10-K 1 c23635e10vk.htm ANNUAL REPORT e10vk
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
     
(X)
  Annual report pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
for the fiscal year ended December 31, 2007
    OR
( )
  Transition report pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
for the transition period from        to       .
 
         
    Exact name of registrant as specified in its charter;
   
Commission
  State of Incorporation;
  IRS Employer
File Number
 
Address and Telephone Number
 
Identification No.
 
         
1-14756
  Ameren Corporation
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
  43-1723446
         
1-2967
  Union Electric Company
(Missouri Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
  43-0559760
         
1-3672
  Central Illinois Public Service Company
(Illinois Corporation)
607 East Adams Street
Springfield, Illinois 62739
(888) 789-2477
  37-0211380
         
333-56594
  Ameren Energy Generating Company
(Illinois Corporation)
1901 Chouteau Avenue
St. Louis, Missouri 63103
(314) 621-3222
  37-1395586
         
2-95569
  CILCORP Inc.
(Illinois Corporation)
300 Liberty Street
Peoria, Illinois 61602
(309) 677-5271
  37-1169387
         
1-2732
  Central Illinois Light Company
(Illinois Corporation)
300 Liberty Street
Peoria, Illinois 61602
(309) 677-5271
  37-0211050
         
1-3004
  Illinois Power Company
(Illinois Corporation)
370 South Main Street
Decatur, Illinois 62523
(217) 424-6600
  37-0344645


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Securities Registered Pursuant to Section 12(b) of the Securities Exchange Act of 1934:
 
Each of the following classes or series of securities is registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 and is listed on the New York Stock Exchange:
 
     
Registrant
 
Title of each class
 
Ameren Corporation
 
Common Stock, $0.01 par value per share and Preferred Share Purchase Rights
 
Securities Registered Pursuant to Section 12(g) of the Securities Exchange Act of 1934:
 
     
Registrant
 
Title of each class
 
Union Electric Company
 
Preferred Stock, cumulative, no par value,
Stated value $100 per share –
   
  $4.56 Series     $4.50 Series
   
  $4.00 Series     $3.50 Series
Central Illinois Public Service Company
 
Preferred Stock, cumulative, $100 par value per share –
   
  6.625% Series   4.90% Series
   
  5.16% Series     4.25% Series
   
  4.92% Series     4.00% Series
   
Depository Shares, each representing one-fourth of a share of 6.625% Preferred Stock, cumulative, $100 par value per share
Central Illinois Light Company
 
Preferred Stock, cumulative, $100 par value per share –
   
  4.50% Series
 
Ameren Energy Generating Company, CILCORP Inc., and Illinois Power Company do not have securities registered under either Section 12(b) or 12(g) of the Securities Exchange Act of 1934.
 
Indicate by check mark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.
 
                                 
Ameren Corporation
    Yes       (X )     No       )
Union Electric Company
    Yes       (X )     No       )
Central Illinois Public Service Company
    Yes       )     No       (X )
Ameren Energy Generating Company
    Yes       )     No       (X )
CILCORP Inc. 
    Yes       )     No       (X )
Central Illinois Light Company
    Yes       )     No       (X )
Illinois Power Company
    Yes       )     No       (X )
 
Indicate by check mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.
 
                                 
Ameren Corporation
    Yes       )     No       (X )
Union Electric Company
    Yes       )     No       (X )
Central Illinois Public Service Company
    Yes       )     No       (X )
Ameren Energy Generating Company
    Yes       (X )     No       )
CILCORP Inc. 
    Yes       (X )     No       )
Central Illinois Light Company
    Yes       )     No       (X )
Illinois Power Company
    Yes       (X )     No       )
 
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 ( )


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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
 
         
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 large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “accelerated filer”, “large accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.
 
                                 
    Large
                Smaller
 
    Accelerated
    Accelerated
    Non-Accelerated
    Reporting
 
    Filer     Filer     Filer     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 Corporation
    Yes       )     No       (X )
Union Electric Company
    Yes       )     No       (X )
Central Illinois Public Service Company
    Yes       )     No       (X )
Ameren Energy Generating Company
    Yes       )     No       (X )
CILCORP Inc. 
    Yes       )     No       (X )
Central Illinois Light Company
    Yes       )     No       (X )
Illinois Power Company
    Yes       )     No       (X )
 
As of June 29, 2007, Ameren Corporation had 207,510,090 shares of its $0.01 par value common stock outstanding. The aggregate market value of these shares of common stock (based upon the closing price of these shares on the New York Stock Exchange on that date) held by nonaffiliates was $10,170,069,511. The shares of common stock of the other registrants were held by affiliates as of June 29, 2007.
 
The number of shares outstanding of each registrant’s classes of common stock as of January 31, 2008, was as follows:
 
Ameren Corporation Common stock, $0.01 par value per share: 208,728,929
 
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 Development Company (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


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DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the definitive proxy statement of Ameren Corporation and portions of the definitive information statements of Union Electric Company, Central Illinois Public Service Company, and Central Illinois Light Company for the 2008 annual meetings of shareholders are incorporated by reference into Part III of this Form 10-K.
 
OMISSION OF CERTAIN INFORMATION
 
Ameren Energy Generating Company and CILCORP Inc. meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this form with the reduced disclosure format allowed under that General Instruction.
 
This combined Form 10-K 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 annual 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
 
    1  
    3  
 
  Business        
   
    4  
   
    5  
   
    5  
   
    7  
   
    10  
   
    10  
   
    11  
   
    13  
  Risk Factors     13  
  Unresolved Staff Comments     19  
  Properties     19  
  Legal Proceedings     22  
  Submission of Matters to a Vote of Security Holders     22  
    22  
 
PART II
  Market for Registrants’ Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities     25  
  Selected Financial Data     27  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     28  
   
    28  
   
    30  
   
    47  
   
    61  
   
    64  
   
    64  
   
    66  
  Quantitative and Qualitative Disclosures About Market Risk     67  
  Financial Statements and Supplementary Data     73  
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     165  
Item 9A and
Item 9A(T).
  Controls and Procedures     165  
  Other Information     165  
 
PART III
  Directors, Executive Officers and Corporate Governance     165  
  Executive Compensation     166  
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     166  
  Certain Relationships and Related Transactions and Director Independence     167  
  Principal Accountant Fees and Services     167  
           
PART IV            
  Exhibits and Financial Statement Schedules     168  
    172  
    180  
 Exhibit 10.31
 Exhibit 10.33
 Exhibit 12.1
 Exhibit 12.2
 Exhibit 12.3
 Exhibit 12.4
 Exhibit 12.5
 Exehibit 12.6
 Exhibit 12.7
 Exhibit 21.1
 Exhibit 23.1
 Exhibit 23.2
 Exehibit 23.3
 Exhibit 24.1
 Exhibit 24.2
 Exhibit 24.3
 Exhibit 24.4
 Exhibit 24.5
 Exhibit 24.6
 Exhibit 24.7
 Exhibit 31.1
 Exhibit 31.2
 Exhibit 31.3
 Exhibit 31.4
 Exhibit 31.5
 Exhibit 31.6
 Exhibit 31.7
 Exhibit 31.8
 Exhibit 31.9
 Exhibit 31.10
 Exhibit 31.11
 Exhibit 31.12
 Exhibit 31.13
 Exhibit 31.14
 Exhibit 32.1
 Exhibit 32.2
 Exhibit 32.3
 Exhibit 32.4
 Exhibit 32.5
 Exhibit 32.6
 Exhibit 32.7
 
This Form 10-K 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 3 of this Form 10-K 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.


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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 Resources Company subsidiary that procures fuel and natural gas and manages the related risks for the Ameren Companies.
Ameren – Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.
Ameren Companies – The individual registrants within the Ameren consolidated group.
Ameren Illinois Utilities – CIPS, IP and the rate-regulated electric and gas utility operations of CILCO.
Ameren Services – Ameren Services Company, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.
AMIL – The balancing authority area operated by Ameren, which includes the load of the Ameren Illinois Utilities and the generating assets of AERG and Genco.
AMMO – The balancing authority area operated by Ameren, which includes the load and generating assets of UE.
AMT – Alternative minimum tax.
APB – Accounting Principles Board.
ARB – Accounting Research Bulletin.
ARO – Asset retirement obligations.
Baseload  – The minimum amount of electric power delivered or required over a given period of time at a steady rate.
Btu – British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.
Capacity factor – A percentage measure that indicates how much of an electric power generating unit’s capacity was used during a specific period.
CILCO – Central Illinois Light Company, a CILCORP subsidiary that operates a rate-regulated electric transmission and distribution business, a non-rate-regulated electric generation business through AERG, and a rate-regulated natural gas transmission and distribution business, all in Illinois, as AmerenCILCO. CILCO owns all of the common stock of AERG.
CILCORP – CILCORP Inc., an Ameren Corporation subsidiary that operates as a holding company for CILCO and various non-rate-regulated subsidiaries.
CIPS – Central Illinois Public Service Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS.
CIPSCO – CIPSCO Inc., the former parent of CIPS.
CO2 – Carbon dioxide.
Cooling degree-days – The summation of positive differences between the mean daily temperature and a 65-degree Fahrenheit base. This statistic is useful for estimating electricity demand by residential and commercial customers for summer cooling.
CT – Combustion turbine electric generation equipment used primarily for peaking capacity.
CUB – Citizens Utility Board.
Development Company – Ameren Energy Development Company was an Ameren Energy Resources Company subsidiary and parent of Genco, Marketing Company, AFS, and Medina Valley. It was eliminated in an internal reorganization in February 2008.
DOE – Department of Energy, a U.S. government agency.
DRPlus – Ameren Corporation’s dividend reinvestment and direct stock purchase plan.
Dth (dekatherm) – one million BTUs of natural gas.
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. In February 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.
EITF – Emerging Issues Task Force, an organization designed to assist the FASB in improving financial reporting through the identification, discussion and resolution of financial issues in keeping with existing authoritative literature.
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.
ERISA – Employee Retirement Income Security Act of 1974, as amended.
Exchange Act – Securities Exchange Act of 1934, as amended.
FASB – Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.
FERC – The Federal Energy Regulatory Commission, a U.S. government agency.
FIN – FASB Interpretation.  An explanation intended to clarify accounting pronouncements previously issued by the FASB.
Fitch – Fitch Ratings, a credit rating agency.
FSP – FASB Staff Position.  A publication that provides application guidance on FASB literature.
FTRs – Financial transmission rights, financial instruments that entitle the holder to pay or receive compensation for certain congestion-related transmission charges between two designated points.
Fuelco – Fuelco LLC, a limited-liability company that provides nuclear fuel management and services to its members. The members are UE, Texas Generation Company LP, and Pacific Energy Fuels Company.


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GAAP – Generally accepted accounting principles in the United States.
Genco – Ameren Energy Generating Company, a Resources Company subsidiary that operates a non-rate-regulated electric generation business in Illinois and Missouri.
Gigawatthour – One thousand megawatthours.
Heating degree-days – The summation of negative differences between the mean daily temperature and a 65- degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter space heating for residential and commercial customers.
IBEW – International Brotherhood of Electrical Workers, a labor union.
ICC – Illinois Commerce Commission, a state agency that regulates the Illinois utility businesses and operations of CIPS, CILCO and IP.
Illinois Customer Choice Law – Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which provided for electric utility restructuring and introduced competition into the retail supply of electric energy in Illinois.
Illinois electric settlement agreement – A comprehensive settlement of issues in Illinois arising out of the end of ten years of frozen electric rates, effective January 2, 2007. The Illinois electric settlement agreement, which became effective on August 28, 2007, was designed to avoid new rate rollback and freeze legislation and legislation that would impose a tax on electric generation in Illinois. The settlement addresses the issue of future power procurement, and it includes a comprehensive rate relief and customer assistance program.
Illinois EPA – Illinois Environmental Protection Agency, a state government agency.
Illinois Regulated – A financial reporting segment consisting of the regulated electric and gas transmission and distribution businesses of CIPS, CILCO and IP.
IP – Illinois Power Company, an Ameren Corporation subsidiary. IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenIP.
IP LLC – Illinois Power Securitization Limited Liability Company, which is a special-purpose Delaware limited-liability company.
IP SPT – Illinois Power Special Purpose Trust, which was created as a subsidiary of IP LLC to issue TFNs as allowed under the Illinois Customer Choice Law. 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.
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.
ISRS – Infrastructure system replacement surcharge.  A cost recovery mechanism in Missouri that allows UE to recover gas infrastructure replacement costs from utility customers without a traditional rate case.
IUOE – International Union of Operating Engineers, a labor union.
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 Resources Company subsidiary that markets power for Genco, AERG and EEI.
Medina Valley – Ameren Energy Medina Valley Cogen LLC, a Resources Company subsidiary, which owns a 40-megawatt gas-fired electric generation plant.
Megawatthour – One thousand kilowatthours.
MGP – Manufactured gas plant.
MISO – Midwest Independent Transmission System Operator, Inc.
MISO Day Two Energy Market – A market that began operating on April 1, 2005. It uses market-based pricing, which incorporates transmission congestion and line losses, to compensate market participants for power.
Missouri Environmental Authority – Environmental Improvement and Energy Resources Authority of the state of Missouri, a governmental body authorized to finance environmental projects by issuing tax-exempt bonds and notes.
Missouri Regulated – A financial reporting segment consisting of all the operations of UE’s business, except for non-rate-regulated activities.
Money pool – Borrowing agreements among Ameren and its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools maintained for rate-regulated and non-rate-regulated businesses 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.
NCF&O – National Congress of Firemen and Oilers, a labor union.
NERC – North American Electric Reliability Corporation.
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.
Noranda – Noranda Aluminum, Inc.
NRC – Nuclear Regulatory Commission, a U.S. government agency.
NYMEX – New York Mercantile Exchange.
NYSE – New York Stock Exchange, Inc.
OATT – Open Access Transmission Tariff.
OCI – Other comprehensive income (loss) as defined by GAAP.
Off-system revenues – Revenues from nonnative load sales.
OTC – Over-the-counter.
PGA – Purchased Gas Adjustment tariffs, which allow the passing through of the actual cost of natural gas to utility customers.


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PJM – PJM Interconnection LLC.
PUHCA 1935 – The Public Utility Holding Company Act of 1935. It 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 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.
SERC – SERC Reliability Corporation, one of the regional electric reliability councils organized for coordinating the planning and operation of the nation’s bulk power supply.
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. Under the application of FIN 46R, IP does not consolidate IP SPT. Therefore, the obligation to IP SPT appears on IP’s balance sheet.
TVA – 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 natural gas transmission and distribution business in Missouri as AmerenUE.
 
 
FORWARD-LOOKING STATEMENTS
 
Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed under Risk Factors and elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:
 
•     regulatory or legislative actions, including changes in regulatory policies and ratemaking determinations, such as the outcome of pending 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 the new power procurement process in Illinois beginning 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 risk management strategies and the use of financial and derivative instruments;
•     prices for power in the Midwest, including forward prices;
•     business and economic conditions, including their impact on interest rates;
•     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;


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•     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 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.
 
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.
 
PART I
 
ITEM 1.   BUSINESS.
 
