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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, 2006
    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
(217) 523-3600
  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
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 Light Company
 
Preferred Stock, cumulative, $100 par value per share – 4.50% Series
 
Securities Registered Pursuant to Section 12(g) of the Securities Exchange Act of 1934:
 
     
Registrant
 
Title of each class
 
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
 
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       )     No       (X )
 
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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Securities Exchange Act of 1934.
 
                         
    Large Accelerated Filer     Accelerated Filer     Non-Accelerated Filer  
 
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 30, 2006, Ameren Corporation had 205,831,309 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 $10,394,481,105. The shares of common stock of the other registrants were held by affiliates as of June 30, 2006.
 
The number of shares outstanding of each registrant’s classes of common stock as of February 1, 2007, was as follows:
 
Ameren Corporation Common stock, $0.01 par value per share: 206,599,810
 
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 2007 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    
   
  5
   
  5
   
  7
   
  11
   
  12
   
  13
   
  14
  Risk Factors   14
  Unresolved Staff Comments   21
  Properties   21
  Legal Proceedings   24
  Submission of Matters to a Vote of Security Holders   24
  25
 
  Market for Registrants’ Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities   27
  Selected Financial Data   29
  Management’s Discussion and Analysis of Financial Condition and Results of Operations    
   
  31
   
  33
   
  50
   
  63
   
  67
   
  68
   
  69
  Quantitative and Qualitative Disclosures About Market Risk   70
  Financial Statements and Supplementary Data   75
  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   170
  Controls and Procedures   170
  Other Information   171
 
  Directors, Executive Officers and Corporate Governance   171
  Executive Compensation   172
  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   172
  Certain Relationships and Director Independence   173
  Principal Accounting Fees and Services   173
 
  Exhibits and Financial Statement Schedules   174
  178
  186
 Exhibit 12.1
 Exhibit 12.1
 Exhibit 12.3
 Exhibit 12.4
 Exhibit 12.5
 Exhibit 12.6
 Exhibit 12.7
 Exhibit 21
 Exhibit 23.1
 Exhibit 23.2
 Exhibit 23.3
 Exhibit 23.4
 Exhibit 23.5
 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
 Certification
 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 Development Company subsidiary that procures fuel and natural gas and manages the related risks for the Ameren Companies.
Ameren – Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.
Ameren Companies – The individual registrants within the Ameren consolidated group.
Ameren Energy – Ameren Energy, Inc., an Ameren Corporation subsidiary that is a power marketing and risk management agent for affiliated companies. Effective January 1, 2007, Ameren Energy serves only UE.
Ameren Illinois Utilities – CIPS, IP and the rate-regulated electric and gas utility operations of CILCO.
Ameren Services – Ameren Services Company, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.
AMT – Alternative minimum tax.
APB – Accounting Principles Board.
ARO – Asset retirement obligations.
Baseload  – The minimum amount of electric power delivered or required over a given period of time at a steady rate.
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.
CERCLA (Superfund) – Comprehensive Environmental Response Compensation Liability Act of 1980, a federal environmental law that addresses remediation of contaminated sites.
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.
Cooling degree-days – The summation of positive differences between the mean daily temperature and a 65-degree Fahrenheit base. This statistic is a useful measure of 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.
Dekatherm (Dth) – one million BTUs of natural gas.
Development Company – Ameren Energy Development Company, which is a Resources Company subsidiary and Genco, Marketing Company and AFS parent.
DMG – Dynegy Midwest Generation, Inc., a Dynegy subsidiary.
DOE – Department of Energy, a U.S. government agency.
DRPlus – Ameren Corporation’s dividend reinvestment and direct stock purchase plan.
Dynegy – Dynegy Inc.
DYPM – Dynegy Power Marketing, Inc., a Dynegy subsidiary.
EEI – Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary (40% owned by UE and 40% owned by Development Company) that operates non-rate-regulated electric generation facilities and FERC-regulated transmission facilities in Illinois. 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.  A FIN statement is an explanation intended to clarify accounting pronouncements previously issued by the FASB.
Fitch – Fitch Ratings, a credit rating agency.
FSP – FASB Staff Position, which provides application guidance on FASB literature.
FTRs – Financial transmission rights, financial instruments that entitle the holder to pay or receive compensation for certain congestion-related transmission charges between two designated points.
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 Development Company subsidiary that operates a non-rate-regulated electric generation business in Illinois and Missouri.
Gigawatthour – One thousand megawatthours.
Heating degree-days – The summation of negative differences between the mean daily temperature and a 65- degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter space heating for residential and commercial customers.
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 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.
Illinova – Illinova Corporation, the former parent company of IP.
IP – Illinois Power Company, an Ameren Corporation subsidiary acquired from Dynegy on September 30, 2004. IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenIP.
IP LLC – Illinois Power Securitization Limited Liability Company, which is a special-purpose Delaware limited-liability company. Under FIN 46R, Consolidation of Variable-interest Entities, IP LLC was no longer consolidated within IP’s financial statements as of December 31, 2003.
IP SPT – Illinois Power Special Purpose Trust, which was created as a subsidiary of IP LLC to issue TFNs as allowed under the Illinois Customer Choice Law. Pursuant to FIN 46R, IP SPT is a variable-interest entity, as the equity investment is not sufficient to permit IP SPT to finance its activities without additional subordinated debt.
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.
MAIN – Mid-America Interconnected Network, Inc., a regional electric reliability council organized to coordinate the planning and operation of the nation’s bulk power supply. MAIN ceased operations on January 1, 2006.
Marketing Company – Ameren Energy Marketing Company, a Development Company subsidiary that markets power for Genco, AERG and EEI.
Medina Valley – AmerenEnergy Medina Valley Cogen (No. 4) LLC and its subsidiaries, all Development Company subsidiaries, which indirectly own a 40-megawatt gas-fired electric generation plant.
Megawatthour – One thousand kilowatthours.
MGP – Manufactured gas plant.
MISO – Midwest Independent Transmission System Operator, Inc.
MISO Day Two Energy Market – A market that began operating on April 1, 2005. It uses market-based pricing, incorporating transmission congestion and line losses, to compensate market participants for power. The previous system required generators to make advance reservations for transmission service.
Missouri 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 UE’s 40% interest in EEI and other 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 are maintained between rate-regulated and non-rate-regulated businesses. These are referred to as the utility money pool and the non-state-regulated subsidiary money pool, respectively.
Moody’s – Moody’s Investors Service Inc., a credit rating agency.
MoPSC – Missouri Public Service Commission, a state agency that regulates the Missouri utility business and operations of UE.
NCF&O – National Congress of Firemen and Oilers, a labor union.
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.
OTC – Over-the-counter.
PGA – Purchased Gas Adjustment tariffs, which allow the passing through of the actual cost of natural gas to utility customers.
PJM – PJM Interconnection LLC.
PUHCA 1935 – The Public Utility Holding Company Act of 1935, which was repealed effective February 8, 2006, by the Energy Policy Act of 2005 that was enacted on August 8, 2005.


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PUHCA 2005 – The Public Utility Holding Company Act of 2005, enacted as part of the Energy Policy Act of 2005, effective February 8, 2006.
Resources Company – Ameren Energy Resources Company, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Development Company, Genco, Marketing Company, AFS, and Medina Valley.
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 – Southeastern Electric Reliability Council, Inc., 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. Since 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 in UE’s pending electric and gas rate cases and the outcome of CIPS, CILCO and IP rate rehearing proceedings, or the enactment of legislation freezing electric rates at 2006 levels or similar actions that impair the full and timely recovery of costs in Illinois;
•     the implementation of the Ameren Illinois Utilities Customer Elect electric rate increase phase-in plan;
•     the impact of the termination of the JDA;
•     changes in laws and other governmental actions, including monetary and fiscal policies;
•     the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at both the state and federal levels, and the implementation of deregulation, such as occurred when the electric rate freeze and power supply contracts expired in Illinois at the end of 2006;
•     the effects of participation in the MISO;
•     the availability of fuel such as coal, natural gas, and enriched uranium used to produce electricity; the availability of purchased power and natural gas for distribution; and the level and volatility of future market prices for such commodities, including the ability to recover the costs for such commodities;
•     the effectiveness of our risk management strategies and the use of financial and derivative instruments;
•     prices for power in the Midwest;
•     business and economic conditions, including their impact on interest rates;
•     disruptions of the capital markets or other events that make the Ameren Companies’ access to necessary capital more difficult or costly;
•     the impact of the adoption of new accounting standards and the application of appropriate technical accounting rules and guidance;
•     actions of credit rating agencies and the effects of such actions;
•     weather conditions and other natural phenomena;
•     the impact of system outages caused by severe weather conditions or other events;
•     generation plant construction, installation and performance, including costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident and the plant’s future operation;
•     recoverability through insurance of costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident;
•     operation of UE’s nuclear power facility, including planned and unplanned outages, and decommissioning costs;
•     the effects of strategic initiatives, including acquisitions and divestitures;
•     the impact of current environmental regulations on utilities and power generating companies and the expectation that more stringent requirements, including those related to greenhouse gases, will be introduced over time, which could have a negative financial effect;
•     labor disputes, future wage and employee benefits costs, including changes in returns on benefit plan assets;


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•     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.


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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 registered with the SEC as a public utility holding company under PUHCA 1935 until that act was repealed effective February 8, 2006. Ameren was formed in 1997 by the merger of UE and CIPSCO, the former parent company of CIPS. 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.
 
The following table presents our total employees at December 31, 2006:
 
         
Ameren(a)
    8,988  
Missouri Regulated:
       
UE
    3,592  
Illinois Regulated:
       
CIPS
    694  
CILCO
    408  
IP
    1,211  
Non-rate-regulated Generation:
       
Genco
    555  
CILCO (AERG)
    206  
         
 
(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 63% of Ameren’s total employees. They represent 73% of the employees at UE, 83% at CIPS, 71% at Genco, 71% at CILCORP, 71% at CILCO, and 91% at IP. Two IBEW collective bargaining agreements covering about 320 UE workers expired on September 30, 2006. Another IBEW agreement covering 17 IP workers expired on November 30, 2006. The UE collective bargaining agreements have been extended indefinitely by mutual agreement, and the IP agreement is currently in force under an extension, while negotiations continue on all three agreements. At this time, all employees continue to work without disruption. The most significant remaining issue associated with the UE agreements involves health care benefit plan revisions, and the most significant issue associated with the IP agreement involves continuity of work and incentive pay provisions. Most of the remaining collective bargaining agreements, covering 5,000 employees at UE, CIPS, Genco, CILCORP, CILCO and IP, expire throughout 2007.
 
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.
 
BUSINESS SEGMENTS
 
Before the third quarter of 2006, Ameren reported only one business segment, Utility Operations, which comprised electric generation and electric and gas transmission and distribution operations. Ameren holding company activity was listed in the caption called Other.
 
In the third quarter of 2006, Ameren determined that it has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. UE determined it has one reportable segment: Missouri Regulated. CILCORP and CILCO determined they have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. See Note 17 – 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 also regulates UE, CIPS, Genco, CILCO and IP 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. Less than 5% of the Ameren Companies’ electric operating revenues fall under FERC regulations.
 
About 39% of Ameren’s electric and 12% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2006. About 43% of


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Ameren’s electric and 88% of its gas operating revenues were subject to regulation by the ICC that year. Interchange revenues are not subject to direct MoPSC or ICC regulation.
 
Missouri Regulated
 
About 82% of UE’s electric and 100% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2006.
 
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.
 
A new 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 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 during the fourth quarter of 2006. We are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted. UE requested approval of a fuel and purchased power cost recovery mechanism in its electric rate case filed with the MoPSC in July 2006. The MoPSC staff and intervenors have recommended that UE not be granted the right to use such a mechanism. UE also requested an environmental cost recovery mechanism as part of this electric rate case. However, no environmental adjustment clause has been submitted in the rate case since final environmental cost recovery rules have not been adopted. UE’s requests are subject to approval by the MoPSC.
 
For further information on Missouri rate matters, including the Missouri law enabling fuel, purchased power and environmental cost recovery mechanisms, UE’s pending electric and gas rate cases following the expiration of a rate-adjustment moratorium in 2006 and termination of the JDA among UE, CIPS and Genco, 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 3 – Rate and Regulatory Matters, and Note 14 – 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, 2006:
 
                     
    Electric(a)     Gas      
CIPS
    100 %     100 %    
CILCORP
    91       100      
CILCO
    91       100      
IP
    100       100      
                     
 
(a)  Interchange revenues are not subject to ICC regulation.
 
During 2006, retail electric rates were subject to a legislative rate freeze in Illinois. In February 2005, CIPS, CILCO and IP filed with the ICC a proposal for power procurement through an ICC-monitored auction including, among other things, a rate mechanism that would pass power supply costs directly through to customers after the rate freeze expired on January 1, 2007, and power supply contracts expired December 2006. In January 2006, the ICC issued an order that unanimously approved the Ameren Illinois Utilities’ proposed power procurement auction and the related tariffs for the period commencing January 2, 2007, including the retail rates by which power supply costs would be passed through to electric customers.
 
The power procurement auction was held and declared successful for fixed-price customers in September 2006. The vast majority of electric customers of CIPS, CILCO and IP are fixed-price customers.
 
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.
 
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 would allow 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 will be recovered by IP from a $20 million trust fund established by IP and financed with contributions of $10 million each by Ameren and Dynegy. If cash expenditures are less than the amount in base rates, IP will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recovered through charges assessed to customers under the tariff rider.
 
This report includes further information on rate matters, including the ICC order allowing for the recovery of prudently incurred power costs effective January 2, 2007, and related court proceedings; CIPS’, CILCO’s and IP’s 2006 ICC electric delivery services rate case orders; and actions taken by certain Illinois legislators, the Illinois governor, the Illinois attorney general, and others regarding the expiration of the rate freeze and oppositions to the power procurement auction. See Results of Operations and Outlook in Management’s Discussion and Analysis of Financial


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Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 3 – Rate and Regulatory Matters, and Note 14 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
 
General Regulatory Matters
 
PUHCA 2005, enacted as part of the Energy Policy Act of 2005, repealed PUHCA 1935, effective February 8, 2006. Under PUHCA 2005, 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 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’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. The license for the Osage plant expired on February 28, 2006, but the plant is allowed to operate under this license pending FERC’s decision on UE’s license renewal application. In May 2005, the U.S. Department of the Interior and various state agencies reached a settlement agreement that is expected to lead to FERC’s relicensing of UE’s Osage plant for another 40 years. The settlement must be approved by FERC. The license for UE’s Taum Sauk plant expires on June 30, 2010. The Taum Sauk plant is currently out of service 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 3 – Rate and Regulatory Matters and Note 14 – 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 subjected 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 14 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
 
SUPPLY FOR ELECTRIC POWER
 
During 2006, the Ameren Companies’ peak demand from retail and wholesale customers was 17,703 megawatts. The combined peak capability to deliver power from owned generation and power supply agreements was 20,899 megawatts. Ameren-owned generation and purchased power currently meet the energy needs of UE, Genco, AERG and Marketing Company customers, with the required reserve margins. Power for the Ameren Illinois Utilities is purchased through an ICC-approved auction that was first held in September 2006. 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.
 
