10-K/A 1 d10ka.htm AMENDMENT NO. 1 TO FORM 10-K Amendment No. 1 to Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K/A

AMENDMENT NO. 1

 

  (X) Annual report pursuant to Section 13 or 15(d)
     of the Securities Exchange Act of 1934
     for the fiscal year ended December 31, 2005

OR

  (  ) Transition report pursuant to Section 13 or 15(d)
     of the Securities Exchange Act of 1934
     for the transition period from          to         .

 

Commission

File Number

   

Exact name of registrant as specified in its charter;

State of Incorporation;

Address and Telephone Number

    IRS Employer
Identification No.

1-2732

    Central Illinois Light Company    37-0211050
  

(Illinois Corporation)

   
  

300 Liberty Street

   
  

Peoria, Illinois 61602

   
  

(309) 677-5271

   

Securities Registered Pursuant to Section 12(b) of the Securities Exchange Act of 1934:

The following class 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: Preferred Stock, cumulative, $100 par value per share – 4 1/2% Series

Securities Registered Pursuant to Section 12(g) of the Securities Exchange Act of 1934: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933. Yes (  )    No (X)

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes (  )    No (X)

Indicate by check mark whether the registrant: (1) has 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) has been subject to such filing requirements for the past 90 days. Yes  (X)    No  (  )

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 the 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.  (X)

Indicate by check mark whether the 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    
(  )   (  )   (X)  

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes (  )    No (X)

As of June 30, 2005, the shares of common stock of Central Illinois Light Company were held by affiliates.

The number of shares outstanding of the registrant’s class of common stock as of February 1, 2006, was as follows:

Common stock, no par value, held by CILCORP Inc.

(parent company of the registrant and subsidiary of

Ameren Corporation): 13,563,871

  

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive information statement of Central Illinois Light Company for the 2006 annual meeting of shareholders are incorporated by reference into Part III of this Form 10-K.

EXPLANATORY NOTE

This Amendment on Form 10-K/A constitutes Amendment No. 1 to Central Illinois Light Company’s Annual Report on Form 10-K for the year ended December 31, 2005, which was originally filed with the Securities and Exchange Commission (SEC) on March 7, 2006 (Annual Report). This Amendment is being filed solely to correct an error in the report provided by the Independent Registered Public Accounting Firm with respect to the financial statements of Central Illinois Light Company included in Item 8.

This Amendment revises the first sentence of the Report of Independent Registered Public Accounting Firm with respect to Central Illinois Light Company from “In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Central Illinois Light Company and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.” to “In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Central Illinois Light Company and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.” It does not otherwise affect any of the financial statements and footnotes contained in the Annual Report and does not reflect events occurring after the original filing date of March 7, 2006.

In order to comply with certain requirements of the SEC’s rules in connection with the filing of this Amendment on Form 10-K/A, this Amendment includes (i) the complete text of Item 8. Financial Statements and Supplementary Data and (ii) Item 15. Exhibits and Financial Statement Schedules to reflect the filing of updated certifications of the principal executive and principal financial officers of Central Illinois Light Company.

The Form 10-K for the year ended December 31, 2005 that was originally filed with the SEC on March 7, 2006 was a combined Form 10-K that was 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. This Amendment does not constitute an amendment to the Form 10-K filed by Ameren Corporation, Union Electric Company, Central Illinois Public Service Company, Ameren Energy Generating Company, CILCORP Inc. or Illinois Power Company for the year ended December 31, 2005. Central Illinois Light Company is filing on its own behalf all of the information contained in this Amendment that relates to it. Central Illinois Light Company is not filing any information that does not relate to it, and therefore makes no representation as to any such information.

 

1

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.

AES – The AES Corporation.

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 serves as a power marketing and risk management agent for UE and Genco primarily for transactions of less than one year.

Ameren Services – Ameren Services Company, an Ameren Corporation subsidiary that provides support services to Ameren and its subsidiaries.

APB – Accounting Principles Board.

ARO – Asset retirement obligations.

Baseload – The minimum amount of electric power delivered or required over a given period of time at a steady rate.

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 primarily non-rate-regulated electric generation business through AERG, and a rate-regulated natural gas transmission and distribution business, all in Illinois, as AmerenCILCO. CILCO owns all of the common stock of AERG.

CILCORP – CILCORP Inc., an Ameren Corporation subsidiary that operates as a holding company for CILCO and various non-rate-regulated subsidiaries.

CIPS – Central Illinois Public Service Company, an Ameren Corporation subsidiary that operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenCIPS.

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.

Development Company – Ameren Energy Development Company, a Resources Company subsidiary and Genco parent, which primarily develops and constructs generating facilities for Genco.

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 electric generation and 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.

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 Number (FIN). 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.

 

2

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.

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, IP and (prior to May 2, 2005) UE.

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.

Illinova – Illinova Corporation, the former parent company of IP.

IP – Illinois Power Company, which was acquired from Dynegy by, and became a subsidiary of, Ameren Corporation 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. As of December 31, 2003, under FIN 46R, IP SPT was no longer consolidated within IP’s financial statements.

IUOE – International Union of Operating Engineers, a labor union.

Jobs Creation Act – The American Jobs Creation Act of 2004.

Kilowatthour – A measure of electricity consumption equivalent to the use of 1,000 watts of power over a period of one hour.

LIBOR – London Interbank Offered Rate, an interest rate that banks charge each other for loans.

MAIN – Mid-America Interconnected Network, Inc., was 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, primarily for periods over one year.

Medina Valley – AmerenEnergy Medina Valley Cogen (No. 4) LLC and its subsidiaries, which are 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 OPC – Missouri Office of the Public Counsel, which was established to represent the interests of Missouri utility customers in proceedings before the MoPSC.

MMBtu – One million Btus.

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.

NOx – Nitrogen oxide.

Noranda – Noranda Aluminum, Inc.

NRC – Nuclear Regulatory Commission, a U.S. government agency.

NYMEX – New York Mercantile Exchange.

 

3

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 enacted on August 8, 2005.

PUHCA 2005 – The Public Utility Holding Company Act of 2005, enacted as part of the Energy Policy Act of 2005, effective February 8, 2006.

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 Illinois’ deregulation legislation. 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 and, prior to May 2, 2005, in Illinois, as AmerenUE.

 

4

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

of Ameren Corporation:

We have completed integrated audits of Ameren Corporation’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005 and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

 

5

Consolidated financial statements and financial statement schedule

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Ameren Corporation and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003 and December 31, 2005.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2006

 

6

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Union Electric Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Union Electric Company and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003 and December 31, 2005.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2006

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Central Illinois Public Service Company:

In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Central Illinois Public Service Company at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of December 31, 2005.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2006

 

7

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Ameren Energy Generating Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Ameren Energy Generating Company and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003 and December 31, 2005.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2006

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of CILCORP Inc.:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of CILCORP Inc. and its subsidiaries at December 31, 2005 and 2004 (successor), and the results of their operations and their cash flows for the years ended December 31, 2005 and 2004 (successor) and for the periods February 1, 2003 to December 31, 2003 (successor) and January 1, 2003 to January 31, 2003 (predecessor) in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the years ended December 31, 2005 and 2004 listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003 and December 31, 2005.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2006

 

8

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Central Illinois Light Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Central Illinois Light Company and its subsidiaries at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the years ended December 31, 2005 and 2004 listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003 and December 31, 2005.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2006

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Illinois Power Company:

In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial position of Illinois Power Company at December 31, 2005 and 2004 (successor), and the results of their operations and their cash flows for the year ended December 31, 2005 and for the periods October 1, 2004 to December 31, 2004 (successor) and January 1, 2004 to September 30, 2004 (predecessor) and for the year ended December 31, 2003 (predecessor) in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for asset retirement costs as of January 1, 2003 and December 31, 2005. As discussed in Note 1, the Company adopted certain provisions of Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities an interpretation of ARB 51 (revised December 2003), as of December 31, 2003.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2006

 

9

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF INCOME

(In millions, except per share amounts)

 

    Year Ended December 31,  
          2005                 2004                 2003        

Operating Revenues:

      

Electric

   $      5,431     $      4,263     $      3,918  

Gas

     1,345       866       648  

Other

     4       6       8  
                       

Total operating revenues

     6,780       5,135       4,574  
                       

Operating Expenses:

      

Fuel and purchased power

     2,055       1,253       1,036  

Gas purchased for resale

     957       598       457  

Other operations and maintenance

     1,487       1,337       1,224  

Coal contract settlement

     -       -       (51 )

Depreciation and amortization

     632       557       519  

Taxes other than income taxes

     365       312       299  
                       

Total operating expenses

     5,496       4,057       3,484  
                       

Operating Income

     1,284       1,078       1,090  

Other Income and Expenses:

      

Miscellaneous income

     29       32       27  

Miscellaneous expense

     (12 )     (5 )     (15 )
                       

Total other income

     17       27       12  
                       

Interest Charges

     301       278       277  

Income Before Income Taxes, Minority Interest and Preferred Dividends of Subsidiaries and Cumulative Effect of Change in Accounting Principle

     1,000       827       825  

Income Taxes

     356       282       301  
                       

Income Before Minority Interest and Preferred Dividends of Subsidiaries and Cumulative Effect of Change in Accounting Principle

     644       545       524  

Minority Interest and Preferred Dividends of Subsidiaries

     (16 )     (15 )     (18 )
                       

Income Before Cumulative Effect of Change in Accounting Principle

     628       530       506  

Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes (Benefit) of $(15), $-, and $12

     (22 )     -       18  
                       

Net Income

   $ 606     $ 530     $ 524  
                       

Earnings per Common Share – Basic and Diluted:

      

Income before cumulative effect of change in accounting principle

   $ 3.13     $ 2.84     $ 3.14  

Cumulative effect of change in accounting principle, net of income taxes

     (0.11 )     -       0.11  
                       

Earnings per common share – basic and diluted

   $ 3.02     $ 2.84     $ 3.25  
                       

Dividends per Common Share

   $ 2.54     $ 2.54     $ 2.54  

Average Common Shares Outstanding

     200.8       186.4       161.1  

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

 

10

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

(In millions, except per share amounts)

 

     December 31,  
             2005                     2004          
ASSETS     
Current Assets:     

Cash and cash equivalents

    $ 96     $ 69  

Accounts receivables – trade (less allowance for doubtful
accounts of $22 and $14, respectively)

      552       442  

Unbilled revenue

      382       336  

Miscellaneous accounts and notes receivable

      31       38  

Materials and supplies

      572       497  

Other current assets

      185       90  
                

Total current assets

      1,818       1,472  
                

Property and Plant, Net

      13,572       13,297  

Investments and Other Assets:

     

Investments in leveraged leases

      50       140  

Nuclear decommissioning trust fund

      250       235  

Goodwill and other intangibles, net

      1,222       1,066  

Other assets

      419       411  

Regulatory assets

      831       829  
                

Total investments and other assets

      2,772       2,681  
                

TOTAL ASSETS

    $ 18,162     $ 17,450  
                
LIABILITIES AND STOCKHOLDERS’ EQUITY     

Current Liabilities:

     

Current maturities of long-term debt

    $ 96     $ 423  

Short-term debt

      193       417  

Accounts and wages payable

      706       567  

Taxes accrued

      131       26  

Other current liabilities

      361       362  
                

Total current liabilities

      1,487       1,795  
                

Long-term Debt, Net

      5,354       5,021  

Preferred Stock of Subsidiary Subject to Mandatory Redemption

      19       20  

Deferred Credits and Other Liabilities:

     

Accumulated deferred income taxes, net

      1,969       1,914  

Accumulated deferred investment tax credits

      129       139  

Regulatory liabilities

      1,132       1,042  

Asset retirement obligations

      518       439  

Accrued pension and other postretirement benefits

      760       756  

Other deferred credits and liabilities

      218       315  
                

Total deferred credits and other liabilities

      4,726       4,605  
                

Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption

      195       195  

Minority Interest in Consolidated Subsidiaries

      17       14  

Commitments and Contingencies (Notes 1, 3, 15 and 16)

     

Stockholders’ Equity:

     

Common stock, $.01 par value, 400.0 shares authorized –
shares outstanding of 204.7 and 195.2, respectively

      2       2  

Other paid-in capital, principally premium on common stock

      4,399       3,949  

Retained earnings

      1,999       1,904  

Accumulated other comprehensive loss

      (24 )     (45 )

Other

      (12 )     (10 )
                

Total stockholders’ equity

      6,364       5,800  
                

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

    $       18,162     $       17,450  
                

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

 

11

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)

 

    Year Ended December 31,  
          2005                 2004                 2003        

Cash Flows From Operating Activities:

      

Net income

   $         606     $         530     $         524  

Adjustments to reconcile net income to net cash provided by operating activities:

      

Cumulative effect of change in accounting principle

     22       -       (18 )

Gain on sale of leveraged leases

     (22 )     -       -  

Depreciation and amortization

     588       557       519  

Amortization of nuclear fuel

     28       31       33  

Amortization of debt issuance costs and premium/discounts

     15       13       10  

Deferred income taxes and investment tax credits, net

     59       339       1  

Coal contract settlement

     -       36       (36 )

Other

     2       (44 )     -  

Changes in assets and liabilities, excluding the effects of acquisitions:

      

Receivables, net

     (160 )     (18 )     6  

Materials and supplies

     (75 )     (25 )     (47 )

Accounts and wages payable

     129       29       (16 )

Taxes accrued

     107       (67 )     39  

Assets, other

     (113 )     (62 )     (15 )

Liabilities, other

     (37 )     (3 )     58  

Pension and other postretirement benefit obligations, net

     22       (187 )     (36 )
                       

Net cash provided by operating activities

     1,171       1,129       1,022  
                       

Cash Flows From Investing Activities:

      

Capital expenditures

     (947 )     (806 )     (682 )

Proceeds from sale of leveraged lease companies, net

     54       -       -  

Acquisitions, net of cash acquired

     12       (443 )     (479 )

Nuclear fuel expenditures

     (17 )     (42 )     (23 )

Other

     17       25       3  
                       

Net cash used in investing activities

     (881 )     (1,266 )     (1,181 )
                       

Cash Flows From Financing Activities:

      

Dividends on common stock

     (511 )     (479 )     (410 )

Capital issuance costs

     (6 )     (40 )     (14 )

Short-term debt, net

     (224 )     256       (110 )

Redemptions, repurchases, and maturities:

      

Nuclear fuel lease

     -       (67 )     (46 )

Long-term debt

     (618 )     (1,465 )     (815 )

Preferred stock

     (1 )     (1 )     (31 )

Issuances:

      

Common stock

     454       1,441       361  

Long-term debt

     643       458       698  

Other

     -       (8 )     9  
                       

Net cash provided by (used in) financing activities

     (263 )     95       (358 )
                       

Net change in cash and cash equivalents

     27       (42 )     (517 )

Cash and cash equivalents at beginning of year

     69       111       628  
                       

Cash and cash equivalents at end of year

   $ 96     $ 69     $ 111  
                       

Cash Paid During the Periods:

      

Interest

   $ 307     $ 337     $ 286  

Income taxes, net

     187       28       266  

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

 