GENERAL
 
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren was formed in 1997 by the merger of UE and CIPSCO. Ameren acquired CILCORP in 2003 and IP in 2004. Ameren’s primary assets are the common stock of its subsidiaries, including UE, CIPS, Genco, CILCORP and IP. Ameren’s subsidiaries, which are separate, independent legal entities, 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 upon distributions made to it by its subsidiaries.
 
To streamline its organizational structure, during late 2007, Ameren dissolved, merged or consolidated various of its subsidiaries that were inactive or had minimal or ancillary business operations. Among the subsidiaries eliminated was Ameren Energy, Inc., which previously served as a power marketing and risk management agent for UE. UE now performs such functions for itself. To further streamline its organizational structure, in February 2008, Development Company was eliminated through merger and Ameren Energy Resources Company was merged into the newly created Resources Company. As a part of this internal reorganization, on February 29, 2008, UE’s 40% ownership interest and Development Company’s 40% ownership interest in EEI were transferred to this newly created Resources Company.
 
The following table presents our total employees at December 31, 2007:
 
         
         
Ameren(a)
    9,069  
UE
    3,665  
CIPS
    664  
Genco
    561  
CILCORP/CILCO
    598  
IP
    1,165  
         
 
(a) Total for Ameren includes Ameren registrant and nonregistrant subsidiaries.
 
The IBEW, the IUOE, the NCF&O and the Laborers and Gas Fitters labor unions collectively represent about 61% of Ameren’s total employees. They represent 72% of the employees at UE, 81% at CIPS, 72% at Genco, 70% at CILCORP, 70% at CILCO, and 90% at IP. All collective bargaining agreements that expired in 2007 have been renegotiated and ratified, with the exception of the benefits provisions contained in the agreements between IP and IBEW locals 51, 309, 702, and 1306. Bargaining over these benefits provisions continues at this time, with existing provisions remaining in effect. The majority of the renegotiated agreements have four- or five-year terms, and expire in 2011 and 2012. Four collective bargaining agreements between IP and the Laborers and Gas Fitters labor unions, covering approximately 127 employees, expire June 30, 2008.
 
For additional information about the development of our businesses, our business operations, and factors affecting our operations and financial position, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.


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BUSINESS SEGMENTS
 
Ameren has three reportable segments: Missouri Regulated, Illinois Regulated, and Non-rate-regulated Generation. CILCORP and CILCO have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. See Note 16 – Segment Information to our financial statements under Part II, Item 8, of this report for additional information on reporting segments.
 
RATES AND REGULATION
 
Rates
 
Rates that UE, CIPS, CILCO and IP are allowed to charge for their utility services are the single most important influence upon their and Ameren’s consolidated results of operations, financial position, and liquidity. The utility rates charged to UE, CIPS, CILCO and IP customers are determined by governmental entities. Decisions by these entities are influenced by many factors, including the cost of providing service, the quality of service, regulatory staff knowledge and experience, economic conditions, public policy, and social and political views. Decisions made by these governmental entities regarding rates could have a material impact on the results of operations, financial position, or liquidity of UE, CIPS, CILCORP, CILCO, IP and Ameren.
 
The ICC regulates rates and other matters for CIPS, CILCO and IP. The MoPSC regulates UE. FERC regulates UE, CIPS, Genco, CILCO, IP and EEI as to their ability to charge market-based rates for the sale and transmission of energy in interstate commerce and various other matters discussed below under General Regulatory Matters.
 
About 37% of Ameren’s electric and 13% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2007. About 41% of Ameren’s electric and 87% of its gas operating revenues were subject to regulation by the ICC in the year ended December 31, 2007. Wholesale revenues for UE, Genco and AERG are subject to FERC regulation, but not subject to direct MoPSC or ICC regulation.
 
Missouri Regulated
 
About 83% of UE’s electric and 100% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2007.
 
If certain criteria are met, UE’s gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer. The ISRS permits prudently incurred gas infrastructure replacement costs to be passed directly to the consumer.
 
A Missouri law enacted in July 2005 enables the MoPSC to put in place fuel and purchased power and environmental cost recovery mechanisms for Missouri’s electric utilities. The law also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental cost recovery mechanism, and prudency reviews, among other things. Rules for the fuel and purchased power cost recovery mechanism were approved by the MoPSC in September 2006 and became effective that year. Rules for the environmental cost recovery mechanism were approved by the MoPSC in February 2008 and will be effective once published in the Missouri Register. UE will not be able to utilize the cost recovery mechanisms until the MoPSC authorizes them as part of a rate case proceeding. UE was denied use of a fuel and purchased power cost recovery mechanism in its last electric rate order, in May 2007. UE plans to request use of a fuel and purchased power cost recovery mechanism and, potentially an environmental cost recovery mechanism, in its next electric rate case filing, expected in the second quarter of 2008.
 
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 and for a natural gas delivery rate increase. In March 2007, a stipulation and agreement approved by the MoPSC authorized 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 did not prevent UE from filing to recover gas infrastructure replacement costs through an ISRS during this three-year rate moratorium. In February 2008, the MoPSC approved UE’s petition requesting the establishment of an ISRS to recover annual revenues of $4 million effective March 29, 2008.
 
In May 2007, the MoPSC issued an order, which, as clarified, granted UE an increase in base rates for electric service, effective June 4, 2007. For further information on Missouri rate matters, including the Missouri law enabling fuel and purchased power and environmental cost recovery mechanisms, see Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 2 – Rate and Regulatory Matters, and Note 13 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
 
Illinois Regulated
 
The following table presents the approximate percentage of electric and gas operating revenues subject to regulation by the ICC for each of the Illinois Regulated companies for the year ended December 31, 2007:
 
                     
    Electric     Gas      
                     
CIPS
    100 %     100 %    
CILCORP/CILCO(a)
    58       100      
IP
    100       100      
                     
 
(a)  AERG’s revenues are not subject to ICC regulation.
 
If certain criteria are met, CIPS’, CILCO’s and IP’s gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer.


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Environmental adjustment rate riders authorized by the ICC permit the recovery of prudently incurred MGP remediation and litigation costs from CIPS’, CILCO’s and IP’s Illinois electric and natural gas utility customers. As a part of the order approving Ameren’s acquisition of IP, the ICC also approved a tariff rider that allows IP 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 is recoverable by IP from a trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy. At December 31, 2007, the trust fund balance was $22 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 recoverable through charges assessed to customers under the tariff rider.
 
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 on behalf of Ameren Illinois Utilities’ customers in the September 2006 power procurement auction in accordance with a January 2006 ICC order. See Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 2 – Rate and Regulatory Matters, and Note 13 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for further information on rate matters. This material summarizes actions taken by certain Illinois legislators, the Illinois governor, the Illinois attorney general, and others regarding the expiration of the rate freeze at the beginning of 2007, opposition to the 2006 power procurement auction, and the Illinois electric settlement agreement and establishment of the IPA, as well as electric and gas delivery service rate cases filed by CIPS, CILCO and IP in November 2007.
 
General Regulatory Matters
 
UE, CIPS, CILCO and IP must receive FERC approval to issue short-term debt securities and to conduct certain acquisitions, mergers and consolidations involving electric utility holding companies having a value in excess of $10 million. In addition, these Ameren utilities must receive authorization from the applicable state public utility regulatory agency to issue stock and long-term debt securities (with maturities of more than 12 months) and to conduct mergers, affiliate transactions, and various other activities. Genco, AERG and EEI are subject to FERC’s jurisdiction when they issue any securities.
 
Under PUHCA 2005, FERC and any state public utility regulatory agencies may access books and records of Ameren and its subsidiaries that are determined to be relevant to costs incurred by Ameren’s rate-regulated subsidiaries with respect to jurisdictional rates. PUHCA 2005 also permits Ameren, the ICC, or the MoPSC to request that FERC review cost allocations by Ameren Services to other Ameren companies.
 
Operation of UE’s Callaway nuclear plant is subject to regulation by the NRC. Its facility operating license expires on June 11, 2024. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. UE’s Osage hydroelectric plant and UE’s Taum Sauk pumped-storage hydroelectric plant, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other things, the general operation and maintenance of the projects. On March 30, 2007, FERC granted a new 40-year license for UE’s Osage hydroelectric plant and approved a settlement agreement among UE, the U.S. Department of the Interior, and various state agencies that was submitted in May 2005 in support of the license renewal. The license for UE’s Taum Sauk plant expires on June 30, 2010. UE intends to file with FERC an application for license renewal of the Taum Sauk facility no later than June 30, 2008. The Taum Sauk plant is currently out of service and being rebuilt due to a major breach of the upper reservoir in December 2005. UE’s Keokuk plant and its dam, in the Mississippi River between Hamilton, Illinois, and Keokuk, Iowa, are operated under open-ended authority granted by an Act of Congress in 1905.
 
For additional information on regulatory matters, see Note 2 – Rate and Regulatory Matters and Note 13 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, which include a discussion about the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric plant.
 
Environmental Matters
 
Certain of our operations are subject to federal, state, and local environmental statutes or regulations relating to the safety and health of personnel, the public, and the environment. These matters include identification, generation, storage, handling, transportation, disposal, record keeping, labeling, reporting, and emergency response in connection with hazardous and toxic materials, safety and health standards, and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants. Failure to comply with those statutes or regulations could have material adverse effects on us. We could be subject to criminal or civil penalties by regulatory agencies. We could be ordered to make payment to private parties by the courts. Except as indicated in this report, we believe that we are in material compliance with existing statutes and regulations.
 
For additional discussion of environmental matters, including NOx, SO2, and mercury emission reduction requirements and the December 2005 breach of the upper reservoir at UE’s Taum Sauk hydroelectric plant, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 13 –


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Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
 
SUPPLY FOR ELECTRIC POWER
 
Ameren operates an integrated transmission system that comprises the transmission assets of UE, CILCO, CIPS, and IP. Ameren also operates two balancing authority areas, AMMO (which includes UE) and AMIL (which includes CILCO, CIPS, IP, AERG and Genco). During 2007, the peak demand in AMMO was 8,606 MW and in AMIL was 9,386 MW. Factors that could cause us to purchase power include, among other things, absence of sufficient owned generation, plant outages, the failure of suppliers to meet their power supply obligations, extreme weather conditions, and the availability of power at a cost lower than the cost of generating it. The Ameren transmission system directly connects with 17 other balancing authority areas for the exchange of electric energy.
 
UE, CIPS, CILCO and IP are transmission-owning members of MISO, and they have transferred functional control of their systems to MISO. Transmission service on the UE, CIPS, CILCO and IP transmission systems is provided pursuant to the terms of the MISO OATT on file with FERC. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further information. EEI operates its own balancing authority area and its own transmission facilities in southern Illinois. The EEI transmission system is directly connected to MISO and TVA. EEI’s generating units are dispatched separately from those of UE, Genco and AERG.
 
The Ameren Companies and EEI are members of SERC, a regional electric reliability organization with NERC-delegated authority for proposing and enforcing reliability standards. SERC is responsible for the bulk electric power supply system in much of the southeastern United States, including all or portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, Oklahoma, Iowa, and Texas. The Ameren membership covers UE, CIPS, CILCO and IP.
 
Missouri Regulated
 
Factors that could cause UE to purchase power include, among other things, absence of sufficient owned generation, plant outages, the failure of suppliers to meet their power supply obligations, extreme weather conditions, and the availability of power at a cost lower than the cost of generating it.
 
UE’s electric supply is obtained primarily from its own generation. In March 2006, UE completed the purchase of three CT facilities, totaling 1,490 megawatts of capacity at a price of $292 million. These purchases were designed to help meet UE’s increased generating capacity needs and to provide UE with additional flexibility in determining when to add future baseload generating capacity. UE expects these CT facilities to satisfy demand growth until 2018 to 2020. However, due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE is actively studying future plant alternatives, including those that would use coal or nuclear fuel. See Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and Note 13 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report. UE filed in February 2008 an integrated resource plan with the MoPSC. The plan includes proposals to pursue energy efficiency programs, expand the role of renewable energy sources in UE’s overall generation mix, increase operational efficiency at existing power plants, and possibly retire some generating units that are older and less efficient.
 
Illinois Regulated
 
As of January 1, 2007, CIPS, CILCO and IP were required to obtain all electric supply requirements for customers who did not purchase electric supply from third-party suppliers through the Illinois reverse power procurement auction held in September 2006. CIPS, CILCO and IP entered into power supply contracts with the winning bidders, including their affiliate, Marketing Company. Under these contracts, the electric suppliers are responsible for providing to CIPS, CILCO and IP energy, capacity, certain transmission, volumetric risk management, and other services necessary for the Ameren Illinois Utilities to serve their customers at an all-inclusive fixed price with one-third of the supply contracts expiring in each of May 2008, 2009 and 2010. New electric rates for CIPS, CILCO and IP went into effect on January 2, 2007. The new rates reflected delivery service tariffs approved by the ICC in November 2006 and full cost recovery of power purchased on behalf of Ameren Illinois Utilities’ customers in the September 2006 reverse power procurement auction.
 
A portion of the electric power supply required for the Ameren Illinois Utilities to satisfy their distribution customers’ requirements is purchased from Marketing Company on behalf of Genco, AERG and EEI. As part of the Illinois electric settlement agreement reached in 2007, the reverse power procurement auction in Illinois was discontinued and will be replaced with a new process led by the IPA, beginning in 2009. In 2008, utilities will contract for necessary power and energy requirements not already supplied through the September 2006 auction contracts, primarily through a request-for-proposal process, subject to ICC review and approval. Existing supply contracts from the September 2006 reverse power procurement auction remain in place. Also as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of their around-the-clock power requirements during the period June 1, 2008, to December 31, 2012, at relevant market prices. These financial contracts do not include capacity, are not load-following products, and do not involve the physical delivery of energy. See Note 2 – Rate and Regulatory Matters and Note 12 – Related Party Transactions to our financial


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statements under Part II, Item 8, of this report for a discussion of the ICC-approved power procurement auction.
 
Non-rate-regulated Generation
 
Factors that could cause Marketing Company to purchase power for the Non-rate-regulated Generation business segment include, among other things, absence of sufficient owned generation, plant outages, the failure of suppliers to meet their power supply obligations, and extreme weather conditions.
 
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. All of Genco’s and AERG’s generating capacity now competes for the sale of energy and capacity in the competitive energy markets through Marketing Company. See Note 12 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information.
 
On December 31, 2005, EEI’s power supply contract with its affiliates, including UE, CIPS and IP, expired. EEI entered into a power supply agreement with Marketing Company whereby EEI sells 100% of its capacity and energy to Marketing Company at market-based prices. All of EEI’s generating capacity now competes for the sale of energy and capacity in the competitive energy markets through Marketing Company. See Note 12 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information.
 
The following table presents the source of electric generation by fuel type, excluding purchased power, for the years ended December 31, 2007, 2006 and 2005:
 
                                         
    Coal     Nuclear     Natural Gas     Hydroelectric     Oil  
                                         
Ameren:(a)
                                       
2007
    84 %     12 %     2 %     2 %     (b )%
2006
    85       13       1       1       (b )
2005
    86       10       1       2       1  
Missouri Regulated:
                                       
UE:
                                       
2007
    76 %     19 %     2 %     3 %     (b )%
2006
    77       20       1       2       (b )
2005
    80       16       1       3       (b )
Non-rate-regulated Generation:
                                       
Genco:
                                       
2007
    96 %     - %     4 %     - %     (b )%
2006
    97       -       2       -       1  
2005
    96       -       3       -       1  
CILCO (AERG):
                                       
2007
    99 %     - %     1 %     - %     (b )%
2006
    99       -       1       -       (b )
2005
    99       -       1       -       (b )
EEI:
                                       
2007
    100 %     - %     - %     - %     - %
2006
    100       -       (b )     -       -  
2005
    100       -       (b )     -       -  
Total Non-rate-regulated Generation:
                                       
2007
    98 %     - %     2 %     - %     (b )%
2006
    99       -       1       -       (b )
2005
    98       -       2       -       (b )
                                         
 
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Less than 1% of total fuel supply.