Effective January 1, 2006, Ameren became a member of SERC, a regional electric reliability organization. SERC is responsible for promoting, coordinating and ensuring the reliability and adequacy of the bulk electric power supply system in much of the southeastern United States, including portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, and Texas. The Ameren membership covers UE, CIPS, CILCO and IP. Ameren was previously a member of MAIN, which ceased operations on January 1, 2006.
 
Before the termination of the JDA on December 31, 2006, the bulk power system of UE, CIPS and Genco operated as a single control area and transmission system,


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and CILCO and IP operated as separate control areas. On July 7, 2006, UE, CIPS and Genco mutually agreed to terminate the JDA on December 31, 2006. This action was accepted by the FERC in September 2006. In conjunction with terminating the JDA, Ameren’s transmission-owning entities restructured their control areas into one control area in Missouri for UE’s transmission facilities and one in Illinois for the transmission facilities of CIPS, CILCO and IP. See Note 3 – Rate and Regulatory Matters and Note 13 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for more information on the JDA. In 2006, we had at least 18 direct connections with other control areas for the exchange of electric energy, some directly and some through the facilities of others. EEI operates a separate control area in southern Illinois. EEI’s transmission system is directly connected to MISO and TVA. EEI’s generating units are dispatched separately from those of UE, Genco and AERG. UE, CIPS, CILCO and IP are transmission-owning members of the MISO, and they have transferred functional control of their systems to the 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 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further information.
 
Missouri Regulated
 
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 the addition of these CT facilities to satisfy demand growth until about 2018. In the meantime, UE will be evaluating baseload electric generating plant options, including coal-fired, nuclear, pumped-storage and integrated gasification combined cycle coal technology. See Note 2 – Acquisitions to our financial statements under Part II, Item 8, of this report for a discussion of the CT facilities purchases.
 
Illinois Regulated
 
CIPS, CILCO and IP own no generation facilities. CIPS bought power from Genco, and CILCO bought power from AERG, both under contracts that expired at the end of 2006. IP’s primary power supply contract with Dynegy also expired at the end of 2006. In connection with the expiration of the power supply agreements, the ICC approved an auction framework to allow electric utilities in Illinois, including CIPS, CILCO and IP, to procure power for use by their customers in 2007. The power procurement auction was held in September 2006. See Note 3 – Rate and Regulatory Matters and Note 13 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for a discussion of the ICC-approved power procurement auction.
 
Non-rate-regulated Generation
 
In December 2005, EEI entered into a power supply agreement with Marketing Company, whereby EEI sells 100% of its capacity and energy to Marketing Company. Commencing in 2007, Genco and AERG are also selling power to Marketing Company. Marketing Company sold power through the Illinois power procurement auction to CIPS, CILCO and IP and is selling power through other contracts with wholesale and retail customers. See Note 3 – Rate and Regulatory Matters and Note 13 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for a discussion of power supply agreements.
 


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The following table presents the source of electric generation by fuel type, excluding purchased power, for the years ended December 31, 2006, 2005 and 2004:
 
                                         
    Coal     Nuclear     Natural Gas     Hydroelectric     Oil  
Ameren:(a)
                                       
2006
    85 %     13 %     1 %     1 %     (b )
2005
    86       10       1       2       1  
2004
    86       10       1       2       1  
Missouri regulated:
                                       
UE:
                                       
2006
    77 %     20 %     1 %     2 %     (b )
2005
    80       16       1       3       (b )
2004
    80       17       (b )     3       (b )
Non-rate-regulated generation:
                                       
Genco:
                                       
2006
    97 %     -       2 %     -       1 %
2005
    96       -       3       -       1  
2004
    98       -       2       -       (b )
CILCO (AERG)(c)
                                       
2006
    99 %     -       1 %     -       (b )
2005
    99       -       1       -       (b )
2004
    99       -       1       -       (b )
EEI:
                                       
2006
    100 %     -       (b )     -       -  
2005
    100       -       (b )     -       -  
2004
    100       -       (b )     -       -  
Total Non-rate-regulated generation:
                                       
2006
    99 %     -       1 %     -       (b )
2005
    98       -       2       -       (b )
2004
    99       -       1       -       (b )
                                         
 
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Less than 1% of total fuel supply.
(c) The remaining CILCO (Illinois Regulated) generating facilities were contributed to CILCO (AERG) effective December 31, 2006.


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The following table presents the cost of fuels for electric generation for the years ended December 31, 2006, 2005 and 2004.
 
                         
Cost of Fuels (Dollars per million Btus)   2006     2005     2004  
Ameren:
                       
Coal(a)
  $ 1.271     $ 1.153     $ 1.055  
Nuclear
    0.434       0.421       0.432  
Natural gas(b)
    8.917       9.044       8.471  
Weighted average-all fuels(c)
  $ 1.256     $ 1.184     $ 1.024  
Missouri regulated:
                       
UE:
                       
Coal(a)
  $ 1.084     $ 0.994     $ 0.893  
Nuclear
    0.434       0.421       0.432  
Natural gas(b)
    8.625       8.825       6.960  
Weighted average-all fuels(c)
  $ 1.035     $ 0.993     $ 0.823  
Non-rate-regulated generation:
                       
Genco:
                       
Coal(a)
  $ 1.691     $ 1.589     $ 1.328  
Natural gas(b)
    9.391       9.395       8.868  
Weighted average-all fuels(c)
  $ 1.865     $ 1.808     $ 1.474  
CILCO (AERG):
                       
Coal(a)
  $ 1.419     $ 1.317     $ 1.426  
Natural gas(b)
    8.133       8.849       8.074  
Weighted average-all fuels(c)
  $ 1.466     $ 1.396     $ 1.462  
EEI:
                       
Coal(a)
  $ 1.266     $ 1.053     $ 0.989  
Total non-rate-regulated generation:
                       
Coal(a)
  $ 1.513     $ 1.378     $ 1.253  
Natural gas(b)
    9.385       9.384       8.866  
Weighted average-all fuels(c)
  $ 1.613     $ 1.508     $ 1.323  
                         
 
(a) The fuel cost for coal represents the cost of coal and costs for transportation.
(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 to calculate 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, CILCO (AERG) and EEI have agreements in place to purchase coal and to transport it to electric generating facilities through 2011. 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. As of December 31, 2006, 100% of UE’s, Genco’s, AERG’s and EEI’s expected 2007 coal usage was under contract, and about 54% of the expected coal usage for 2008 to 2011 was under contract. Ameren burned 40 million (UE – 23 million, Genco – 8 million, AERG – 4 million, EEI – 5 million) tons of coal in 2006.
 
More than 90% of Ameren’s coal is purchased from the Powder River Basin in Wyoming. The remaining coal is 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, 2006, coal inventories for UE, Genco, AERG and EEI were adequate and consistent with historical levels, but below targeted levels due to rail deliveries from the Powder River Basin below requested levels. Disruptions in deliveries of coal could cause UE, Genco, AERG and EEI to incur higher costs for fuel and purchased power and could reduce their interchange sales.
 
Nuclear
 
Fuel assemblies for the 2007 spring refueling are already at UE’s Callaway nuclear plant. UE also has agreements or inventories to meet 61% of Callaway’s 2008 to 2011 requirements. UE expects to enter into additional contracts to purchase nuclear fuel. Prices cannot be accurately predicted at this time. UE is a member of Fuelco, which allows UE to join with other member 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


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completed in November 2005. The next refueling is scheduled for April 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’s, Genco’s 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. UE, Genco and EEI 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, 2006, UE had about 39% and Genco had 100% of its required gas supply for generation for 2007 hedged for price risk. For 2008 to 2011, UE has 1% of its estimated required natural gas supply for generation hedged for price risk, and Genco has 7% hedged. As of December 31, 2006, EEI did not have any of its required gas supply for generation hedged for price risk.
 
Purchased Power
 
We believe that we can obtain enough purchased power to meet future needs. However, during periods of high demand, the price and availability of purchased power may be significantly affected. The Ameren transmission system has a minimum of 18 direct connections to other control areas, which give us access to numerous sources of supply. UE, CIPS, CILCO and IP are members of the MISO. The MISO Day Two Energy Market is designed to provide transparency of power pricing and to make generation dispatch efficient. The MISO Day Two Energy Market also makes available power from the entire MISO transmission grid.
 
Illinois Regulated
 
CIPS, CILCO and IP were subject to legislative electric rate freezes in Illinois through January 1, 2007, and had power supply contracts in place through December 31, 2006, to meet their customers’ needs. In January 2006, the ICC approved a power procurement auction and the related tariffs for the period commencing January 2, 2007, including the retail rates at which power supply costs would be passed through to customers. The power procurement auction was held at the beginning of September 2006. The auction was designed to procure the power supply needs of CIPS, CILCO and IP through a portfolio of one-, two- and three-year supply agreements for residential and small commercial customers and one-year agreements for large commercial and industrial customers. Through the auction, CIPS, CILCO and IP acquired 100% of expected power supply requirements for all customers through May 31, 2008, two-thirds of supply requirements for residential and small commercial customers for June 1, 2008, through May 31, 2009, and one-third of the requirements for these customers for June 1, 2009, through May 31, 2010. See Note 14 – Commitments and Contingencies under Part II, Item 8, of the report for more information on the results of the Illinois power procurement auction. The next Illinois power procurement auction is scheduled for January 2008.
 
See Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Risk Factors under Part I, Item 1A, and Note 3 – Rate and Regulatory Matters, under Part II, Item 8, of this report for a discussion of credit rating changes issued in response to potential actions in Illinois that could threaten the financial solvency of CIPS, CILCO and IP and their ability to procure power.
 
Non-rate-regulated Generation
 
In December 2006, Genco and AERG each entered into separate power supply agreements to sell all of their generation capacity to Marketing Company. Both agreements began on January 1, 2007, and will continue through December 31, 2022, and from year to year thereafter unless either party elects to terminate the agreement. In December 2005, Marketing Company entered into a power supply agreement with EEI, whereby EEI agreed to sell 100% of its capacity and energy to Marketing Company. This agreement expires on December 30, 2015. A portion of this power was sold by Marketing Company into the Illinois power procurement auction. For additional information on the electric power supply agreements, see Note 13 – Related Party Transactions to our financial statements under Part II, Item 8, of this report.
 
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


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financial markets are used to hedge the price paid for natural gas. Prudently incurred natural gas purchase costs are passed on to UE, CIPS, CILCO and IP gas customers in Illinois and Missouri dollar-for-dollar 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; Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, of this report; and Note 1 – Summary of Significant Accounting Policies, Note 8 – Derivative Financial Instruments, Note 13 – Related Party Transactions, Note 14 – Commitments and Contingencies, and Note 15 – Callaway Nuclear Plant to our financial statements under Part II, Item 8, of this report.
 
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 and regulation;
•     the potential for more intense competition in generation and supply;
•     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;
•     availability of fuel and increases in prices;
•     rising labor and material costs;
•     continually developing and complex environmental laws, regulations and issues, including new air-quality standards, mercury regulations, and possible greenhouse gas limitations;
•     public concern about the siting of new facilities;
•     construction of new power generating and transmission facilities;
•     proposals for programs to encourage energy efficiency and renewable sources of power;
•     public concerns about nuclear plant operation and decommissioning and the disposal of nuclear waste;
•     consolidation of electric and gas companies; and
•     global climate issues.
 
We are monitoring these issues. 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 3 – Rate and Regulatory Matters, and Note 14 – 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. Unless otherwise indicated, IP is included only for the periods after its acquisition on September 30, 2004.
 
                             
Electric Operating Statistics – Year Ended December 31,   2006     2005     2004      
Electric operating revenues (millions)
                           
Residential
  $ 1,751     $ 1,805     $ 1,323      
Commercial
    1,634       1,630       1,289      
Industrial
    996       955       765      
Wholesale
    290       339       335      
Other
    52       51       33      
Interchange
    741       499       420      
Miscellaneous
    121       152       98      
Total electric operating revenues
  $ 5,585     $ 5,431     $ 4,263      
Kilowatthour sales (millions)
                           
Residential
    24,557       25,570       19,121      
Commercial
    26,164       26,259       21,846      
Industrial
    23,429       22,590       18,988      
Wholesale
    7,982       9,684       9,388      
Other
    709       732       421      
Interchange
    17,580       11,224       13,801      
Total kilowatthour sales
    100,421       96,059       83,565      
Residential revenue per kilowatthour (average)
    7.13 ¢     7.06 ¢     6.92 ¢    
Capability at time of peak, including net purchases and sales (thousands of megawatts)
                           
UE
    10,153       9,892 (a)     9,243 (a)    
Genco
    4,872 (a)     4,815 (a)     4,603 (a)    
AERG
    1,401       1,380       1,380      
IP
    3,950       4,000 (a)     (b )    
EEI (Ameren’s ownership interest)
    801       801       801      
Generating capability at time of peak (thousands of megawatts)(c)
                           
UE
    10,279       9,318       8,351      
Genco
    3,713       3,685       4,239      
AERG
    1,216       1,230       1,230      
EEI (Ameren’s ownership interest)
    801       801       801      
Price per ton of delivered coal (average)
  $ 22.74     $ 21.31     $ 19.65      
Source of energy supply
                           
Coal
    65.8 %     66.0 %     74.9 %    
Gas
    0.9       1.1       0.7      
Oil
    0.7       0.8       0.9      
Nuclear
    9.7       8.1       9.3      
Hydroelectric
    0.9       1.3       1.7      
Purchased and interchanged, net
    22.0       22.7       12.5      
      100.0 %     100.0 %     100.0 %    
                             
 
(a) Includes purchases from EEI.
(b) Peak occurred before the acquisition date of September 30, 2004.
(c) Represents gross generating capability.
 


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Gas Operating Statistics Year Ended – December 31,   2006     2005     2004      
Natural gas operating revenues (millions)
                           
Residential
  $ 791     $ 804     $ 506      
Commercial
    317       320       198      
Industrial
    140       158       121      
Other
    47       63       41      
Total natural gas operating revenues
  $ 1,295     $ 1,345     $ 866      
Dth sales (millions of Dth)
                           
Residential
    62       67       49      
Commercial
    26       28       21      
Industrial
    21       19       18      
Total Dth sales (millions of Dth)
    109       114       88      
Peak day throughput (thousands of Dth)
                           
UE
    124       161       182      
CIPS
    242       250       272      
CILCO
    356       370       412      
IP
    540       569       541 (a)    
Total peak day throughput
    1,262       1,350       1,407      
                             
 
(a) Represents peak day throughput since the acquisition date of September 30, 2004. IP’s peak day throughput for the first three quarters of 2004 was 654 Dth.
 