12

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)

 

    December 31,  
          2005                 2004                 2003        

Common Stock:

      

Beginning of year

   $ 2     $ 2     $ 2  

Shares issued

     -       -       -  
                       

Common stock, end of year

     2       2       2  
                       

Other Paid-in Capital:

      

Beginning of year

     3,949       2,552       2,203  

Shares issued (less issuance costs of $1, $37 and $8, respectively)

     454       1,404       353  

Tax benefit of stock option exercises

     2       5       -  

Employee stock awards

     (6 )     (12 )     (4 )
                       

Other paid-in capital, end of year

     4,399       3,949       2,552  
                       

Retained Earnings:

      

Beginning of year

     1,904       1,853       1,739  

Net income

     606       530       524  

Dividends

     (511 )     (479 )     (410 )
                       

Retained earnings, end of year

     1,999       1,904       1,853  
                       

Accumulated Other Comprehensive Income (Loss):

      

Derivative financial instruments, beginning of year

     17       12       9  

Change in derivative financial instruments

     23       5       3  
                       

Derivative financial instruments, end of year

     40       17       12  
                       

Minimum pension liability, beginning of year

     (62 )     (56 )     (102 )

Change in minimum pension liability

     (2 )     (6 )     46  
                       

Minimum pension liability, end of year

     (64 )     (62 )     (56 )
                       

Total accumulated other comprehensive loss, end of year

     (24 )     (45 )     (44 )
                       

Other:

      

Beginning of year

     (10 )     (9 )     (9 )

Restricted stock compensation awards

     (8 )     (6 )     (5 )

Compensation amortized and mark-to-market adjustments

     6       5       5  
                       

Other, end of year

     (12 )     (10 )     (9 )
                       

Total Stockholders’ Equity

   $ 6,364     $ 5,800     $ 4,354  
                       

Comprehensive Income, Net of Taxes:

      

Net income

   $ 606     $ 530     $ 524  

Unrealized net gain on derivative hedging instruments, net of income taxes of $19, $9, and $2, respectively

     31       8       5  

Reclassification adjustments for (gains) included in net income, net of income taxes of $5, $4, and $1, respectively

     (8 )     (3 )     (2 )

Minimum pension liability adjustment, net of income tax (benefit) of $(1), $(4), and $27, respectively

     (2 )     (6 )     46  
                       

Total comprehensive income, net of taxes

   $ 627     $ 529     $ 573  
                       
                         
     

Common stock shares at beginning of period

     195.2       162.9       154.1  

Shares issued

     9.5       32.3       8.8  
                       

Common stock shares at end of period

           204.7             195.2             162.9  
                       

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

 

13

UNION ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF INCOME

(In millions)

 

    Year Ended December 31,  
          2005                 2004                 2003        

Operating Revenues:

      

Electric

   $       2,706     $       2,477     $       2,471  

Gas

     181       163       145  

Other

     2       -       -  
                       

Total operating revenues

     2,889       2,640       2,616  
                       

Operating Expenses:

      

Fuel and purchased power

     817       566       545  

Gas purchased for resale

     108       100       91  

Other operations and maintenance

     771       785       747  

Coal contract settlement

     -       -       (51 )

Depreciation and amortization

     324       294       284  

Taxes other than income taxes

     229       222       213  
                       

Total operating expenses

     2,249       1,967       1,829  
                       

Operating Income

     640       673       787  

Other Income and Expenses:

      

Miscellaneous income

     28       25       23  

Miscellaneous expense

     (7 )     (7 )     (7 )
                       

Total other income

     21       18       16  
                       

Interest Charges

     116       104       105  
                       

Income Before Income Taxes

     545       587       698  

Income Taxes

     193       208       251  
                       

Net Income

     352       379       447  

Preferred Stock Dividends

     6       6       6  
                       

Net Income Available to Common Stockholder

   $ 346     $ 373     $ 441  
                       

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

 

14

UNION ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEET

(In millions, except per share amounts)

 

     December 31,  
           2005                 2004        
ASSETS     

Current Assets:

     

Cash and cash equivalents

    $ 20     $ 48  

Accounts receivable – trade (less allowance for doubtful
accounts of $6 and $3, respectively)

      190       188  

Unbilled revenue

      133       118  

Miscellaneous accounts and notes receivable

      7       13  

Accounts receivable – affiliates

      53       8  

Current portion of intercompany note receivable – CIPS

      6       -  

Materials and supplies

      199       199  

Other current assets

      57       18  
                

Total current assets

      665       592  
                

Property and Plant, Net

      7,379       7,075  

Investments and Other Assets:

     

Nuclear decommissioning trust fund

      250       235  

Intercompany note receivable – CIPS

      61       -  

Other assets

      332       263  

Regulatory assets

      590       585  
                

Total investments and other assets

      1,233       1,083  
                

TOTAL ASSETS

    $       9,277     $       8,750  
                
LIABILITIES AND STOCKHOLDERS’ EQUITY     

Current Liabilities:

     

Current maturities of long-term debt

    $ 4     $ 3  

Short-term debt

      80       375  

Borrowings from money pool

      -       2  

Accounts and wages payable

      274       252  

Accounts and wages payable – affiliates

      134       73  

Taxes accrued

      59       51  

Other current liabilities

      96       108  
                

Total current liabilities

      647       864  
                

Long-term Debt, Net

      2,698       2,059  

Deferred Credits and Other Liabilities:

     

Accumulated deferred income taxes, net

      1,277       1,217  

Accumulated deferred investment tax credits

      96       108  

Regulatory liabilities

      802       776  

Asset retirement obligations

      466       431  

Accrued pension and other postretirement benefits

      203       219  

Other deferred credits and liabilities

      72       80  
                

Total deferred credits and other liabilities

      2,916       2,831  
                

Commitments and Contingencies (Notes 1, 3, 15 and 16)

     

Stockholders’ Equity:

     

Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding

      511       511  

Preferred stock not subject to mandatory redemption

      113       113  

Other paid-in capital, principally premium on common stock

      733       718  

Retained earnings

      1,689       1,688  

Accumulated other comprehensive loss

      (30 )     (34 )
                

Total stockholders’ equity

      3,016       2,996  
                

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

    $ 9,277     $ 8,750  
                

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

 

15

UNION ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)

 

    Year Ended December 31  
          2005                 2004                 2003        

Cash Flows From Operating Activities:

      

Net income

   $         352     $         379     $         447  

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation and amortization

     324       294       284  

Amortization of nuclear fuel

     28       31       33  

Amortization of debt issuance costs and premium/discounts

     5       5       4  

Deferred income taxes and investment tax credits, net

     33       111       37  

Coal contract settlement

     -       36       (36 )

Other

     11       7       -  

Changes in assets and liabilities:

      

Receivables, net

     (82 )     7       (4 )

Materials and supplies

     -       (24 )     (13 )

Accounts and wages payable

     75       9       (21 )

Taxes accrued

     8       -       (52 )

Assets, other

     (36 )     (27 )     (41 )

Liabilities, other

     (4 )     20       20  

Pension and other postretirement obligations, net

     (16 )     (99 )     (25 )
                       

Net cash provided by operating activities

     698       749       633  
                       

Cash Flows From Investing Activities:

      

Capital expenditures

     (787 )     (524 )     (480 )

Nuclear fuel expenditures

     (17 )     (42 )     (23 )

Other

     12       (14 )     -  
                       

Net cash used in investing activities

     (792 )     (580 )     (503 )
                       

Cash Flows From Financing Activities:

      

Dividends on common stock

     (280 )     (315 )     (288 )

Dividends on preferred stock

     (6 )     (6 )     (6 )

Capital issuance costs

     (5 )     (4 )     (6 )

Changes in short-term debt, net

     (295 )     225       (100 )

Changes in money pool borrowings

     (2 )     2       (15 )

Redemptions, repurchases, and maturities:

      

Nuclear fuel lease

     -       (67 )     (46 )

Long-term debt

     (3 )     (377 )     (367 )

Issuances:

      

Long-term debt

     643       404       698  

Capital contribution from parent

     15       -       -  

Other

     (1 )     2       6  
                       

Net cash provided by (used in) financing activities

     66       (136 )     (124 )
                       

Net change in cash and cash equivalents

     (28 )     33       6  

Cash and cash equivalents at beginning of year

     48       15       9  
                       

Cash and cash equivalents at end of year

   $ 20     $ 48     $ 15  
                       

Cash Paid During the Periods:

      

Interest

   $ 104     $ 101     $ 100  

Income taxes, net

     152       115       306  

Noncash Investing Activities:

In 2005, UE sold an interest in assets to CIPS in exchange for a promissory note from CIPS, and UE contributed an interest in assets to Ameren Corporation. See Note 3 – Rate and Regulatory Matters for further details.

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

 

16

UNION ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)

 

    December 31,  
          2005                 2004                 2003        

Common Stock

   $ 511     $ 511     $ 511  

Preferred Stock Not Subject to Mandatory Redemption

     113       113       113  

Other Paid-in Capital:

      

Beginning of year

     718       702       702  

Capital contribution from parent

     15       16       -  
                       

Other paid-in capital, end of year

     733       718       702  
                       

Retained Earnings:

      

Beginning of year

     1,688       1,630       1,477  

Net income

     352       379       447  

Common stock dividends

     (280 )     (315 )     (288 )

Preferred stock dividends

     (6 )     (6 )     (6 )

Dividend-in-kind to Ameren

     (67 )     -       -  

Other

     2       -       -  
                       

Retained earnings, end of year

     1,689       1,688       1,630  
                       

Accumulated Other Comprehensive Income (Loss):

      

Derivative financial instruments, beginning of year

     2       1       4  

Change in derivative financial instruments

     3       1       (3 )
                       

Derivative financial instruments, end of year

     5       2       1  
                       

Minimum pension liability, beginning of year

     (36 )     (34 )     (62 )

Change in minimum pension liability

     1       (2 )     28  
                       

Minimum pension liability, end of year

     (35 )     (36 )     (34 )
                       

Total accumulated other comprehensive loss, end of year

     (30 )     (34 )     (33 )
                       

Total Stockholders’ Equity

   $       3,016     $       2,996     $       2,923  
                       

Comprehensive Income, Net of Taxes:

      

Net income

   $ 352     $ 379     $ 447  

Unrealized net gain (loss) on derivative hedging instruments, net of income taxes (benefit) of $3, $1, and $(1), respectively

     4       1       (3 )

Reclassification adjustments for (gains) included in net income, net of income taxes of $1, $-, and $-, respectively

     (1 )     -       -  

Minimum pension liability adjustment, net of income taxes (benefit) of $1, $(2), and $16, respectively

     1       (2 )     28  
                       

Total comprehensive income, net of taxes

   $ 356     $ 378     $ 472  
                       

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

 

17

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

STATEMENT OF INCOME

(In millions)

 

    Year Ended December 31  
          2005                 2004                 2003        

Operating Revenues:

      

Electric

   $         710     $         538     $         555  

Gas

     222       195       185  

Other

     2       2       2  
                       

Total operating revenues

     934       735       742  
                       

Operating Expenses:

      

Purchased power

     456       325       341  

Gas purchased for resale

     152       125       121  

Other operations and maintenance

     144       148       156  

Depreciation and amortization

     64       53       52  

Taxes other than income taxes

     33       26       27  
                       

Total operating expenses

     849       677       697  
                       

Operating Income

     85       58       45  

Other Income and Expenses:

      

Miscellaneous income

     18       24       27  

Miscellaneous expense

     (4 )     (1 )     (3 )
                       

Total other income

     14       23       24  
                       

Interest Charges

     30       33       34  
                       

Income Before Income Taxes

     69       48       35  

Income Taxes

     25       16       6  
                       

Net Income

     44       32       29  

Preferred Stock Dividends

     3       3       3  
                       

Net Income Available to Common Stockholder

   $ 41     $ 29     $ 26  
                       

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

 

18

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

BALANCE SHEET

(In millions)

 

    December 31,  
          2005               2004        
ASSETS    

Current Assets:

    

Cash and cash equivalents

   $ -   $ 2  

Accounts receivable – trade (less allowance for doubtful
accounts of $4 and $1, respectively)

     70     48  

Unbilled revenue

     71     71  

Accounts receivable – affiliates

     18     12  

Current portion of intercompany note receivable – Genco

     34     249  

Current portion of intercompany tax receivable – Genco

     10     11  

Materials and supplies

     75     56  

Other current assets

     28     19  
             

Total current assets

     306     468  
             

Property and Plant, Net

     1,130     953  

Investments and Other Assets:

    

Intercompany note receivable – Genco

     163     -  

Intercompany tax receivable – Genco

     125     138  

Other assets

     24     23  

Regulatory assets

     36     33  
             

Total investments and other assets

     348     194  
             

TOTAL ASSETS

   $ 1,784   $ 1,615  
             
LIABILITIES AND STOCKHOLDERS’ EQUITY    

Current Liabilities:

    

Current maturities of long-term debt

   $ 20   $ 20  

Accounts and wages payable

     36     27  

Accounts and wages payable – affiliates

     65     49  

Borrowings from money pool

     2     68  

Current portion of intercompany note payable – UE

     6     -  

Taxes accrued

     26     -  

Other current liabilities

     43     32  
             

Total current liabilities

     198     196  
             

Long-term Debt, Net

     410     430  

Deferred Credits and Other Liabilities:

    

Accumulated deferred income taxes and investment tax credits, net

     302     308  

Intercompany note payable – UE

     61     -  

Regulatory liabilities

     208     151  

Other deferred credits and liabilities

     36     40  
             

Total deferred credits and other liabilities

     607     499  
             

Commitments and Contingencies (Notes 1, 3, and 15)

    

Stockholders’ Equity:

    

Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding

     -     -  

Other paid-in capital

     189     121  

Preferred stock not subject to mandatory redemption

     50     50  

Retained earnings

     329     323  

Accumulated other comprehensive income (loss)

     1     (4 )
             

Total stockholders’ equity

     569     490  
             

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $       1,784   $       1,615  
             

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

 

19

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

STATEMENT OF CASH FLOWS

(In millions)

 

    Year Ended December 31,  
          2005                 2004                 2003        

Cash Flows From Operating Activities:

      

Net income

   $           44     $           32     $           29  

Adjustments to reconcile net income to net cash
provided by operating activities:

      

Depreciation and amortization

     64       53       52  

Amortization of debt issuance costs and premium/discounts

     1       1       1  

Deferred income taxes and investment tax credits, net

     (15 )     10       (19 )

Other

     1       9       5  

Changes in assets and liabilities:

      

Receivables, net

     3       12       15  

Materials and supplies

     (19 )     (5 )     (10 )

Accounts and wages payable

     24       4       (15 )

Taxes accrued

     26       (13 )     (13 )

Assets, other

     (3 )     (7 )     16  

Liabilities, other

     7       (7 )     5  

Pension and other postretirement obligations, net

     -       (16 )     (9 )
                       

Net cash provided by operating activities

     133       73       57  
                       

Cash Flows From Investing Activities:

      

Capital expenditures

     (64 )     (46 )     (50 )

Proceeds from intercompany note receivable – Genco

     52       124       46  

Changes in money pool advances

     -       -       16  
                       

Net cash provided by (used in) investing activities

     (12 )     78       12  
                       

Cash Flows From Financing Activities:

      

Dividends on common stock

     (35 )     (75 )     (62 )

Dividends on preferred stock

     (3 )     (3 )     (3 )

Changes in money pool borrowings

     (66 )     (53 )     121  

Redemptions, repurchases, and maturities:

      

Long-term debt

     (20 )     (70 )     (95 )

Preferred Stock

     -       -       (30 )

Issuances:

      

Long-term debt

     -       35       -  

Other

     1       1       (1 )
                       

Net cash used in financing activities

     (123 )     (165 )     (70 )
                       

Net change in cash and cash equivalents

     (2 )     (14 )     (1 )

Cash and cash equivalents at beginning of year

     2       16       17  
                       

Cash and cash equivalents at end of year

   $ -     $ 2     $ 16  
                       

Cash Paid During the Periods:

      

Interest

   $ 29     $ 33     $ 36  

Income taxes, net

     14       26       38  

Noncash Investing Activities:

In 2005, CIPS purchased an interest in assets from UE in exchange for a promissory note to UE, and CIPS received a contribution of assets from Ameren Corporation. See Note 3 – Rate and Regulatory Matters for further details.