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The following table presents the cost of fuels for electric generation for the years ended December 31, 2007, 2006 and 2005.
 
                         
Cost of Fuels (Dollars per million Btus)   2007     2006     2005  
                         
Ameren:
                       
Coal(a)
  $ 1.399     $ 1.271     $ 1.153  
Nuclear
    0.490       0.434       0.421  
Natural gas(b)
    7.872       8.917       9.044  
Weighted average – all fuels(c)
  $ 1.437     $ 1.256     $ 1.184  
                         
Missouri Regulated:
                       
UE:
                       
Coal(a)
  $ 1.284     $ 1.084     $ 0.994  
Nuclear
    0.490       0.434       0.421  
Natural gas(b)
    7.580       8.625       8.825  
Weighted average – all fuels(c)
  $ 1.271     $ 1.035     $ 0.993  
Non-rate-regulated Generation:
                       
Genco:
                       
Coal(a)
  $ 1.717     $ 1.691     $ 1.589  
Natural gas(b)
    8.440       9.391       9.395  
Weighted average – all fuels(c)
  $ 1.939     $ 1.865     $ 1.808  
CILCO (AERG):
                       
Coal(a)
  $ 1.309     $ 1.419     $ 1.317  
Weighted average – all fuels(c)
  $ 1.450     $ 1.466     $ 1.396  
EEI:
                       
Coal(a)
  $ 1.329     $ 1.266     $ 1.053  
Total Non-rate-regulated Generation:
                       
Coal(a)
  $ 1.545     $ 1.513     $ 1.378  
Natural gas(b)
    8.440       9.385       9.384  
Weighted average – all fuels(c)
  $ 1.698     $ 1.613     $ 1.508  
                         
 
(a) The fuel cost for coal represents the cost of coal, costs for transportation, which includes diesel fuel adders, and cost of emission allowances.
(b) The fuel cost for natural gas represents the actual cost of natural gas and variable costs for transportation, storage, balancing, and fuel losses for delivery to the plant. In addition, the fixed costs for firm transportation and firm storage capacity are included in the calculation of fuel cost for the generating facilities.
(c) Represents all costs for fuels used in our electric generating facilities, to the extent applicable, including coal, nuclear, natural gas, oil, propane, tire chips, paint products, and handling. Oil, paint, propane, and tire chips are not individually listed in this table because their use is minimal.
 
Coal
 
UE, Genco, AERG and EEI have agreements in place to purchase a portion of their coal needs and to transport it to electric generating facilities through 2012. UE, Genco, AERG and EEI expect to enter into additional contracts to purchase coal. Coal supply agreements typically have an initial term of five years, with about 20% of the contracts expiring annually. Ameren burned 40.6 million (UE – 22.4 million, Genco – 10.1 million, AERG – 3.1 million, EEI – 5.0 million) tons of coal in 2007. See Part II, Item 7A – Quantitative and Qualitative Disclosures about Market Risk of this report for additional information about coal supply contracts.
 
About 94% of Ameren’s coal (UE – 97%, Genco – 88%, AERG – 92%, EEI – 100%) is purchased from the Powder River Basin in Wyoming. The remaining coal is typically purchased from the Illinois Basin. UE, Genco, AERG and EEI have a policy to maintain coal inventory consistent with their projected usage. Inventory may be adjusted because of uncertainties of supply due to potential work stoppages, delays in coal deliveries, equipment breakdowns, and other factors. As of December 31, 2007, coal inventories for UE, Genco, AERG and EEI were adequate and in excess of historical levels, but below 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.
 
Nuclear
 
Fuel assemblies for the 2008 fall refueling at UE’s Callaway nuclear plant will begin manufacture during the second quarter of 2008. Enriched uranium for such assemblies is already at the facility. UE also has agreements or inventories to price-hedge 87% of Callaway’s 2010 and 2011 refueling requirements. There is no refueling scheduled in 2009 or 2012. UE expects to enter into additional contracts to purchase nuclear fuel. UE is a member of Fuelco, which allows UE to join with other member


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companies to increase its purchasing power and opportunities for volume discounts. The Callaway nuclear plant normally requires refueling at 18-month intervals. The last refueling was completed in May 2007.
 
Natural Gas Supply for Power Generation
 
Ameren’s portfolio of natural gas supply resources includes firm transportation capacity and firm no-notice storage capacity leased from interstate pipelines to maintain gas deliveries to our gas-fired generating units throughout the year, especially during the summer peak demand. UE, Genco and EEI primarily use the interstate pipeline systems of Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, and Mississippi River Transmission Corporation to transport natural gas to generating units. In addition to physical transactions, Ameren uses financial instruments, including some in the NYMEX futures market and some in the OTC financial markets, to hedge the price paid for natural gas.
 
UE, Genco and EEI’s natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to their generating units. UE, Genco and EEI do this in two ways. They optimize transportation and storage options and minimize cost and price risk through various supply and price hedging agreements that allow them to maintain access to multiple gas pools, supply basins, and storage. As of December 31, 2007, UE had hedged about 25% of its required gas supply for generation in 2008 and Genco about 90%. As of December 31, 2007, EEI did not have any of its required gas supply for generation hedged for price risk.
 
NATURAL GAS SUPPLY FOR DISTRIBUTION
 
UE, CIPS, CILCO and IP are responsible for the purchase and delivery of natural gas to their gas utility customers. UE, CIPS, CILCO and IP develop and manage a portfolio of gas supply resources, including firm gas supply under term agreements with producers, interstate and intrastate firm transportation capacity, firm storage capacity leased from interstate pipelines, and on-system storage facilities to maintain gas deliveries to our customers throughout the year and especially during peak demand. UE, CIPS, CILCO and IP primarily use the Panhandle Eastern Pipe Line Company, the Trunkline Gas Company, the Natural Gas Pipeline Company of America, the Mississippi River Transmission Corporation, and the Texas Eastern Transmission Corporation interstate pipeline systems to transport natural gas to their systems. In addition to physical transactions, financial instruments, including those entered into in the NYMEX futures market and in the OTC financial markets, are used to hedge the price paid for natural gas. Prudently incurred natural gas purchase costs are passed on to customers of UE, CIPS, CILCO and IP in Illinois and Missouri under PGA clauses, subject to prudency review by the ICC and the MoPSC.
 
For additional information on our fuel and purchased power supply, see Results of Operations, Liquidity and Capital Resources and Effects of Inflation and Changing Prices in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report. Also see Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, of this report, Note 1 – Summary of Significant Accounting Policies, Note 7 – Derivative Financial Instruments, Note 12 – Related Party Transactions, Note 13 – Commitments and Contingencies, and Note 14 – Callaway Nuclear Plant to our financial statements under Part II, Item 8.
 
INDUSTRY ISSUES
 
We are facing issues common to the electric and gas utility industry and the non-rate-regulated electric generation industry. These issues include:
 
•     political and regulatory resistance to higher rates;
•     the potential for changes in laws, regulation, and policies at the state and federal level, including those resulting from election cycles;
•     the potential for more intense competition in generation and supply;
•     the potential for reregulation in some states, which could cause electric distribution companies to build generation facilities and to purchase less power from electric generating companies like Genco, AERG and EEI;
•     changes in the structure of the industry as a result of changes in federal and state laws, including the formation of non-rate-regulated generating entities and RTOs;
•     fluctuations in power prices due to the balance of supply and demand and fuel prices;
•     the availability of fuel and increases in prices;
•     the availability of labor and material and rising costs;
•     regulatory lag;
•     negative free cash flows due to rising investments and the regulatory framework;
•     continually developing and complex environmental laws, regulations and issues, including new air-quality standards, mercury regulations, and increasingly likely greenhouse gas limitations;
•     public concern about the siting of new facilities;
•     construction of power generation and transmission facilities;
•     proposals for programs to encourage or mandate energy efficiency and renewable sources of power;
•     public concerns about nuclear plant operation and decommissioning and the disposal of nuclear waste;
•     uncertainty in the credit markets; and
•     consolidation of electric and gas companies.
 
We are monitoring these issues. Except as otherwise noted in this report, we are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, and Outlook and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 2 – Rate and Regulatory Matters, and Note 13 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.


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OPERATING STATISTICS
 
The following tables present key electric and natural gas operating statistics for Ameren for the past three years.
 
                             
Electric Operating Statistics – Year Ended December 31,   2007     2006     2005      
                             
Electric Sales – kilowatthours (in millions):
                           
Missouri Regulated:
                           
Residential
    14,258       13,081       13,859      
Commercial
    14,766       14,075       14,539      
Industrial
    9,675       9,582       8,820      
Other
    759       739       781      
Native
    39,458       37,477       37,999      
Non-affiliate interchange sales
    10,984       3,132       3,549      
Affiliate interchange sales
    -       10,072       11,564      
Subtotal
    50,442       50,681       53,112      
Illinois Regulated:
                           
Residential
                           
Generation and delivery service
    11,857       11,476       11,711      
Commercial
                           
Generation and delivery service
    7,232       11,406       10,082      
Delivery service only
    5,178       269       204      
Industrial
                           
Generation and delivery service
    1,606       10,950       9,728      
Delivery service only
    11,199       2,349       3,275      
Other
    576       598       606      
Affiliate interchange sales
    -       -       2,055      
Subtotal
    37,648       37,048       37,661      
Non-rate-regulated Generation:
                           
Non-affiliate energy sales
    25,196       24,921       27,884      
Affiliate energy sales
    7,296       18,425       17,149      
Subtotal
    32,492       43,346       45,033      
Eliminate affiliate sales
    (7,296 )     (28,036 )     (30,768 )    
Eliminate Illinois Regulated/Non-rate-regulated Generation common customers
    (5,800 )     (2,024 )     (8,979 )    
Ameren Total
    107,486       101,015       96,059      
Electric Operating Revenues (in millions):
                           
Missouri Regulated:
                           
Residential
  $ 980     $ 899     $ 937      
Commercial
    839       796       814      
Industrial
    390       392       363      
Other
    111       104       109      
Native
    2,320       2,191       2,223      
Non-affiliate interchange sales
    466       263       253      
Affiliate interchange sales
    -       196       230      
Subtotal
  $ 2,786     $ 2,650     $ 2,706      
Illinois Regulated:
                           
Residential
                           
Generation and delivery service
  $ 1,055     $ 852     $ 868      
Commercial
                           
Generation and delivery service
    666       784       713      
Delivery service only
    54       3       -      
Industrial
                           
Generation and delivery service
    105       489       449      
Delivery service only
    24       2       -      
Other
    358       112       118      
Affiliate interchange sales
    -       -       36      
Subtotal
  $ 2,262     $ 2,242     $ 2,184      
                             


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Electric Operating Statistics – Year Ended December 31,   2007     2006     2005      
                             
Non-rate-regulated Generation:
                           
Non-affiliate energy sales
  $ 1,266     $ 1,032     $ 1,041      
Affiliate native energy sales
    495       662       614      
Affiliate other sales
    37       19       18      
Subtotal
  $ 1,798     $ 1,713     $ 1,673      
Eliminate affiliate sales
    (579 )     (1,020 )     (1,131 )    
Ameren Total
  $ 6,267     $ 5,585     $ 5,432      
Electric Generation – megawatthours (in millions):
                           
Missouri Regulated
    50.3       50.8       49.6      
Non-rate-regulated Generation:
                           
Genco
    17.4       15.4       14.2      
AERG
    5.3       6.7       6.0      
EEI
    8.1       8.3       7.9      
Medina Valley
    0.2       0.2       0.2      
Subtotal
    31.0       30.6       28.3      
Ameren Total
    81.3       81.4       77.9      
Price per ton of delivered coal (average)
  $ 25.20     $ 22.74     $ 21.31      
Source of energy supply:
                           
Coal
    68.7 %     65.8 %     66.0 %    
Gas
    1.8       0.9       1.1      
Oil
    -       0.7       0.8      
Nuclear
    9.4       9.7       8.1      
Hydroelectric
    1.6       0.9       1.3      
Purchased and interchanged, net
    18.5       22.0       22.7      
      100.0 %     100.0 %     100.0 %    
                             
 
                             
Gas Operating Statistics – Year Ended December 31,   2007     2006     2005      
                             
Gas Sales (millions of Dth)
                           
Missouri Regulated:
                           
Residential
    7       7       8      
Commercial
    4       3       4      
Industrial
    1       1       1      
Subtotal
    12       11       13      
Illinois Regulated:
                           
Residential
    59       55       59      
Commercial
    25       23       24      
Industrial
    10       13       13      
Subtotal
    94       91       96      
Other:
                           
Residential
    -       -       -      
Commercial
    -       -       -      
Industrial
    2       7       5      
Subtotal
    2       7       5      
Ameren Total
    108       109       114      
Natural Gas Operating Revenues (in millions)
                           
Missouri Regulated:
                           
Residential
  $ 108     $ 101     $ 111      
Commercial
    47       46       47      
Industrial
    12       13       13      
Other
    7       (2 )     11      
Subtotal
  $ 174     $ 158     $ 182      
                             

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Gas Operating Statistics – Year Ended December 31,   2007     2006     2005      
                             
Illinois Regulated:
                           
Residential
  $ 687     $ 690     $ 693      
Commercial
    272       271       273      
Industrial
    103       82       98      
Other
    39       53       54      
Subtotal
  $ 1,101     $ 1,096     $ 1,118      
Other:
                           
Residential
  $ -     $ -     $ -      
Commercial
    -       -       -      
Industrial
    16       60       72      
Other
    -       -       -      
Subtotal
  $ 16     $ 60     $ 72      
Eliminate affiliate sales
    (12 )     (19 )     (27 )    
Ameren Total
  $ 1,279     $ 1,295     $ 1,345      
Peak day throughput (thousands of Dth):
                           
UE
    155       124       161      
CIPS
    250       242       250      
CILCO
    401       356       370      
IP
    574       540       569      
Total peak day throughput
    1,380       1,262       1,350      
                             
 
AVAILABLE INFORMATION
 
The Ameren Companies make available free of charge through Ameren’s Internet Web site (www.ameren.com) their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably possible after such reports are electronically filed with, or furnished to, the SEC. These documents are also available through an Internet Web site maintained by the SEC (www.sec.gov).
 
The Ameren Companies also make available free of charge through Ameren’s Web site (www.ameren.com) the charters of Ameren’s board of directors’ audit and risk committee, human resources committee, nominating and corporate governance committee, nuclear oversight committee, and public policy committee; the corporate governance guidelines; a policy regarding communications to the board of directors; policies and procedures with respect to related-person transactions; a code of ethics for principal executive officers and senior financial officers; a code of business conduct applicable to all directors, officers and employees; and a director nomination policy that applies to the Ameren Companies.
 