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 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; a policy and procedures with respect to related-person transactions; a code of ethics for principal executive 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 currently the subject of rate case proceedings and potential legislative action. The outcome of these proceedings and of other potential legislative action or future rate proceedings is largely outside of our control. Should these events result in the inability of UE, CIPS, CILCO or IP to recover their respective costs and earn an appropriate return on investment, it could have a material adverse effect on our future results of operations, financial position, or liquidity. In particular, we believe freezing electric rates at 2006 levels in Illinois would lead to CIPS, CILCORP, CILCO and IP being financially insolvent.
 
The rates that certain Ameren Companies are allowed to charge for their services are the single most important item influencing the results of operations, financial position, or liquidity of the Ameren Companies. The electric and gas utility industry is highly regulated. The regulation of the rates that we charge our customers is determined, in large part, by governmental entities outside of our control, including the MoPSC, the ICC, and FERC. Decisions made by these entities could have a material adverse effect on our results of operations, financial position, or liquidity.
 
Increased costs and investments, when combined with rate reductions and moratoriums, have caused decreased returns in Ameren’s utility businesses. Ameren expects that many of its operating expenses will continue to rise. Ameren further expects to continue to make significant investment in its energy infrastructure. These are the two principal factors underlying the pending rate increase requests with the MoPSC and the rate increase requests recently acted upon and pending rehearing with the ICC. We cannot predict the outcome of these rate case proceedings or of potential Illinois legislative action to deny full recovery of costs. In addition, in response to competitive, economic, political, legislative and regulatory pressures, in connection with the resolution of our current rate case proceedings or otherwise, we may be subject to further rate moratoriums, rate refunds, limits on rate increases, or rate reductions, including phase-in plans. Any or all of these could have a material adverse effect on our results of operations, financial position, or liquidity.

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Illinois
 
Electric Delivery Service Rate Cases
 
A provision of the Illinois Customer Choice Law related to the restructuring of the Illinois electric industry put a rate freeze into effect through January 1, 2007, for CIPS, CILCO and IP. CIPS, CILCO and IP filed rate cases with the ICC in December 2005 to modify their electric delivery service rates effective January 2, 2007. CIPS, CILCO and IP requested to increase their annual revenues for electric delivery service by $202 million in the aggregate (CIPS – $14 million, CILCO – $43 million and IP – $145 million). In November 2006, the ICC issued an order that approved an aggregate revenue increase of $97 million effective January 2, 2007 (CIPS – an $8 million decrease, CILCO – a $21 million increase and IP – an $84 million increase) based on an allowed return on equity of 10%. In December 2006, the ICC granted the Ameren Illinois Utilities’ petition for rehearing of the November 2006 order on the recovery of certain administrative and general expenses, totaling $50 million, that were disallowed. The ICC’s decision on the recovery of these expenses is due in May 2007. The ICC denied requests for rehearings filed by other parties in this case. Because of the ICC’s cost disallowances and regulatory lag, the Ameren Illinois Utilities are not expected to earn their allowed return on equity of 10% in 2007. Most customers were taking service under a frozen bundled electric rate in 2006, which includes the cost of power, so these delivery service revenue changes will not directly correspond to a change in CIPS’, CILCO’s or IP’s revenues or earnings under the new electric delivery service rates that became effective January 2, 2007.
 
Potential Electric Rate Freeze and Recovery of Post-2006 Power Supply Costs
 
Consistent with the Illinois Customer Choice Law that froze electric rates for CIPS, CILCO and IP through January 1, 2007, these companies entered into power supply contracts that expired on December 31, 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers through an auction. It also approved the related tariffs to collect these costs from customers for the period commencing January 2, 2007. This approval is subject to pending court appeals. In accordance with the January 2006 ICC order, a power procurement auction was held in September 2006.
 
Subsequently, the ICC determined that it would not investigate the results of the auction to procure power for fixed-price customers, and the independent auction manager declared a successful result in the auction for these fixed-price customers, which include the vast majority of electric customers of CIPS, CILCO and IP. Certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties sought to block the power procurement auction. They continue to challenge the auction and the structure for the recovery of costs for power supply resulting from the auction through rates to customers. In February 2006, legislation was introduced in the Illinois House of Representatives that would have extended the electric rate freeze in Illinois at 2006 levels through 2010. On October 2, 2006, Speaker of the Illinois House of Representatives Michael Madigan sent a letter to Illinois Governor Rod Blagojevich asking the Illinois governor to call a special session of the Illinois General Assembly to consider this rate freeze legislation. The governor sent a letter indicating that once the votes to pass the legislation were in place, he would immediately call for a special session of the legislature. The governor’s letter further provided that if a consensus among members of the general assembly could not be reached in the near future, he would call a special session as well. The governor’s letter stated that he continued to support legislation extending the rate freeze and would like to sign it into law as soon as possible. No special session was called in 2006. During the Illinois General Assembly’s session that ended in January 2007, the Illinois House of Representatives passed legislation to freeze rates at 2006 levels through 2010, and the Illinois Senate passed legislation containing an electric rate increase phase-in plan. The Illinois Senate bill provided for a mandatory phase-in of the 2007 increase in residential electric rates over a three-year period. Neither piece of legislation was passed by the other chamber before the end of the session in early January 2007.
 
Any legislative measure will need to be approved by the Illinois House of Representatives and Illinois Senate, and signed by the Illinois governor before it can become law. New rates for CIPS, CILCO and IP reflecting the power costs resulting from the ICC-approved September 2006 auction and the delivery service rates authorized by the November 2006 ICC order became effective January 2, 2007. A new Illinois General Assembly went into session in late January 2007. As a result, all previous bills expired. New bills have been introduced during the current legislative session, including legislation to rollback rates to 2006 levels similar to previously proposed legislation. On February 27, 2007, the Ameren Illinois Utilities announced that they intended to file an electric rate increase mitigation plan with the ICC. As part of the plan, which is subject to ICC approval, the Ameren Illinois Utilities would fund an approximate $20 million one-time reduction to active residential accounts that would appear on electric bills in March and April 2007. The rate mitigation plan is targeted to customers with high volume usage. As part of the filing, the carrying charge of 3.25% in the current ICC-approved phase-in plan would be eliminated. If approved by the ICC, the one-time credit for residential customers would result in a charge to Ameren’s earnings in 2007 of $20 million, or 6 cents per share. In addition, eliminating the below-market interest rate on deferred amounts under the phase-in plan would increase financing costs for the Ameren Illinois Utilities during the deferral period. The actual cost to Ameren will depend on the level of participation in the phase-in plan.
 
CIPS, CILCORP, CILCO and IP believe that legislation freezing electric rates at 2006 levels, if enacted, would have a material adverse effect on their results of operations, financial position, and liquidity, including the financial insolvency of CIPS, CILCORP, CILCO and IP. They believe it could cause significant job losses and, without governmental intervention, significant disruptions in electric and gas


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service. Since Ameren’s Illinois utilities own no generation facilities, the companies must purchase power on the competitive market to meet customers’ energy needs. If electric rates were to be frozen at 2006 levels, the major credit rating agencies have stated that the Ameren Illinois Utilities’ credit ratings would be downgraded to deep junk (or speculative) status. Such a downgrade of CILCO’s ratings would also result in a similar downgrade of CILCORP’s ratings. We believe that CIPS, CILCORP, CILCO and IP would be faced with potential collateral and prepayment requirements for products and services, such as natural gas, and would eventually run out of cash and available credit and be unable to borrow. We believe that this would cause the Ameren Illinois Utilities and CILCORP to become financially insolvent. In reaction to intensified political discussion in Illinois regarding electric rate freeze extension legislation, in October 2006, S&P downgraded the short- and long-term credit ratings of the Ameren Companies and kept the Ameren Companies on credit watch with negative implications; Moody’s placed the long-term debt ratings of the Ameren Companies under review for possible downgrade; and Fitch placed the ratings of Ameren, CIPS, CILCORP, CILCO and IP on rating watch negative.
 
CIPS, CILCO and IP strongly believe that freezing rates at 2006 levels in Illinois would not be in the best interests of any of the Ameren Illinois Utilities or their customers. In December 2006, the ICC approved a constructive rate increase phase-in plan proposed by CILCO, CIPS and IP for residential, small commercial, and eligible local governmental and school customers to address the significant increases in customer rates for the Ameren Illinois Utilities beginning in 2007. However, if the Illinois legislature passes rate phase-in legislation that does not allow for the full and timely recovery of costs, it could have a material adverse effect on CIPS’, CILCORP’s, CILCO’s and IP’s results of operations, financial position, or liquidity.
 
Ameren, CIPS, CILCO and IP will continue to explore a number of legal and regulatory actions, strategies, and alternatives to address these Illinois electric issues. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their legal and financial interests, including seeking the protection of the bankruptcy courts. However, there can be no assurance that Ameren and the Ameren Illinois Utilities will prevail over the stated opposition of certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other stakeholders, or that the legal and regulatory actions, strategies and alternatives that Ameren and the Ameren Illinois Utilities are considering will be successful.
 
We are unable to predict the results of the court appeals of the January 2006 ICC order approving CIPS’, CILCO’s and IP’s power procurement auction and the related tariffs. Nor can we predict the actions the Illinois General Assembly and governor may take that may affect electric rates or the power procurement process for CIPS, CILCO and IP. Any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover purchased power or distribution costs from their electric customers in a timely manner would result in material adverse consequences to Ameren, CIPS, CILCORP, CILCO and IP. These consequences could include a significant drop in credit ratings to deep junk (or speculative) status, a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, significant risk of disruption in electric and gas service, significant job losses, and financial insolvency. In addition, Ameren, CILCORP and IP could be required to record a charge for goodwill impairment for the goodwill that was recorded when Ameren acquired CILCORP and IP. As of December 31, 2006, Ameren had $830 million, CILCORP $542 million and IP $213 million of goodwill on their balance sheets. Furthermore, if the Ameren Illinois Utilities are unable to recover their costs from customers, the utilities could be required to cease applying SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” which allows CIPS, CILCORP, CILCO and IP to defer certain costs pursuant to actions of rate regulators and to recover such costs in rates charged to customers. This would result in the elimination of all regulatory assets recorded by CIPS, CILCORP, CILCO and IP on their balance sheets and a one-time extraordinary charge on their statements of income that could be material. As of December 31, 2006, CIPS had $146 million, CILCORP $75 million, CILCO $75 million and IP $401 million recorded as regulatory assets on their balance sheets.
 
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 December 2006, the MoPSC staff and other stakeholders filed direct testimony in response to UE’s rate case filings. The MoPSC staff recommended in their testimony an electric rate reduction of $136 million to $168 million and a gas rate increase of $2 million to $3 million. During the course of the rate proceeding, parties to the case may change their positions. A decision from the MoPSC is expected no later than June 2007. Any change in electric or gas rates may not directly correspond to a change in UE’s earnings.
 
UE does not currently have a rate-adjustment clause for its electric operations in Missouri that would allow it to recover from customers the costs for purchased power, fuel, or infrastructure investment. Therefore, insofar as UE has not hedged its fuel and power costs, UE is exposed to changes in fuel and power prices to the extent they exceed the costs embedded in current electric rates. In its Missouri electric rate case filed in July 2006, UE requested a fuel and purchased power cost recovery mechanism that would be subject to MoPSC approval. The MoPSC staff and intervenors in the electric rate case have recommended that UE not be granted the right to use such a mechanism. UE also requested an environmental cost-recovery mechanism as part of its pending Missouri electric rate case, but no rules have been established for such a mechanism. Any new energy infrastructure investment could result in increased


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financing requirements for UE, which could increase further depending on rate case outcomes. The lack of timely recovery of these costs could have a material adverse effect on UE’s results of operations, financial position, or liquidity. We are unable to predict whether the MoPSC will approve our request for a fuel and purchased power cost recovery mechanism in our pending electric rate case. We also are unable to predict when rules implementing the environmental cost recovery mechanism will be formally proposed and adopted.
 
If Illinois electric rates are frozen at 2006 levels or if the ability of CIPS, CILCO and IP to recover post-2006 power supply costs or increase electric delivery service rates is otherwise impaired, there may be a material adverse effect on Ameren, UE and Genco in addition to the Ameren Illinois Utilities and CILCORP.
 
We believe that freezing electric rates at 2006 levels in Illinois would cause CIPS, CILCORP, CILCO and IP to become financially insolvent. Although the Ameren Companies are separate, independent legal entities with separate businesses, assets and liabilities, there is a risk that the financial insolvency of CIPS, CILCORP, CILCO and IP could have a materially adverse effect on Ameren, UE and Genco. If rates are frozen at 2006 levels in Illinois for CIPS, CILCO and IP, or if the ability of CIPS, CILCO and IP to recover post-2006 power supply costs or increase electric delivery service rates is otherwise impaired, such events might increase Ameren’s, UE’s and Genco’s cost of capital or adversely affect the ability of these companies to access the capital markets, particularly during times of uncertainty in the capital markets, which could negatively affect their ability to maintain and expand their businesses. Moody’s, S&P and Fitch each have indicated that they would lower the credit ratings for CIPS, CILCORP, CILCO and IP to deep junk (or speculative) status, if electric rates were frozen at 2006 levels, reflecting the material impact such action would have on the cash flow and liquidity of these companies. It is possible that the rating agencies could decide to lower the credit ratings of Ameren, UE or Genco at the same time. Any adverse change in the ratings of Ameren, UE or Genco could also increase their cost of borrowing under existing credit facilities, and suppliers might begin to request prepayment for products and services (such as fuel, power and gas) or the posting of collateral.
 
If CIPS, CILCORP, CILCO and IP become insolvent, their commitments to Ameren, Genco and AERG might be unfulfilled. Pursuant to agreements executed in connection with the recent Illinois power procurement auction, Marketing Company is selling to CIPS, CILCO and IP power that is being supplied under contracts from Genco and AERG. If CIPS, CILCORP, CILCO and IP become insolvent, Genco, AERG or Marketing Company may not be able to recover the cost of power delivered to those companies but not paid for prior to insolvency. Marketing Company’s commitments to sell power to CIPS, CILCO, IP and other unaffiliated parties also rely, in part, on power supplied by AERG. In the event of financial insolvency, AERG may not be able to deliver power it has committed to sell to Marketing Company; that could force Marketing Company to acquire the power to meet its commitments at a higher cost.
 