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

 

20

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)

 

    December 31,  
          2005                 2004                 2003        

Common Stock

   $ -     $ -     $ -  

Other Paid-in Capital:

      

Beginning of year

             121               120               120  

Equity contribution from parent

     68       1       -  
                       

Other paid-in capital, end of year

     189       121       120  
                       

Preferred Stock Not Subject to Mandatory Redemption:

      

Beginning of year

     50       50       80  

Redemptions

     -       -       (30 )
                       

Preferred stock not subject to mandatory redemption, end of year

     50       50       50  
                       

Retained Earnings:

      

Beginning of year

     323       369       405  

Net income

     44       32       29  

Common stock dividends

     (35 )     (75 )     (62 )

Preferred stock dividends

     (3 )     (3 )     (3 )
                       

Retained earnings, end of year

     329       323       369  
                       

Accumulated Other Comprehensive Income (Loss):

      

Derivative financial instruments, beginning of year

     4       -       -  

Change in derivative financial instruments

     3       4       -  
                       

Derivative financial instruments, end of year

     7       4       -  
                       

Minimum pension liability, beginning of year

     (8 )     (7 )     (13 )

Change in minimum pension liability

     2       (1 )     6  
                       

Minimum pension liability, end of year

     (6 )     (8 )     (7 )
                       

Total accumulated other comprehensive income (loss), end of year

     1       (4 )     (7 )
                       

Total Stockholders’ Equity

   $ 569     $ 490     $ 532  
                       

Comprehensive Income, Net of Taxes:

      

Net income

   $ 44     $ 32     $ 29  

Unrealized net gain on derivative hedging instruments,
net of income taxes of $4, $2, and $-, respectively

     5       4       -  

Reclassification adjustments for (gains) included in net income, net of income taxes of $1, $-, and $-, respectively

     (2 )     -       -  

Minimum pension liability adjustment, net of income taxes
of $1, $-, and $4, respectively

     2       (1 )     6  
                       

Total comprehensive income, net of taxes

   $ 49     $ 35     $ 35  
                       

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

 

21

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF INCOME

(In millions)

 

    Year Ended December 31,  
          2005                 2004               2003        

Operating Revenues:

      

Electric

   $       1,035     $         871   $         783  

Other

     3       2     2  
                     

Total operating revenues

     1,038       873     785  
                     

Operating Expenses:

      

Fuel and purchased power

     558       377     350  

Other operations and maintenance

     140       136     142  

Depreciation and amortization

     72       76     75  

Taxes other than income taxes

     11       19     21  
                     

Total operating expenses

     781       608     588  
                     

Operating Income

     257       265     197  

Other Income and Expenses:

      

Miscellaneous income

     1       -     -  

Miscellaneous expense

     -       -     (1 )
                     

Total other income (expense)

     1       -     (1 )
                     

Interest Charges

     73       94     101  
                     

Income Before Income Taxes and Cumulative Effect of Change
in Accounting Principle

     185       171     95  

Income Taxes

     72       64     38  
                     

Income Before Cumulative Effect of Change in
Accounting Principle

     113       107     57  

Cumulative Effect of Change in Accounting Principle,

      

Net of Income Taxes (Benefit) of $(10), $-, and $ 12

     (16 )     -     18  
                     

Net Income

   $ 97     $ 107   $ 75  
                     

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

 

22

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED BALANCE SHEET

(In millions, except shares)

 

    December 31,  
          2005                 2004        
ASSETS    

Current Assets:

    

Cash and cash equivalents

   $ -     $ 1  

Accounts receivable – affiliates

     102       86  

Accounts receivable

     29       10  

Materials and supplies

     73       70  

Other current assets

     1       2  
               

Total current assets

     205       169  
               

Property and Plant, Net

     1,514       1,749  

Other Assets

     92       37  
               

TOTAL ASSETS

   $ 1,811     $ 1,955  
               
LIABILITIES AND STOCKHOLDER’S EQUITY    

Current Liabilities:

    

Current maturities of long-term debt

   $ -     $ 225  

Current portion of intercompany notes payable – CIPS

     34       283  

Borrowings from money pool

     203       116  

Accounts and wages payable

     41       32  

Accounts and wages payable – affiliates

     60       28  

Current portion of intercompany tax payable – CIPS

     10       11  

Taxes accrued

     37       35  

Other current liabilities

     16       16  
               

Total current liabilities

     401       746  
               

Long-term Debt, Net

     474       473  

Intercompany Notes Payable – CIPS

     163       -  

Deferred Credits and Other Liabilities:

    

Accumulated deferred income taxes, net

     156       144  

Accumulated deferred investment tax credits

     10       12  

Intercompany tax payable – CIPS

     125       138  

Asset retirement obligations

     29       -  

Accrued pension and other postretirement benefits

     8       5  

Other deferred credits and liabilities

     1       2  
               

Total deferred credits and other liabilities

     329       301  
               

Commitments and Contingencies (Notes 1, 3, and 15)

    

Stockholder’s Equity:

    

Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding

     -       -  

Other paid-in capital

     228       225  

Retained earnings

     220       211  

Accumulated other comprehensive loss

     (4 )     (1 )
               

Total stockholder’s equity

     444       435  
               

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY

   $       1,811     $       1,955  
               

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

 

23

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)

 

    Year Ended December 31,  
          2005                 2004                 2003        

Cash Flows From Operating Activities:

      

Net income

   $           97     $         107     $           75  

Adjustments to reconcile net income to net cash
provided by operating activities:

      

Cumulative effect of change in accounting principle

     16       -       (18 )

Depreciation and amortization

     72       76       75  

Amortization of debt issuance costs and discounts

     1       1       1  

Deferred income taxes and investment tax credits, net

     20       59       28  

Voluntary retirement and other restructuring charges

     -       -       (2 )

Other

     (21 )     (18 )     (4 )

Changes in assets and liabilities:

      

Accounts receivable

     (35 )     (8 )     (10 )

Materials and supplies

     (7 )     1       (13 )

Accounts and wages payable

     46       (17 )     (9 )

Taxes accrued, net

     2       5       89  

Assets, other

     (35 )     1       (2 )

Liabilities, other

     (16 )     (14 )     -  

Pension and other postretirement obligations, net

     3       (13 )     1  
                       

Net cash provided by operating activities

     143       180       211  
                       

Cash Flows From Investing Activities:

      

Capital expenditures

     (76 )     (50 )     (58 )

Proceeds from asset sale to UE

     241       -       -  
                       

Net cash provided by (used in) investing activities

     165       (50 )     (58 )
                       

Cash Flows From Financing Activities:

      

Dividends on common stock

     (88 )     (66 )     (36 )

Changes in money pool borrowings

     87       (8 )     (67 )

Redemptions, repurchases, and maturities:

      

Intercompany notes payable – CIPS and Ameren

     (86 )     (128 )     (51 )

Long-term debt

     (225 )     -       -  

Capital contribution from parent

     3       75       -  

Other

     -       (4 )     -  
                       

Net cash used in financing activities

     (309 )     (131 )     (154 )
                       

Net change in cash and cash equivalents

     (1 )     (1 )     (1 )

Cash and cash equivalents at beginning of year

     1       2       3  
                       

Cash and cash equivalents at end of year

   $ -     $ 1     $ 2  
                       

Cash Paid During the Periods:

      

Interest

   $ 56     $ 95     $ 99  

Income taxes, net paid (refunded)

     42       1       (76 )

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

 

24

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY

(In millions)

 

    December 31,  
          2005                 2004                 2003        

Common Stock

   $ -     $ -     $ -  

Other Paid-in Capital:

      

Beginning of year

     225       150       150  

Equity contribution from Ameren

     3       75       -  
                       

Other paid-in capital, end of year

     228       225       150  
                       

Retained Earnings:

      

Beginning of year

     211       170       131  

Net income

     97       107       75  

Common stock dividends

     (88 )     (66 )     (36 )
                       

Retained earnings, end of year

     220       211       170  
                       

Accumulated Other Comprehensive Income (Loss):

      

Derivative financial instruments, beginning of year

     3       5       5  

Change in derivative financial instruments

     (1 )     (2 )     -  
                       

Derivative financial instruments, end of year

     2       3       5  
                       

Minimum pension liability, beginning of year

     (4 )     (4 )     (6 )

Change in minimum pension liability

     (2 )     -       2  
                       

Minimum pension liability, end of year

     (6 )     (4 )     (4 )
                       

Total accumulated other comprehensive income (loss), end of year

     (4 )     (1 )     1  
                       

Total Stockholder’s Equity

   $         444     $         435     $         321  
                       

Comprehensive Income, Net of Taxes:

      

Net income

   $ 97     $ 107     $ 75  

Reclassification adjustments for (gains) included in net income, net of income taxes of $-, $1 and $-, respectively

     (1 )     (2 )     -  

Minimum pension liability adjustment, net of income taxes
(benefit) of $(1), $-, and $1, respectively

     (2 )     -       2  
                       

Total comprehensive income, net of taxes

   $ 94     $ 105     $ 77  
                       

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

 

25

CILCORP INC.

CONSOLIDATED STATEMENT OF INCOME

(In millions)

 

                                    Successor                                     
    

Year

Ended
December 31,

    

Year

Ended
December 31,

     Eleven
Months
Ended
December 31,		     Predecessor
January
            2005                   2004                   2003                   2003       

Operating Revenues:

          

Electric

   $           387     $           391     $           512     $             49

Gas

     359       326       303       58

Other

     1       5       4       -
                               

Total operating revenues

     747       722       819       107
                               
   

Operating Expenses:

          

Fuel and purchased power

     158       146       276       26

Gas purchased for resale

     262       231       230       44

Other operations and maintenance

     174       190       135       14

Depreciation and amortization

     72       69       72       6

Taxes other than income taxes

     20       25       34       4
                               

Total operating expenses

     686       661       747       94
                               
   

Operating Income

     61       61       72       13
   

Other Income and Expenses:

          

Miscellaneous income

     -       1       1       -

Miscellaneous expense

     (6 )     (5 )     (3 )     -
                               

Total other expenses

     (6 )     (4 )     (2 )     -
                               
   

Interest Charges

     51       53       48       5
   

Income Before Income Taxes, Preferred Dividends of Subsidiaries and Cumulative Effect of Change in Accounting Principle

     4       4       22       8
   

Income Tax Expense (Benefit)

     (3 )     (8 )     6       3
                               
   

Income Before Preferred Dividends of Subsidiaries and Cumulative Effect of Change in Accounting Principle

     7       12       16       5
   

Preferred Dividends of Subsidiaries

     2       2       2       -
                               
   

Income Before Cumulative Effect of Change in Accounting Principle

     5       10       14       5
   

Cumulative Effect of Change in Accounting Principle, Net of Income Taxes (Benefit) of $(1), $-, $-, and $2

     (2 )     -       -       4
                               
   

Net Income

   $ 3     $ 10     $ 14     $ 9
                               

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

 

26

CILCORP INC.

CONSOLIDATED BALANCE SHEET

(In millions, except shares)

 

    December 31,
          2005               2004      
ASSETS    

Current Assets:

    

Cash and cash equivalents

   $ 3   $ 7

Accounts receivables – trade (less allowance for doubtful accounts of $5 and $3, respectively)

     61     46

Unbilled revenue

     59     46

Accounts receivables – affiliates

     18     9

Note receivable – Resources Company

     42     -

Materials and supplies

     85     67

Other current assets

     50     19
           

Total current assets

     318     194
           

Property and Plant, Net

     1,212     1,179

Investments and Other Assets:

    

Investments in leveraged leases

     21     113

Goodwill and other intangibles, net

     637     626

Other assets

     35     33

Regulatory assets

     11     11
           

Total investments and other assets

     704     783
           

TOTAL ASSETS

   $      2,234   $      2,156
           
LIABILITIES AND STOCKHOLDER’S EQUITY    

Current Liabilities:

    

Current maturities of long-term debt

   $ -   $ 16

Borrowings from money pool

     154     166

Intercompany note payable – Ameren

     186     72

Accounts and wages payable

     81     57

Accounts and wages payable – affiliates

     28     42

Other current liabilities

     55     58
           

Total current liabilities

     504     411
           

Long-term Debt, Net

     534     623

Preferred Stock of Subsidiary Subject to Mandatory Redemption

     19     20

Deferred Credits and Other Liabilities:

    

Accumulated deferred income taxes, net

     163     214

Accumulated deferred investment tax credits

     9     10

Regulatory liabilities

     41     38

Accrued pension and other postretirement benefits

     251     242

Other deferred credits and liabilities

     31     31
           

Total deferred credits and other liabilities

     495     535
           

Preferred Stock of Subsidiary Not Subject to Mandatory Redemption

     19     19

Commitments and Contingencies (Notes 1, 3 and 15)

    

Stockholder’s Equity:

    

Common stock, no par value, 10,000 shares authorized – 1,000 shares outstanding

     -     -

Other paid-in capital

     640     544

Retained earnings

     -     -

Accumulated other comprehensive income

     23     4
           

Total stockholder’s equity

     663     548
           

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY

   $ 2,234   $ 2,156
           

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

 

27

CILCORP INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)

 

                                       Successor                                           
    

Year

Ended
 December 31, 

    

Year

Ended
 December 31, 

    

Eleven

Months Ended
 December 31, 

      Predecessor 
January		  
     2005     2004     2003     2003  

Cash Flows From Operating Activities:

        

Net income

   $               3     $             10     $             14     $               9  

Adjustments to reconcile net income to net cash provided by operating activities:

        

Cumulative effect of change in accounting principle

     2       -       -       (4 )

Depreciation and amortization

     68       69       72       6  

Deferred income taxes and investment tax credits

     (25 )     43       2       (5 )

Other

     -       7       (2 )     -  

Changes in assets and liabilities:

        

Receivables, net

     (40 )     14       (4 )     (20 )

Materials and supplies

     (18 )     20       (15 )     13  

Accounts and wages payable

     8       (9 )     (25 )     20  

Taxes accrued

     14       (9 )     (5 )     11  

Assets, other

     (8 )     (19 )     17       6  

Liabilities, other

     (3 )     27       (26 )     (5 )

Pension and postretirement benefit obligations, net

     12       (17 )     11       -  
                                 

Net cash provided by operating activities

     13       136       39       31  
                                 
 

Cash Flows From Investing Activities:

        

Capital expenditures

     (107 )     (125 )     (71 )     (16 )

Proceeds from sale of leveraged lease, net

     13       -       -       -  

Other

     5       5       (9 )     1  
                                 

Net cash used in investing activities

     (89 )     (120 )     (80 )     (15 )
                                 
 

Cash Flows From Financing Activities:

        

Dividends on common stock

     (30 )     (18 )     (27 )     -  

Changes in money pool borrowings

     (12 )     21       149       -  

Redemptions, repurchases, and maturities:

        

Short-term debt

     -       -       -       (10 )

Long-term debt

     (101 )     (142 )     (153 )     -  

Preferred stock

     (1 )     (1 )     (1 )     -  

Issuances:

        

Long-term debt

     -       19       -       -  

Intercompany note payable – Ameren

     114       26       46       -  

Capital contribution from parent

     102       75       -       -  
                                 

Net cash provided by (used in) financing activities

     72       (20 )     14       (10 )
                                 
 

Net change in cash and cash equivalents

     (4 )     (4 )     (27 )     6  

Cash and cash equivalents at beginning of period

     7       11       38       32  
                                 

Cash and cash equivalents at end of period

   $ 3     $ 7     $ 11     $ 38  
                                 
 

Cash Paid During the Periods:

        

Interest

   $ 53     $ 39     $ 35     $ 5  

Income taxes, net paid (refunded)

     20       (40 )     15       -  

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

 

28

CILCORP INC.

CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY

(In millions)

 

                                       Successor                                           
     Year Ended
 December 31, 		     Year Ended
 December 31, 		     Eleven Months
Ended
 December 31, 		      Predecessor 
January		  
     2005     2004     2003     2003  

Common Stock

   $ -     $ -     $ -     $ -  
 

Other Paid-in Capital:

        

Beginning of period

     544       477       519       519  

Purchase accounting adjustments

     -       -       (29 )     -  

Common stock dividends

     (27 )     (8 )     (13 )     -  

Dividend-in-kind to Ameren

     (5 )     -       -       -  

Contribution from intercompany sale of leveraged leases

     26       -       -       -  

Capital contribution from parent

     102       75       -       -  
                                 

Other paid-in capital, end of period

     640       544       477       519  
                                 
 

Retained Earnings (Deficit):

        

Beginning of period

     -       -       44       35  

Purchase accounting adjustments

     -       -       (44 )     -  

Net income

     3       10       14       9  

Common stock dividends

     (3 )     (10 )     (14 )     -  
                                 

Retained earnings, end of period

     -       -       -       44  
                                 
 

Accumulated Other Comprehensive Income (Loss):

        

Derivative financial instruments, beginning of period

     4       1       1       1  

Purchase accounting adjustments

     -       -       (1 )     -  

Change in derivative financial instruments

     21       3       1       -  
                                 

Derivative financial instruments, end of period

     25       4       1       1  
                                 

Minimum pension liability, beginning of period

     -       -       (60 )     (60 )

Purchase accounting adjustments

     -       -       60       -  

Change in minimum pension liability

     (2 )     -       -       -  
                                 

Minimum pension liability, end of period

     (2 )     -       -       (60 )
                                 

Total accumulated other comprehensive income (loss), end of period

     23       4       1       (59 )
                                 
 

Total Stockholder’s Equity

   $           663     $           548     $           478     $           504  
                                 
 

Comprehensive Income, Net of Taxes:

        

Net income

   $ 3     $ 10     $ 14     $ 9  

Unrealized net gain on derivative hedging instruments, net of income taxes of $13, $2, $1, and $ -, respectively

     20       5       1       -  

Reclassification adjustments for gains included in net income, net of income taxes (benefits) of $1, $1, $-, and $-, respectively

     1       (2 )     -       -  
                                 

Total comprehensive income, net of taxes

   $ 24     $ 13     $ 15     $ 9  
                                 

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

 

29

CENTRAL ILLINOIS LIGHT COMPANY

CONSOLIDATED STATEMENT OF INCOME

(In millions)

 

    Year Ended December 31,  
          2005                 2004                 2003        

Operating Revenues:

      

Electric

   $           387     $           391     $           561  

Gas

     355       297       278  
                       

Total operating revenues

     742       688       839  
                       

Operating Expenses:

      

Fuel and purchased power

     150       140       303  

Gas purchased for resale

     258       202       189  

Other operations and maintenance

     184       198       165  

Acquisition integration costs

     -       2       21  

Depreciation and amortization

     67       64       70  

Taxes other than income taxes

     20       24       38  
                       

Total operating expenses

     679       630       786  
                       

Operating Income

     63       58       53  

Other Expenses:

      

Miscellaneous expense

     (5 )     (5 )     (4 )
                       

Total other expenses

     (5 )     (5 )     (4 )
                       

Interest Charges

     14       15       16  
                       

Income Before Income Taxes and Cumulative Effect of
Change in Accounting Principle

     44       38       33  

Income Taxes

     16       6       12  
                       

Income Before Cumulative Effect of Change in
Accounting Principle

     28       32       21  

Cumulative Effect of Change in Accounting Principle,
Net of Income Taxes (Benefit) of $(1), $-, and $16

     (2 )     -       24  
                       

Net Income

     26       32       45  

Preferred Stock Dividends

     2       2       2  
                       

Net Income Available to Common Stockholder

   $ 24     $ 30     $ 43  
                       

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

 

30

CENTRAL ILLINOIS LIGHT COMPANY

CONSOLIDATED BALANCE SHEET

(In millions)

 

    December 31,  
          2005               2004        
ASSETS    

Current Assets:

    

Cash and cash equivalents

   $ 2   $ 2  

Accounts receivable – trade (less allowance for doubtful
accounts of $5 and $3, respectively)

     61     46  

Unbilled revenue

     59     43  

Accounts receivable – affiliates

     14     11  

Materials and supplies

     87     68  

Other current assets

     43     6  
             

Total current assets

     266     176  
             

Property and Plant, Net

     1,214     1,165  

Investments in Leveraged Leases

     21     -  

Other Assets

     45     29  

Regulatory Assets

     11     11  
             

TOTAL ASSETS

   $      1,557   $      1,381  
             
LIABILITIES AND STOCKHOLDERS’ EQUITY    

Current Liabilities:

    

Current maturities of long-term debt

   $ -   $ 16  

Borrowings from money pool

     161     169  

Accounts and wages payable

     81     53  

Accounts and wages payable – affiliates

     26     42  

Other current liabilities

     48     49  
             

Total current liabilities

     316     329  
             

Long-term Debt, Net

     122     122  

Preferred Stock Subject to Mandatory Redemption

     19     20  

Deferred Credits and Other Liabilities:

    

Accumulated deferred income taxes, net

     167     130  

Accumulated deferred investment tax credits

     8     10  

Regulatory liabilities

     187     176  

Accrued pension and other postretirement benefits

     146     131  

Other deferred credits and liabilities

     30     26  
             

Total deferred credits and other liabilities

     538     473  
             

Commitments and Contingencies (Notes 1, 3 and 15)

    

Stockholders’ Equity:

    

Common stock, no par value, 20.0 shares authorized – 13.6 shares outstanding

     -     -  

Preferred stock not subject to mandatory redemption

     19     19  

Other paid-in capital

     415     313  

Retained earnings

     119     115  

Accumulated other comprehensive income (loss)

     9     (10 )
             

Total stockholders’ equity

     562     437  
             

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 1,557   $ 1,381  
             

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

 

31

CENTRAL ILLINOIS LIGHT COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)

 

    Year Ended December 31,  
          2005                 2004                 2003        

Cash Flows From Operating Activities:

      

Net income

   $             26     $             32     $             45  

Adjustments to reconcile net income to net cash
provided by operating activities:

      

Cumulative effect of change in accounting principle

     2       -       (24 )

Depreciation and amortization

     67       64       70  

Deferred income taxes and investment tax credits, net

     (25 )     41       (24 )

Acquisition integration costs

     -       -       16  

Other

     12       -       3  

Changes in assets and liabilities:

      

Receivables, net

     (34 )     6       (20 )

Materials and supplies

     (19 )     1       (8 )

Accounts and wages payable

     10       (6 )     24  

Taxes accrued

     15       (13 )     (5 )

Assets, other

     (29 )     (6 )     1  

Liabilities, other

     6       15       23  

Pension and postretirement benefit obligations, net

     16       3       2  
                       

Net cash provided by operating activities

     47       137       103  
                       

Cash Flows From Investing Activities:

      

Capital expenditures

     (107 )     (125 )     (87 )

Proceeds from sale of leveraged lease, net

     13       -       -  

Other

     -       -       1  
                       

Net cash used in investing activities

     (94 )     (125 )     (86 )
                       

Cash Flows From Financing Activities:

      

Dividends on common stock

     (20 )     (10 )     (62 )

Dividends on preferred stock

     (2 )     (2 )     (2 )

Changes in money pool borrowings

     (16 )     20       149  

Redemptions, repurchases, and maturities:

      

Short-term debt

     -       -       (10 )

Long-term debt

     (16 )     (119 )     (105 )

Preferred stock

     (1 )     (1 )     (1 )

Issuances:

      

Long-term debt

     -       19       -  

Capital contribution from parent

     102       75       -  
                       

Net cash provided by (used in) financing activities

     47       (18 )     (31 )
                       

Net change in cash and cash equivalents

     -       (6 )     (14 )

Cash and cash equivalents at beginning of year

     2       8       22  
                       

Cash and cash equivalents at end of year

   $ 2     $ 2     $ 8  
                       

Cash Paid During the Periods:

      

Interest

   $ 15     $ 16     $ 19  

Income taxes, net paid (refunded)

     34       (20 )     22  

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

 

32

CENTRAL ILLINOIS LIGHT COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)

 

    December 31,  
          2005                 2004                 2003        

Common Stock

   $             -     $             -     $             -  

Preferred Stock Not Subject to Mandatory Redemption

     19       19       19  

Other Paid-in Capital:

      

Beginning of year

     313       238       238  

Capital contribution from parent

     102       75       -  
                       

Other paid-in capital, end of year

     415       313       238  
                       

Retained Earnings:

      

Beginning of year

     115       95       114  

Net income

     26       32       45  

Common stock dividends

     (20 )     (10 )     (62 )

Preferred stock dividends

     (2 )     (2 )     (2 )
                       

Retained earnings, end of year

     119       115       95  
                       

Accumulated Other Comprehensive Income (Loss):

      

Derivative financial instruments, beginning of year

     7       3       1  

Change in derivative financial instruments

     18       4       2  
                       

Derivative financial instruments, end of year

     25       7       3  
                       

Minimum pension liability, beginning of year

     (17 )     (13 )     (30 )

Change in minimum pension liability

     1       (4 )     17  
                       

Minimum pension liability, end of year

     (16 )     (17 )     (13 )
                       

Total accumulated other comprehensive income (loss), end of year

     9       (10 )     (10 )
                       

Total Stockholders’ Equity

   $ 562     $ 437     $ 342  
                       

Comprehensive Income, Net of Taxes:

      

Net income

   $ 26     $ 32     $ 45  

Unrealized net gain on derivative hedging instruments, net of income taxes of $13, $2, and $1, respectively

     20       5       2  

Reclassification adjustments for (gains) included in net income, net of income taxes of $1, $1, and $-, respectively

     (2 )     (1 )     -  

Minimum pension liability adjustment, net of income taxes (benefit) of $1, $(3), and $11, respectively

     1       (4 )     17  
                       

Total comprehensive income, net of taxes

   $ 45     $ 32     $ 64  
                       

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

 

33

ILLINOIS POWER COMPANY

CONSOLIDATED STATEMENT OF INCOME

(In millions)

 

                      Successor                                    Predecessor                 
    

Year

Ended
December 31,

     Three
Months
Ended
December 31,		  

Nine

Months
Ended
September 30,

    

Year

Ended
December 31,

  
     2005     2004   2004     2003  

Operating Revenues:

        

Electric

   $         1,112     $           229   $            832     $         1,102  

Gas

     541       150     328       466  
                               

Total operating revenues

     1,653       379     1,160       1,568  
                               
 

Operating Expenses:

        

Purchased power

     686       128     496       681  

Gas purchased for resale

     393       110     222       316  

Other operations and maintenance

     225       43     143       205  

Depreciation and amortization

     79       20     61       79  

Amortization of regulatory assets

     -       1     32       42  

Taxes other than income taxes

     68       15     52       67  
                               

Total operating expenses

     1,451       317     1,006       1,390  
                               
 

Operating Income

     202       62     154       178  
 

Other Income and Expenses:

        

Interest income from former affiliates

     -       -     128       170  

Miscellaneous income

     7       1     16       13  

Miscellaneous expense

     (3 )     -     (1 )     (4 )
                               

Total other income

     4       1     143       179  
                               
 

Interest Charges

     44       17     114       163  
                               
 

Income Before Income Taxes and Cumulative Effect of Change in Accounting Principle

     162       46     183       194  
 

Income Taxes

     65       18     71       75  
                               
 

Income Before Cumulative Effect of Change in Accounting Principle

     97       28     112       119  
 

Cumulative Effect of Change in Accounting Principle, Net of Income Taxes (Benefit)

     -       -     -       (2 )
                               
 

Net Income

     97       28     112       117  
 

Preferred Stock Dividends

     2       1     2       2  
                               

Net Income Available to Common Stockholder

   $ 95     $ 27   $ 110     $ 115  
                               

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

 

34

ILLINOIS POWER COMPANY

CONSOLIDATED BALANCE SHEET

(In millions)

 

    December 31,
          2005                 2004      
ASSETS    

Current Assets:

    

Cash and cash equivalents

   $               -     $              5

Account receivables (less allowance for doubtful accounts of $8 and $6, respectively)

     155       101

Unbilled revenue

     118       98

Miscellaneous accounts and notes receivable

     5       8

Advances to money pool

     -       140

Materials and supplies

     122       85

Other current assets

     31       69
             

Total current assets

     431       506
             

Property and Plant, Net

     2,035       1,984

Investments and Other Assets:

    

Investment in IP SPT

     7       7

Goodwill

     326       320

Other assets

     44       37

Regulatory assets

     194       198

Accumulated deferred income taxes

     19       65
             

Total investments and other assets

     590       627
             

TOTAL ASSETS

   $ 3,056     $ 3,117
             
LIABILITIES AND STOCKHOLDERS’ EQUITY    

Current Liabilities:

    