These documents are also available in print upon written request to Ameren Corporation, Attention: Secretary, P.O. Box 66149, St. Louis, Missouri 63166-6149. The public may read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.
 
ITEM 1A. RISK FACTORS
 
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. Any such events that prevent UE, CIPS, CILCO or IP from recovering their respective costs or from earning appropriate returns on their investments could have a material adverse effect on 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 results of operations, financial position, or liquidity.
 
Our electric and gas utility rates are typically established in a regulatory proceeding that takes up to 11 months to complete. Rates established in those proceedings are primarily based on historical costs and include an allowed return on our investments by the regulator.
 
Our company, and the industry as a whole, is going through a period of rising costs, including increases in fuel, purchased power, labor and material costs, coupled with significant increases in capital, operation and maintenance and financing costs targeted at enhanced distribution system reliability and environmental compliance. Due to rising costs and the fact that our rates are primarily based on historical costs, UE, CIPS, CILCO and IP are not earning the allowed return established by their regulators (often referred to as regulatory lag). As a result, UE, CIPS, CILCO and IP expect to be entering a period where more frequent rate cases and

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requests for cost recovery mechanisms will be necessary. A period of increasing rates to our customers could result in additional regulatory, legislative, political, economic and competitive pressures that could have a material adverse effect on our results of operations, financial position, or liquidity.
 
Illinois
 
Pending Delivery Service Rate Cases
 
Due to inadequate recovery of costs and low returns on equity experienced in 2007 and expected in 2008, 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). 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 ICC has until the end of September 2008 to render a decision in these rate cases. It could materially reduce the amount of the increase requested, or even reduce rates.
 
Illinois Electric Settlement Agreement
 
Due to the magnitude of rate increases that went into effect following the end of a rate freeze on January 2, 2007 under the Illinois Customer Choice Law, various legislators supported legislation that would have reduced and frozen the electric rates of CIPS, CILCO and IP at the level in effect prior to January 2, 2007, or 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 that the Ameren Illinois Utilities are obligated to purchase under wholesale contracts, and would also have caused the Ameren Illinois Utilities to under-recover their delivery service costs until the ICC could approve higher delivery service rates.
 
In order to address these concerns, the Illinois electric settlement agreement was reached in 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 $1 billion over four years to fund both rate relief programs and a new power procurement agency, the IPA. Approximately $488 million of the funding is earmarked as rate relief for customers of the Ameren Illinois Utilities. The Ameren Illinois Utilities, Genco and AERG agreed to make aggregate contributions of $150 million over a four-year period, which commenced in 2007, with $60 million coming from the Ameren Illinois Utilities (CIPS – $21 million; CILCO – $11 million; IP – $28 million), $62 million from Genco and $28 million from AERG. The Illinois electric settlement agreement provides that if legislation freezing or reducing retail electric rates or imposing or authorizing a new tax, special assessment or fee on generation of electricity is enacted before August 1, 2011, then the remaining funding commitments will expire. Any funds set aside in support of those commitments will be refunded to the utilities and electric generators. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for additional information on the Illinois electric settlement agreement.
 
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, timely procurement of power and recovery of costs from the Ameren Illinois Utilities’ customers, and the ability of the Ameren Illinois Utilities or other electric distribution companies to lease or invest in generation facilities;
•     the extent to which the IPA may exercise its statutory authority to build 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 Illinois electric settlement agreement or to pay for or collateralize their obligations under future power purchase agreements;
•     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 meet a portion of Illinois’ total electric demand through the revised power procurement mechanism.
 
If, notwithstanding the Illinois electric settlement agreement, any decision is made or any 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 approved by the MoPSC authorized 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,


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2010. This agreement did not prevent UE from filing to recover infrastructure costs through an ISRS during this three-year rate moratorium. In February 2008, the MoPSC approved UE’s petition requesting the establishment of an ISRS to recover annual revenues of $1 million effective March 29, 2008.
 
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%. Certain aspects of the MoPSC decision have been appealed by UE, the Office of Public Counsel and the Missouri attorney general to the Court of Appeals for the Western District of Missouri. In its order, the MoPSC denied UE the use of a fuel and purchased power cost recovery mechanism. UE expects to incur significant increases in fuel and related transportation costs over the next three years. Without a rate recovery mechanism, UE may experience regulatory lag and not fully recover these costs.
 
Increased federal and state environmental regulation will cause UE, Genco, CILCO (through AERG) and EEI to incur large capital expenditures and 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. Such expenses, if excessive, could result in the closures of coal-fired generating plants.
 
About 61% of Ameren’s (UE – 54%, Genco – 60%, AERG – 95%, EEI – 95%) generating capacity is coal-fired. About 84% (UE – 76%, Genco – 96%, AERG – 99%, EEI – 100%) of its electric generation was produced by its coal-fired plants in 2007. The remaining electric generation comes from nuclear, gas-fired, hydroelectric, and oil-fired power plants. The EPA has 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, and significant capital expenditures. Missouri has adopted rules that substantially follow the federal regulations.
 
Illinois has adopted rules for mercury emissions that are significantly stricter than the federal regulations. In 2006, Genco, AERG, 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 will begin putting into service equipment designed to reduce mercury emissions.
 
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’s decision is subject to appeal, and it is uncertain how the EPA will respond. 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.
 
Ameren’s estimated capital costs based on current technology to comply with both the federal Clean Air Interstate Rule and Clean Air Mercury Rule and related state implementation plans range from $4 billion to $5 billion by 2017 (UE – $1.8 billion to $2.3 billion; Genco – $1.3 billion to $1.6 billion, AERG – $620 million to $760 million, EEI – $310 million to $410 million).
 
Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. Ameren believes that currently proposed legislation can be classified as moderate to extreme depending upon proposed CO2 emission limits, the timing of implementation of those limits, and the method of allocating allowances. The moderate scenarios include provisions for a “safety valve” that provides a ceiling price for emission allowance purchases. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities, but coal-fired power plants are significant sources of CO2, a principal greenhouse gas. Ameren’s current analysis shows that under some policy scenarios being considered in Congress, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the Midwest economy because of the region’s reliance on electricity generated by coal-fired power plants. When consumed natural gas emits about half the amount of CO2 as coal. As a result, economy-wide shifts favoring natural gas as a fuel source for electric generation also would affect the cost of 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 greenhouse gases would result in significant increases in capital expenditures and operating costs. Excessive costs to comply with future legislation or regulations might force Ameren and other similarly-situated electric power generators to close some coal-fired facilities. 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


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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 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 probably require the installation of emission control technology, some of which has already been 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, 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. We are unable to predict the ultimate impact of these matters on our results of operations, financial position or liquidity.
 
The construction of, and capital improvements to, UE’s, CIPS’, CILCO’s and IP’s electric and gas utility infrastructure as well as to Genco’s, CILCO’s (through AERG) and EEI’s non-rate-regulated power generation facilities involve substantial risks, particularly as the Ameren Companies expect to incur significant capital expenditures over the next five years and beyond for compliance with environmental regulations and to make significant investments in our utility infrastructure to improve overall system reliability. Should construction or capital improvement efforts be unsuccessful, it could have a material adverse impact on Ameren’s, UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s and IP’s results of operations, financial position, or liquidity.
 
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 and their non-rate-regulated power generation facilities. The Ameren Companies estimate that they will incur up to $10.6 billion (UE – up to $4.9 billion; CIPS – up to $505 million; Genco – up to $2.1 billion; CILCO (Illinois Regulated) – up to $425 million; CILCO (AERG) – up to $870 million; IP – up to $1.1 billion; EEI – up to $555 million, Other – up to $205 million) of capital expenditures during the period from 2008 through 2012, including construction expenditures, capitalized interest and allowance for funds used during construction (except for Genco, which has no allowance for funds used during construction), and estimated expenditures for compliance with EPA and state regulations regarding SO2 and NOx emissions and mercury emissions from coal-fired power plants. Costs for these types of projects continue to escalate.
 
Investment in Ameren’s regulated operations is expected to be recoverable from ratepayers. The recoverability of amounts expended in non-rate-regulated operations will depend on whether market prices for power adjust as a result of market conditions reflecting increased costs generally for generators.
 
The ability of the Ameren Companies to successfully complete those facilities currently under construction, and those projects yet to begin construction within established estimates is contingent upon many variables and are subject to substantial risks. These variables include, but are not limited to, project management expertise and escalating costs for materials, labor and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their contracts, changes in the scope and timing of projects, and other events beyond our control may occur that may materially affect the schedule, cost and performance of these projects. With respect to capital expenditures related to the installation of pollution control equipment, there is a risk that such electric generating plants would not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines or does not perform as expected. Should any such construction efforts be unsuccessful, the Ameren Companies could be subject to additional costs and the loss of their investment in the project or facility. The Ameren Companies may also be required to purchase additional electricity or gas to supply its customers until the projects are completed. All of these risks may have a material adverse effect on the Ameren Companies’ results of operations, financial position or liquidity.
 
Our counterparties may not meet their obligations to us.
 
We are exposed to the risk that counterparties to various arrangements who owe us money, energy, coal or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to replace or to sell the underlying commitment at then-current market prices. In such event, we might incur losses, or our results of operations, financial position, or liquidity could otherwise be adversely affected.
 
Certain of the Ameren Companies have obligations to other Ameren Companies or other Ameren subsidiaries because of transactions involving energy, coal, or other commodities and services and because of hedging transactions. If one Ameren entity failed to perform under any of these arrangements, other Ameren entities might incur losses. Their results of operations, financial position or liquidity could be adversely affected, resulting in such nondefaulting Ameren entity being unable to meet its obligations to unrelated third parties. Hedging activities are generally undertaken with a view


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to the Ameren-wide exposures. Some Ameren Companies may therefore be more or less hedged than if they were to engage in such hedging alone.
 
Increasing costs associated with our defined benefit retirement plans, health care plans, and other employee-related benefits may adversely affect our results of operations, financial position, or liquidity.
 
We offer defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates, and other actuarial matters have a significant impact on our earnings and funding requirements. In May 2007, the MoPSC issued an electric rate order that allows UE to recover through customer rates pension expense incurred under GAAP. Ameren expects to fund its pension plans at a level equal to the pension expense. Based on Ameren’s assumptions at December 31, 2007, and reflecting this pension funding policy, Ameren expects to make annual contributions of $40 million to $65 million in each of the next five years. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 65%, 8%, 11%, 5%, and 11%, respectively. These amounts are estimates. They may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions.
 
In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs of health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our defined benefit retirement plans, health care plans, and other employee benefits may adversely affect our results of operations, financial position, or liquidity.
 
UE’s, Genco’s, AERG’s, Medina Valley’s and EEI’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, liability, and increased purchased power costs.
 
UE, Genco, AERG, Medina Valley, and EEI own and operate coal-fired, nuclear, gas-fired, hydroelectric, and oil-fired generating facilities. Operation of electric generating facilities involves certain risks that can adversely affect energy output, efficiency levels, operating costs, and investment levels. Among these risks are:
 
•     increased prices for fuel and fuel transportation;
•     facility shutdowns due to operator error or a failure of equipment or processes;
•     longer-than-anticipated maintenance outages;
•     disruptions in the delivery of fuel and lack of adequate inventories;
•     lack of water for cooling plant operations;
•     labor disputes;
•     inability to comply with regulatory or permit requirements;
•     disruptions in the delivery of electricity;
•     increased capital expenditure requirements, including those due to environmental regulation;
•     unusual or adverse weather conditions, including drought; and
•     catastrophic events such as fires, explosions, floods, or other similar occurrences affecting electric generating facilities.
 
Even though agreements have been reached with state and federal authorities, the breach of the upper reservoir of UE’s Taum Sauk pumped-storage hydroelectric facility could continue to have an adverse effect on Ameren’s and UE’s results of operations, liquidity, and financial condition.
 
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 October 2006, FERC approved a stipulation and consent agreement between UE and FERC’s Office of Enforcement that resolves all issues arising from an investigation by FERC’s Office of Enforcement into alleged violations of license conditions and FERC regulations by UE, as the licensee of the Taum Sauk hydroelectric facility, that may have contributed to the breach of the upper reservoir. In November 2007, UE entered into a settlement agreement with the state of Missouri represented by the Missouri attorney general, the Missouri Conservation Commission and the Missouri Department of Natural Resources. The agreement resolved the state of Missouri’s lawsuit and claims for damages and other relief related to the December 2005 Taum Sauk breach. A business owners’ suit, which was filed in the Missouri Circuit Court of Reynolds County and remains pending, seeks damages relating to business losses and lost profit and unspecified punitive damages.
 
In February 2007, UE submitted to FERC an environmental report to rebuild the upper reservoir at Taum Sauk. UE received approval from FERC in August 2007 and hired a contractor in November 2007. The estimated cost to rebuild the upper reservoir is in the range of $450 million. The Taum Sauk plant is expected to be out of service at least through the fall of 2009.
 
As part of the settlement agreement with the state of Missouri, UE agreed not to attempt to recover from ratepayers in any future rate increase any in-kind or monetary payments to the state parties required by the settlement agreement or any costs incurred in the rebuilding of the upper reservoir (expressly excluding, however, enhancements, costs incurred due to circumstances or conditions that are currently not reasonably foreseeable, and costs that would have been incurred absent the December 2005 breach of the upper reservoir at the Taum Sauk plant).
 
If UE needs to purchase power because of the unavailability of the Taum Sauk facility during the rebuild of the upper reservoir, UE has committed to not seek these additional costs from ratepayers. The Taum Sauk incident is expected to reduce Ameren’s and UE’s 2008 pretax earnings by $15 million to $20 million. UE expects to face higher-cost sources of


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power, reduced interchange sales, and increased expenses, net of insurance reimbursement for replacement power costs.
 
UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. Until litigation has been resolved and the insurance review is completed, among other things, we are unable to determine the total impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.
 
The Missouri Parks Association and the Missouri Coalition for the Environment initiated legal proceedings over FERC’s decision to authorize the rebuilding of the upper reservoir at Taum Sauk. They seek injunctive and other relief. If they obtain injunctive relief, it could delay the construction of the rebuild and could delay the return of the plant to service.
 
Genco’s, AERG’s, and EEI’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risks.
 
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. All of Genco’s and AERG’s generating capacity now competes for the sale of energy and capacity in the competitive energy markets through Marketing Company.
 
On December 31, 2005, EEI’s power supply contract with its affiliates, including UE, CIPS and IP, expired. EEI entered into a power supply agreement with Marketing Company whereby EEI sells 100% of its capacity and energy to Marketing Company. All of EEI’s generating capacity now competes for the sale of energy and capacity in the competitive energy markets through Marketing Company.
 
To the extent that electricity generated by these facilities is not under a fixed-price contract to be sold, the revenues and results of operations of these non-rate-regulated subsidiaries generally depend on the prices that they can obtain for energy and capacity in Illinois and adjacent markets. Among the factors that could influence such prices (all of which are beyond our control to a significant degree) are:
 
•     current and future delivered market prices for natural gas, fuel oil, and coal and related transportation costs;
•     current and forward prices for the sale of electricity;
•     the extent of additional supplies of electric energy from current competitors or new market entrants;
•     the regulatory and pricing structures developed for evolving Midwest energy markets and the pace at which regional markets for energy and capacity develop outside of bilateral contracts;
•     changes enacted by the Illinois legislature, the ICC, the IPA or other government agencies with respect to power procurement procedures;
•     the potential for reregulation of generation in some states;
•     future pricing for, and availability of, services on transmission systems, and the effect of RTOs and export energy transmission constraints, which could limit our ability to sell energy in our markets;
•     the growth rate in electricity usage as a result of population changes, regional economic conditions, and the implementation of conservation programs;
•     climate conditions in the Midwest market; and
•     environmental laws and regulations.
 