In addition, dividends on Ameren’s common stock and the payment of Ameren’s other obligations, including its debt, depend on distributions made to it by its subsidiaries. If CIPS, CILCORP, CILCO and IP should become insolvent, they will not be able to make distributions to Ameren. Additionally, if CIPS, CILCORP, CILCO and IP fall below investment grade in ratings of their securities, they will be limited in the amount of dividends they may pay. As a result, the board of directors of Ameren might decide to rely more heavily on UE and Ameren’s unregulated operations to support dividends on Ameren’s common stock, or to reduce or eliminate the payment of dividends. Moreover, the absence of distributions from the Illinois utilities and CILCORP could force Ameren to use other available sources of liquidity to service its debt obligations.
 
We cannot determine at this time whether the freezing of rates at 2006 levels in Illinois that would lead to CIPS, CILCORP, CILCO and IP insolvency will occur. We also cannot determine what the resulting effect would be on Ameren, UE and Genco. However, the financial insolvency of CIPS, CILCORP, CILCO and IP could have a material adverse effect on the results of operations, financial position, or liquidity of Ameren, UE and Genco.
 
Our counterparties may not meet their obligations to us.
 
We are exposed to the risk that counterparties to various arrangements (including our affiliates) who owe us money, energy, coal or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to replace or to sell the underlying commitment at then-current market prices. In such event, we might incur losses, or our results of operations, financial position, or liquidity could otherwise be adversely affected.
 
Increased federal and state environmental regulation will require UE, Genco, CILCO (through AERG) and EEI to incur large capital expenditures and to incur increased operating costs. Future limits on greenhouse gas emissions could result in significant increases in capital and operating expenditures.
 
About 61% of Ameren’s generating capacity is coal-fired and about 85% of its electric generation was produced by its coal-fired plants in 2006. The rest is nuclear, gas-fired, hydroelectric, and oil-fired. In May 2005, the EPA issued final regulations with respect to SO2, NOx, and mercury emissions from coal-fired power plants. The new rules require significant additional reductions in these emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. Preliminary estimates of capital compliance costs for Ameren, UE, Genco and AERG range from $3.5 billion to $4.5 billion by 2016.
 
The Missouri Department of Natural Resources formally proposed rules to implement the federal Clean Air Mercury and Clean Air Interstate Rules in November 2006. Missouri


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rules are similar to the federal rules. The Missouri Air Conservation Commission approved the rules at their February 2007 meeting. The rules will be effective after publication in the Missouri Register targeted for April 2007. The rules will also need to be approved by the EPA. If approved, these rules when fully implemented are expected to reduce mercury emissions 81% by 2018 and to reduce NOx emissions 30% and SO2 emissions 75% by 2015.
 
Illinois has proposed rules to implement the federal Clean Air Interstate Rule program; however it is anticipated that the rules will not be finalized until the second quarter of 2007. The Illinois EPA proposed rules for mercury that are significantly stricter than the federal rules. Illinois has also proposed Clean Air Interstate Rule program rules for NOx that are more stringent than the federal program. In 2006, Genco, AERG, EEI, and the Illinois EPA entered into an agreement on Illinois’ mercury rules. Under the agreement, Illinois generators may delay the compliance date for mercury reductions in exchange for accelerated installation of NOx and SO2 controls. The agreement with the Illinois EPA also restricts the purchase of SO2 and NOx emission allowances to meet specific allowed emission rates set forth in the agreement. The Illinois Joint Committee on Administrative Review approved the Illinois mercury rule in December 2006, and the Illinois Pollution Control Board issued a final order and adopted the mercury rule in late December 2006. The final rule was published in the Illinois Register in January 2007. The rule will also need to be approved by the EPA. When fully implemented, these rules are expected to reduce mercury emissions 90%, NOx emissions 50% and SO2 emissions 70% by 2015.
 
Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities. Coal-fired power plants, however, are significant sources of carbon dioxide, a principal greenhouse gas. Six electric power sector trade associations, including the Edison Electric Institute, of which Ameren is a member, and the TVA, signed a Memorandum of Understanding (MOU) with the DOE in December 2004 calling for a 3% to 5% voluntary decrease in carbon intensity by the utility sector between 2002 and 2012. Currently, Ameren is considering various initiatives to comply with the MOU, including increased generation at nuclear and hydroelectric power plants, increased efficiency measures at our coal-fired units, and investments in renewable energy and carbon sequestration projects. Future legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. Mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and EEI’s results of operations, financial position, or liquidity.
 
The EPA has been conducting an enforcement initiative to determine whether modifications at a number of coal-fired power plants owned by electric utilities in the United States are subject to New Source Review requirements or New Source Performance Standards under the Clean Air Act. The EPA’s inquiries focus on whether the best available emission control technology was or should have been used at such power plants when major maintenance or capital improvements were made.
 
In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act, seeking detailed operating and maintenance history data with respect to its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired plants. Genco is asked to respond to specific EPA questions about certain projects and maintenance activities in order to determine compliance with certain Illinois air pollution and emissions rules and with the New Source Performance Standards required by the Clean Air Act. These information requests are being complied with, but we cannot predict the outcome of this matter.
 
We are unable to predict the ultimate effect of any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation on our results of operations, financial position, or liquidity. Any of these factors could result in a significant increase in capital expenditures, closure of power plants, penalties and operating costs for UE, Genco, CILCO (through AERG) and EEI. Therefore, such factors could also result in decreased revenues, increased financing requirements and increased costs for these Ameren companies. Although costs incurred by UE would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar mechanism for recovery of costs by Genco, AERG or EEI in Illinois.
 
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. Based on our assumptions at December 31, 2006, and the new contribution requirements in the Pension Protection Act of 2006, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2009 at which time we would expect to pay a required contribution of $100 million to $150 million. Required contributions of $150 million to $200 million each year are also expected for 2010 and 2011. We expect the companies to share future funding requirements as follows: UE – 61%; CIPS – 10%; Genco – 11%; CILCO – 7%; and IP – 11%. 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.


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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 and efficiency levels. Among these risks are:
 
•     increased prices for fuel and fuel transportation;
•     facility shutdowns due to a failure of equipment or processes or operator error;
•     longer-than-anticipated maintenance outages;
•     disruptions in the delivery of fuel and lack of adequate inventories;
•     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; and
•     catastrophic events such as fires, explosions, floods, or other similar occurrences affecting electric generating facilities.
 
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.
 
The FERC investigation of the incident has been completed. In October 2006, the FERC approved a stipulation and consent agreement between UE and the FERC’s Office of Enforcement that resolves all issues arising from an investigation by the FERC’s Office of Enforcement. They looked into alleged violations of license conditions and FERC regulations by UE as the licensee of the Taum Sauk hydroelectric facility that may have contributed to the breach of the upper reservoir. As part of the stipulation and consent agreement, UE agreed, among other things, (1) to pay a civil penalty of $10 million, (2) to pay $5 million into an interest-bearing escrow account to fund project enhancements at or near the Taum Sauk facility, and (3) to implement and comply with a new dam safety program developed in connection with the settlement.
 
In December 2006, the state of Missouri, through its attorney general and 10 business owners filed separate lawsuits regarding the Taum Sauk breach. The attorney general’s lawsuit, which was filed in the Missouri circuit court in St. Louis, alleges negligence, violations of the Missouri Clean Water Act, and various other statutory and common law claims. The business owners’ suit, which was filed in the Missouri circuit court in Reynolds County, contains similar allegations. It seeks damages relating to business losses and lost profit. Both suits seek unspecified punitive damages. In January 2007, the Missouri Department of Natural Resources filed a petition to intervene as a plaintiff in the attorney general’s lawsuit.
 
In February 2007, UE submitted plans and an environmental report to FERC to rebuild the upper reservoir at its Taum Sauk Plant, assuming successful resolution of outstanding issues with agencies of the state of Missouri. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through at least the middle of 2009, if not longer. In 2005, the Taum Sauk facility provided 589,000 megawatthours of electricity.
 
To the extent that UE needs to purchase power because of the unavailability of the Taum Sauk facility, there is the risk that UE will not be permitted to recover these additional costs from ratepayers if such a request is made. The Taum Sauk incident is expected to reduce Ameren’s and UE’s 2007 pretax earnings by $15 million to $20 million as a result of higher-cost sources of power, reduced interchange sales, and increased expenses, net of insurance reimbursement for replacement power costs. In addition, there is also the risk that UE will not be permitted to rebuild the Taum Sauk facility upper reservoir. UE could be required to expense its remaining investment in the plant of $64 million immediately.
 
At this time, excluding fines and penalties, UE believes that substantially all of the damage and liabilities caused by the breach will be covered by insurance. Under UE’s insurance policies, all claims by UE are subject to review by its insurance carriers. Until the reviews conducted by state authorities have concluded, litigation has been resolved, the insurance review is completed, a final decision about whether the plant will be rebuilt is made, and future regulatory treatment for the plant is determined, among other things, we are unable to determine the impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.
 
Genco’s, AERG’s, and EEI’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risk.
 
As of December 31, 2006, Genco and CILCO (through AERG) owned non-rate-regulated electric generating facilities with capacities of 4,222 megawatts and 1,138 megawatts, respectively. During 2006, most of Genco’s and AERG’s wholesale and retail electric power supply agreements


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expired. As a result, Genco and AERG now compete for the sale of energy and capacity through Marketing Company.
 
As of December 31, 2006, EEI owned 1,055 megawatts of non-rate-regulated electric generating facilities. On December 31, 2005, EEI’s power supply contract with its affiliates, including UE, CIPS and IP, expired. All of EEI’s generating capacity now competes for the sale of energy and capacity through Marketing Company.
 
To the extent that electric capacity generated by these facilities is not under 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:
 
•     the current and future market prices for natural gas, fuel oil, and coal;
•     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 ICC with respect to power procurement procedures;
•     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 markets adjacent to Illinois;
•     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 13% of UE’s 2006 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 availability 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’s nuclear operations or those of others in the United States;
•     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.
 
UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in 2007. 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 has 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 and other actions are under consideration. However, Ameren and UE cannot predict whether such efforts will result in an overall improvement of operations at Callaway. Any 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 pricing risks, which could result in unanticipated liabilities or increased volatility in our earnings.
 
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


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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, market effects of 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 those related to future environmental compliance. 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 may create uncertainty that could increase our cost of capital or impair our ability to access the capital markets. 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 2 – Acquisitions, Note 6 – Long-term Debt and Equity Financings, and Note 14 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.
 
The following table shows what our electric generating facilities and capability are anticipated to be at the time of our expected 2007 peak summer electrical demand:
 
                     
Primary Fuel Source   Plant   Location   Net Kilowatt Capability(a)      
Missouri Regulated:
                   
UE:
                   
Coal
  Labadie   Franklin County, Mo.     2,396,000      
    Rush Island   Jefferson County, Mo.     1,160,000      
    Sioux   St. Charles County, Mo.     994,000      
    Meramec   St. Louis County, Mo.     854,000      
Total coal
            5,404,000      
Nuclear
  Callaway   Callaway County, Mo.     1,190,000      
Hydroelectric
  Osage   Lakeside, Mo.     226,000      
    Keokuk   Keokuk, Iowa     134,000      
Total hydroelectric
            360,000      
Pumped-storage
  Taum Sauk   Reynolds County, Mo.     (b )    
                     


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Primary Fuel Source   Plant   Location   Net Kilowatt Capability(a)      
Oil (CTs)
  Fairgrounds   Jefferson City, Mo.     55,000      
    Meramec   St. Louis County, Mo.     55,000      
    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.     26,000      
Total oil
            344,000      
Natural gas (CTs)
  Peno Creek(c)(d)   Bowling Green, Mo.     188,000      
    Meramec(d)   St. Louis County, Mo.     52,000      
    Venice(d)   Venice, Ill.     499,000      
    Viaduct   Cape Girardeau, Mo.     25,000      
    Kirksville   Kirksville, Mo.     13,000      
    Audrain(c)(e)   Audrain County, Mo.     600,000      
    Goose Creek(f)   Piatt County, Ill.     432,000      
    Raccoon Creek(f)   Clay County, Ill.     300,000      
    Pinckneyville(g)   Pinckneyville, Ill.     320,000      
    Kinmundy(d)(g)   Kinmundy, Ill.     230,000      
Total natural gas
            2,659,000      
Total UE
            9,957,000      
Non-rate-regulated Generation
                   
EEI(h):
                   
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.     1,151,000      
    Coffeen   Coffeen, Ill.     900,000      
    Meredosia   Meredosia, Ill.     327,000      
    Hutsonville   Hutsonville, Ill.     153,000      
Total coal
            2,531,000      
Oil
  Meredosia   Meredosia, Ill.     186,000      
    Hutsonville (Diesel)   Hutsonville, Ill.     3,000      
Total oil
            189,000      
Natural gas (CTs)
  Grand Tower   Grand Tower, Ill.     516,000      
    Elgin(i)   Elgin, Ill.     452,000      
    Gibson City   Gibson City, Ill.     232,000      
    Joppa 7B(j)   Joppa, Ill.     162,000      
    Columbia(k)   Columbia, Mo.     140,000      
Total natural gas
            1,502,000      
Total Genco
            4,222,000      
CILCO (through AERG):
                   
Coal
  E.D. Edwards(l)   Bartonville, Ill.     749,000      
    Duck Creek(l)   Canton, Ill.     349,000      
Total coal
            1,098,000      
Natural gas
  Sterling Avenue(l)   Peoria, Ill.     30,000      
    Indian Trails(m)   Pekin, Ill.     10,000      
Total natural gas
            40,000      
Total CILCO
            1,138,000      
Medina Valley:
                   
Natural gas
  Medina Valley   Mossville, Ill.     44,000      
Total Non-rate-regulated
            6,459,000      
Total Ameren
            16,416,000      
                     
 
(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. See a discussion of this incident and related matters below.

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(c) There is an economic development lease arrangement applicable to these CTs.
(d) Certain of these CTs have the capability to operate on either oil or natural gas (dual fuel).
(e) UE acquired this CT from affiliates of NRG Energy, Inc., in March 2006.
(f) UE acquired this CT from affiliates of Aquila, Inc., in March 2006.
(g) These CTs were transferred from Genco to UE in May 2005.
(h) Ameren owns an 80% interest in EEI. See Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.
(i) There is a tolling agreement in place for one of Elgin’s units (approximately 100 megawatts).
(j) These CTs are owned by Genco and leased to its parent, Development Company. The operating lease is for a minimum term of 15 years expiring September 30, 2015. Genco receives rental payments under the lease in fixed monthly amounts that vary over the term of the lease and range from $0.8 million to $1.0 million.
(k) 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.
(l) These facilities were transferred from CILCO to AERG in October 2003.
(m) This facility was transferred from CILCO to AERG effective December 31, 2006.
 