Current maturities of long-term debt

   $ -     $ 70

Current maturities of long-term debt to IP SPT

     72       74

Borrowings from money pool

     75       -

Accounts and wages payable

     145       118

Accounts and wages payable – affiliates

     29       4

Taxes accrued

     15       5

Other current liabilities

     135       102
             

Total current liabilities

     471       373
             

Long-term Debt, Net

     704       713

Long-term Debt to IP SPT

     184       278

Deferred Credits and Other Liabilities:

    

Regulatory liabilities

     80       76

Accrued pension and other postretirement liabilities

     255       248

Other deferred credits and other noncurrent liabilities

     75       149
             

Total deferred credits and other liabilities

     410       473
             

Commitments and Contingencies (Notes 1, 3 and 15)

    

Stockholders’ Equity:

    

Common stock, no par value, 100.0 shares authorized – 23.0 shares outstanding

     -       -

Other paid-in-capital

     1,196       1,207

Preferred stock not subject to mandatory redemption

     46       46

Retained earnings

     46       27

Accumulated other comprehensive loss

     (1 )     -
             

Total stockholders’ equity

     1,287       1,280
             

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY

   $ 3,056     $ 3,117
             

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

 

35

ILLINOIS POWER COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)

 

                      Successor                                      Predecessor                 
    

Year

Ended
December 31,

     Three
Months
Ended
December 31,		    

Nine

Months
Ended
September 30,

    

Year

Ended
December 31,

  
     2005     2004     2004     2003  

Cash Flows From Operating Activities:

        

Net income

   $             97     $             28     $           112     $           117  

Adjustments to reconcile net income to net cash provided by operating activities:

        

Cumulative effect of change in accounting principle

     -       -       -       2  

Depreciation and amortization

     42       21       95       121  

Amortization of debt issuance costs and premium/discounts

     2       2       4       12  

Deferred income taxes

     39       98       (59 )     (24 )

Other

     (2 )     (27 )     1       (2 )

Changes in assets and liabilities:

        

Receivables, net

     (66 )     (16 )     23       2  

Materials and supplies

     (37 )     (15 )     (13 )     (23 )

Accounts and wages payable

     50       62       (2 )     (41 )

Assets, other

     (5 )     (25 )     13       (40 )

Liabilities, other

     21       (38 )     (29 )     (3 )

Pension and other postretirement benefit obligations, net

     7       (1 )     13       7  
                                 

Net cash provided by operating activities

     148       89       158       128  
                                 
 

Cash Flows From Investing Activities:

        

Capital expenditures

     (132 )     (35 )     (100 )     (126 )

Changes in money pool advances

     140       (140 )     -       -  

Other

     1       (1 )     4       -  
                                 

Net cash provided by (used in) investing activities

     9       (176 )     (96 )     (126 )
                                 
 

Cash Flows From Financing Activities:

        

Dividends on common stock

     (76 )     -       -       -  

Dividends on preferred stock

     (2 )     (1 )     (2 )     (2 )

Prepaid interest on note receivable from former affiliate

     -       -       43       128  

Borrowings from money pool, net

     75       -       -       -  

Changes in short-term debt

     -       -       -       (100 )

Redemptions and repurchases of long-term debt

     (156 )     (823 )     (65 )     (276 )

Issuances of long-term debt

     -       -       -       150  

Capital contribution from parent

     -       871       -       -  

Transitional funding trust notes overfunding

     (3 )     (6 )     (4 )     (2 )
                                 

Net cash provided by (used in) financing activities

     (162 )     41       (28 )     (102 )
                                 

Net change in cash and cash equivalents

     (5 )     (46 )     34       (100 )

Cash and cash equivalents at beginning of period

     5       51       17       117  
                                 

Cash and cash equivalents at end of period

   $ -     $ 5     $ 51     $ 17  
                                 

Cash Paid During the Periods:

        

Interest

   $ 36     $ 48     $ 81     $ 153  

Income taxes, net paid (refunded)

     (22 )     (41 )     160       94  

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

 

36

ILLINOIS POWER COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)

 

                      Successor                                      Predecessor                 
    

Year

Ended
December 31,

     Three
Months
Ended
December 31,		    

Nine

Months
Ended
September 30,

    

Year

Ended
December 31,

  
     2005     2004     2004     2003  

Common Stock

   $               -     $               -     $               -     $               -  
 

Preferred Stock Not Subject to Mandatory Redemption

     46       46       46       46  
 

Other Paid-in Capital:

        

Beginning of period

     1,207       344       1,276       1,276  

Repurchase of common stock

     -       -       (626 )     -  

Purchase accounting adjustments

     (11 )     (8 )     (306 )     -  

Equity contribution from parent

     -       871       -       -  
                                 

Other paid-in capital, end of period

     1,196       1,207       344       1,276  
                                 
 

Retained Earnings:

        

Beginning of period

     27       -       505       390  

Elimination of remaining note receivable from former affiliate

     -       -       (457 )     -  

Purchase accounting adjustments

     -       -       (158 )     -  

Net income

     97       28       112       117  

Common stock dividends

     (76 )     -       -       -  

Preferred stock dividends and tender charges

     (2 )     (1 )     (2 )     (2 )
                                 

Retained earnings, end of period

     46       27       -       505  
                                 

Accumulated Other Comprehensive Income (Loss):

        

Derivative financial instruments, beginning of period

     -       -       -       -  

Change in derivative financial instruments

     (1 )     -       -       -  
                                 

Derivative financial instruments, end of period

     (1 )     -       -       -  
                                 

Minimum pension liability, beginning of period

     -       -       (10 )     (13 )

Assumption of deferred tax obligations by former affiliate

     -       -       (5 )     -  

Purchase accounting adjustments

     -       -       14       -  

Change in minimum pension liability

     -       -       1       3  
                                 

Minimum pension liability, end of period

     -       -       -       (10 )
                                 

Total accumulated other comprehensive loss, end of period

     (1 )     -       -       (10 )
                                 

Treasury Stock

        

Beginning of period

     -       -       (287 )     (287 )

Purchase accounting adjustments

     -       -       287       -  
                                 

Treasury stock, end of period

     -       -       -       (287 )
                                 

Total Stockholders’ Equity

   $ 1,287     $ 1,280     $ 390     $ 1,530  
                                 

Comprehensive Income, Net of Taxes:

        

Net income

   $ 97     $ 28     $ 112     $ 117  

Unrealized net (loss) on derivative hedging instruments, net of income taxes (benefit) of $(1), $-, and $-, and $-, respectively

     (1 )     -       -       -  

Minimum pension liability adjustment, net of income taxes of $-, $-, $-, and $ 2, respectively

     -       -       1       3  
                                 

Total comprehensive income, net of taxes

   $ 96     $ 28     $ 113     $ 120  
                                 

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

 

37

AMEREN CORPORATION (Consolidated)

UNION ELECTRIC COMPANY (Consolidated)

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

AMEREN ENERGY GENERATING COMPANY (Consolidated)

CILCORP INC. (Consolidated)

CENTRAL ILLINOIS LIGHT COMPANY (Consolidated)

ILLINOIS POWER COMPANY (Consolidated)

COMBINED NOTES TO FINANCIAL STATEMENTS

December 31, 2005

NOTE 1 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with FERC under PUHCA 2005. Ameren was registered with the SEC as a public utility holding company under PUHCA 1935 until that act was repealed effective February 8, 2006. Ameren’s primary asset is the common stock of its subsidiaries. Ameren’s subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock depend on distributions made to it by its subsidiaries. Ameren’s principal subsidiaries are listed below. Also see the Glossary of Terms and Abbreviations at the front of this report.

 

•   UE, or Union Electric Company, also known as AmerenUE, operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. Before May 2, 2005, it also operated those businesses in Illinois. UE was incorporated in Missouri in 1922 and is successor to a number of companies, the oldest of which was organized in 1881. It is the largest electric utility in the state of Missouri. It supplies electric and gas service to a 24,000- square-mile area located in central and eastern Missouri. This area has an estimated population of 3 million and includes the greater St. Louis area. UE supplies electric service to 1.2 million customers and natural gas service to 125,000 customers. See Note 3 – Rate and Regulatory Matters for information regarding the May 2005 transfer of UE’s Illinois electric and natural gas transmission and distribution businesses to CIPS and the addition of a large new electric customer in June 2005.
•   CIPS, or Central Illinois Public Service Company, also known as AmerenCIPS, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. CIPS was incorporated in Illinois in 1902. It supplies electric and gas utility service to portions of central, west central and southern Illinois having an estimated population of 1 million in an area of 20,500 square miles. CIPS supplies electric service to 400,000 customers and natural gas service to 190,000 customers.
•   Genco, or Ameren Energy Generating Company, operates a non-rate-regulated electric generation business in Illinois and Missouri. Genco was incorporated in Illinois in March 2000, in conjunction with the Illinois Customer Choice Law. Genco commenced operations on May 1, 2000, when CIPS transferred its five coal-fired power plants representing in the aggregate about 2,860 megawatts of capacity and related liabilities to Genco at historical net book value. The transfer was made in exchange for a subordinated promissory note from Genco in the amount of $552 million and shares of Genco’s common stock which were subsequently distributed to Ameren as a dividend in-kind. Ameren then contributed the shares to Development Company as an additional capital contribution. Genco also owns 17 CTs, which gives it a total installed generating capacity of about 4,222 megawatts as of December 31, 2005. Genco is a subsidiary of Development Company, a subsidiary of Resources Company, which in turn is a subsidiary of Ameren. See Note 3 – Rate and Regulatory Matters for information regarding the May 2005 transfer of Genco’s 10 CTs located in Pinckneyville and Kinmundy, Illinois, to UE.
•   CILCO, or Central Illinois Light Company, also known as AmerenCILCO, is a subsidiary of CILCORP (a holding company). It operates a rate-regulated electric transmission and distribution business, a primarily non-rate-regulated electric generation business, and a rate-regulated natural gas transmission and distribution business in Illinois. CILCO was incorporated in Illinois in 1913. It supplies electric and gas utility service to portions of central and east central Illinois in areas of 3,700 and 4,500 square miles, respectively, with an estimated population of 1 million. CILCO supplies electric service to 215,000 customers and natural gas service to 220,000 customers. In October 2003, CILCO transferred its coal-fired plants and a CT facility, representing in the aggregate about 1,100 megawatts of electric generating capacity, to a wholly owned subsidiary known as AERG, as a contribution in respect of all the outstanding stock of AERG and AERG’s assumption of certain liabilities. The net book value of the transferred assets was $378 million. No gain or loss was recognized, as the transaction was accounted for as a transfer between entities under common control. The transfer was made in conjunction with the Illinois Customer Choice Law. CILCORP was incorporated in Illinois in 1985.

 

38

•   IP, or Illinois Power Company, also known as AmerenIP, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. Ameren acquired IP on September 30, 2004, from Dynegy, which had acquired it with Illinova in early 2000. IP was incorporated in 1923 in Illinois. It supplies electric and gas utility service to portions of central, east central, and southern Illinois, serving a population of 1.4 million in an area of 15,000 square miles, contiguous to our other service territories. IP supplies electric service to 625,000 customers and natural gas service to 425,000 customers, including most of the Illinois portion of the greater St. Louis area. See Note 2 – Acquisitions for further information.

Ameren has various other subsidiaries responsible for the short- and long-term marketing of power, procurement of fuel, management of commodity risks, and provision of other shared services. Ameren has an 80% ownership interest in EEI through UE and Development Company, which each own 40% of EEI. This 80% ownership in EEI includes a 20% interest indirectly acquired by Resources Company from a Dynegy subsidiary on September 30, 2004. Ameren consolidates EEI for financial reporting purposes, while UE reports EEI under the equity method.

We use the words “our,” “we” or “us” with respect to certain information to indicate that such information relates to all Ameren Companies. When we refer to financing or acquisition activities, or liquidity arrangements, we are defining Ameren as the parent holding company. When appropriate, subsidiaries of Ameren are named specifically as we discuss their various business activities.

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, Cash Flows, and Stockholders’ Equity for the periods prior to September 30, 2004, do not reflect IP’s results of operations. Financial information of CILCORP and CILCO reflected in Ameren’s consolidated financial statements include the period from January 31, 2003, when these companies were acquired. See Note 2 – Acquisitions for further information about the accounting for the IP and CILCORP acquisitions. All significant intercompany transactions have been eliminated. All tabular dollar amounts are in millions, unless otherwise indicated.

 

Our accounting policies conform to GAAP. Our financial statements reflect all adjustments (which include normal, recurring adjustments) necessary, in our opinion, for a fair presentation of our results. The preparation of financial statements in conformity with GAAP requires management to make certain estimates and assumptions. Such estimates and assumptions affect reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the dates of financial statements, and the reported amounts of revenues and expenses during the reported periods. Actual results could differ from those estimates. Certain reclassifications have been made to make prior-year financial statements conform to 2005 reporting.

As part of the acquisition of IP on September 30, 2004, Ameren “pushed down” the effects of purchase accounting to the financial statements of IP. Accordingly, IP’s postacquisition financial statements reflect a new basis of accounting, and separate financial statement amounts are presented for preacquisition (predecessor) and postacquisition (successor) periods, separated by a bold black line. As a result of the acquisition of IP, certain reclassifications have been made to make IP prior-year financial statements conform to our current presentation. Additionally, as part of the acquisition of CILCORP on January 31, 2003, Ameren “pushed down” the effects of purchase accounting to the financial statements of CILCORP, but not to any of CILCORP’s subsidiaries. Accordingly, CILCORP’s postacquisition financial statements reflect a new basis of accounting, and separate financial statement amounts are presented for predecessor and successor periods, separated by a bold black line. CILCO’s financial statements are presented on a historical basis of accounting for all periods presented.

Regulation

Before February 8, 2006, Ameren was subject to regulation by the SEC under PUHCA 1935. Certain Ameren subsidiaries are also regulated by the MoPSC, the ICC, the NRC, and FERC. In accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” UE, CIPS, CILCO and IP defer certain costs pursuant to actions of our rate regulators. These companies are currently recovering such costs in rates charged to customers. See Note 3 – Rate and Regulatory Matters for further information.

 

39

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and temporary investments purchased with an original maturity of three months or less.

Allowance for Doubtful Accounts Receivable

The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our existing accounts receivable. The allowance is based on the application of a historical write-off factor to the amount of outstanding receivables, including unbilled revenue, and a review for collectibility of certain accounts over 90 days past due.

Materials and Supplies

Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average cost method. The following table presents a breakdown of materials and supplies for each of the Ameren Companies at December 31, 2005 and 2004:

 

        Ameren(a)      UE      CIPS      Genco      CILCORP      CILCO      IP

2005:

                                   

Fuel(b)

     $ 130      $ 58      $ -      $ 48      $ 13      $ 15      $ -

Gas stored underground

        253        33        62        -        54        54        104

Other materials and supplies

        189        108        13        25        18        18        18
       $ 572      $ 199      $ 75      $ 73      $ 85      $ 87      $ 122

2004:

                                   

Fuel(b)

     $ 124      $ 61      $ -      $ 45      $ 8      $ 8      $ -

Gas stored underground

        191        33        44        -        40        41        74

Other materials and supplies

        182        105        12        25        19        19        11
       $ 497      $ 199      $ 56      $ 70      $ 67      $ 68      $ 85

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries as well as intercompany eliminations.
(b) Consists of coal, oil, propane, and tire chips.