UE’s ownership and operation of a nuclear generating facility creates business, financial, and waste disposal risks.
 
UE owns the Callaway nuclear plant, which represents about 12% of UE’s generation capacity and produced 19% of UE’s 2007 generation. Therefore, UE is subject to the risks of nuclear generation, which include the following:
 
•     potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;
•     the lack of a permanent waste storage site;
•     limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with UE or other U.S. nuclear operations;
•     uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate;
•     increased public and governmental concerns over the adequacy of security at nuclear power plants;
•     uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives (UE’s facility operating license for the Callaway nuclear plant expires in 2024);
•     limited availability of fuel supply; and
•     costly and extended outages for scheduled or unscheduled maintenance.
 
The NRC has broad authority under federal law to impose licensing and safety requirements for nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose fines, shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as UE’s. In addition, if a serious nuclear incident were to occur, it could have a material but indeterminable adverse effect on UE’s results of operations, financial position, or liquidity. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit.


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UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in the fall of 2008. During an outage, which occurs approximately every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, compared with non-outage years.
 
Operating performance at UE’s Callaway nuclear plant has resulted in unscheduled or extended outages. The operating performance at UE’s Callaway nuclear plant declined both in comparison with its past operating performance and in comparison with the operating performance of other nuclear plants in the United States. Ameren and UE are actively working to address the factors that led to the decline in Callaway’s operating performance. Management and supervision of operating personnel, equipment reliability, maintenance worker practices, engineering performance, training, and overall organizational effectiveness have been reviewed. Some actions have been taken. However, Ameren and UE cannot predict whether such efforts will result in an overall improvement of operations at Callaway. Any additional actions taken are expected to result in incremental operating costs at Callaway. Further, additional unscheduled or extended outages at Callaway could have a material adverse effect on the results of operations, financial position, or liquidity of Ameren and UE.
 
Our energy risk management strategies may not be effective in managing fuel and electricity procurement and pricing risks, which could result in unanticipated liabilities or increased volatility in our earnings and cash flows.
 
We are exposed to changes in market prices for natural gas, fuel, electricity, emission allowances, and transmission congestion. Prices for natural gas, fuel, electricity, and emission allowances may fluctuate substantially over relatively short periods of time and expose us to commodity price risk. We use long-term purchase and sales contracts in addition to derivatives such as forward contracts, futures contracts, options, and swaps to manage these risks. We attempt to manage our risk associated with these activities through enforcement of established risk limits and risk management procedures. We cannot ensure that these strategies will be successful in managing our pricing risk or that they will not result in net liabilities because of future volatility in these markets.
 
Although we routinely enter into contracts to hedge our exposure to the risks of demand, weather, and changes in commodity prices, we do not hedge the entire exposure of our operations from commodity price volatility. Furthermore, our ability to hedge our exposure to commodity price volatility depends on liquid commodity markets. To the extent that commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time. To the extent that unhedged positions exist, fluctuating commodity prices can adversely affect our results of operations, financial position, or liquidity.
 
Our facilities are considered critical energy infrastructure and may therefore be targets of acts of terrorism.
 
Like other electric and gas utilities, our power generation plants, fuel storage facilities, and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues or significant additional costs for repair, which could have a material adverse effect on our results of operations, financial position, or liquidity.
 
Our businesses are dependent on our ability to access the capital markets successfully. We may not have access to sufficient capital in the amounts and at the times needed.
 
We use short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements not satisfied by our operating cash flow, including requirements related to future environmental compliance. As a result of rising costs and increased capital and operations and maintenance expenditures, coupled with near-term regulatory lag, we expect to need more short-term and long-term debt financing. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and to expand our businesses. Our current credit ratings cause us to believe that we will continue to have access to the capital markets. However, events beyond our control, such as the recent collapse of the subprime mortgage market may create uncertainty that could increase our cost of capital or impair our ability to access the capital markets. Certain of the Ameren Companies rely in part on Ameren for access to capital. Circumstances that limit Ameren’s access to capital, including those relating to its other subsidiaries, could impair its ability to provide those Ameren Companies with needed capital. See the Credit Ratings section in Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for a discussion of credit rating changes in response to actions in Illinois with respect to the matter of power procurement commencing in 2007.
 
ITEM 1B. UNRESOLVED STAFF COMMENTS.
 
None.
 
ITEM 2. PROPERTIES.
 
For information on our principal properties, see the generating facilities table below. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for any planned additions, replacements or transfers. See also Note 5 – Long-term Debt and Equity Financings, and Note 13 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.


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The following table shows what our electric generating facilities and capability are anticipated to be at the time of our expected 2008 peak summer electrical demand:
 
                     
Primary Fuel Source   Plant   Location   Net Kilowatt Capability(a)      
Missouri Regulated:
UE:
                   
Coal
  Labadie   Franklin County, Mo.     2,406,000      
    Rush Island   Jefferson County, Mo.     1,181,000      
    Sioux   St. Charles County, Mo.     993,000      
    Meramec   St. Louis County, Mo.     842,000      
Total coal
            5,422,000      
Nuclear
  Callaway   Callaway County, Mo.     1,190,000      
Hydroelectric
  Osage   Lakeside, Mo.     234,000      
    Keokuk   Keokuk, Iowa     134,000      
Total hydroelectric
            368,000      
Pumped-storage
  Taum Sauk   Reynolds County, Mo.     (b )    
Oil (CTs)
  Fairgrounds   Jefferson City, Mo.     55,000      
    Meramec   St. Louis County, Mo.     59,000      
    Mexico   Mexico, Mo.     55,000      
    Moberly   Moberly, Mo.     55,000      
    Moreau   Jefferson City, Mo.     55,000      
    Howard Bend   St. Louis County, Mo.     43,000      
    Venice   Venice, Ill.     (c )    
Total oil
            322,000      
Natural gas (CTs)
  Peno Creek(d)(e)   Bowling Green, Mo.     188,000      
    Meramec(e)   St. Louis County, Mo.     53,000      
    Venice(e)   Venice, Ill.     492,000      
    Viaduct   Cape Girardeau, Mo.     25,000      
    Kirksville   Kirksville, Mo.     13,000      
    Audrain(d)   Audrain County, Mo.     608,000      
    Goose Creek   Piatt County, Ill.     438,000      
    Raccoon Creek   Clay County, Ill.     304,000      
    Pinckneyville   Pinckneyville, Ill.     316,000      
    Kinmundy(e)   Kinmundy, Ill.     216,000      
Total natural gas
            2,653,000      
Total UE
            9,955,000      
Non-rate-regulated Generation
                   
EEI(f):
                   
Coal
  Joppa Generating Station   Joppa, Ill.     1,000,000      
Natural gas (CTs)
  Joppa   Joppa, Ill.     55,000      
Total EEI
            1,055,000      
Genco:
                   
Coal
  Newton   Newton, Ill.     1,208,000      
    Coffeen   Coffeen, Ill.     900,000      
    Meredosia   Meredosia, Ill.     290,000      
    Hutsonville   Hutsonville, Ill.     151,000      
Total coal
            2,549,000      
Oil
  Meredosia   Meredosia, Ill.     156,000      
    Hutsonville (Diesel)   Hutsonville, Ill.     3,000      
Total oil
            159,000      
Natural gas (CTs)
  Grand Tower   Grand Tower, Ill.     511,000      
    Elgin(g)   Elgin, Ill.     460,000      
    Gibson City   Gibson City, Ill.     234,000      
    Joppa 7B(h)   Joppa, Ill.     162,000      
    Columbia(i)   Columbia, Mo.     140,000      
Total natural gas
            1,507,000      
Total Genco
            4,215,000      
                     


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Primary Fuel Source   Plant   Location   Net Kilowatt Capability(a)      
CILCO (through AERG):
                   
Coal
  E.D. Edwards   Bartonville, Ill.     744,000      
    Duck Creek   Canton, Ill.     330,000      
Total coal
            1,074,000      
Natural gas
  Sterling Avenue   Peoria, Ill.     30,000      
    Indian Trails   Pekin, Ill.     10,000      
Total natural gas
            40,000      
Oil
  CAT/Mapleton   Mapleton, Ill     9,000      
    CAT/Mossville   Mossville, Ill     6,000      
Total Oil
            15,000      
Total CILCO
            1,129,000      
Medina Valley:
                   
Natural gas
  Medina Valley   Mossville, Ill.     44,000      
Total Non-rate-regulated Generation
            6,443,000      
Total Ameren
            16,398,000      
                     
 
(a) “Net Kilowatt Capability” is the generating capacity available for dispatch from the facility into the electric transmission grid.
(b) This facility is out of service. It is not operational because of a breach of its upper reservoir in December 2005. Its 2005 peak summer electrical demand net kilowatt capability was 440,000. For additional information on the Taum Sauk incident, see Note 13 – Commitments and Contingencies under Part II, Item 8 of this report.
(c) This facility will be out of service in 2008.
(d) There are economic development lease arrangements applicable to these CTs.
(e) Certain of these CTs have the capability to operate on either oil or natural gas (dual fuel).
(f) Ameren owns an 80% interest in EEI. See Part I, Item 1, Business and Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.
(g) There is a tolling agreement in place for one of Elgin’s units (approximately 100 megawatts).
(h) These CTs are owned by Genco and were leased to Development Company prior to its elimination in an internal reorganization in February 2008. The operating lease was terminated in February 2008. Genco received rental payments under the lease in fixed monthly amounts that varied over the term of the lease and ranged from $0.8 million to $1.0 million.
(i) Genco has granted the city of Columbia, Missouri, options to purchase an undivided ownership interest in these facilities, which would result in a sale of up to 72 megawatts (about 50%) of the facilities. Columbia can exercise one option for 36 megawatts at the end of 2010 for a purchase price of $15.5 million, at the end of 2014 for a purchase price of $9.5 million, or at the end of 2020 for a purchase price of $4 million. The other option can be exercised for another 36 megawatts at the end of 2013 for a purchase price of $15.5 million, at the end of 2017 for a purchase price of $9.5 million, or at the end of 2023 for a purchase price of $4 million. A power purchase agreement pursuant to which Columbia is now purchasing up to 72 megawatts of capacity and energy generated by these facilities from Marketing Company will terminate if Columbia exercises the purchase options.
 
The following table presents electric and natural gas utility-related properties for UE, CIPS, CILCO and IP as of December 31, 2007:
 
                                     
    UE     CIPS     CILCO     IP      
                                     
Circuit miles of electric transmission lines
    2,931       2,306       331       1,853      
Circuit miles of electric distribution lines
    32,489       14,872       8,908       21,538      
Percent of circuit miles of electric distribution lines underground
    21 %     11 %     26 %     12 %    
Miles of natural gas transmission and distribution mains
    3,145       5,311       3,878       8,722      
Number of propane-air plants
    1       -       -       -      
Number of underground gas storage fields
    -       3       2       7      
Billion cubic feet of total working capacity of underground gas storage fields
    -       2       8       15      
                                     
 
Our other properties include office buildings, warehouses, garages, and repair shops.
 
With only a few exceptions, we have fee title to all principal plants and other units of property material to the operation of our businesses, and to the real property on which such facilities are located (subject to mortgage liens securing our outstanding first mortgage bond and credit facility indebtedness and to certain permitted liens and judgment liens). The exceptions are as follows:
 
•     A portion of UE’s Osage plant reservoir, certain facilities at UE’s Sioux plant, most of UE’s Peno Creek and Audrain CT facilities, Genco’s Columbia CT facility, AERG’s Indian Trails generating facility, Medina Valley’s generating facility, certain of Ameren’s substations, and most of our transmission and distribution lines and gas mains are situated on lands we occupy under leases, easements, franchises, licenses or permits.
•     The United States or the state of Missouri may own or may have paramount rights to certain lands lying in the bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River on which

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certain of UE’s generating and other properties are located.
•     The United States, the state of Illinois, the state of Iowa, or the city of Keokuk, Iowa, may own or may have paramount rights with respect to certain lands lying in the bed of the Mississippi River on which a portion of UE’s Keokuk plant is located.
 
Substantially all of the properties and plant of UE, CIPS, CILCO and IP are subject to the direct first liens of the indentures securing their mortgage bonds. In July 2006 and February 2007, AERG recorded open-ended mortgages and security agreements with respect to its E.D. Edwards and Duck Creek power plants. These plants serve as collateral to secure its obligations under multiyear, senior secured credit facilities entered into on July 14, 2006 and February 9, 2007, along with other Ameren subsidiaries. See Note 4 – Credit Facilities and Liquidity for details of the credit facilities.
 
UE has conveyed most of its Peno Creek CT facility to the city of Bowling Green, Missouri, and leased the facility back from the city through 2022. Under the terms of this capital lease, UE is responsible for all operation and maintenance responsibilities for the facility. Ownership of the facility will transfer to UE at the expiration of the lease, at which time the property and plant will become subject to the lien of any outstanding UE first mortgage bond indenture.
 
In March 2006, UE purchased a CT facility located in Audrain County, Missouri, from NRG Audrain Holding, LLC, and NRG Audrain Generating LLC, affiliates of NRG Energy, Inc. (collectively, NRG). As a part of this transaction, UE was assigned the rights of NRG as lessee of the CT facility under a long-term lease with Audrain County and assumed NRG’s obligations under the lease. The lease term will expire December 1, 2023. Under the terms of this capital lease, UE has all operation and maintenance responsibilities for the facility, and ownership of the facility will be transferred to UE at the expiration of the lease. When ownership of the Audrain County CT facility is transferred to UE by the county, the property and plant will become subject to the lien of any outstanding UE first mortgage bond indenture.
 
See Note 13 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for information on mechanics’ liens filed against CILCO’s Duck Creek plant.
 
ITEM 3. 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 December 2007, Caterpillar Inc., in conjunction with other industrial customers as a coalition, intervened in the 2007 rate cases filed by CILCO and IP with the ICC to modify their electric and natural gas delivery service rates. Douglas R. Oberhelman is an executive officer of Caterpillar Inc. and a member of the board of directors of Ameren. Mr. Oberhelman did not participate in Ameren Corporation’s board and committee deliberations relating to these matters.
 
For additional information on legal and administrative proceedings, see Rates and Regulation under Item 1, Business, and Item 1A, Risk Factors, above. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 2 – Rate and Regulatory Matters, and Note 13 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
 
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
 
There were no matters submitted to a vote of security holders during the fourth quarter of 2007 with respect to any of the Ameren Companies.
 
EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):
 
The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 2007, all positions and offices held with the Ameren Companies, tenure as officer, and business background for at least the last five years. Some executive officers hold multiple positions within the Ameren Companies; their titles are given in the description of their business experience.