In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. Should the decision be made to rebuild the Taum Sauk plant, UE would expect it to be out of service through at least the middle of 2009, if not longer. For additional information on the Taum Sauk incident, see Note 14 – Commitments and Contingencies under Part II, Item 8 of this report.
 
The following table presents electric and natural gas utility-related properties for UE, CIPS, CILCO and IP as of December 31, 2006:
 
                                     
    UE     CIPS     CILCO     IP      
Circuit miles of electric transmission lines
    2,930       2,310       330       1,850      
Circuit miles of electric distribution lines
    32,200       14,800       8,800       21,400      
Percent of circuit miles of electric distribution lines underground
    21 %     11 %     25 %     12 %    
Miles of natural gas transmission and distribution mains
    3,090       5,020       3,840       8,640      
Number of propane-air plants
    1       1       -       -      
Number of underground gas storage fields
    -       3       2       7      
Billion cubic feet of total working capacity of underground gas storage fields
    -       3       8       15      
                                     
 
Our other properties include distribution lines, underground cables, 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 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 October 2003, CILCO transferred substantially all of its generating property and plant to its non-rate-regulated electric generating subsidiary, AERG. In December 2006, CILCO transferred the remainder of its generating property and plant to AERG. As part of these transfers, CILCO’s transferred generating property and plant was released from the lien of the indenture securing its first mortgage bonds. In May 2005, UE transferred substantially all of its Illinois electric and gas transmission and distribution properties to CIPS. As a part of the transfer, UE’s transferred utility properties were released from the lien of the indenture securing its first mortgage bonds and immediately became subject to the lien of the indenture securing CIPS’ first 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 to 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 5 –


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Credit Facilities and Liquidity for details of the credit facilities.
 
In December 2002, UE conveyed most of its Peno Creek CT facility to the city of Bowling Green, Missouri, and leased the facility back from the city for a 20-year term. As a part of the transaction, most of UE’s Peno Creek CT property and plant was released from the lien of the indenture securing UE’s first mortgage bonds. Under the terms of this capital lease, UE retains all operation and maintenance responsibilities for the facility. Ownership of the facility will return to UE at the expiration of the lease. When ownership of the Peno Creek CT facility is returned to UE by Bowling Green, the property and plant may again 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.
 
For additional information on these CT lease arrangements, see Note 2 – Acquisitions under Part II, Item 8, of this report.
 
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 April 2005, Caterpillar Inc. intervened in the ICC proceedings relating to the power procurement auction and related tariffs of CILCO, CIPS and IP. In the Ameren Illinois Utilities’ 2005 auction process proceedings, Caterpillar Inc., in conjunction with other industrial customers as a coalition, opposed the Ameren Illinois Utilities’ filing on issues regarding auction design and auction process, among others. In February 2006, Caterpillar Inc. intervened in the 2006 rate cases filed by the Ameren Illinois Utilities with the ICC to modify their electric delivery service rates. In the 2006 rate cases, Caterpillar Inc., in conjunction with other industrial customers as a coalition, opposed the Ameren Illinois Utilities’ filings on issues regarding rate design and revenue requirements, among others. 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.
 
Anheuser-Busch, Incorporated, an affiliate of Anheuser-Busch Companies, Inc., and The Boeing Company are members of the Missouri Industrial Energy Consumers group (MIEC) which, on September 1, 2006, intervened in the MoPSC proceedings relating to UE’s request for an increase in base rates for electric service. MIEC’s position in the case is that UE overstated its needed revenue requirement and that a disproportionate amount of the increase has been assigned to industrial customers. MIEC also opposes UE’s requested fuel and purchased power cost recovery mechanism. Patrick T. Stokes is the chairman of the board of directors of Anheuser-Busch Companies, Inc. and James C. Johnson is an officer of The Boeing Company. Mr. Stokes and Mr. Johnson are also members of the board of directors of Ameren. Neither Mr. Stokes nor Mr. Johnson participated 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 3 – Rate and Regulatory Matters, and Note 14 – 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 2006 with respect to any of the Ameren Companies.
 


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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, 2006, 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.
 
AMEREN CORPORATION:
 
         
    Age at
   
Name   12/31/06   Positions and Offices Held
 
Gary L. Rainwater
  60   Chairman, Chief Executive Officer, President and Director
Rainwater joined UE in 1979 as an engineer. He was elected vice president, corporate planning, in 1993. Rainwater was elected executive vice president of CIPS in January 1997 and president and chief executive officer of CIPS in December 1997. He was elected president of Resources Company in 1999 and Genco in 2000. He was elected president and chief operating officer of Ameren, UE, and Ameren Services in August 2001, at which time he relinquished his position as president of Resources Company and Genco. In January 2003, Rainwater was elected president and chief executive officer of CILCORP and CILCO upon Ameren’s acquisition of those companies. Effective January 1, 2004, Rainwater became chairman and chief executive officer of Ameren, UE, and Ameren Services, in addition to being president. At that time, he was also elected chairman of CILCORP and CILCO. Rainwater was elected chairman, chief executive officer and president of IP in September 2004 upon Ameren’s acquisition of that company. In October 2004, he relinquished his position of president of CIPS, CILCO and IP and, effective January 1, 2007, he relinquished all of his officer positions in UE, CIPS, CILCO, IP and Ameren Services.
         
Warner L. Baxter
  45   Executive Vice President and Chief Financial Officer
Baxter joined UE in 1995 as assistant controller. He was promoted to controller of UE in 1996, elected controller of Ameren Services in 1997 and elected vice president and controller of Ameren, UE, and Ameren Services in 1998. Baxter was elected vice president and controller of CIPS in 1999 and of Genco in 2000. He was elected senior vice president, finance, of Ameren, UE, CIPS, Ameren Services, and Genco in 2001. In January 2003, Baxter was elected senior vice president of CILCORP and CILCO upon Ameren’s acquisition of those companies. Baxter was elected to the position of executive vice president and chief financial officer at Ameren, UE, CIPS, Genco, AERG, AFS, Medina Valley, CILCORP, CILCO and Ameren Services in October 2003 and at IP in September 2004, upon Ameren’s acquisition of that company. He was elected chairman, chief executive officer, and president of Ameren Services effective January 1, 2007.
         
Thomas R. Voss
  59   Executive Vice President and Chief Operating Officer
Voss joined UE in 1969 as an engineer. From 1973 to 1998, he held various positions at UE, including district manager and distribution operating manager. Voss was elected vice president of CIPS in 1998 and senior vice president of UE, CIPS and Ameren Services in 1999. He was elected senior vice president of CILCORP and CILCO in January 2003 and of IP in September 2004, upon Ameren’s acquisitions of those companies. In October 2003, Voss was elected president of Genco, Resources Company, Marketing Company, AFS, Ameren Energy, Medina Valley, and AERG. Voss relinquished his presidency of these companies, with the exception of Ameren Energy, Medina Valley, and Resources Company, in October 2004. He was elected to his present position at Ameren in January 2005. In June 2005, Voss relinquished his position as president of Ameren Energy. 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 and relinquished his position as president of Resources Company.
         
Steven R. Sullivan
  46   Senior Vice President, General Counsel and Secretary
Sullivan joined Ameren, UE, CIPS and Ameren Services in 1998 as vice president, general counsel, and secretary, and he added those positions at Genco in 2000. In January 2003, Sullivan was elected vice president, general counsel, and secretary of CILCORP and CILCO upon Ameren’s acquisition of those companies. He was elected to his present position at Ameren, UE, CIPS, Genco, Marketing, Resources Company, AERG, AFS, Medina Valley, CILCORP, CILCO, and Ameren Services in October 2003 and at IP in September 2004, upon Ameren’s acquisition of that company.


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    Age at
   
Name   12/31/06   Positions and Offices Held
 
         
Jerre E. Birdsong
  52   Vice President and Treasurer
Birdsong joined UE in 1977 as an economist. He was promoted to assistant treasurer in 1984 and manager of finance in 1989. He was elected treasurer of UE in 1993. He was elected treasurer of Ameren, CIPS and Ameren Services in 1997, Resources Company in 1999, Genco, AFS and Marketing in 2000, and AERG and Medina Valley in 2003. In addition to being treasurer, in 2001 he was elected vice president at Ameren and the subsidiaries listed above, with the exception of AERG and Medina Valley. Birdsong was elected vice president at AERG and Medina Valley in 2003. Additionally, he was elected vice president and treasurer of CILCORP and CILCO in January 2003 and of IP in September 2004, upon Ameren’s acquisition of those companies.
         
Martin J. Lyons
  40   Vice President and Controller
Lyons joined Ameren, UE, CIPS, Genco, AFS, and Ameren Services in October 2001 as controller. He was elected controller of CILCORP, CILCO and AERG in January 2003 and Medina Valley in February 2003, upon Ameren’s acquisition of those companies. He was also elected vice president of Ameren, UE, CIPS, Genco, AFS, CILCORP, CILCO, and Ameren Services in February 2003 and vice president and controller of IP in September 2004, upon Ameren’s acquisition of that company.
         
SUBSIDIARIES:
       
         
Scott A. Cisel   53   Chairman, Chief Executive Officer and President
(CILCO, CIPS and IP)
Cisel assumed the position of vice president and chief operating officer for CILCO in 2003, upon Ameren’s acquisition of that company. Prior to that acquisition, he served as senior vice president of CILCO. Cisel has held various management positions at CILCO in sales, customer services, and district operations, including manager of commercial office operations in 1981, manager of consumer and energy services in 1984, manager of rates, sales, and customer service in 1988, and director of corporate sales in 1993. From 1995 to 2001, he was vice president, at first managing sales and marketing, then legislative and public affairs, and later sales, marketing and trading. In April 2001, he was elected senior vice president of CILCO. In September 2004, Cisel was elected vice president of UE and Ameren Services. In October 2004, he was elected 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 of president.
         
Daniel F. Cole
  53   Senior Vice President
(CILCO, CIPS, CILCORP, Genco, IP and UE)
Cole joined UE in 1976 as an engineer. He was named UE’s manager of resource planning in 1996 and general manager of corporate planning in 1997. In 1998, Cole was elected vice president of corporate planning of Ameren Services. He was elected senior vice president at UE and Ameren Services in 1999 and at CIPS in 2001. He was elected president of Genco in 2001 and relinquished that position in 2003. He was elected senior vice president at CILCORP and CILCO in January 2003, at Genco in May 2004 and at IP in September 2004
         
R. Alan Kelley
  54   Chairman, Chief Executive Officer and President (Resources Company), President (Genco) and Senior Vice President (CILCO and UE)
Kelley joined UE in 1974 as an engineer. He was named UE’s manager of corporate planning in 1985 and vice president of energy supply in 1988. He was elected vice president of Ameren Services in 1997 and vice president of Resources Company in 2000. Kelley was elected senior vice president of Ameren Services in 1999 and of Genco in 2000. He was elected senior vice president at CILCO in January 2003, upon Ameren’s acquisition of that company. In October 2004, Kelley was elected president of Genco, AERG, and Medina Valley, and senior vice president of UE. Effective January 1, 2007, he was elected chairman, chief executive officer, and president of Resources Company.

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    Age at
   
Name   12/31/06   Positions and Offices Held
 
         
Richard J. Mark
  51   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. Before joining Ameren, Mark was employed for 11 years by Ancilla Systems Inc. During that time, he served as vice president for governmental affairs, chief operating officer, and for the final six years, as chief executive officer of St. Mary’s Hospital in East St. Louis, Illinois.
         
Donna K. Martin
  59   Senior Vice President and Chief Human Resources Officer (Ameren Services)
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. Before joining Ameren Services, she was employed from 2000 to 2002 by Faulding Pharmaceuticals of Paramus, New Jersey, where she was senior vice president, human resources.
         
Michael G. Mueller
  43   President (AFS)
Mueller joined UE in 1986 as an engineer in corporate planning. In 1988, he became a fuel buyer in the fossil fuel department, and in 1994 he was named senior fuel buyer for UE. In 1998, Mueller became director of coal trade for Ameren Energy. In 1999, he was promoted to manager of the fossil fuel department of Ameren Services. Mueller was elected vice president of AFS in 2000 and president in 2004.
         
Charles D. Naslund
  54   Senior Vice President and Chief Nuclear Officer (UE)
Naslund joined UE in 1974 as an assistant engineer in engineering and construction. He became manager, nuclear operations support, in 1986. In 1991, he was named manager, nuclear engineering. 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. Naslund was elected senior vice president and chief nuclear officer at UE in January 2005.
         
Andrew M. Serri
  45   President (Ameren Energy Marketing Company)
Serri joined Marketing Company as vice president of sales and marketing in 2000. Serri was elected vice president of marketing and trading and of Ameren Services in 2004, before being elected president of Marketing Company and vice president of Ameren Energy that same year. In June 2005, Serri was elected president of Ameren Energy.
 
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. Except for Richard J. Mark and Donna K. Martin, all of the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.
 
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 May 25, 2006, Ameren submitted to the NYSE a certificate of the chief executive officer of Ameren certifying that he was not aware of any violation by Ameren of NYSE corporate governance listing standards.

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Ameren common shareholders of record totaled 79,041 on January 31, 2007. The following table presents the price ranges and dividends paid per Ameren common share for each quarter during 2006 and 2005.
 
                                     
    High     Low     Close     Dividends Paid      
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      
AEE 2005 Quarter Ended:
                                   
March 31
  $ 52.00     $ 47.51     $ 49.01       631/2 ¢    
June 30
    55.84       48.70       55.30       631/2      
September 30
    56.77       52.05       53.49       631/2      
December 31
    54.46       49.61       51.24       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; Development 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 2006 and 2005:
 
                                                                         
      2006
      2005
     
      Quarter Ended       Quarter Ended      
Registrant     December 31     September 30     June 30     March 31       December 31     September 30     June 30     March 31      
UE
    $ 95     $ 70     $ 42     $ 42       $ 71     $ 74     $ 75     $ 60      
CIPS
      -       25       25       -         14       12       9       -      
Genco
      20       22       49       22         29       25       20       14      
CILCORP(a)
      -       -       -       50         -       -       -       30      
IP
      -       -       -       -         16       20       20       20      
Nonregistrants
      16       14       14       16         -       2       -       -      
Ameren
    $ 131     $ 131     $ 130     $ 130       $ 130     $ 133     $ 124     $ 124      
                                                                         
 
(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. CILCO paid dividends to CILCORP of $20 million in the quarterly period ended March 31, 2005.
 
On February 9, 2007, 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 30, 2007, to stockholders of record on March 7, 2007.
 
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.
 
