
4.5
Ameren
IP
Supplemental Indenture dated as of April 1, 2008 by and between IP and The Bank of New York Trust Company, N.A., as Trustee, under the General Mortgage Indenture and Deed of Trust dated as of November 1, 1992, relating to IP Mortgage Bonds, Senior Notes Series CC securing IP 6.25% Senior Secured Notes due 2018April 8, 2008 Form 8-K, Exhibit 4.9, File No. 1-3004
Material Contracts
10.1
Ameren
Genco
CILCORP
Ameren System Amended and Restated Non-Regulated Subsidiary Money Pool Agreement dated March 1, 2008
10.2
Ameren
CIPS
CILCORP
CILCO
IP
Amendment dated as of March 26, 2008 to Credit Agreement – Illinois Facility, dated as of July 14, 2006, among CIPS, CILCO, IP, AERG, CILCORP and JPMorgan Chase Bank, N.A., as administrative agentMarch 28, 2008 Form 8-K, Exhibit 10.1, File No. 1-14756
10.3
Ameren
CIPS
CILCORP
CILCO
IP
Amendment dated as of March 26, 2008 to Credit Agreement – Illinois Facility, dated as of February 9, 2007, among CIPS, CILCO, IP, AERG, CILCORP and JPMorgan Chase Bank, N.A., as administrative agentMarch 28, 2008 Form 8-K, Exhibit 10.2, File No. 1-14756
10.4
Ameren
Genco
Amended and Restated Power Supply Agreement between Genco and Marketing Company, dated March 28, 2008March 28, 2008 Form 8-K, Exhibit 10.3, File No. 1-14756
84
Exhibit DesignationRegistrant(s)Nature of ExhibitPreviously Filed as Exhibit to:
Statement re: Computation of Ratios
12.1AmerenAmeren’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.2UE
UE’s Statement of Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Stock Dividend Requirements
12.3CIPS
CIPS’ Statement of Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Stock Dividend Requirements
12.4GencoGenco’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.5CILCORPCILCORP’s Statement of Computation of Ratio of Earnings to Fixed Charges
12.6CILCO
CILCO’s Statement of Computation of Ratio of Earnings to Fixed Charges and
Combined Fixed Charges and Preferred Stock Dividend Requirements
91
Exhibit
Designation
Registrant(s)
Nature of Exhibit
12.7IP
IP’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined
Fixed Charges and Preferred Stock Dividend Requirements
Rule 13a-14(a) / 15d-14(a) Certifications
31.1AmerenRule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren
31.2AmerenRule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren
31.3UERule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE
31.4UERule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE
31.5CIPSRule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CIPS
31.6CIPSRule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CIPS
31.7GencoRule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco
31.8GencoRule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Genco
31.9CILCORPRule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCORP
31.10CILCORPRule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCORP
31.11CILCORule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCO
31.12CILCORule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCO
31.13IPRule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of IP
31.14IPRule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of IP
85
Exhibit DesignationRegistrant(s)Nature of ExhibitPreviously Filed as Exhibit to:
Section 1350 Certifications
32.1Ameren
Section 1350 Certification of Principal Executive Officer and Principal Financial
Officer of Ameren
32.2UE
Section 1350 Certification of Principal Executive Officer and Principal Financial
Officer of UE
32.3CIPS
Section 1350 Certification of Principal Executive Officer and Principal Financial
Officer of CIPS
32.4Genco
Section 1350 Certification of Principal Executive Officer and Principal Financial
Officer of Genco
32.5CILCORP
Section 1350 Certification of Principal Executive Officer and Principal Financial
Officer of CILCORP
32.6CILCO
Section 1350 Certification of Principal Executive Officer and Principal Financial
Officer of CILCO
32.7IP
Section 1350 Certification of Principal Executive Officer and Principal Financial
Officer of IP
Additional Exhibits
99.1
Ameren
CILCORP
CILCO
Amended and Restated Power Supply Agreement between AERG and Marketing Company, dated March 28, 2008March 28, 2008 Form 8-K, Exhibit 99.1, File No. 2-95569


9286

SIGNATURES

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
Senior Vice President and Controller                                                                   Chief Accounting Officer
            (Principal(Principal Accounting Officer)




UNION ELECTRIC COMPANY
(Registrant)
 
                           /s/ Martin J. Lyons                               
Martin J. Lyons
Senior Vice President and
        Principal Chief Accounting Officer
       (Principal(Principal Accounting Officer)




CENTRAL ILLINOIS PUBLIC SERVICE COMPANY
(Registrant)
 
                           /s/ Martin J. Lyons                               
Martin J. Lyons
Senior Vice President and Controller                                                                   Chief Accounting Officer
               (Principal(Principal Accounting Officer)





AMEREN ENERGY GENERATING COMPANY
(Registrant)

                           /s/ Martin J. Lyons                               
Martin J. Lyons
            �� Senior Vice President and ControllerChief Accounting Officer
              (Principal(Principal Accounting Officer)
87

 CILCORP INC.
(Registrant)
                           /s/ Martin J. Lyons                               
Martin J. Lyons
Senior Vice President and Chief Accounting Officer
(Principal Accounting Officer)

CENTRAL ILLINOIS LIGHT COMPANY
(Registrant)
                           /s/ Martin J. Lyons                               
Martin J. Lyons
Senior Vice President and Chief Accounting Officer
(Principal Accounting Officer)
ILLINOIS POWER COMPANY
(Registrant)
                           /s/ Martin J. Lyons                               
Martin J. Lyons
Senior Vice President and Chief Accounting Officer
(Principal Accounting Officer)
Date:  May 8, 2008





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88
               CILCORP INC.
               (Registrant)

                    /s/ Martin J. Lyons                   
                 Martin J. Lyons
Vice President and Controller
          (Principal Accounting Officer)




             CENTRAL ILLINOIS LIGHT COMPANY
(Registrant)
                    /s/ Martin J. Lyons                   
                 Martin J. Lyons
Vice President and Controller
        (Principal Accounting Officer)




                                                                                   ILLINOIS POWER COMPANY
               (Registrant)

                    /s/ Martin J. Lyons                   
                 Martin J. Lyons
Vice President and Controller
        (Principal Accounting Officer)



Date:  November 9, 2007


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