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AMEREN CORPORATION:
 
         
    Age at
   
Name   12/31/07   Positions and Offices Held
 
Gary L. Rainwater
  61   Chairman, Chief Executive Officer, President, and Director
Rainwater began his career with UE in 1979 as an engineer and has held various positions with UE and other Ameren subsidiaries during his employment. Effective January 1, 2004, Rainwater was elected to serve as chairman and chief executive officer of Ameren, UE, and Ameren Services in addition to his position as president. At that time, he was elected chairman of CILCORP and CILCO in addition to his position as chief executive officer and president of those companies, which he assumed in 2003. In September 2004, upon Ameren’s acquisition of IP, Rainwater was elected chairman, chief executive officer, and president of IP. He held the position of chairman of CIPS, CILCO and IP after relinquishing his position as president in October 2004. Effective January 2007, Rainwater relinquished his positions as chairman, president, and chief executive officer of UE and Ameren Services and as chairman and chief executive officer of CIPS, CILCO and IP.
         
Warner L. Baxter
  46   Executive Vice President and Chief Financial Officer, Chairman, Chief Executive Officer, President, and Chief Financial Officer (Ameren Services)
Baxter joined UE in 1995. He was elected senior vice president, finance, of Ameren, UE, CIPS, Ameren Services, and Genco in 2001 and of CILCORP and CILCO in 2003. Baxter was elected to the position of executive vice president and chief financial officer of Ameren, UE, CIPS, Genco, CILCORP, CILCO, and Ameren Services in October 2003 and of IP in September 2004. He was elected chairman, chief executive officer, president, and chief financial officer of Ameren Services effective January 1, 2007.
         
Thomas R. Voss
  60   Executive Vice President and Chief Operating Officer,
Chairman, Chief Executive Officer, and President (UE)
Voss joined UE in 1969 as an engineer. He was elected senior vice president of UE, CIPS, and Ameren Services in 1999, of Genco in 2001, of CILCORP and CILCO in 2003, and of IP in 2004. In October 2003, Voss was elected president of Genco; he relinquished his presidency of this company in October 2004. He was elected to his present position at Ameren in January 2005. In May 2006, he was elected executive vice president of UE, CIPS, CILCORP, CILCO and IP. Effective January 1, 2007, Voss was elected chairman, chief executive officer, and president of UE. He relinquished his positions at CIPS, CILCORP, CILCO and IP in April 2007.
         
Donna K. Martin
  60   Senior Vice President and Chief Human Resources Officer
Martin joined Ameren Services in May 2002 as vice president, human resources. In February 2005, Martin was elected senior vice president and chief human resources officer of Ameren Services. She was elected to the same positions at Ameren in April 2007.
         
Steven R. Sullivan
  47   Senior Vice President, General Counsel, and Secretary
Sullivan joined Ameren, UE, CIPS, and Ameren Services in 1998 as vice president, general counsel, and secretary. He added those positions at Genco in 2000. In January 2003, Sullivan was elected vice president, general counsel, and secretary of CILCORP and CILCO. He was elected to his present position at Ameren, UE, CIPS, Genco, CILCORP, CILCO, and Ameren Services in October 2003, and at IP in September 2004.
         
Jerre E. Birdsong
  53   Vice President and Treasurer
Birdsong joined UE in 1977 and was elected treasurer of UE in 1993. He was elected treasurer of Ameren, CIPS, and Ameren Services in 1997, and Genco in 2000. In addition to being treasurer, in 2001 he was elected vice president at Ameren and at the subsidiaries listed above. Additionally, he was elected vice president and treasurer of CILCORP and CILCO in January 2003, and of IP in September 2004.
         
Martin J. Lyons
  41   Senior Vice President and Chief Accounting Officer
Lyons joined Ameren, UE, CIPS, Genco, and Ameren Services in 2001 as controller. He was elected controller of CILCORP and CILCO in January 2003. He was also elected vice president of Ameren, UE, CIPS, Genco, CILCORP, CILCO, and Ameren Services in February 2003 and vice president and controller of IP in September 2004. In July 2007, his position at UE was changed to vice president and principal accounting officer. Effective January 1, 2008, Lyons was elected senior vice president and chief accounting officer of the Ameren Companies and various other Ameren subsidiaries.


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    Age at
   
Name   12/31/07   Positions and Offices Held
 
SUBSIDIARIES:
         
Scott A. Cisel
  54   Chairman, Chief Executive Officer, and President
(CILCO, CIPS and IP)
Cisel joined CILCO in 1975. He was named senior vice president and leader of CILCO’s Sales and Marketing Business Unit in 2001. Cisel assumed the position of vice president and chief operating officer for CILCO in 2003, upon Ameren’s acquisition of that company. In 2004, Cisel was elected vice president of UE and president and chief operating officer of CIPS, CILCO and IP. Effective January 1, 2007, Cisel was elected chairman and chief executive officer of CIPS, CILCO and IP in addition to his position as president. He relinquished his position at UE in April 2007.
         
Daniel F. Cole
  54   Senior Vice President (CILCO, CIPS, CILCORP, IP and UE)
Cole joined UE in 1976 as an engineer. He was elected senior vice president of UE and Ameren Services in 1999, and of CIPS in 2001. He was elected president of Genco in 2001; he relinquished that position in 2003. He was elected senior vice president of CILCORP and CILCO in January 2003, and at IP in September 2004.
         
R. Alan Kelley
  55   Chairman, Chief Executive Officer, and President (Resources Company), and President (Genco)
Kelley joined UE in 1974 as an engineer. Kelley was elected senior vice president of Ameren Services in 1999 and of Genco in 2000. He was elected senior vice president of CILCO in January 2003, upon Ameren’s acquisition of that company. In October 2004, Kelley was elected president of Genco, and senior vice president of UE. Effective January 1, 2007, he was elected chairman, chief executive officer, and president of Ameren Energy Resources Company, and of its successor, Resources Company, in February 2008. Kelley relinquished his positions at UE, Ameren Services, and CILCO in April 2007.
         
Richard J. Mark
  52   Senior Vice President (UE)
Mark joined Ameren Services in January 2002 as vice president of customer service. In 2003, he was elected vice president of governmental policy and consumer affairs at Ameren Services, with responsibility for government affairs, economic development, and community relations for Ameren’s operating utility companies. He was elected senior vice president at UE in January 2005, with responsibility for Missouri energy delivery. In April 2007, Mark relinquished his position at Ameren Services.
         
Michael L. Moehn
  38   Vice President (Ameren Services)
Moehn joined Ameren Services as assistant controller in June 2000. He was named director of Ameren Services’ corporate modeling and transaction support in 2001 and elected vice president of business services for Resources Company in 2002. In 2004, Moehn was elected vice president of corporate planning for Ameren Services and relinquished his position at Resources Company.
         
Michael G. Mueller
  44   President (AFS)
Mueller joined UE in 1986 as an engineer. He was elected vice president of AFS in 2000 and president of AFS in 2004.
         
Charles D. Naslund
  55   Senior Vice President and Chief Nuclear Officer (UE)
Naslund joined UE in 1974. He was elected vice president of power operations at UE in 1999, vice president of Ameren Services in 2000, and vice president of nuclear operations at UE in September 2004. He relinquished his position at Ameren Services in 2001. Naslund was elected senior vice president and chief nuclear officer at UE in January 2005.
         
Andrew M. Serri
  46   President (Marketing Company)
Serri joined Marketing Company as vice president of sales and marketing in 2000. He was elected vice president of marketing and trading of Ameren Services in 2004, before being elected president of Marketing Company that same year. He relinquished his position at Ameren Services in 2007.
 
Officers are generally elected or appointed annually by the respective board of directors of each company, following the election of board members at the annual meetings of shareholders. No special arrangement or understanding exists between any of the above-named executive officers and the Ameren Companies, nor, to our knowledge, with any other person or persons pursuant to which any executive officer was selected as an officer. There are no family relationships among the officers. All of the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.


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PART II
 
ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
 
Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren began trading on January 2, 1998, following the merger of UE and CIPSCO on December 31, 1997. On April 27, 2007, Ameren submitted to the NYSE a certificate of its chief executive officer certifying that he was not aware of any violation by Ameren of NYSE corporate governance listing standards.
 
Ameren common shareholders of record totaled 74,419 on January 31, 2008. The following table presents the price ranges and dividends paid per Ameren common share for each quarter during 2007 and 2006.
 
                                     
    High     Low     Close     Dividends Paid      
                                     
AEE 2007 Quarter Ended:
                                   
March 31
  $ 55.00     $ 48.56     $ 50.30       631/2 ¢    
June 30
    55.00       48.23       49.01       631/2      
September 30
    53.89       47.10       52.50       631/2      
December 31
    54.74       51.81       54.21       631/2      
AEE 2006 Quarter Ended:
                                   
March 31
  $ 52.75     $ 48.51     $ 49.82       631/2 ¢    
June 30
    51.30       47.96       50.50       631/2      
September 30
    53.77       49.80       52.79       631/2      
December 31
    55.24       52.19       53.73       631/2      
                                     
 
There is no trading market for the common stock of UE, CIPS, Genco, CILCORP, CILCO or IP. Ameren holds all outstanding common stock of UE, CIPS, CILCORP and IP; Resources Company holds all outstanding common stock of Genco; and CILCORP holds all outstanding common stock of CILCO.
 
The following table sets forth the quarterly common stock dividend payments made by Ameren and its subsidiaries during 2007 and 2006:
 
                                                                         
            2007
                        2006
                 
            Quarter Ended                         Quarter Ended                  
Registrant     December 31     September 30     June 30     March 31       December 31     September 30     June 30     March 31      
                                                                         
UE
    $ 21     $ 119     $ 47     $ 80       $ 95     $ 70     $ 42     $ 42      
CIPS
      40       -       -       -         -       25       25       -      
Genco
      -       -       74       39         20       22       49       22      
CILCORP(a)
      -       -       -       -         -       -       -       50      
IP
      61       -       -       -         -       -       -       -      
Nonregistrants
      10       13       11       12         16       14       14       16      
Ameren
    $ 132     $ 132     $ 132     $ 131       $ 131     $ 131     $ 130     $ 130      
                                                                         
 
(a) CILCO paid dividends to CILCORP of $50 million in the quarterly period ended March 31, 2006, and $15 million in the quarterly period ended September 30, 2006.
 
On February 8, 2008, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 63.5 cents per share. The common share dividend is payable March 31, 2008, to stockholders of record on March 5, 2008.
 
For a discussion of restrictions on the Ameren Companies’ payment of dividends, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report.


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Purchases of Equity Securities
 
The following table presents Ameren’s purchases of equity securities reportable under Item 703 of Regulation S-K:
 
                                 
                      Maximum Number
 
                Total Number of Shares
    (or Approximate Dollar Value)
 
    Total Number
    Average Price
    (or Units) Purchased as
    of Shares That May Yet
 
    of Shares (or Units)
    Paid per Share
    Part of Publicly Announced
    Be Purchased Under the
 
Period   Purchased(a)     (or Unit)     Plans or Programs     Plans or Programs  
                                 
October 1 – 31, 2007
    -     $ -       -       -  
November 1 – 30, 2007
    3,350       54.11       -       -  
December 1 – 31, 2007
    1,700       54.04       -       -  
Total
    5,050     $ 54.09       -       -  
                                 
 
(a) Included in December were 1,000 shares of Ameren common stock purchased by Ameren in open-market transactions pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan in satisfaction of Ameren’s obligations for Ameren Board of Directors’ compensation awards. The remaining shares of Ameren common stock were purchased by Ameren in open-market transactions in satisfaction of Ameren’s obligations upon the exercise by employees of options issued under Ameren’s Long-term Incentive Plan of 1998. Ameren does not have any publicly announced equity securities repurchase plans or programs.
 
None of the other Ameren Companies purchased equity securities reportable under Item 703 of Regulation S-K during the period October 1 to December 31, 2007.
 
Performance Graph
 
The following graph shows Ameren’s cumulative total shareholder return during the five fiscal years ended December 31, 2007. The graph also shows the cumulative total returns of the S&P 500 Index and the Edison Electric Institute Index (EEI Index), which comprises most investor-owned electric utilities in the United States. The comparison assumes that $100 was invested on December 31, 2002, in Ameren common stock and in each of the indices shown, and it assumes that all of the dividends were reinvested.
[LINE GRAPH]
 
                                                     
December 31,   2002     2003     2004     2005     2006     2007      
                                                     
Ameren
  $ 100.00     $ 117.36     $ 135.10     $ 144.92     $ 159.57     $ 169.05      
S&P 500 Index
    100.00       128.69       142.69       149.70       173.33       182.85      
EEI Index
    100.00       123.48       151.68       176.03       212.57       247.77      
                                                     
 
Ameren management cautions that the stock price performance shown in the graph above should not be considered indicative of potential future stock price performance.


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Table of Contents

 
ITEM 6. SELECTED FINANCIAL DATA.
 
                                             
For the Years Ended December 31,
                                 
(In millions, except per share amounts)   2007     2006     2005     2004     2003      
Ameren:
                                           
Operating revenues(a)
  $ 7,546     $ 6,880     $ 6,780     $ 5,135     $ 4,574      
Operating income(a)
    1,342       1,173       1,284       1,078       1,090      
Net income(a)(b)
    618       547       606       530       524      
Common stock dividends
    527       522       511       479       410      
Earnings per share – basic(a)(b)
    2.98       2.66       3.02       2.84       3.25      
                   – diluted(a)(b)
    2.98       2.66       3.02       2.84       3.25      
Common stock dividends per share
    2.54       2.54       2.54       2.54       2.54      
As of December 31:
                                           
Total assets
  $ 20,728     $ 19,635     $ 18,171     $ 17,450     $ 14,236      
Long-term debt, excluding current maturities
    5,691       5,285       5,354       5,021       4,070      
Preferred stock subject to mandatory redemption
    16       17       19       20       21      
Total stockholders’ equity
    6,752       6,583       6,364       5,800       4,354      
UE:
                                           
Operating revenues
  $ 2,961     $ 2,823     $ 2,889     $ 2,640     $ 2,616      
Operating income
    590       620       640       673       787      
Net income after preferred stock dividends
    336       343       346       373       441      
Dividends to parent
    267       249       280       315       288      
As of December 31:
                                           
Total assets
  $ 10,903     $ 10,290     $ 9,277     $ 8,750     $ 8,517      
Long-term debt, excluding current maturities
    3,208       2,934       2,698       2,059       1,758      
Total stockholders’ equity
    3,601       3,153       3,016       2,996       2,923      
CIPS:
                                           
Operating revenues
  $ 1,005     $ 954     $ 934     $ 735     $ 742      
Operating income
    49       69       85       58       45      
Net income after preferred stock dividends
    14       35       41       29       26      
Dividends to parent
    40       50       35       75       62      
As of December 31:
                                           
Total assets
  $ 1,860     $ 1,855     $ 1,784     $ 1,615     $ 1,742      
Long-term debt, excluding current maturities
    456       471       410       430       485      
Total stockholders’ equity
    517       543       569       490       532      
Genco:
                                           
Operating revenues
  $ 872     $ 992     $ 1,038     $ 873     $ 785      
Operating income
    256       131       257       265       197      
Net income(b)
    125       49       97       107       75      
Dividends to parent
    113       113       88       66       36      
As of December 31:
                                           