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)
 
    (a) 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     (or Unit)     Plans or Programs     Plans or Programs  
October 1 – 31, 2006
    5,800     $ 53.48       -       -  
November 1 – 30, 2006
    2,004       54.85       -       -  
December 1 – 31, 2006
    -       -       -       -  
Total
    7,804     $ 53.83       -       -  
                                 
 
(a) Included in each of October and November 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. Included in November were four shares of Ameren common stock purchased to satisfy an employee’s tax obligation incurred with the vesting of performance share units and share distribution under Ameren’s Long-term Incentive Plan of 1998 upon the employee’s death. 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.


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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, 2006.
 
Performance Graph
 
The following graph shows Ameren’s cumulative total shareholder return during the five fiscal years ended December 31, 2006. The graph also shows the cumulative total returns of the S&P 500 Index and the Edison Electric Institute (EEI) Index (which comprises most investor-owned electric utilities in the United States). The comparison assumes that $100 was invested on January 1, 2002, in Ameren common stock and in each of the indices shown, and it assumes that all of the dividends were reinvested.
[LINE GRAPH]
 
                                                     
    01/01/2002     01/01/2003     01/01/2004     01/01/2005     01/01/2006     01/01/2007      
Ameren
  $ 100.00     $ 104.32     $ 122.43     $ 140.94     $ 151.17     $ 166.46      
S&P 500 Index
    100.00       78.04       100.23       111.01       116.34       134.49      
EEI Index
    100.00       85.27       105.29       129.34       150.10       181.26      
                                                     
 
Ameren management cautions that the stock price performance shown in the graph above should not be considered indicative of potential future stock price performance.
 
ITEM 6. SELECTED FINANCIAL DATA.
 
                                             
For the Years Ended December 31,
                                 
(In millions, except per share amounts)   2006     2005     2004     2003     2002      
Ameren:
                                           
Operating revenues(a)
  $ 6,880     $ 6,780     $ 5,135     $ 4,574     $ 3,841      
Operating income(a)
    1,173       1,284       1,078       1,090       873      
Net income(a)(b)
    547       606       530       524       382      
Common stock dividends
    522       511       479       410       376      
Earnings per share – basic(a)(b)
    2.66       3.02       2.84       3.25       2.61      
                                – diluted(a)(b)
    2.66       3.02       2.84       3.25       2.60      
Common stock dividends per share
    2.54       2.54       2.54       2.54       2.54      
As of December 31:
                                           
Total assets
  $ 19,578     $ 18,171     $ 17,450     $ 14,236     $ 12,151      
Long-term debt, excluding current maturities
    5,285       5,354       5,021       4,070       3,433      
Preferred stock subject to mandatory redemption
    18       19       20       21       -      
Total stockholders’ equity
    6,583       6,364       5,800       4,354       3,842      
                                             


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For the Years Ended December 31,
                                 
(In millions, except per share amounts)   2006     2005     2004     2003     2002      
UE:
                                           
Operating revenues
  $ 2,823     $ 2,889     $ 2,640     $ 2,616     $ 2,650      
Operating income
    620       640       673       787       644      
Net income after preferred stock dividends
    343       346       373       441       336      
Dividends to parent
    249       280       315       288       299      
As of December 31:
                                           
Total assets
  $ 10,287     $ 9,277     $ 8,750     $ 8,517     $ 8,103      
Long-term debt, excluding current maturities
    2,934       2,698       2,059       1,758       1,687      
Total stockholders’ equity
    3,153       3,016       2,996       2,923       2,745      
CIPS:
                                           
Operating revenues
  $ 954     $ 934     $ 735     $ 742     $ 824      
Operating income
    69       85       58       45       52      
Net income after preferred stock dividends
    35       41       29       26       23      
Dividends to parent
    50       35       75       62       62      
As of December 31:
                                           
Total assets
  $ 1,847     $ 1,784     $ 1,615     $ 1,742     $ 1,821      
Long-term debt, excluding current maturities
    471       410       430       485       534      
Total stockholders’ equity
    543       569       490       532       592      
Genco:
                                           
Operating revenues
  $ 992     $ 1,038     $ 873     $ 785     $ 743      
Operating income
    131       257       265       197       138      
Net income(b)
    49       97       107       75       32      
Dividends to parent
    113       88       66       36       21      
As of December 31:
                                           
Total assets
  $ 1,850     $ 1,811     $ 1,955     $ 1,977     $ 2,010      
Long-term debt, excluding current maturities
    474       474       473       698       698      
Subordinated intercompany notes
    163       197       283       411       462      
Total stockholder’s equity
    563       444       435       321       280      
CILCORP:
                                           
Operating revenues
  $ 733     $ 747     $ 722     $ 926     $ 790      
Operating income
    65       61       61       85       98      
Net income(b)
    19       3       10       23       25      
Dividends to parent
    50       30       18       27       -      
As of December 31:
                                           
Total assets
  $ 2,241     $ 2,243     $ 2,156     $ 2,136     $ 1,928      
Long-term debt, excluding current maturities
    542       534       623       669       791      
Preferred stock of subsidiary subject to mandatory redemption
    18       19       20       21       22      
Total stockholders’ equity
    671       663       548       478       495      
CILCO:
                                           
Operating revenues
  $ 733     $ 742     $ 688     $ 839     $ 731      
Operating income
    79       63       58       53       97      
Net income after preferred stock dividends(b)
    45       24       30       43       48      
Dividends to parent
    65       20       10       62       40      
As of December 31:
                                           
Total assets
  $ 1,641     $ 1,557     $ 1,381     $ 1,324     $ 1,250      
Long-term debt, excluding current maturities
    148       122       122       138       316      
Preferred stock subject to mandatory redemption
    18       19       20       21       22      
Total stockholders’ equity
    535       562       437       342       342      
                                             

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For the Years Ended December 31,
                                 
(In millions, except per share amounts)   2006     2005     2004     2003     2002      
IP:(c)
                                           
Operating revenues
  $ 1,694     $ 1,653     $ 1,539     $ 1,568     $ 1,518      
Operating income
    141       202       216       178       203      
Net income after preferred stock dividends(b)
    55       95       137       115       159      
Dividends to parent
    -       76       -       -       -      
As of December 31:
                                           
Total assets
  $ 3,175     $ 3,056     $ 3,117     $ 5,059     $ 5,050      
Long-term debt, excluding current maturities
    772       704       713       1,435       1,719      
Long-term debt to IP SPT, excluding current maturities(d)
    92       184       278       345       -      
Total stockholders’ equity
    1,346       1,287       1,280       1,530       1,412      
                                             
 
(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; and 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 $18 million ($(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. See Note 2 – Acquisitions to our financial statements under Part II, Item 8, of this report for further information.
(d) Effective December 31, 2003, IP SPT was deconsolidated from IP’s financial statements in conjunction with the adoption of FIN 46R. 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
 
Clearly, 2006 will be remembered as an incredibly challenging year for Ameren, as well as for the communities served by UE, CIPS, CILCO and IP. For the better part of the second half of 2006, Ameren was focused on addressing the consequences resulting from unprecedented summer and winter storms. In 2006, UE also continued its extensive restoration efforts associated with the December 2005 breach of the upper reservoir at its Taum Sauk pumped-storage, hydroelectric facility and settled related liability matters with federal authorities. Unfortunately, UE did not receive a unified settlement offer from all relevant Missouri state authorities. On February 2, 2007, UE submitted plans and an environmental report to the FERC to rebuild the upper reservoir of the Taum Sauk plant assuming successful resolution of outstanding issues with authorities of the state of Missouri.
 
Because of the likelihood of higher electric rates in Illinois following the end of a legislative rate freeze on January 2, 2007, certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties sought to block an ICC-approved auction that occurred in September 2006 to procure power for use by the Ameren Illinois Utilities’ customers beginning in 2007. These parties continue to challenge the auction process and the recovery of costs for power supply resulting from the auction through rates to customers. To mitigate the impact of the electric rate increases on customers, an electric rate increase phase-in plan was approved by the ICC in December 2006. In November, the Ameren Illinois Utilities also received an ICC order increasing their electric delivery service rates by an aggregate of $97 million. This order authorized a 10% return on equity, but was significantly less than the Ameren Illinois Utilities’ request for approximately a $200 million increase primarily because of the disallowance of significant levels of expenses, which the Ameren Illinois Utilities believe were prudently incurred. Primarily as a result of this order and cost increases since the 2004 base year for setting these rates, the return on equity in 2007 for the Ameren Illinois Utilities will be meaningfully below the 10% return on equity allowed by the order. A rehearing was granted on a portion of the disallowed costs. The necessity and timing of additional electric delivery services rate increase requests in Illinois will be influenced by the result of this rehearing, which is expected in May 2007. In July 2006, UE filed for its first electric rate increase in almost 20 years. UE’s electric rate filing included a proposed annual increase in electric rates of $361 million. UE also filed last July for an increase in natural gas delivery rates of $11 million annually. Interveners in the electric rate case have recommended rate reductions. Decisions are expected by the MoPSC by June 2007.
 
While 2006 was full of challenges, we did remain focused on our core operations and were able to achieve several notable accomplishments. From an operational standpoint, Ameren’s power plants performed very well in 2006, setting records for generation output. Availability and capacity factors of the Missouri Regulated coal-fired power plants were comparable with solid 2005 results, averaging 90% and 82%, respectively. In 2006, Ameren’s non-rate-regulated coal-fired plants improved their availability from 82% to 85% year over year and capacity factors from 68% to 73%. We also successfully executed our plan to hedge most of our estimated available 2007 non-rate-regulated

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generation due to the expiration of our below-market contracts at the end of 2006.
 
Earnings
 
Ameren reported earnings of $2.66 per share for 2006 which compared to earnings of $3.02 per share last year. Ameren’s earnings in 2005 included an 11 cent per share charge for the adoption of a new accounting principle related to AROs. Earnings in 2006 were affected by restoration efforts associated with severe storms that reduced Ameren’s net income by 26 cents per share. In addition, costs related to the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility decreased 2006 earnings by 20 cents per share. Ameren also incurred a charge of 5 cents per share related to funding commitments for low-income energy assistance and energy-efficiency programs associated with the December 2006 ICC order associated with the electric rate increase phase-in plan. Incremental gains of approximately 9 cents per share in 2006, associated with the sale of certain non-core properties, including leveraged leases, reduced the negative impact of these items.
 
Earnings in 2006 were also unfavorably affected by escalating costs for fuel and related transportation, operating materials, and financing costs and depreciation associated with significant energy infrastructure investments in Ameren’s regulated electric and gas utility businesses. In addition, earnings were significantly affected by mild summer and winter weather, as well as lower power prices for excess energy sales as compared to 2005. Market prices for power in 2005 were higher than 2006 as a result of the significant impact of hurricanes and rail disruptions in 2005. Operating results in 2006 benefited from organic sales growth; improved plant performance; the lack of a scheduled refueling and maintenance outage at UE’s Callaway nuclear plant; Illinois electric commercial and industrial customers returning to tariff rates because these rates were below market rates for power; and higher sales levels of emission allowances.
 
Liquidity
 
Cash flows from operations of $1.3 billion in 2006 at Ameren, along with other funds, were used to pay dividends to common shareholders of $522 million and fund capital expenditures of $992 million and CT acquisitions of $292 million. Financing activities in 2006 primarily consisted of refinancing debt and funding capital investment with borrowings under credit facilities.
 
Outlook
 
Electric rates in Illinois are expected to continue to be a source of debate among legislators and regulators in 2007. Proposed actions have included freezing rates at 2006 levels despite significantly higher purchased power costs for the Ameren Illinois Utilities. Any decision or action that impairs the ability of CIPS, CILCO and IP to fully recover costs from their electric customers in a timely manner would result in material adverse consequences for Ameren, CIPS, CILCORP, CILCO, and IP. CIPS, CILCORP, CILCO and IP expect to take whatever actions are necessary to protect their financial interests, including seeking the protection of the bankruptcy courts.
 
The ultimate resolution of pending electric and gas rate cases in Missouri, coupled with a final decision in the rehearing of certain electric delivery service rate case issues in Illinois, will have a significant impact on earnings in 2007 and 2008. Ameren’s regulated utilities are expected to experience significant increases in the costs of serving their customers, including coal and related transportation costs that are expected to increase by 15% to 20% in 2007 and another 5% to 10% in 2008. Many of these costs will be in excess of those reflected in 2007 regulated rates because rates are largely based on historical costs. Ameren expects to realize significantly higher electric margins due to the replacement of below-market power sales contracts, which expired in 2006, with higher-priced contracts in 2007. In the future, Ameren also expects to realize lower income associated with the sale of emission allowances and noncore properties than realized in 2006. While Ameren expects continued economic growth in its service territory to benefit energy demand in 2007 and beyond, higher energy prices could result in reduced demand from consumers.
 
The EPA, together with state authorities, is requiring more stringent emission limits on all coal-fired power plants. Between 2007 and 2016, Ameren expects its subsidiaries will be required to spend between $3.5 billion and $4.5 billion to retrofit their power plants with pollution control equipment. Approximately half of this investment will be at UE and therefore is expected to be recoverable over time from ratepayers. The recoverability of amounts invested in non-rate-regulated operations will depend on whether market prices for power adjust to reflect this increased investment by the industry.
 
General
 
Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren was registered with the SEC as a public utility holding company under PUHCA 1935 until that act was repealed effective February 8, 2006. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries, which are separate, independent legal entities with separate businesses, assets and liabilities, operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses and non-rate-regulated electric generation businesses in Missouri and Illinois, as discussed below. Dividends on Ameren’s common stock 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


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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 transmission and distribution business, a non-rate-regulated electric generation business (through its subsidiary, AERG) and a rate-regulated natural gas transmission and distribution business in Illinois.
•     IP 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. As the acquisition of IP occurred on September 30, 2004, Ameren’s Consolidated Statements of Income and Cash Flows for the periods before September 30, 2004, do not reflect IP’s results of operations or financial position. See Note 2 – Acquisitions to our financial statements under Part II, Item 8, of this report for further information on the accounting for the IP acquisition. 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. About 90% of Ameren’s revenues were directly subject to state or federal regulation in 2006. This regulation can have a material impact on the prices we charge for our services. Our non-rate-regulated sales are subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We do not currently have fuel or purchased power cost recovery mechanisms in Missouri for our electric utility businesses. We do have natural gas cost recovery mechanisms in Missouri and Illinois for our gas delivery businesses. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8 for a discussion of pending rate cases and the Illinois power procurement auction process and related tariffs. Fluctuations in interest rates affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risks and other risks inherent in our 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 $547 million ($2.66 per share) for 2006, $606 million ($3.02 per share) for 2005, and $530 million ($2.84 per share) for 2004. 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 loss of adopting FIN 47 is presented below for the applicable registrant companies:
 
             
    Net Cumulative Effect
     
    Aftertax Loss      
Ameren(a)
  $ 22      
Genco
    16      
CILCORP
    2      
CILCO
    2      
IP
    -      
             
 
(a)  Includes amounts for EEI.
 