 

Emission Allowances

As of December 31, 2005, Ameren and CILCORP had emission allowances of $242 million (2004 – $126 million) and $58 million (2004 – $67 million), respectively, included in goodwill and other intangibles; and, UE and Genco had emission allowances of $62 million and $79 million (2004 – $19 million), respectively, included in other assets. Emission allowances are charged to fuel expense as they are used in operations.

Property and Plant

We capitalize the cost of additions to and betterments of units of property and plant. The cost includes labor, material, applicable taxes, and overhead. An allowance for funds used during construction, or the cost of borrowed funds and the cost of equity funds (preferred and common stockholders’ equity) applicable to rate-regulated construction expenditures, is also added for our rate-regulated assets. Interest during construction is added for non-rate-regulated assets. Maintenance expenditures are expensed as incurred. When units of depreciable property are retired, the original costs, less salvage value, are charged to accumulated depreciation. Asset removal costs incurred by our non-rate-regulated operations, which do not constitute legal obligations, are expensed as incurred. Asset removal costs accrued by our rate-regulated operations, which do not constitute legal obligations, are classified as a regulatory liability. See Accounting Changes and Other Matters relating to SFAS No. 143 and FIN 47 below and Note 4 – Property and Plant, Net for further information.

Depreciation

Depreciation is provided over the estimated lives of the various classes of depreciable property by applying composite rates on a straight-line basis. The provision for depreciation for the Ameren Companies in 2005, 2004 and 2003 generally ranged from 3% to 4% of the average depreciable cost. Beginning in January 2003, with the adoption of SFAS No. 143, depreciation rates for our non-rate-regulated assets were reduced to reflect the discontinuation of the accrual of dismantling and removal costs. See Accounting Changes and Other Matters relating to SFAS No. 143 and FIN 47 below for further information.

Allowance for Funds Used During Construction

In our rate-regulated operations, we capitalize the allowance for funds used during construction, as is the utility industry accounting practice. Allowance for funds used during construction does not represent a current source of

 

40

cash funds. This accounting practice offsets the effect on earnings of the cost of financing current construction, and it treats such financing costs in the same manner as construction charges for labor and materials.

Under accepted ratemaking practice, cash recovery of allowance for funds used during construction, as well as other construction costs, occurs when completed projects are placed in service and reflected in customer rates. The following table presents the allowance for funds used during construction rates that were utilized during 2005, 2004 and 2003:

 

        2005      2004      2003  

Ameren(a)

     3% - 9 %    1% - 9 %    3% - 4 %

UE

      6      5      4  

CIPS

      7      1      3  

CILCORP(b) and CILCO

      3      1      3  

IP(b)

     9      9      7  

 

(a) Excludes rates for IP before the acquisition date of September 30, 2004.
(b) Represents predecessor information for CILCORP before January 31, 2003, and for IP before September 30, 2004.

Goodwill

Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. We evaluate goodwill for impairment in the fourth quarter of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Ameren’s and IP’s goodwill relates to the acquisitions of IP and an additional 20% ownership interest in EEI in 2004, and Ameren’s and CILCORP’s relates to the acquisitions of CILCORP and Medina Valley in 2003. See Note 2 – Acquisitions for additional information regarding the acquisitions.

Leveraged Leases

Certain Ameren subsidiaries own interests in assets that have been financed as leveraged leases. Ameren’s investment in these leveraged leases represents the equity portion, generally 20% of the total investment, either as an undivided interest in the equipment or as a shared interest through a partnership. Ameren, CILCORP and CILCO account for these investments as a net investment in these assets; they do not include the amount of outstanding debt because the third-party debt is nonrecourse to Ameren and the Ameren subsidiaries. The net investment consists of rents receivable and unearned revenue. This net investment is then adjusted over time as rents are received, income is realized, and the asset is eventually sold. Certain of the leveraged leases were sold in 2005. See Note 3 – Rate and Regulatory Matters for further information on the sales.

Impairment of Long-lived Assets

We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The determination of whether impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets as compared with the carrying value of the assets. If impairment has occurred, we recognize the amount of the impairment by estimating the fair value of the assets and recording a provision for loss if the carrying value is greater than the fair value.

Investments

Ameren and UE evaluate investments held in UE’s nuclear decommissioning trust fund for impairment. Investments are considered to be impaired when a decline in fair value below the cost basis is estimated to be other than temporary. If the decline is determined to be other than temporary, the cost basis of the security is written down to fair value. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which we believe would be reflected in electric rates paid by UE’s customers. Accordingly, any impairments would be recorded as regulatory assets on Ameren’s and UE’s Consolidated Balance Sheets. Ameren and UE consider, among other factors, general market conditions, the duration and the extent to which the security’s fair value has been less than cost, and UE’s intent and ability to hold the investment. See Note 17 – Fair Value of Financial Instruments for disclosure of the fair value and unrealized gains and losses of UE’s investments.

Environmental Costs

Environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and the amount of the liability can be reasonably estimated. Estimated environmental expenditures are based on internal and third-party estimates, which are regularly reviewed and updated. Costs are expensed or deferred as a regulatory asset when it is expected that the costs will be recovered from customers in future rates. If environmental expenditures are related to facilities currently in use, such as pollution control equipment, the cost is capitalized and depreciated over the expected life of the asset.

Unamortized Debt Discount, Premium, and Expense

Discount, premium and expense associated with long-term debt are amortized over the lives of the related issues.

Revenue

Utility Revenues

UE, CIPS, Genco, CILCO and IP record operating revenue for electric or gas service when it is delivered to customers. We accrue an estimate of electric and gas

 

41

revenues for service rendered, but unbilled, at the end of each accounting period. See Accounting Matters – Critical Accounting Policies under Part II – Item 7 of this report for further information.

Interchange Revenues

The following table presents the interchange revenues included in Operating Revenues – Electric for the years ended December 31, 2005, 2004 and 2003:

 

        2005      2004      2003  

Ameren(a)

     $ 499      $ 420      $ 351  

UE

        483        340        320  

CIPS

        36        37        37  

Genco

        230        163        140  

CILCORP(b)

       26        46        19  

CILCO

        26        46        19  

IP

        (c )      (c )      (c )

 

(a) Excludes amounts for IP before the acquisition date of September 30, 2004; excludes amounts for CILCORP before the acquisition date of January 31, 2003; and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. Includes interchange revenues at EEI of $32 million for the year ended December 31, 2005 (2004 – $53 million, 2003 – $56 million).
(b) The 2003 amount includes January 2003 predecessor information, which was $3 million.
(c) Amounts for 2003 and January through September 2004 represent predecessor information. The 2005, 2004 and 2003 amounts were less than $1 million.

Trading Activities

We present the revenues and costs associated with certain energy derivative contracts designated as trading on a net basis in Operating Revenues – Electric and Other.

Purchased Power

The following table presents the purchased power expenses included in Operating Expenses – Fuel and Purchased Power for the years ended December 31, 2005, 2004 and 2003. See Note 14 – Related Party Transactions for further information on affiliate purchased power transactions.

 

        2005      2004      2003

Ameren(a)

     $ 1,119      $ 454      $ 294

UE

        330        203        179

Genco

        310        150        152

CILCORP(b)

       63        43        205

CILCO

        63        43        202

 

(a) Excludes amounts for IP before the acquisition date of September 30, 2004; excludes amounts for CILCORP before the acquisition date of January 31, 2003; and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations. Includes purchase power for EEI of $2 million for the year ended December 31, 2005 (2004 – $40 million, 2003 – $51 million).
(b) The 2003 amount includes January 2003 predecessor information, which was $12 million.

 

Fuel and Gas Costs

In UE’s, CIPS’, CILCO’s and IP’s retail electric utility jurisdictions, there are currently no provisions in effect for adjusting rates in response to changes in the cost of fuel for electric generation. In UE’s, CIPS’, CILCO’s and IP’s retail gas utility jurisdictions, changes in gas costs are generally reflected in billings to gas customers through PGA clauses.

UE’s cost of nuclear fuel is amortized to fuel expense on a unit-of-production basis. Spent fuel disposal cost, based on net kilowatthours generated and sold, is charged to expense.

Stock-based Compensation

Effective January 1, 2003, Ameren and predecessor IP adopted the fair value recognition provisions of SFAS No. 123, “Accounting for Stock-based Compensation,” by using the prospective method of adoption under SFAS No. 148, “Accounting for Stock-based Compensation – Transition and Disclosure,” for all employee awards granted or with terms modified on or after January 1, 2003.

In December 2004, the FASB issued SFAS No. 123 (as revised SFAS No. 123R), “Share Based Payment,” which revises SFAS No. 123 and supersedes APB Opinion No. 25. SFAS No. 123R requires companies to measure the cost of employee services received in exchange for an award of equity instruments by the grant-date fair value of the award. The fair value of the award will be remeasured subsequently at each reporting date through the settlement date; the changes in fair value will be recognized as compensation cost in each period. The fair value method in this statement is similar to the fair value method in SFAS No. 123 in most respects. The statement applies to all awards granted or modified after the effective date. Ameren’s adoption of this statement, effective January 1, 2006, is not expected to have any material impact on its results of operations, financial condition, or liquidity.

Had compensation cost for all stock options and stock awards granted prior to 2003 been determined on a fair value basis consistent with SFAS No. 123, Ameren’s net income would have been reduced by $1 million for each of the years ended December 31, 2004 and 2003; and, its pro forma basic and diluted earnings per share would have equaled actual earnings per share for the years ended December 31, 2004 and 2003. Compensation cost for Ameren’s options granted prior to 2003 would have been fully recognized in 2004. Had compensation cost for all stock options awards granted prior to 2003 been determined on a fair value basis for Dynegy equity compensation in which IP employees participated, predecessor IP’s net income would have been reduced by $3 million and $4 million for the nine months ended September 30, 2004 and the year ended December 31, 2003, respectively. On October 1, 2004, as a result of Ameren’s acquisition of IP, all unvested stock options granted to IP employees became null and void.

See Note 12 – Stock-based Compensation for further information.

 

42

Excise Taxes

Excise taxes reflected on Missouri electric, Missouri gas, and Illinois gas customer bills are imposed on us. They are recorded gross in Operating Revenues and Taxes Other than Income Taxes on each company’s statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer. They are recorded as tax collections payable and included in Taxes Accrued for Ameren, CIPS, Genco and IP and in Other Current Liabilities for CILCORP and CILCO. The following table presents excise taxes recorded in Operating Revenues and Taxes Other than Income Taxes for the years ended 2005, 2004 and 2003:

 

        2005      2004      2003

Ameren(a)

     $ 159      $ 134      $ 137

UE

        105        103        101

CIPS

        13        13        14

CILCORP(b)

       10        12        24

CILCO(c)

       10        12        24

IP(d)

       31        36        40

 

(a) Excludes amounts for IP before the acquisition date of September 30, 2004; excludes amounts for CILCORP and CILCO before the acquisition date of January 31, 2003.
(b) The 2003 amount includes January 2003 predecessor information, which was $2 million.
(c) With the exception of taxes reflected on CILCO customer bills issued prior to October 27, 2003, excise taxes at CILCO are recorded as tax collections payable and are included on the Consolidated Balance Sheet as Other Current Liabilities.
(d) The 2003 amount represents predecessor information. The 2004 amount includes January through September 2004 predecessor information, which was $30 million.

 

Income Taxes

Ameren uses an asset and liability approach for its financial accounting and reporting of income taxes, in accordance with the provisions of SFAS No. 109 “Accounting for Income Taxes.” Deferred tax assets and liabilities are recognized for transactions that are treated differently for financial reporting and tax return purposes. These deferred tax assets and liabilities are determined by statutory tax rates.

We recognize that regulators will probably reduce future revenues for deferred tax liabilities initially recorded at rates in excess of the current statutory rate. Therefore, reductions in the deferred tax liability, which were recorded due to decreases in the statutory rate, were credited to a regulatory liability. A regulatory asset has been established to recognize the probable future recovery in rates of future income taxes resulting principally from the reversal of allowance for funds used during construction – equity and temporary differences related to property, plant and equipment acquired before 1976, which were unrecognized temporary differences prior to the adoption of SFAS No. 109.

Investment tax credits used on tax returns of prior years have been deferred for book purposes; they are being amortized over the useful lives of the related properties. Deferred income taxes were recorded on the temporary difference represented by the deferred investment tax credits and a corresponding regulatory liability. This recognizes the expected reduction in rate revenue for future lower income taxes associated with the amortization of the investment tax credits. See Note 13 – Income Taxes for the treatment of IP’s unamortized investment tax credits and deferred tax liabilities upon the acquisition of IP by Ameren.

Minority Interest and Preferred Dividends of Subsidiaries

For the years ended December 31, 2005, 2004, and 2003, Ameren had minority interest expense related to EEI of $3 million, $4 million and $7 million, respectively, and preferred dividends of subsidiaries of $13 million, $11 million, and $11 million, respectively.

Earnings Per Share

There were no material differences between Ameren’s basic and diluted earnings per share amounts in 2005, 2004, and 2003. The assumed stock option conversions increased the number of shares outstanding in the diluted earnings per share calculation by 65,917 shares in 2005, 196,709 shares in 2004, and 289,244 shares in 2003.

Accounting Changes and Other Matters

SFAS No.143 – “Accounting for Asset Retirement Obligations” and FIN 47 – “Accounting for Conditional Asset Retirement Obligations”

We adopted the provisions of SFAS No. 143 and FIN 47, effective January 1, 2003, and December 31, 2005, respectively. SFAS No. 143 provides the accounting requirements for AROs associated with tangible, long-lived

 

43

assets. SFAS No. 143 requires us to record the estimated fair value of legal obligations associated with the retirement of tangible long-lived assets in the period in which the liabilities are incurred and to capitalize a corresponding amount as part of the book value of the related long-lived asset. In subsequent periods, we are required to make adjustments in AROs based on changes in estimated fair value. Corresponding increases in asset book values are depreciated over the remaining useful life of the related asset. Uncertainties as to the probability, timing or amount of cash flows associated with AROs affect our estimates of fair value.

FIN 47 clarified that an entity must recognize a liability for the fair value of a conditional ARO when it is incurred if the liability’s fair value can be reasonably estimated. FIN 47 also specified the information an entity would need to reasonably estimate the fair value of an ARO.

In 2005, Ameren, Genco, CILCORP, and CILCO recognized net aftertax losses of $22 million, $16 million, $2 million, and $2 million, respectively, for the cumulative effect of a change in accounting principle for FIN 47. Upon adoption of FIN 47, Ameren, UE, Genco, CILCORP, and CILCO recorded AROs for retirement costs associated with asbestos removal, ash ponds, and river structures. In addition, Ameren, UE, CIPS, and IP recorded AROs for the disposal of certain transformers.