Total assets
  $ 1,968     $ 1,850     $ 1,811     $ 1,955     $ 1,977      
Long-term debt, excluding current maturities
    474       474       474       473       698      
Subordinated intercompany notes
    126       163       197       283       411      
Total stockholder’s equity
    648       563       444       435       321      
CILCORP:
                                           
Operating revenues
  $ 990     $ 733     $ 747     $ 722     $ 926      
Operating income
    135       65       61       61       85      
Net income(b)
    47       19       3       10       23      
Dividends to parent
    -       50       30       18       27      
As of December 31:
                                           
Total assets
  $ 2,459     $ 2,250     $ 2,243     $ 2,156     $ 2,136      
Long-term debt, excluding current maturities
    537       542       534       623       669      
Preferred stock of subsidiary subject to mandatory redemption
    16       17       19       20       21      
Total stockholder’s equity
    715       671       663       548       478      
CILCO:
                                           
Operating revenues
  $ 990     $ 733     $ 742     $ 688     $ 839      
Operating income
    144       79       63       58       53      
Net income after preferred stock dividends(b)
    74       45       24       30       43      
Dividends to parent
    -       65       20       10       62      
As of December 31:
                                           
Total assets
  $ 1,862     $ 1,650     $ 1,557     $ 1,381     $ 1,324      
Long-term debt, excluding current maturities
    148       148       122       122       138      
                                             


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For the Years Ended December 31,
                                 
(In millions, except per share amounts)   2007     2006     2005     2004     2003      
Preferred stock subject to mandatory redemption
    16       17       19       20       21      
Total stockholders’ equity
    622       535       562       437       342      
IP:(c) Operating revenues
  $ 1,646     $ 1,694     $ 1,653     $ 1,539     $ 1,568      
Operating income
    109       141       202       216       178      
Net income after preferred stock dividends(b)
    24       55       95       137       115      
Dividends to parent
    61       -       76       -       -      
As of December 31:
                                           
Total assets
  $ 3,319     $ 3,212     $ 3,056     $ 3,117     $ 5,059      
Long-term debt, excluding current maturities
    1,014       772       704       713       1,435      
Long-term debt to IP SPT, excluding current maturities(d)
    2       92       184       278       345      
Total stockholders’ equity
    1,308       1,346       1,287       1,280       1,530      
                                             
 
(a) Includes amounts for IP since the acquisition date of September 30, 2004; includes amounts for CILCORP since the acquisition date of January 31, 2003; includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) For the years ended December 31, 2005 and 2003, net income included income (loss) from cumulative effect of change in accounting principle of $(22) million and $18 million or ($(0.11) and $0.11 per share) for Ameren, $(16) million and $18 million for Genco, $(2) million and $4 million for CILCORP, $(2) million and $24 million for CILCO, and $- and $(2) million for IP.
(c) Includes 2004 combined financial data under ownership by Ameren and IP’s former ultimate parent, Dynegy.
(d) Effective December 31, 2003, IP SPT was deconsolidated from IP’s financial statements in conjunction with the adoption of FIN 46R, “Variable Interest Entities.” See Note 1 – Summary of Significant Accounting Policies, Variable-interest Entities, to our financial statements under Part II, Item 8, of this report for further information.
 
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
 
OVERVIEW
 
Ameren Executive Summary
 
Operations
 
In 2007, we accomplished some key objectives that we believe will bring significant long-term benefits to our customers and shareholders. In Illinois, the Ameren Illinois Utilities, Genco and AERG reached a comprehensive settlement that will help Ameren Illinois Utilities customers’ transition to higher electric rates and bring stability to the power procurement process. Rate rollback and freeze legislation in response to higher electric rates in Illinois, driven by deregulation of that market, would have had severe negative operational and financial consequences for Ameren, CIPS, CILCORP, CILCO and IP, as well as significantly impacted the Ameren Illinois Utilities’ ability to deliver reliable service to their customers. Major stakeholders involved with this issue, including the Illinois governor’s office, leaders of the House of Representatives and Senate in Illinois, and the Illinois attorney general’s office, agreed to the Illinois electric settlement agreement. As a result, the Illinois electric settlement agreement provides significantly greater levels of legislative, regulatory and legal certainty. It also enables a viable competitive power supply market to continue to develop in Illinois.
 
In late 2007, the Ameren Illinois Utilities requested to increase annual revenues for electric and gas delivery services by $247 million in the aggregate. The Ameren Illinois Utilities also requested ICC approval to implement rate adjustment mechanisms for bad debt expenses, certain electric infrastructure investments and the decoupling of natural gas revenues from sales volumes. The ICC has until the end of September 2008 to render a decision in these rate cases. UE also expects to file an electric rate increase request in Missouri in the second quarter of 2008 to mitigate higher cost and investment levels. Constructive outcomes for the rate cases in Illinois and Missouri are very important to UE and the Ameren Illinois Utilities. UE, CIPS, CILCO and IP need to recover their costs to continue investing in their energy infrastructure on a timely basis and provide their customers with safe and reliable service.
 
In Missouri, we were able to settle all state and federal issues associated with the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. UE has begun rebuilding the upper reservoir and expects the plant to be out of service until the fall of 2009, if not longer. The cost of the rebuild is expected to be in the range of $450 million. UE believes that substantially all damages and liabilities (but not fines and 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 or replacement power, up to $8 million annually, will be covered by insurance.
 
In February 2008, UE filed an integrated resource plan with the MoPSC. The integrated resource plan outlines support for energy efficiency measures to reduce demand growth, expand renewable generation and increase existing power plant efficiency. Some of UE’s coal-fired power plants are aging, and an analysis will be completed in 2009 to determine which units are likely candidates for retirement. The integrated resource plan concludes that a new baseload plant is expected to be required in our regulated Missouri operations in the 2018 to 2020 timeframe. For that reason, UE is preserving the option to develop additional nuclear generation, while researching clean coal and carbon sequestration technologies. UE expects to file in 2008 a

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construction and operating license application with the NRC for a new unit at UE’s Callaway nuclear plant site. While this filing will not represent a final decision, it preserves the option to build a nuclear unit. UE will not proceed on any new baseload power plant unless construction costs are recoverable through rates in Missouri. In addition to considering a new unit at Callaway, UE also began the process in 2008 to extend through 2044 the existing unit license at Callaway, which currently expires in 2024.
 
In 2007, Ameren’s Non-rate-regulated Generation business segment continued to execute its plan for investing in its power plants to improve their future productivity, as well as to effectively market their generation, consistent with their risk management framework. Non-rate-regulated Generation has also begun significant work on some of its coal-fired plants to begin installing additional environmental controls.
 
Earnings
 
Ameren reported net income of $618 million, or $2.98 per share, for 2007 compared to net income of $547 million, or $2.66 per share, in 2006. Earnings in 2007 principally benefited from, among other things, higher-priced power sales contracts in Ameren’s Non-rate-regulated Generation business segment, the June 2007 implementation of a Missouri electric rate order and greater demand for electricity and natural gas caused by warmer summer and cooler winter weather than in 2006.
 
Ameren’s 2007 earnings were reduced by 21 cents per share for the net cost of the Illinois electric settlement agreement. Storm-related costs in 2006 reduced net income by 26 cents per share. The impact of storm restoration efforts was less in 2007, but still significant. Ameren’s 2007 earnings were reduced by 9 cents per share as a result of the cost of restoration efforts associated with a severe ice storm in January 2007. In addition, a FERC order retroactively adjusting prior years’ RTO costs reduced 2007 earnings by 6 cents per share. Other items that unfavorably impacted earnings were, among other things, higher fuel costs and bad debt expenses, lower emission allowance sales, increased expenditures to improve reliability in Ameren’s regulated business segments and higher depreciation and financing costs due to greater energy infrastructure investment. In addition, there were fewer sales of noncore properties in 2007.
 
Liquidity
 
Cash flows from operations of $1.1 billion in 2007 at Ameren, along with other funds, were used to pay dividends to common shareholders of $527 million and to fund capital expenditures of $1.4 billion. Financing activities in 2007 primarily consisted of refinancing debt and funding capital investment with borrowings under credit facilities.
 
Outlook
 
Over the next few years, we expect to make significant investments in our electric and gas infrastructure to improve the reliability of our distribution systems and to comply with environmental regulations. These investments are consistent with our customers’ and regulators’ expectations. We expect that earnings growth in our rate-regulated businesses will come from updating existing customer rates to better reflect these investments and the current levels of costs UE and the Ameren Illinois Utilities are experiencing. However, in the near-term, the returns experienced in 2007 and expected to be experienced in 2008 by UE and the Ameren Illinois Utilities are below levels allowed by the respective state utility commissions in their last rate cases. That is due to the fact that UE’s and the Ameren Illinois Utilities’ current rates are significantly below the cost and investment levels they are incurring in their businesses today. In a rising cost environment, earnings will be negatively impacted due to regulatory lag until appropriate levels of rate relief are granted. Our plan to address this shortfall and to achieve earnings growth is very straightforward: UE and the Ameren Illinois Utilities will file more frequent rate cases requesting moderate rate increases, as well as seek appropriate cost recovery mechanisms to mitigate regulatory lag.
 
In addition, we will continue to optimize Ameren’s Non-rate-regulated Generation’s assets, focusing on improving the output of these plants and related energy marketing. While we currently believe that rising costs, including fuel, depreciation and financing costs will largely offset these productivity gains, we believe our plants will be well positioned for earnings growth in the future should energy and capacity prices improve.
 
The EPA has issued more stringent emission limits on all coal-fired power plants. Between 2008 and 2017 Ameren expects that certain Ameren Companies will be required to invest between $4 billion and $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 45% of this investment will be in Ameren’s regulated UE operations, and it is therefore expected to be recoverable from ratepayers.
 
Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. 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. We support public policy that will result in substantial reductions in CO2 emission. However, CO2 policy must take into account the profound economic implications of moving toward a carbon constrained economy. We believe any legislation should include the following principles in order to limit the negative impact on our customers, economy and company:
 
•     Recognition of the significant economic impact of greenhouse gas policies on consumers and businesses in regions now dependent on coal.
•     Compliance timelines consistent with development of advanced technologies.


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•     Provisions for significant research funding.
•     Provisions for an effective cap and trade program.
•     Allowances for greenhouse gas offsets, such as reforestation.
•     Removal of potential regulatory and financial barriers to improvement in existing infrastructure.
•     Broad-based CO2 regulation across all industries.
•     A national and global policy approach.
 
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 Ameren Companies will incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and gas utility infrastructure to improve overall system reliability. Expenditures not funded with operating cash flows are expected to be funded primarily with debt.
 
General
 
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois, as discussed below. Dividends on Ameren’s common stock are dependent on distributions made to it by its subsidiaries. See Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report for a detailed description of our principal subsidiaries.
 
•     UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. Before May 2, 2005, UE also operated those businesses in Illinois.
•     CIPS operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.
•     Genco operates a non-rate-regulated electric generation business.
•     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.
 
The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. All tabular dollar amounts are expressed in millions, unless otherwise indicated.
 
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 year.
 
RESULTS OF OPERATIONS
 
Earnings Summary
 
Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. The vast majority of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. Non-rate-regulated Generation sales are also subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We do not currently have a fuel and purchased power cost recovery mechanism in Missouri for our electric utility business. We do have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery businesses and purchased power cost recovery mechanisms for our Illinois electric delivery businesses. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, for a discussion of pending and recently decided rate cases and the Illinois electric settlement 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 was $618 million ($2.98 per share) for 2007, $547 million ($2.66 per share) for 2006, and $606 million ($3.02 per share) for 2005. In 2005, Ameren’s net income included a net cumulative effect aftertax loss of $22 million (11 cents per share) associated with recording liabilities for conditional AROs as a result of our adoption of FIN 47, “Accounting for Conditional Asset Retirement Obligations.” The net cumulative effect aftertax


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loss of adopting FIN 47 is presented below for the applicable registrant companies:
 
             
    2005 Net Cumulative
   
    Effect Aftertax Loss    
             
Ameren(a)
  $ 22      
Genco
    16      
CILCORP
    2      
CILCO
    2      
             
 
(a)  Includes amounts for EEI.
 
Ameren’s net income increased $71 million and earnings per share increased 32 cents in 2007 compared with 2006.
 
Compared with 2006 earnings, 2007 earnings were favorably affected by:
 
•     higher margins 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;
•     favorable weather conditions (estimated at 14 cents per share);
•     the absence of costs in 2007 that were incurred in 2006 related to the reservoir breach at UE’s Taum Sauk plant (15 cents per share);
•     higher electric rates, lower depreciation expense, decreased income tax expense and $5 million in SO2 emission allowance sales in the Missouri Regulated segment pursuant to the MoPSC electric rate order for UE issued in May 2007 (21 cents per share); and
•     decreased costs associated with outages caused by severe storms (17 cents per share).
 
Compared with 2006 earnings, 2007 earnings were negatively affected by:
 
•     electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities’ electric customers under the Illinois electric settlement agreement (21 cents per share) described in Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report;
•     the combined effect of the elimination of the Ameren Illinois Utilities’ bundled tariffs, implementation of new delivery service tariffs effective January 2, 2007, and the expiration of below-market power supply contracts;
•     higher fuel and related transportation prices (31 cents per share);
•     higher labor and employee benefit costs (18 cents per share);
•     increased depreciation and amortization expense (13 cents per share);
•     higher financing costs (17 cents per share);
•     a planned refueling and maintenance outage at UE’s Callaway nuclear plant net of an unplanned outage at Callaway in 2006 (9 cents per share);
•     increases in distribution system reliability expenditures (15 cents per share);
•     higher bad debt expenses (8 cents per share);
•     lower emission allowance sales (16 cents per share); and
•     reduced gains on the sale of noncore properties, including leveraged leases (15 cents per share).
 
The cents per share information presented above is based on average shares outstanding in 2006.
 
Ameren’s net income before cumulative effect of the adoption of FIN 47 decreased $81 million and earnings per share decreased 47 cents in 2006 compared with 2005.
 
Compared with 2005 earnings, 2006 earnings were negatively affected by:
 
•     costs and lost electric margins associated with outages caused by severe storms (26 cents per share);
•     milder weather conditions (estimated at 17 cents per share);
•     costs associated with the reservoir breach at UE’s Taum Sauk plant (20 cents per share);
•     an unscheduled outage at UE’s Callaway nuclear plant (7 cents per share);
•     higher depreciation expense (11 cents per share);
•     increased taxes other than income taxes (8 cents per share);
•     contributions made in association with the Illinois Customer Elect electric rate increase phase-in plan (5 cents per share);
•     increased fuel and purchased power costs; and
•     higher financing costs.
 
An increase in the number of common shares outstanding also reduced Ameren’s earnings per share in 2006 compared with 2005.
 
Compared with 2005, earnings in 2006 were favorably affected by:
 
•     higher margins on interchange sales (33 cents per share);
•     increased net gains on the sale of noncore properties, including leveraged leases, compared with 2005 (9 cents per share);
•     the lack of a refueling and maintenance outage at UE’s Callaway nuclear plant in 2006 (18 cents per share);
•     increased sales of emission allowances (5 cents per share); and
•     other factors including improved plant operations, lack of coal conservation efforts, industrial electric customers switching back to the Ameren Illinois Utilities, lower bad debt expenses, and organic growth.
 
The cents per share information presented above is based on average shares outstanding in 2005.