Ameren’s 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.
 
Earnings were negatively impacted in 2006 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 upper reservoir breach in December 2005 at UE’s Taum Sauk pumped-storage hydroelectric 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.


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Earnings were favorably impacted in 2006 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.
 
Cents per share information presented above is based on average shares outstanding in 2005.
 
Ameren’s net income before cumulative effect of the adoption of FIN 47 in 2005 increased $98 million and earnings per share increased 29 cents in 2005 compared with 2004.
 
Earnings were favorably impacted in 2005 by:
 
•     warmer weather in the summer of 2005 compared with extremely mild conditions in the summer of 2004 (estimated at 26 cents per share);
•     inclusion of IP results for an additional nine months in 2005 (23 cents per share);
•     increased margins on interchange sales (11 cents per share);
•     the lower cost of the refueling and maintenance outage at UE’s Callaway nuclear plant in 2005 versus the 2004 refueling and maintenance outage (3 cents per share);
•     increased emission allowance sales earnings (2 cents per share);
•     net gains on sales of noncore properties, including leveraged leases in 2005 (7 cents per share);
•     lower employee benefit costs (5 cents per share); and
•     other factors including organic growth.
 
Earnings were negatively impacted in 2005 by:
 
•     incremental costs of operating in the MISO Day Two Energy Market (29 cents per share);
•     the lack of a FERC-ordered refund of $18 million in exit fees as had occurred in 2004 – this fee had previously been paid by UE and CIPS to the MISO, upon their re-entry into the MISO (6 cents per share);
•     increased labor costs (8 cents per share); and
•     other factors including increased fuel and purchased power costs and coal conservation efforts in 2005.
 
An increase in the number of common shares outstanding also reduced Ameren’s earnings per share in 2005 compared with 2004.
 
Cents per share information presented above is based on average shares outstanding in 2004.
 
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, 2006, 2005 and 2004:
 
                             
    2006     2005     2004      
Net income:
                           
UE(a)(b)
  $ 343     $ 346     $ 373      
CIPS
    35       41       29      
Genco(a)
    49       97       107      
CILCORP(a)
    19       3       10      
IP(c)
    55       95       27      
Other(d)
    46       24       (16 )    
Ameren net income
  $ 547     $ 606     $ 530      
                             
 
(a) Includes earnings from market-based interchange power sales that provided the following contributions to net income: UE: 2006 – $65 million; 2005 – $75 million; 2004 – $75 million. Genco: 2006 – $20 million; 2005 – $47 million; 2004 – $39 million. CILCORP: 2006 – $18 million; 2005 – $13 million.
(b) Includes earnings from a non-rate-regulated 40% interest in EEI.
(c) Excludes net income prior to the acquisition on September 30, 2004.
(d) Includes earnings 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 (2005 and 2006), transition costs associated with the CILCORP and IP acquisitions (2004), and intercompany eliminations.
 
Before the third quarter of 2006, Ameren reported one segment, Utility Operations, comprising electric generation and electric and gas transmission and distribution operations. Ameren holding company activity was listed in the caption called Other. As a result of the following changes in circumstances, Ameren, UE, CILCORP and CILCO changed their segments in the third quarter of 2006:
 
•     the Ameren Companies’ chief operating decision-making group began to assess the performance and allocate resources based on a new segment structure and made related organizational and management reporting changes in the third and fourth quarters of 2006;
•     electric generation deregulation in Illinois, which became effective on January 1, 2007;
•     the expiration of affiliate power supply agreements for CIPS and CILCO, and other supply agreements for IP on December 31, 2006;
•     the July 2006 termination of the JDA among UE, Genco and CIPS effective December 31, 2006; and
•     the September 2006 completion of a statewide auction to procure power for CIPS, CILCO and IP for 2007 and beyond, and Marketing Company’s sale in that auction of power being acquired from Genco and AERG.
 
In the third quarter of 2006, Ameren determined that it has three reportable segments: Missouri Regulated, Illinois Regulated and Non-rate-regulated Generation. UE determined that it has one reportable segment: Missouri Regulated. CILCORP and CILCO determined that they have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. A discussion of changes in components of net income between periods by business segment is provided below where material. Prior-period


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presentation has been adjusted for comparative purposes. See Note 17 – Segment Information to our financial statements under Part II, Item 8, of this report for further discussion of Ameren’s, UE’s, CILCORP’s and CILCO’s business segments.
 
Below is a table of income statement components by segment for the years ended December 31, 2006, 2005 and 2004:
 
                                             
                Non-rate-
    Other/
           
    Missouri
    Illinois     regulated
    Intersegment            
2006   Regulated     Regulated(a)     Generation     Eliminations     Total      
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
    (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 revenues
    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
    (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      
2004
                                           
Electric margin
  $ 1,911     $ 454     $ 676     $ (31 )   $ 3,010      
Gas margin
    63       205       -       -       268      
Other revenue
    -       2       2       2       6      
Other operations and maintenance
    (785 )     (336 )     (242 )     26       (1,337 )    
Depreciation and amortization
    (294 )     (124 )     (110 )     (29 )     (557 )    
Taxes other than income taxes
    (222 )     (64 )     (25 )     (1 )     (312 )    
Other income and expenses
    14       19       5       (11 )     27      
Interest expense
    (103 )     (62 )     (146 )     33       (278 )    
Income taxes
    (211 )     (25 )     (60 )     14       (282 )    
Minority interest and preferred dividends
    (6 )     (5 )     (4 )     -       (15 )    
Net Income
    367       64       96       3       530      
                                             
 
(a) Ameren acquired IP on September 30, 2004. Therefore, 2004 included IP results for just three months. See discussion below in each respective section for the effect of the additional nine months of IP results in 2005.


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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, 2006, 2005 and 2004. 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.
 
The variations in electric and gas margins for Ameren show the contribution from IP for the first nine months of 2005 as a separate line item, which allows an easier comparison with other margin components. The variation in IP electric margin in 2005 is compared with the full year of 2004, despite Ameren’s acquisition of IP occurring on September 30, 2004.
 
                                                                 
2006 versus 2005   Ameren(a)     UE     CIPS     Genco     CILCORP     CILCO     IP        
Electric revenue change:
                                                               
Effect of weather (estimate)
  $ (82 )   $ (39 )   $ (16 )   $ -     $ (10 )   $ (10 )   $ (17 )        
Storm-related outages (estimate)
    (10 )     (9 )     (3 )     3       -       -       (1 )        
Noranda
    46       46       -       -       -       -       -          
Illinois service territory transfer
    -       (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          
Fuel and purchased power change:
                                                               
Fuel:
                                                               
Generation and other
  $ (15 )   $ 3     $ -     $ (10 )   $ 6     $ 8     $ 1          
Sales of emission allowances
    14       30       -       (21 )     -       -       -          
Price
    (82 )     (40 )     -       (18 )     (20 )     (20 )     -          
Purchased power
    (31 )     69       (15 )     (10 )     29       29       (52 )        
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          
                                                                 
                                                                 
                                                                 
2005 versus 2004   Ameren(a)     UE     CIPS     Genco     CILCORP     CILCO     IP(c)        
Electric revenue change:
                                                               
IP – January through September 2005
  $ 861     $ -     $ -     $ -     $ -     $ -     $ -          
Effect of weather (estimate)
    115       72       24       -       16       16       51          
Noranda
    81       81       -       -       -       -       -          
Illinois service territory transfer
    -       (104 )     101       74       -       -       -          
Rate reductions
    (7 )     (7 )     -       -       -       -       -          
Interchange revenues
    79       143       (1 )     67       (20 )     (20 )     -          
Transmission service and other revenues
    30       (15 )     10       (6 )     (1 )     (1 )     (5 )        
Growth and other (estimate)
    9       59       38       29       1       1       5          
Total electric revenue change
  $ 1,168     $ 229     $ 172     $ 164     $ (4 )   $ (4 )   $ 51          
Fuel and purchased power change:
                                                               
IP – January through September 2005
  $ (509 )   $ -     $ -     $ -     $ -     $ -     $ -          
Fuel:
                                                               
Generation and other
    (97 )     (57 )     -       (13 )     (17 )     (15 )     -          
Sales of emission allowances
    5       (26 )     -       21       -       -       -          
Price
    (45 )     (41 )     -       (29 )     25       25       -          
Purchased power
    (156 )     (127 )     (131 )     (160 )     (20 )     (20 )     (62 )        
Total fuel and purchased power change
  $ (802 )   $ (251 )   $ (131 )   $ (181 )   $ (12 )   $ (10 )   $ (62 )        
Net change in electric margins
  $ 366     $ (22 )   $ 41     $ (17 )   $ (16 )   $ (14 )   $ (11 )        
Net change in gas margins
  $ 120     $ 10     $ -     $ -     $ 2     $ 2     $ 2          
                                                                 
 
(a) Excludes amounts for IP before the acquisition date of September 30, 2004, and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) The effect of storm-related native-load outages increasing interchange revenues is included under the storm-related outages line.
(c) Includes predecessor information for periods before September 30, 2004.


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2006 versus 2005
 
Ameren
 
Ameren’s electric margin increased by $41 million, or 1%, in 2006 compared with 2005. Factors contributing to an increase in Ameren’s electric margin were as follows:
 
•     A $162 million, or 67%, increase in margins on interchange sales. The expiration of EEI’s affiliate cost-based power supply contract on December 31, 2005, the expiration of several large Marketing Company power supply contracts in 2006, and an increase in plant availability provided Ameren with additional power to sell in the spot market. The increase in margins on interchange sales from these items was reduced by lower power prices, resulting from declining market prices for natural gas, the significant impact of hurricanes and rail disruptions on prices in 2005.
•     Plant efficiencies, primarily at CILCO (AERG), as Ameren’s baseload electric generating plants’ average capacity and equivalent availability factors were approximately 80% and 88%, respectively, in 2006 compared with 76% and 86%, respectively, in 2005.
•     The lack of a UE Callaway nuclear plant refueling and maintenance outage in 2006, which resulted in an increased electric margin of $25 million.
•     Upgrades performed during the refueling and maintenance outage in 2005, which increased Callaway’s output and electric margin by $22 million.
•     Organic growth and industrial customers who switched back to below-market Illinois tariff rates because of the expiration of power contracts with suppliers.
•     Lower purchased power costs at IP.
•     Sales to Noranda, which began receiving power on June 1, 2005, resulting in increased electric margin of $20 million at UE.
•     Increased sales of emission allowances, totaling $14 million, and lower emission allowance costs, totaling $5 million, in 2006 compared with 2005.
 
Factors contributing to a decrease in Ameren’s electric margin were as follows:
 
•     Unfavorable weather conditions, as evidenced by a 9% decline in cooling degree-days, that reduced the electric margin by $33 million in 2006 compared with 2005.
•     Severe storm-related outages in 2006 that reduced overall electric margin by $9 million as less electricity was sold for native load, partially offset by an increase in margins on the sales of this power on the interchange market.
•     An increase in fuel and purchased power costs for native load at UE and Genco due to the expiration of a cost-based power supply contract with EEI.
•     A 12% increase in coal and transportation prices.
•     A $25 million reduction in margins because of the unavailability of UE’s Taum Sauk hydroelectric plant in 2006 compared with 2005.
•     An $11 million reduction in native load margins from UE’s other hydroelectric generation in 2006 compared with 2005.
•     An unscheduled outage in 2006 at UE’s Callaway nuclear plant, which reduced electric margins by an estimated $20 million.
•     Reduced transmission service revenues, primarily due to the elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market.
 
Ameren’s gas margin decreased by $24 million, or 6%, in 2006 compared with 2005 primarily because of the following factors:
 
•     Unfavorable weather conditions, as evidenced by a 9% decrease in heating degree-days, which reduced the gas margin by $15 million in 2006 from 2005. Weather-sensitive residential and commercial gas sales volumes decreased by 8% each, in 2006 compared with 2005.
•     Unrecoverable purchased gas costs, together with unfavorable customer sales mix totaling $19 million.
 
Factors contributing to an increase in Ameren’s gas margin were as follows:
 
•     An IP rate increase that became effective in May 2005, which added revenues of $6 million in 2006.
•     Increased sales to customers, excluding the impact from weather, of 2%, or $4 million.
 
Missouri Regulated
 
UE
 
UE’s total electric margin increased by $21 million in 2006 from 2005. UE’s Missouri Regulated electric margin increased by $9 million in 2006 compared with 2005. Factors contributing to an increase in UE’s electric margin were as follows:
 
•     Sales to Noranda that increased electric margin by $20 million and other organic growth.
•     Increased sales of emission allowances, totaling $30 million.
•     The lack of a scheduled Callaway nuclear plant refueling and maintenance outage in 2006.
•     Capacity upgrades at the Callaway plant during the refueling and maintenance outage in 2005.
 
UE’s other electric margin increased by $12 million as a result of the adoption of Staff Accounting Bulletin 108. See Note 1 – Summary of Significant Accounting Policies, Accounting Changes and Other Matters, to our financial statements under Part II, Item 8, of this report, for further information.
 
Factors that contributed to a decrease in UE’s electric margin were as follows:
 
•     Unfavorable weather conditions that reduced electric margin by $11 million, as evidenced by an 8% decline in cooling degree-days in 2006 compared with 2005.
•     Severe storm-related outages in 2006 that reduced electric native load sales and resulted in an estimated net reduction in overall electric margin of $6 million.
•     Lower margins on nonaffiliate interchange sales in 2006 compared with 2005, which resulted from reduced


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power prices. The average realized power prices on UE’s interchange sales decreased from $48 per megawatthour in 2005 to $37 per megawatthour in 2006. However, margins on interchange sales benefited from the January 10, 2006, amendment of the JDA. The MoPSC-required and FERC-approved change in the JDA methodology (to basing the allocation of third-party short-term power sales of excess generation on generation output instead of load requirements) resulted in $23 million in incremental margins on interchange sales for UE in 2006 compared with 2005.
•     The transfer of UE’s Illinois service territory in May 2005 to CIPS, which decreased electric margin by an estimated $22 million in 2006 compared with 2005.
•     A 9% increase in coal and related transportation prices.
•     Fees of $4 million levied by FERC in 2006 for prior years’ generation benefits provided to UE’s Osage hydroelectric plant.
•     Reduced electric margin because of the unavailability of UE’s Taum Sauk hydroelectric plant.
•     Reduced electric margin from UE’s other hydroelectric generation, due to drought-like conditions across the central and southern portions of Missouri.
•     An unscheduled 20-day outage at UE’s Callaway nuclear plant in the second quarter of 2006 that reduced electric margin (maintenance expenses were covered under warranty).
•     MISO Day Two Energy Market costs, which were $6 million higher in 2006, as this market did not begin operating until the second quarter of 2005.
•     The expiration of a cost-based power supply contract with EEI on December 31, 2005.
•     Reduced transmission service revenues of $13 million, primarily due to elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market.
 