 

Upon adoption of SFAS No. 143, Ameren and Genco recognized a net aftertax gain of $18 million in 2003 for the cumulative effect of a change in accounting principle. Prior to Ameren’s acquisition of CILCORP, predecessor CILCORP and CILCO recognized a net aftertax gain in 2003 of $4 million and $24 million, respectively, for the cumulative effect of a change in accounting principle. The gains recorded by Ameren, Genco, predecessor CILCORP, and CILCO were due to the elimination of costs of removal for non-rate-regulated assets previously accrued as a component of accumulated depreciation that were not a legal obligation. In addition, in accordance with SFAS No. 143, estimated net future removal costs associated with Ameren’s, UE’s, CIPS’, CILCORP’s and CILCO’s rate-regulated operations that had previously been embedded in accumulated depreciation were reclassified as a regulatory liability. Upon adoption of SFAS No. 143, UE recorded AROs related to its Callaway nuclear plant decommissioning costs and retirement costs for a river structure. Additionally, Genco recorded an ARO for the retirement costs for a power plant ash pond. CILCORP and CILCO recorded AROs related to AERG power plant ash ponds.

Before Ameren’s acquisition of IP, predecessor IP recognized a net aftertax loss upon adoption of SFAS No. 143 of $2 million for the cumulative effect of a change in accounting principle.

 

The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2005 and 2004:

 

        Ameren(a)(b)        UE(b)        CIPS      Genco       

CILCORP/

CILCO

      IP  

Balance at December 31, 2003

      $ 418        $ 408        $ -      $ 4        $ 5      $ 1  

Accretion in 2004(c) 

        23          23          -        (d )        1        (d )

Settled in 2004

        -          -          -        -          -        (1 )

Change in estimate

        2          -          -        -          2        -  

Balance at December 31, 2004

        443          431          -        4          8        -  

Accretion in 2005(c) 

        28          23          -        2          1        -  

Change in estimate(e)

       (42 )        (42 )        -        -          -        -  

Adoption of FIN 47

        94          54          2        28          4        2  

Balance at December 31, 2005

      $ 523        $ 466        $ 2      $ 34        $ 13      $ 2  

 

(a) Ameren amounts may not equal total due to AROs at EEI.
(b) The nuclear decommissioning trust fund assets of $250 million and $235 million as of December 31, 2005 and 2004, respectively, are restricted for decommissioning of the Callaway nuclear plant.
(c) Substantially all accretion expense was recorded as an increase to regulatory assets.
(d) Less than $1 million.
(e) Revision of UE’s Callaway nuclear plant ARO estimate.

The following table shows what our AROs would have been if FIN 47 had been in effect in 2003 and 2004:

 

        Pro Forma Asset Retirement Obligation
        Ameren      UE      CIPS      Genco     

CILCORP/

CILCO

      IP

January 1, 2003

      $ 508      $ 457      $ 2      $ 29      $ 11      $ 2

December 31, 2003

        513        459        2        30        12        2

December 31, 2004

        518        462        2        32        12        2

 

44

If FIN 47 had been applied for the years ended December 31, 2005, 2004, and 2003, Ameren’s, Genco’s, CILCORP’s and CILCO’s net income would have been lower by $2 million, $1 million, less than $1 million, and less than $1 million, respectively, in each year. The FIN 47 application would have reduced Ameren’s basic and diluted EPS $0.01 per share in each of these three years. The adoption of FIN 47 did not have any income statement impact on UE, CIPS, or IP because a regulatory asset was recorded as an offset to the AROs and the related net capitalized asset retirement costs.

SFAS No. 153 – “Exchanges of Nonmonetary Assets – an amendment of APB Opinion No. 29”

In December 2004, the FASB issued SFAS No. 153, which amends APB Opinion No. 29 to require the accounting at fair value for nonmonetary exchanges with commercial substance. The Ameren Companies were required to apply the provisions of SFAS No. 153 prospectively to transactions occurring after July 1, 2005. During the third quarter of 2005, Ameren, UE and Genco had nonmonetary emission allowance swaps that were accounted for at fair value under SFAS No. 153. As a result, Genco recorded a gain equal to the difference between the fair value of allowances received less the book value of allowances exchanged. The gain was recorded as a $21 million (pretax) reduction to fuel expense and an increase to other assets. UE recorded an increase to other assets and regulatory liabilities of $63 million.

FIN 46 – “Consolidation of Variable-interest Entities”

In January 2003, the FASB issued FIN 46, which changed the consolidation requirements for special-purpose entities (SPEs) and non-special-purpose entities (non-SPEs) that meet the criteria for designation as variable-interest entities (VIEs). In December 2003, the FASB revised FIN 46 (FIN 46R) to clarify certain aspects of FIN 46 and to modify the effective dates of the new guidance. FIN 46R provides guidance on the accounting for entities that are controlled through means other than voting rights by another entity. FIN 46R requires a VIE to be consolidated by a company if that company is designated as the primary beneficiary.

The Ameren Companies do not have any interests in entities that are considered SPEs, other than IP’s investment in IP LLC. FIN 46R was effective on March 31, 2004, for any interests the Ameren Companies held in non-SPEs. The adoption of FIN 46R did not have a material impact on the consolidated financial statements of the Ameren Companies. We have determined that the following significant variable-interest entities are held by the Ameren Companies:

 

•   EEI. Ameren has an 80% ownership interest in EEI through UE’s 40% interest and Development Company’s 40% interest. Under the FIN 46R model, Ameren, UE, and Development Company have a variable interest in EEI, and Ameren is the primary beneficiary. Accordingly, Ameren continues to consolidate EEI, and UE continues to account for its investment in EEI under the equity method. The maximum exposure to loss as a result of these variable interests in EEI is limited to Ameren’s, UE’s, and Development Company’s equity investments in EEI.
•   Tolling agreement. CILCO has a variable interest in Medina Valley through a tolling agreement to purchase steam, chilled water, and electricity. We have concluded that CILCO is not the primary beneficiary of Medina Valley. Accordingly, CILCO does not consolidate Medina Valley. The maximum exposure to loss as a result of this variable interest in the tolling agreement is not material.
•   Leveraged lease and affordable housing partnership investments. Ameren, UE, CILCORP and CILCO have investments in leveraged lease and affordable housing partnership arrangements that are variable interests. We have concluded that none of these companies is a primary beneficiary of any of the VIEs related to these investments. The maximum exposure to loss as a result of these variable interests is limited to the investments in these arrangements. At December 31, 2005, Ameren, CILCORP, and CILCO had net investments in leveraged leases of $50 million, $21 million, and $21 million, respectively. At December 31, 2005, Ameren and UE had investments in affordable housing partnerships of $16 million and $10 million, respectively, after CILCORP transferred its housing interests to Union Electric Development Corporation (a UE subsidiary) in 2005.
•   IP SPT. Ameren acquired a variable interest in IP SPT with the acquisition of IP on September 30, 2004. IP has a variable interest in IP SPT, which was established in 1998 to issue TFNs. IP has indemnified and is liable to IP SPT if IP does not bill the applicable charges to its customers on behalf of IP SPT or if it does not remit the collection to IP SPT; however, the note holders are considered the primary beneficiaries of this special-purpose trust. Accordingly, Ameren and IP do not consolidate IP SPT.

FSP SFAS No. 106-1 and FSP SFAS No. 106-2 – “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”

On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare Prescription Drug Act) became law. The Medicare Prescription Drug Act introduced a prescription drug benefit for retirees under Medicare as well as a federal subsidy for

 

45

sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit. Through its postretirement benefit plans, Ameren provides retirees with prescription drug coverage that we believe is actuarially equivalent to the Medicare prescription drug benefit. In January 2004, the FASB issued FSP SFAS 106-1, which permitted a plan sponsor of a postretirement health care plan that provides a prescription drug benefit to make a one-time election to defer the accounting for the effects of the Medicare Prescription Drug Act. We made this one-time election allowed by FSP SFAS 106-1.

In May 2004, the FASB issued FSP SFAS 106-2, which superseded FSP SFAS 106-1. FSP SFAS 106-2 provides guidance on accounting for the effects of the Medicare Prescription Drug Act for employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. Ameren elected to adopt FSP SFAS 106-2 during the second quarter ended June 30, 2004, retroactive to January 1, 2004. See Note 11 – Retirement Benefits for additional information on the impact of adoption of FSP SFAS 106-2.

Predecessor IP’s adoption of FSP SFAS 106-2 on July 1, 2004, had no impact on IP’s results of operations, financial position, or liquidity because its drug benefit was not actuarially equivalent to the drug benefit under Medicare Part D.

NOTE 2 – ACQUISITIONS

IP and EEI

On September 30, 2004, Ameren completed the acquisition of all the common stock and 662,924 shares of preferred stock of IP and an additional 20% ownership interest in EEI from subsidiaries of Dynegy. Ameren acquired IP to complement its existing Illinois gas and electric operations. The purchase included IP’s rate-regulated electric and natural gas transmission and distribution business serving 625,000 electric customers and 425,000 gas customers in areas contiguous to our existing Illinois utility service territories. With the acquisition, IP became an Ameren subsidiary operating as AmerenIP.

The total transaction value was $2.3 billion, including the assumption of $1.8 billion of IP debt and preferred stock. Cash consideration was $429 million, net of $51 million cash acquired, and included transaction costs. In addition, this transaction included a fixed-price capacity power supply agreement for IP’s annual purchase in 2005 and 2006 of 2,800 megawatts of electricity from DYPM. This agreement supplied about 70% of IP’s electric customer requirements during 2005. It is expected to supply about 70% of the requirements in 2006. The remaining 30% of IP’s power needs is being supplied by other companies through contracts and open-market purchases. In the event that suppliers are unable to provide the electricity required by existing agreements, IP would be forced to find alternative suppliers to meet its load requirements, thus exposing itself to market price risk, which could have a material impact on Ameren’s and IP’s results of operations, financial position, or liquidity.

Ameren funded this acquisition with the issuance of new Ameren common stock. Ameren issued an aggregate of 30 million common shares in February 2004 and July 2004, which generated net proceeds of $1.3 billion. Proceeds from these issuances were used to finance the cash portion of the purchase price and to reduce IP debt assumed as part of this transaction and to pay related premiums.

In December 2004, 230 IP employees accepted a voluntary separation opportunity, which provided an enhanced separation benefit and extended medical and dental benefits. Employees who accepted the voluntary separation opportunity departed IP throughout 2005 as business needs warranted. These voluntary separations were consistent with Ameren’s plan for the integration of IP and conditions in the ICC order approving the acquisition, which relate to the realization of administrative synergies from the acquisition. As of December 31, 2005, separation costs of $26 million were deferred as a regulatory asset for future recovery from customers, which is also consistent with the ICC order.

For income tax purposes, Ameren and Dynegy have elected to treat Ameren’s acquisition of IP stock as an asset acquisition under Section 338(h)(10) of the Internal Revenue Code of 1986, as amended.

Ameren acquired IP for $355 million, including transaction costs, plus the assumption of $1.8 billion of IP debt and preferred stock. During the quarter ended September 30, 2005, Ameren finalized the allocation of the purchase price and completed its valuations of the acquired net assets and liabilities of IP and EEI, including third-party valuations of property and plant, intangible assets, pension and other postretirement benefit obligations, and contingent obligations. The fair value of IP’s power supply agreements, including the fixed-price capacity power supply agreement with DYPM recorded at the acquisition date, resulted in a net liability of $109 million (December 31, 2005 – $43 million). This amount is being amortized through December 31, 2006. In addition, IP recorded a fair value adjustment, resulting in a net asset of $20 million, which was fully amortized by December 31, 2005, for IP’s power supply agreement with EEI that expired at the end of 2005. The excess of the purchase price for IP’s common stock and preferred stock over net assets acquired was allocated to goodwill in the amount of $326 million, net of future tax benefits. For income

 

46

tax purposes, a portion of the purchase price will be allocated to goodwill; that portion will be deducted ratably over a 15-year period. Goodwill increased by $6 million since December 31, 2004, primarily because of net adjustments to regulatory assets, income tax accounts, property and plant, accrued environmental reserves, and net assets for IP’s power supply agreement with EEI. These increases in goodwill were partially offset by net adjustments to accrued severance, accrued relocation and accrued claims expenses, as well as cash payments from Dynegy under working capital and indemnification provisions pursuant to the terms of the stock purchase agreement. The following table presents the final estimated fair values of the assets acquired and liabilities assumed at the date of Ameren’s acquisition of IP.

 

Current assets

      $ 368

Property and plant

        1,962

Investments and other noncurrent assets

        370

Goodwill

        326

Total assets acquired

        3,026

Current liabilities

        221

Long-term debt, including current maturities

        1,982

Accrued pension and other postretirement liabilities

        244

Other noncurrent liabilities

        211

Total liabilities assumed

        2,658

Preferred stock assumed

        13

Net assets acquired

      $ 355

The following unaudited pro forma financial information presents a summary of Ameren’s consolidated results of operations for the years ended December 31, 2004 and 2003, as if the acquisition of IP had been completed at the beginning of 2003. It includes pro forma adjustments to reflect the allocation of the purchase price to the acquired net assets. The pro forma financial information does not include cost savings that may result from the combination of Ameren with IP.

 

For the years ended December 31,    2004    2003

Operating revenues

    $ 6,295    $ 6,089
Income before cumulative effect of change in accounting principle      677      663
Cumulative effect of change in accounting principle, net of taxes      -      16

Net income

    $ 677    $ 679

Earnings per share – basic

    $ 3.49    $ 3.55

                                – diluted

    $ 3.49    $ 3.55

This pro forma information is not necessarily indicative of the results of operations as they would have been had the transaction been effected on the assumed date, nor is it an indication of trends for future results.

IP’s note receivable from a former affiliate of $2.3 billion was eliminated as of September 30, 2004, before Ameren’s acquisition of IP, to meet the conditions of the closing.

 

The portion of the total transaction value attributable to Ameren’s acquisition of Dynegy’s 20% ownership interest in EEI now held by Development Company was $125 million. The purchase price for this ownership interest was allocated, based on fair value, to property and plant ($55 million) and emission allowances ($48 million), partially offset by a net liability for power supply agreements ($25 million) and a reduction to net deferred tax assets ($31 million). The excess of purchase price over fair value was allocated to goodwill in the amount of $65 million. Goodwill increased by $11 million since December 31, 2004, due to adjustments to property and plant and the net liability for power supply agreements, partially offset by adjustments to both emission allowances and income tax accounts, resulting from the refinement of the third-party valuation of EEI’s net assets.

CILCORP and Medina Valley

On January 31, 2003, Ameren completed the acquisition of all of the outstanding common stock of CILCORP from AES. CILCORP is the parent company of CILCO. On February 4, 2003, Ameren also completed the acquisition from AES of Medina Valley, which indirectly owns a 40-megawatt gas-fired electric generation plant. The total acquisition cost of $1.4 billion included the assumption by Ameren of CILCORP and Medina Valley debt of $895 million and consideration of $479 million in cash, net of $38 million cash acquired. Goodwill of $584 million (CILCORP – $574 million; Medina Valley – $10 million) was recognized in connection with the CILCORP and Medina Valley acquisitions in addition to specifically identifiable intangible assets of $6 million comprising customer contracts, which are subject to amortization with an average life of 10 years. In the fourth quarter of 2005, Ameren became aware of a misstatement in the amount of deferred income taxes recorded in connection with the acquisition accounting for CILCORP and Medina Valley. Ameren determined that the adjustment required to correct this misstatement was not material to the consolidated financial statements of either CILCORP or Ameren. Accordingly, an adjustment to increase net deferred income tax liabilities and goodwill was recorded in the fourth quarter of 2005 at CILCORP and Ameren.