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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 years ended December 31, 2007, 2006 and 2005:
 
                             
    2007     2006     2005      
                             
Net income:
                           
UE(a)
  $ 336     $ 343     $ 346      
CIPS
    14       35       41      
Genco
    125       49       97      
CILCORP
    47       19       3      
IP
    24       55       95      
Other(b)
    72       46       24      
Ameren net income
  $ 618     $ 547     $ 606      
                             
 
(a) Includes earnings from a non-rate-regulated 40% interest in EEI.
(b) Includes net income from non-rate-regulated operations and a 40% interest in EEI held by Development Company, corporate general and administrative expenses, gains on sales of noncore assets, and intercompany eliminations.
 
Below is a table of income statement components by segment for the years ended December 31, 2007, 2006 and 2005:
 
                                             
                Non-rate-
    Other /
           
    Missouri
    Illinois     regulated
    Intersegment            
2007   Regulated     Regulated     Generation     Eliminations     Total      
                                             
Electric margin
  $ 1,984     $ 760     $ 1,034     $ (65 )   $ 3,713      
Gas margin
    70       317       -       (8 )     379      
Other revenues
    2       3       -       (5 )     -      
Other operations and maintenance
    (900 )     (550 )     (313 )     75       (1,688 )    
Depreciation and amortization
    (333 )     (217 )     (105 )     (26 )     (681 )    
Taxes other than income taxes
    (234 )     (121 )     (25 )     (1 )     (381 )    
Other income and expenses
    35       19       6       7       67      
Interest expense
    (194 )     (132 )     (107 )     10       (423 )    
Income taxes (benefit)
    (143 )     (25 )     (182 )     20       (330 )    
Minority interest and preferred dividends
    (6 )     (7 )     (27 )     2       (38 )    
Net Income
  $ 281     $ 47     $ 281     $ 9     $ 618      
2006
                                           
Electric margin
  $ 1,898     $ 824     $ 756     $ (61 )   $ 3,417      
Gas margin
    60       307       -       (3 )     364      
Other revenues
    2       2       1       (5 )     -      
Other operations and maintenance
    (800 )     (535 )     (283 )     62       (1,556 )    
Depreciation and amortization
    (335 )     (192 )     (106 )     (28 )     (661 )    
Taxes other than income taxes
    (230 )     (137 )     (24 )     -       (391 )    
Other income and expenses
    33       13       2       (2 )     46      
Interest expense
    (171 )     (95 )     (103 )     19       (350 )    
Income taxes (benefit)
    (184 )     (65 )     (78 )     43       (284 )    
Minority interest and preferred dividends
    (6 )     (7 )     (27 )     2       (38 )    
Net Income
  $ 267     $ 115     $ 138     $ 27     $ 547      
2005
                                           
Electric margin
  $ 1,889     $ 829     $ 703     $ (45 )   $ 3,376      
Gas margin
    73       315       -       -       388      
Other revenue
    2       3       2       (3 )     4      
Other operations and maintenance
    (785 )     (490 )     (255 )     43       (1,487 )    
Depreciation and amortization
    (310 )     (190 )     (106 )     (26 )     (632 )    
Taxes other than income taxes
    (229 )     (119 )     (17 )     -       (365 )    
Other income and expenses
    17       12       (1 )     (11 )     17      
Interest expense
    (116 )     (86 )     (119 )     20       (301 )    
Income taxes (benefit)
    (206 )     (101 )     (86 )     37       (356 )    
Minority interest and preferred dividends
    (6 )     (7 )     (3 )     -       (16 )    
Cumulative effect of change in accounting principle
    -       -       (23 )     1       (22 )    
Net Income
  $ 329     $ 166     $ 95     $ 16     $ 606      
                                             

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Margins
 
The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins from the previous year. 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. The table covers the years ended December 31, 2007, 2006, and 2005. 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 they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.
 
                                                                 
2007 versus 2006   Ameren(a)     UE     CIPS     Genco     CILCORP     CILCO     IP        
Electric revenue change:
                                                               
Effect of weather (estimate)
  $ 73     $ 31     $ 16     $ -     $ 9     $ 9     $ 17          
UE electric rate increase
    29       29       -       -       -       -       -          
Storm-related outages (estimate)
    10       9       3       (3 )     -       -       1          
JDA terminated December 31, 2006
    -       (196 )     -       (97 )     -       -       -          
Elimination of CILCO/AERG power supply agreement
    108       -       -       -       108       108       -          
Interchange revenues, excluding estimated weather impact of ($47) million
    252       252       -       -       -       -       -          
Illinois electric settlement agreement, net of reimbursement
    (73 )     -       (11 )     (30 )     (20 )     (20 )     (14 )        
FERC-ordered MISO resettlements – March 2007
    17       -       -       12       4       4       -          
Mark-to-market losses on energy contracts
    (21 )     (13 )     -       -       -       -       -          
Illinois rate redesign, generation repricing, growth and other (estimate)
    287       11       36       (2 )     160       160       (49 )        
Total electric revenue change
  $ 682     $ 123     $ 44     $ (120 )   $ 261     $ 261     $ (45 )        
Fuel and purchased power change:
                                                               
Fuel:
                                                               
Generation and other
  $ (35 )   $ (10 )   $ -     $ (48 )   $ 22     $ 21     $ -          
Emission allowance sales (costs)
    (38 )     (29 )     -       -       14       11       -          
Mark-to-market gains (losses) on fuel contracts
    23       9       -       6       1       1       -          
Price
    (98 )     (84 )     -       (5 )     (5 )     (5 )     -          
JDA terminated December 31, 2006
    -       97       -       196       -       -       -          
Purchased power
    (90 )     (25 )     (48 )     101       (120 )     (119 )     35          
Entergy Arkansas, Inc. power purchase agreement
    (12 )     (12 )     -       -       -       -       -          
Elimination of CILCO/AERG power supply agreement
    (108 )     -       -       -       (108 )     (108 )     -          
Insurance recovery
    8       20       -       2       7       7       -          
FERC-ordered MISO resettlements – March 2007
    (35 )     (11 )     (8 )     -       (4 )     (4 )     (12 )        
Storm-related energy costs (estimate)
    (1 )     (2 )     -       1       -       -       1          
Total fuel and purchased power change
  $ (386 )   $ (47 )   $ (56 )   $ 253     $ (193 )   $ (196 )   $ 24          
Net change in electric margins
  $ 296     $ 76     $ (12 )   $ 133     $ 68     $ 65     $ (21 )        
Net change in gas margins
  $ 15     $ 10     $ 2     $ -     $ 5     $ 5     $ 1          
                                                                 
                                                                 
 
                                                                 
2006 versus 2005   Ameren(a)     UE     CIPS     Genco     CILCORP     CILCO     IP        
Electric revenue change:
                                                               
Effect of weather on native load (estimate)
  $ (82 )   $ (39 )   $ (16 )   $ -     $ (10 )   $ (10 )   $ (17 )        
Storm-related outages (estimate)
    (10 )     (9 )     (3 )     3       -       -       (1 )        
Noranda
    46       46       -       -       -       -       -          
UE Illinois service territory transfer to CIPS
    -       (38 )     41       34       -       -       -          
Wholesale contracts
    (76 )     -       -       (76 )     -       -       -          
Interchange revenues(b)
    236       (26 )     (34 )     (46 )     8       8       -          
Transmission service and other revenues
    (32 )     (4 )     3       2       2       2       (12 )        
Growth and other (estimate)
    72       27       27       40       12       12       67          
Total electric revenue change
  $ 154     $ (43 )   $ 18     $ (43 )   $ 12     $ 12     $ 37          
                                                                 


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2006 versus 2005   Ameren(a)     UE     CIPS     Genco     CILCORP     CILCO     IP        
Fuel and purchased power change:
                                                               
Fuel:
                                                               
Generation and other
  $ (29 )   $ 3     $ -     $ (10 )   $ (3 )   $ -     $ -          
Emission allowances sales (costs)
    28       30       -       (21 )     9       8       -          
Price
    (82 )     (40 )     -       (18 )     (20 )     (20 )     -          
Purchased power
    (31 )     69       (15 )     (10 )     29       29       (51 )        
Storm-related energy costs (estimate)
    1       2       -       (1 )     -       -       (1 )        
Total fuel and purchased power change
  $ (113 )   $ 64     $ (15 )   $ (60 )   $ 15     $ 17     $ (52 )        
Net change in electric margins
  $ 41     $ 21     $ 3     $ (103 )   $ 27     $ 29     $ (15 )        
Net change in gas margins
  $ (24 )   $ (13 )   $ 1     $ -     $ (10 )   $ (10 )   $ 1          
                                                                 
 
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The effect of storm-related outages increasing interchange revenues is included in the storm-related outages (estimate) line.
 
2007 versus 2006
 
Ameren
 
Ameren’s electric margin increased by $296 million, or 9%, in 2007 compared with 2006. Factors contributing to an increase in Ameren’s electric margin were as follows:
 
•     More power sold by Non-rate-regulated Generation at market-based prices in 2007. These 2007 sales compared favorably with 2006 sales at below-market prices, pursuant to cost-based power supply agreements that expired on December 31, 2006.
•     Favorable weather conditions, as evidenced by a 19% increase in cooling degree-days, increased electric margin by $35 million.
•     UE’s electric rate increase, effective June 4, 2007, which increased electric margin by $29 million.
•     An 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 to sell its excess power, originally obligated to Genco under the JDA at cost, in the spot market at higher prices. This increase was reduced by higher purchased power costs of $12 million associated with an agreement with Entergy Arkansas, Inc. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report, for more information on the UE power purchase agreement with Entergy Arkansas, Inc.
•     A 67% increase in hydroelectric generation because of improved water levels, which allowed additional generation to be used for interchange sales and reduced utilization of higher priced energy sources, increased Ameren’s electric margin by $27 million.
•     Increased Non-rate-regulated Generation capacity sales of $11 million.
•     Reduced severe storm-related outages in 2007 compared to those that occurred in 2006, which negatively impacted electric sales and resulted in a net reduction in overall electric margin of $9 million in 2006.
•     Insurance recoveries of $8 million related to power purchased to replace Taum Sauk generation. See Note 13 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, for more information.
 
Factors contributing to a decrease in electric margin for 2007 as compared with 2006 were as follows:
 
•     The combined effect on the Ameren Illinois Utilities’ of the elimination of bundled tariffs, implementation of new delivery service tariffs effective January 2, 2007, and the expiration of below-market power supply contracts.
•     A 14% increase in fuel prices.
•     Rate relief and customer assistance programs under the Illinois electric settlement agreement, which reduced electric margin by $73 million.
•     The loss of wholesale margins at Genco from power acquired through the JDA, which terminated in 2006.
•     Decreased emission allowance sales of $53 million, offset by lower emission allowance costs of $15 million.
•     Purchased power costs that were $18 million higher for the year because of a March 2007 FERC order that resettled costs among market participants retroactive to 2005.
•     Reduced plant availability. Ameren’s baseload nuclear and coal-fired generating plants’ average capacity and equivalent availability factors were approximately 78% and 86%, respectively, in 2007 compared with 80% and 88%, respectively, in 2006.
 
Ameren’s gas margin increased by $15 million, or 4%, in 2007. The primary causes of the increase were favorable weather conditions, as evidenced by an 8% increase in heating degree-days, which increased gas margin by an estimated $10 million, and the UE gas rate increase that went into effect in April 2007, which increased gas margin by $4 million.
 
Missouri Regulated
 
UE
 
UE’s electric margin increased $76 million, or 4%, in 2007 compared with 2006. The following items had a favorable impact on UE’s electric margin:
 
•     An increase in margin on interchange sales, primarily because of the termination of the JDA on December 31, 2006. The termination of the JDA allowed UE to sell its


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excess power, originally obligated to Genco under the JDA at cost, in the spot market at higher prices. This increase was reduced by higher purchased power costs of $12 million associated with an agreement with Entergy Arkansas, Inc. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report, for more information.
•     The electric rate increase that went into effect June 4, 2007, which increased electric margin by $29 million.
•     A 67% increase in hydroelectric generation because of improved water levels. This allowed additional generation to be used for interchange sales and reduced UE’s use of higher priced energy sources, which increased electric margin by $27 million.
•     Favorable weather conditions, as evidenced by a 19% increase in cooling degree-days, which increased electric margin by $22 million.
•     Replacement power insurance recoveries of $20 million, including $8 million associated with Taum Sauk. See Note 13 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, for more information.
•     Increased transmission service revenues of $18 million due to the ancillary service agreement with CIPS, CILCO, and IP. See Note 12 – Related Party Transactions to our financial statements under Part II, Item 8, of this report, for more information.
•     Decreased fuel costs due to the lack of $4 million in fees levied by FERC in 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.
•     Reduced severe storm-related outages in 2007 compared with 2006, which negatively impacted electric sales that year and resulted in a net reduction in overall electric margin of $7 million in 2006.
 
Items that had an unfavorable impact on electric margin in 2007 as compared with 2006 were as follows:
 
•     A 21% increase in fuel prices.
•     Decreased emission allowance sales of $29 million.
•     MISO purchased power costs that were $11 million higher due to the March 2007 FERC order.
•     Other MISO purchased power costs, excluding the effect of the March 2007 FERC order, that were $20 million higher.
•     Reduced power plant availability because of planned maintenance activities. UE’s baseload nuclear and coal-fired generating plants’ average capacity and equivalent availability factors were approximately 81% and 89%, respectively, in 2007 compared with 84% and 90%, respectively, in 2006.
 
UE’s gas margin increased by $10 million, or 17%, in 2007 compared with 2006. The following items had a favorable impact on gas margins:
 
•     The UE gas rate increase effective in April 2007, which increased gas margin by $4 million.
•     Unrecoverable purchased gas costs totaling $4 million in 2006 that did not recur in 2007.
•     Favorable weather conditions, as evidenced by an 8% increase in heating degree-days, which increased gas margin by $2 million.
 
Illinois Regulated
 
Illinois Regulated’s electric margin decreased by $64 million, or 8%, and gas margin increased by $10 million, or 3%, in 2007 compared with 2006. See below for explanations of electric and gas margin variances for the Illinois Regulated segment.
 
CIPS
 
CIPS’ electric margin decreased by $12 million, or 5%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:
 
•     The combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs on January 2, 2007, and the expiration of below-market power supply contracts.
•     The Illinois electric settlement agreement, which reduced electric margin by $11 million.
•     MISO purchased power costs that increased $8 million because of the March 2007 FERC order.
 
The following items had a favorable impact on electric margin in 2007 as compared with 2006:
 
•     Other MISO purchased power costs, excluding the effect of the March 2007 FERC order, that were $19 million lower, partly because of customers switching to third party suppliers and the termination of the JDA agreement at the end of 2006.
•     Reduced severe storm-related outages in 2007 compared to those that occurred in 2006, which negatively affected electric sales and resulted in a net reduction in overall electric margin of $3 million in 2006.
•     Favorable weather conditions, as evidenced by a 20% increase in cooling degree-days, which increased native load electric margin by $6 million.
 
CIPS’ gas margin was comparable in 2007 and 2006.
 
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 2007 compared with 2006:
 
             
    2007 versus 2006      
             
CILCO (Illinois Regulated)
  $ (31 )    
CILCO (AERG)
    96      
Total change in electric margin
  $ 65