UE’s gas margin decreased by $13 million, or 18%, in 2006 compared with 2005. Factors contributing to the decreased margins were as follows:
 
•     Mild winter weather conditions that reduced gas margins by $2 million, as evidenced by an 8% decrease in heating degree-days in 2006 compared with 2005.
•     The transfer of UE’s Illinois service territory in May 2005 to CIPS, which reduced gas margin by $4 million.
•     A reduction in gas sales to customers, excluding the impacts from weather.
•     Unrecoverable purchased gas costs totaling $4 million.
 
Illinois Regulated
 
Illinois Regulated’s electric margin decreased by $5 million, or 1%, and gas margin decreased by $8 million, or 3%, in 2006 compared with 2005. See below for explanations of electric and gas margin variances for the Illinois Regulated segment.
 
CIPS
 
CIPS’ electric margin increased by $3 million, or 1%, in 2006 compared with 2005. Factors contributing to an increase in CIPS’ electric margin were as follows:
 
•     The transfer to CIPS of UE’s Illinois service territory in May 2005, which increased electric margin by $7 million.
•     Primarily industrial customers, switching back to CIPS from Marketing Company in 2006 because tariff rates were below market rates for power.
•     Decrease in MISO Day Two Energy Market costs of $7 million.
•     Increased miscellaneous revenues of $2 million.
 
Factors contributing to a decrease in CIPS’ electric margin were as follows:
 
•     Unfavorable weather conditions, as evidenced by a 9% decrease in cooling degree-days in 2006 compared with 2005 that reduced electric margins by $7 million.
•     Severe storm-related outages in 2006 that reduced electric sales and reduced the electric margin by $3 million.
•     Reduced transmission service revenues, primarily due to elimination of interim cost recovery mechanisms, and reduced revenues associated with the MISO Day Two Energy Market.
 
Due to the expiration of CIPS’ cost-based power supply agreement with EEI in December 2005, pursuant to which CIPS sold its entitlements under the agreement to Marketing Company, both interchange revenues and purchased power expenses decreased by $34 million in 2006 compared with 2005.
 
CIPS’ gas margin increased by $1 million, or 1%, in 2006, compared with 2005, primarily because the transfer to CIPS of UE’s Illinois service territory in May 2005 added $4 million to gas margin. CIPS’ increase in gas margin was reduced by mild winter weather, as evidenced by a 10% decrease in heating degree-days in 2006 compared with 2005, which reduced the gas margin by $3 million.
 
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 2006 compared with 2005:
 
             
    2006 versus 2005      
CILCO (Illinois Regulated)
  $ 7      
CILCO (AERG)(a)
    22      
Total change in electric margin
  $ 29      
             
 
(a)  See Non-rate-regulated Generation under Results of Operations for a detailed explanation of CILCO’s (AERG) change in electric margin in 2006 compared with 2005.
 
CILCO’s Illinois Regulated electric margin increased by $7 million, or 5%, in 2006 compared with 2005. Factors


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contributing to an increase in CILCO’s Illinois Regulated electric margin were as follows:
 
•     Increased native load growth, primarily in the industrial sector.
•     Increased miscellaneous revenues totaling $2 million.
•     A decrease in MISO Day Two Energy Market costs totaling $2 million.
 
Factors contributing to a decrease in CILCO’s Illinois Regulated electric margin were as follows:
 
•     Unfavorable weather conditions, as evidenced by an 18% decrease in cooling degree-days in 2006 compared with 2005, that reduced electric margins by $7 million.
•     Reduced transmission service revenues, primarily due to elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market.
 
CILCO’s (Illinois Regulated) gas margin decreased by $10 million, or 10%, in 2006 compared with 2005. Factors contributing to a decrease in CILCO’s gas margin were as follows:
 
•     Mild winter weather conditions in CILCO’s service territory, as evidenced by a 7% decrease in heating degree-days in 2006 compared with 2005, that reduced gas margin by $3 million.
•     Lower transportation volumes, together with unfavorable customer sales mix.
 
IP
 
IP’s electric margin decreased by $15 million, or 4%, in 2006 compared with 2005. Factors contributing to a decrease in IP’s electric margin were as follows:
 
•     Unfavorable weather conditions, as evidenced by a 10% decrease in cooling degree-days in 2006 compared with 2005, that reduced electric margins by $9 million.
•     Severe storm-related outages in 2006 that resulted in reduced electric sales, decreasing electric margin by $2 million.
•     Reduced transmission service revenues of $17 million, primarily due to the elimination of interim cost recovery mechanisms and reduced revenues associated with the MISO Day Two Energy Market.
 
Factors contributing to an increase in IP’s electric margin were as follows:
 
•     A net increase in electric margin as a result of primarily industrial customers switching back to IP because tariff rates were below market rates for power. The increase in revenues more than offset an increase in purchased power costs.
•     Lower transmission expenses included in purchased power costs due, in part, to a $6 million favorable settlement of disputed ancillary charges with MISO.
•     Lower MISO Day Two Energy Market costs totaling $4 million.
•     Increased rental and miscellaneous revenues totaling $5 million.
 
IP’s gas margin increased by $1 million, or 1%, in 2006 compared with 2005. Factors contributing to an increase in IP’s gas margin were as follows:
 
•     A rate increase effective in May 2005 that added revenues of $6 million in 2006.
•     Organic growth, primarily in the industrial sector.
 
The increase in gas margin was reduced by mild winter weather conditions, as evidenced by a 9% decrease in heating degree-days in 2006 compared with 2005, that reduced gas margin by $7 million.
 
Non-rate-regulated Generation
 
Non-rate-regulated Generation’s electric margin increased by $53 million, or 8%, in 2006 compared with 2005. See below for explanations of electric margin variances for the Non-rate-regulated Generation segment.
 
Genco
 
Genco’s electric margin decreased by $103 million, or 22%, in 2006 compared with 2005. Factors contributing to a decrease in Genco’s electric margin were as follows:
 
•     Lower wholesale margins as Genco purchased additional power at higher costs to supply Marketing Company after the expiration of the cost-based power supply contract between EEI and its affiliates on December 31, 2005.
•     Higher net emission allowance costs because of a $21 million gain at Genco in the third quarter of 2005, which resulted from the nonmonetary swap of certain earlier vintage-year SO2 emission allowances for later vintage-year allowances.
•     A 9% increase in coal and transportation prices.
•     Lower margins on interchange sales in 2006 compared with 2005, primarily because of lower power prices, and a $23 million reduction in 2006 due to the amendment of the JDA among UE, Genco and CIPS. The average realized power prices on Genco’s interchange sales decreased from $47 per megawatt in 2005 to $38 per megawatt hour in 2006.
•     Higher MISO Day Two Energy Market costs totaling $12 million in 2006 compared with 2005, since the market did not begin operating until the second quarter of 2005.
 
Genco’s decrease in electric margin was reduced by increased sales to CIPS as a result of the May 2005 transfer of UE’s Illinois service territory to CIPS.
 
CILCO (AERG)
 
AERG’s electric margin increased by $22 million, or 25%, in 2006 compared with 2005. Factors contributing to an increase in AERG’s electric margin were as follows:
 
•     Lower purchased power costs due to improved power plant availability.
•     A decrease in emission allowance utilization expenses of $9 million in 2006 compared with 2005.


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•     An increase in margins on interchange sales due to improved plant availability. AERG’s electric generating plants’ average capacity and equivalent availability factors were approximately 69% and 81%, respectively, in 2006 compared with 61% and 73%, respectively, in 2005.
 
AERG’s electric margin was reduced by a 31% increase in coal and transportation prices in 2006 over 2005.
 
EEI
 
EEI’s electric margin increased by $194 million in 2006 compared with 2005. Factors contributing to EEI’s increase in electric margin were as follows:
 
•     An increase in margins on interchange sales, which resulted from the expiration of its affiliate cost-based sales contract on December 31, 2005, and its replacement with an affiliate market-based sales contract.
•     Sales of emission allowances.
 
2005 versus 2004
 
Ameren
 
Ameren’s electric margin increased by $366 million in 2005 compared with 2004. An additional nine months of IP results was included in 2005, which added $352 million of electric margin. Other factors contributing to an increase in Ameren’s electric margin were as follows:
 
•     An increase in margin on interchange sales of $66 million in 2005 compared with 2004, principally because of higher power prices and access to the MISO Day Two Energy Market. Average realized prices on Ameren’s interchange sales increased from $30 per megawatthour in 2004 to $44 per megawatthour in 2005. Higher market prices for natural gas, emission allowances, and coal in 2005 contributed to the higher power prices. Hurricanes and disruptions in coal delivery contributed to these higher prices. The MISO Day Two Energy Market also contributed to an increase in margins on interchange sales by an estimated $34 million in 2005 as compared to 2004. With the inception of the MISO Day Two Energy Market in 2005, all transmission losses, previously borne by the energy providers, were transferred to MISO, which effectively allowed the generation units to increase sales by approximately 1.8%.
•     Favorable weather conditions, as warmer summer weather in 2005 compared with extremely mild conditions in the summer of 2004 resulted in a 37% increase in cooling degree-days in 2005 in Ameren’s service territory. Excluding the additional nine months of IP sales in 2005, Ameren’s weather-sensitive residential and commercial sales were up 10% and 3%, respectively, in 2005 compared with 2004.
•     Sales to Noranda, which increased electric margin by $33 million. Effective June 1, 2005, UE began to supply approximately 470 megawatts (peak load) of electric service (or about 5% of UE’s generating capability, including committed purchases) to Noranda’s primary aluminum smelter in southeast Missouri under a 15-year agreement.
•     Organic growth.
 
Factors contributing to a decrease in Ameren’s electric margin were as follows:
 
•     MISO costs that were $107 million higher in 2005 compared with 2004. MISO costs increased as a result of line losses, transmission congestion charges, and charges associated with volatile weather conditions and deviations of actual from forecasted plant availability and customer loads. Some of these higher costs were attributed to the relative infancy of the MISO Day Two Energy Market, suboptimal dispatching of plants, and price volatility.
•     Electric rate reductions resulting from the 2002 UE electric rate case settlement in Missouri that negatively affected electric revenues by $7 million during 2005. These were the final rate reductions under the 2002 rate case settlement.
•     An extended refueling and maintenance outage at UE’s Callaway nuclear plant in 2005.
•     Expiration and nonrenewal of low-margin, non-rate-regulated power sales contracts to customers outside our core service territory.
•     Coal conservation efforts that reduced interchange sales.
•     Unscheduled coal-fired plant outages during the peak summer period, which resulted in increased higher-cost CT generation used to serve the demand.
•     Increased utilization and mark-to-market losses on emission allowance put options of $50 million in 2005. However, fuel and purchased power costs were reduced in 2005 by a $21 million gain at Genco resulting from the nonmonetary swap of certain earlier vintage-year SO2 emission allowances for later vintage-year emission allowances.
 
Ameren’s gas margin increased by $120 million in 2005 compared with 2004, primarily because of the inclusion of an additional nine months of IP results in 2005. Excluding these IP results, gas margin increased $16 million, primarily due to UE’s rate increase, which became effective in the first quarter of 2005, and more favorable weather conditions in the fourth quarter of 2005 than in the same period in 2004.
 
Missouri Regulated
 
UE
 
UE’s electric margin decreased by $22 million in 2005 compared with 2004. Factors contributing to a decrease in UE’s electric margin were as follows:
 
•     The transfer of UE’s Illinois service territory to CIPS, which was completed in May 2005. This transfer resulted in an estimated decrease in electric margin of $74 million in 2005.
•     Reduced electric rates in the first quarter of 2005 as compared to the first quarter of 2004.


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•     Increased MISO Day Two Energy Market costs totaling $59 million in 2005 compared with 2004.
•     Coal conservation efforts that reduced excess plant production and interchange sales.
•     Increased CT generation using high-cost natural gas to serve increased summer demand.
•     A $12 million decrease in emission allowance transactions in 2005 compared with 2004.
 
Factors contributing to an increase in UE’s electric margin were as follows:
 
•     Sales to Noranda, which increased electric margin by $33 million.
•     An increase in margins on interchange sales. Margins on interchange sales with nonaffiliates increased $26 million in 2005, compared with 2004, primarily because of higher power prices and access to the MISO Day Two Energy Market. The MISO Day Two Energy Market resulted in an increase in margins on interchange sales by an estimated $23 million in 2005 compared to 2004, as a result of reduced transmission losses.
•     Favorable weather conditions as evidenced by a 25% increase in cooling degree-days in 2005 compared with 2004.
 
UE’s gas margin increased by $10 million in 2005 compared with 2004, because of the effect of a rate increase in the first quarter of 2005 and favorable weather. This increase was reduced by the May 2005 transfer of UE’s Illinois service territory to CIPS, which decreased the gas margin by $4 million.
 
Illinois Regulated
 
Illinois Regulated’s electric margin increased by $41 million, or 5%, in 2005 compared with 2004. Illinois Regulated’s gas margin increased by $5 million, or 2%, in 2005 compared with 2004. See below for explanations of the variances in electric and gas margins for the Illinois Regulated segment.
 
CIPS
 
CIPS’ electric margin increased by $41 million in 2005 compared with 2004. Factors contributing to an increase in CIPS’ electric margin were as follows:
 
•     Increased native load sales as a result of the transfer to CIPS of UE’s Illinois service territory. The transfer of the Illinois service territory resulted in an estimated increase in electric margin of $27 million in 2005.
•     Favorable weather conditions, as evidenced by a 44% increase in cooling degree-days in 2005 compared with 2004.
•     Customers who switched back to CIPS from Marketing Company because tariff rates were below market rates.
 
CIPS’ electric margin was reduced by a $23 million increase in MISO costs, included in purchased power, in 2005 compared with 2004.
 
CIPS’ 2005 gas margin was comparable with 2004. The transfer to CIPS of UE’s service territory and favorable weather conditions offset gas inventory and other adjustments. The service territory transfer increased CIPS’ gas margin by $4 million in 2005.
 
CILCO (Illinois Regulated)
 
The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for 2005 compared with 2004:
 
             
    2005 versus 2004      
CILCO (Illinois Regulated)
  $ 11      
CILCO (AERG)(a)
    (25 )    
Total change in electric margin
  $