NOTE 3 – RATE AND REGULATORY MATTERS

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

 

47

Intercompany Transfer of Illinois Service Territory and Electric Generating Facilities

Illinois Service Territory Transfer

On May 2, 2005, following the receipt of all required regulatory approvals, UE completed the transfer to CIPS of its Illinois electric and natural gas service territory, including its Illinois-based distribution assets and certain of its transmission assets, at a net book value of $133 million. UE’s electric generating facilities and a certain insignificant amount of its electric transmission and communication facilities in Illinois were not part of the transfer. Pursuant to the asset transfer agreement, UE transferred 50% of the assets directly to CIPS in consideration for a CIPS subordinated promissory note in the principal amount of $67 million and 50% of the assets by means of a dividend in kind to Ameren, followed by a capital contribution by Ameren to CIPS. With the completion of this transfer, UE no longer operates as a public utility in Illinois subject to ICC regulation.

In February 2005, the MoPSC issued an order approving the transfer and clarified its order in March 2005. The MoPSC’s order, as clarified, included the following principal conditions:

 

•   The order allows UE to recover in rates up to 6% of unknown UE generation-related liabilities associated with the generation that was formerly allocated to UE’s Illinois service territory if UE can show that the benefits of the transfer of the Illinois service territory outweigh these costs in future rate cases.
•   The order requires an amendment to the joint dispatch agreement among UE, Genco and CIPS to declare that margins on third-party short-term power sales of excess generation will be divided by generation output, not by load requirements. See Federal – Amendment to Joint Dispatch Agreement below for a discussion of an amendment to the joint dispatch agreement entered into in January 2006, subject to acceptance and approval by FERC, in compliance with the order.
•   The MoPSC also ordered that UE may complete the transfer before it receives all regulatory approvals necessary to effectuate the required amendment to the joint dispatch agreement. This permission is based on UE’s commitment that for ratemaking purposes the joint dispatch agreement amendment will be deemed to have been accepted by UE on the date the transfer closed. In the event that the regulatory approval for the amendment is not obtained, this commitment would result in just the allocation of these additional margins to UE for determining the revenue requirements in the ratemaking process, with no impact on Genco’s margins.
•   The order requires that, in a future rate case, revenues UE could have received for incremental energy transfers under the joint dispatch agreement to Genco resulting from the service territory transfer to CIPS be based on market prices unless UE can show that the benefits of the transfer of the Illinois service territory outweigh the difference between the market prices and the actual cost-based charges for such incremental energy transfers.

Electric Generating Facilities Transfer

On May 2, 2005, following the receipt of all required regulatory approvals, Genco completed the transfer to UE of its 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois, at a net book value of $241 million. This transfer completed the remainder of UE’s commitment under the 2002 Missouri electric rate case settlement discussed below under Missouri – Electric, which required the addition of 700 megawatts of generation capacity by June 30, 2006.

The Illinois service territory transfer and the electric generating facilities transfer discussed above were accounted for at book value, with no gain or loss recognition.

CT Facilities Purchases

In December 2005, UE entered into an asset purchase and sale agreement with NRG Audrain Holding, LLC, and NRG Audrain Generating LLC, affiliates of NRG Energy, Inc. (collectively “NRG”), for the purchase of a 640-megawatt CT facility located in Audrain County, Missouri, at a price of $115 million (subject to adjustment for the book value of inventory at closing). As a part of this transaction, UE will acquire the rights of NRG as lessee of the CT facility under a long-term lease with Audrain County. This lease was entered into pursuant to Missouri economic development statutes to provide a development incentive property tax savings to the lessee for locating in Audrain County. In an arrangement similar to UE’s existing economic development lease arrangement with the city of Bowling Green, Missouri, relating to UE’s Peno Creek CT facility, UE will acquire NRG’s ownership of a taxable industrial development revenue bond (principal amount of $240 million) issued to it by Audrain County in exchange for title to the NRG CT facility. The lease term will expire no later than the final maturity of the bond (December 1, 2023). It is a net lease, with UE as the lessee being responsible for rental payments under the lease in an amount sufficient to pay the debt service of the bond. No capital was initially raised in the transaction and no capital will be raised as a result of UE’s assumption of NRG’s lease obligations. Audrain County will retain title to the CT facility during the term of the bond and the lease, and therefore the facility will be exempt from ad valorem taxation. Under the terms of the lease, UE will retain all operation and maintenance responsibilities for the CT facility. The title to the facility will be transferred to UE at the expiration of the lease.

 

48

Also in December 2005, UE entered into an asset purchase and sale agreement with Aquila Piatt County Power, LLC, a subsidiary of Aquila, Inc., for the purchase of the 510-megawatt Goose Creek CT facility in Piatt County, Illinois, at a price of $105 million. In addition, UE entered into an asset purchase and sale agreement with MEP Flora Power, LLC, another subsidiary of Aquila, Inc., for the purchase of the 340-megawatt Raccoon Creek CT facility located in Clay County, Illinois, at a price of $70 million. Completion of each of these two purchase transactions is conditioned upon the closing of both transactions.

These CT facility purchases are designed to meet UE’s increased generating capacity needs as well as to provide UE with additional flexibility in determining future base-load generating capacity additions. Completion of these transactions requires the authorization of various regulatory agencies and the satisfaction of other customary closing conditions. All three transactions require the approval of FERC. The sale of the Aquila CT facilities also requires approval of the Kansas Corporation Commission. UE’s assumption of the economic development lease and related documents pertaining to the NRG CT facility was approved by the MoPSC in February 2006. Filings seeking these regulatory agency authorizations were made in late December 2005 and decisions by such agencies are expected to be received in the first half of 2006. The waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 for all three transactions have expired. In the FERC proceedings relating to these transactions, the Missouri Joint Municipal Electric Utility Commission (MJMEUC) has filed motions to intervene and protests requesting technical conferences to address alleged competition problems relating to UE’s CT purchases and alleged transmission constraints that contribute to the competition problems. On February 7, 2006, UE responded to the protest of the MJMEUC. In the response, UE contended that the acquisitions should be approved as being reasonable in all respects and not harmful as alleged by MJMEUC. In particular, UE contended that the acquisition was reasonable using the MISO footprint as the relevant market for purposes of FERC’s review of the proposed transactions, and that MJMEUC failed to show that a smaller relevant market was appropriate. Further, UE contended that its analysis supporting the proposed transactions was thorough and had adequately considered all relevant effects on the transmission system. UE cannot predict whether it will be able to receive all the regulatory approvals necessary to complete the transactions.

Missouri

Electric

In August 2002, a stipulation and agreement resolved an excess-earnings complaint brought against UE by the MoPSC staff following the expiration of UE’s experimental alternative regulation plan. The resolution became effective following agreement by all parties to the case and approval by the MoPSC. The stipulation and agreement included the following features:

 

•   The phase-in of $110 million of electric rate reductions through April 2004, $50 million of which was retroactively effective as of April 1, 2002, $30 million of which became effective on April 1, 2003, and $30 million of which became effective on April 1, 2004.
•   A rate moratorium providing for no changes in rates before July 1, 2006, subject to certain statutory and other exceptions.
•   A commitment to make $2.25 billion to $2.75 billion in critical energy infrastructure investments from January 1, 2002, through June 30, 2006, including, among other things, the addition of more than 700 megawatts of new generation capacity and the replacement of steam generators at UE’s Callaway nuclear plant. The 700 megawatts of new generation was satisfied by UE’s addition of 240 megawatts in 2002 and the transfer at net book value to UE of 550 megawatts of generation assets from Genco in 2005. See Intercompany Transfer of Illinois Service Territory and Electric Generating Facilities within this note for additional information. The replacement of the steam generators at UE’s Callaway plant was completed in November 2005.
•   An electric cost-of-service study to be submitted to the MoPSC staff and other parties to the 2002 stipulation and agreement by January 1, 2006. In late December 2005, UE submitted a confidential cost-of-service study based on a test year of the twelve months ending June 30, 2005. This submission did not constitute an electric rate adjustment request, and UE has not decided when it will file to adjust electric rates in Missouri. Several factors will influence UE’s decision, including determining the appropriate test year to use in a potential rate filing to set future electric rates, economic and energy market conditions, expected generating plant additions, and the status of the pending MoPSC rulemaking proceedings on fuel, purchased power, and environmental cost recovery mechanisms (see MoPSC Rulemaking Proceedings in this note), among other things. The MoPSC staff and other stakeholders will review UE’s cost-of-service study and, after their analyses, may also make recommendations as to electric rate adjustments. Generally, a proceeding to change rates in Missouri could take up to 11 months.

Noranda Aluminum, Inc. (Noranda)

Following the receipt of all regulatory approvals and satisfaction of all regulatory and other conditions, the tariff by

 

49

which UE serves Noranda became effective June 1, 2005. UE serves Noranda under a 15-year agreement to supply about 470 megawatts (peak load) of electricity (or 5% of UE’s generating capability, including currently committed purchases) to Noranda’s primary aluminum smelter in southeast Missouri.

Gas

In January 2004, a stipulation and agreement resolved a request by UE to increase annual natural gas rates. The resolution became effective following agreement by all parties to the case and approval by the MoPSC. The stipulation and agreement authorized an increase in annual gas delivery rates of $13 million, effective February 15, 2004. Other principal features of the stipulation and agreement include:

 

•   A rate moratorium prohibiting changes in gas delivery rates before July 1, 2006, absent the occurrence of a significant unusual event that has a major impact on UE.
•   A commitment to make $15 million to $25 million in infrastructure improvement investments from July 1, 2003, through December 31, 2006, including replacement of cast-iron main and unprotected steel service lines. UE agreed not to propose rate adjustments to recover infrastructure costs through a statutory infrastructure system replacement surcharge before January 1, 2006.
•   Commitments to contribute an aggregate of $310,000 annually to programs for weatherization energy assistance for low-income customers, and energy-efficient equipment in UE’s service territory.

MoPSC Rulemaking Proceeding

In July 2005, a new law was enacted that enables the MoPSC to put in place fuel, purchased power, and environmental cost recovery mechanisms for Missouri’s utilities. The law also includes rate case filing requirements, a 2.5% annual rate increase cap for the environmental recovery mechanism and prudency reviews, among other things. Detailed rules for these mechanisms are expected to be issued by the MoPSC in 2006.

Illinois

IP and EEI Acquisition

Ameren received all the regulatory agency approvals necessary to acquire IP and a 20% interest in EEI from Dynegy on September 30, 2004.

The ICC order approving Ameren’s acquisition of IP contains several important provisions, including the following:

 

•   The order requires IP to submit quarterly reports in 2005 and 2006 on certain milestones regarding IP’s progress in achieving an estimated $33 million in annual synergies by the beginning of 2007, and it provides for adjustments in IP’s next electric and gas rate cases if IP fails to achieve those milestones.
•   Commencing in 2007, IP will recover over four years, through rates, $67 million in reorganization costs related to the integration of IP into the Ameren system and the restructuring of IP. As of December 31, 2005, these reorganization costs were incurred and deferred as a regulatory asset.
•   The order approves a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms. Beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates will 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.
•   Ameren commits to cause an aggregate of at least $750 million principal amount of IP’s long-term debt, including IP’s $550 million principal amount of 11.50% Series mortgage bonds due 2010, to be redeemed, repurchased or retired on or before December 31, 2006. As of December 31, 2005, $770 million principal amount of IP debt was retired in accordance with this provision.
•   The order provides IP with the ability to declare and pay $80 million of dividends on its common stock in 2005 and $160 million of dividends on its common stock cumulatively through 2006, provided IP has achieved an investment-grade credit rating from S&P or Moody’s. If, however, IP’s $550 million principal amount of 11.50% Series mortgage bonds are not eliminated by December 31, 2006, IP may not thereafter declare or pay common dividends without seeking authority from the ICC. As of December 31, 2005, less than $1 million of the 11.50% Series mortgage bonds were outstanding. The bonds are callable at the end of 2006.
•   IP will establish a dividend policy comparable to the dividend policy of Ameren’s other Illinois utilities consistent with achieving and maintaining a common equity to total capitalization ratio between 50% to 60%.
•   Ameren will commit IP to make between $275 million and $325 million in energy infrastructure investments over its first two years of ownership. As of December 31, 2005, IP has made approximately $190 million in energy infrastructure investments. IP’s estimated capital expenditures in 2006 include additional energy infrastructure improvements that will satisfy this commitment.

 

50

Electric

By 2002, the power market for Illinois residential, commercial and industrial customers of UE, CIPS, CILCO and IP was opened to alternative electric suppliers under the Illinois Customer Choice Law. Under the Illinois Customer Choice Law, UE, CIPS, CILCO and IP rates initially were frozen through January 1, 2005. An amendment to the Illinois Customer Choice Law extended the rate freeze through January 1, 2007. As a result of this extension, and pursuant to ICC orders, CIPS and Marketing Company extended their power supply agreements through December 31, 2006, as did CILCO and AERG. See Illinois Service Territory transfer and Electric Generating Facilities transfer above for a discussion of UE’s discontinuance of utility operations in Illinois and Note 14 – Related Party Transactions for a discussion of the affiliate power supply agreements.

During 2004, the ICC conducted workshops to seek input from interested parties on the framework for retail electric rate determination and power procurement after the current Illinois electric rate freeze expires on January 1, 2007, and supply contracts expire on December 31, 2006. Using input from these workshops, in February 2005 CIPS, CILCO and IP filed with the ICC a proposed process for power procurement through an ICC-monitored auction, including a rate mechanism to pass power supply costs directly through to customers, among other things. The form of power supply would meet the full requirements of the utility, and the risk of fluctuations in power supply requirements would be borne by the supplier.

In December 2005, an administrative law judge issued a proposed order recommending approval of the power procurement auction proposed by CIPS, CILCO and IP and related tariffs including the retail rates by which power supply costs would be passed through to customers.

On January 24, 2006, the ICC issued an order which unanimously approved the Ameren Illinois utilities’ proposed power procurement auction and the related tariffs, including the retail rates by which power supply costs would be passed through to customers. The order includes the following key findings and provisions:

 

•   The auction proposal is reasonably designed to enable CIPS, CILCO and IP to procure power supply in a competitive and least-cost manner.
•   The first auction to take place in the first 10 days of September 2006.
•   There is a limitation of 35% on the amount of power any single supplier can provide the Ameren Illinois utilities’ expected annual load. Genco and AERG would probably participate in the power procurement auction through Marketing Company, subject to this limit. Genco, AERG and EEI would be considered one supplier.
•   Requires a portfolio of one-, two-, and three-year supply contracts.
•   Allows full cost recovery through a rate mechanism.
•   Requires an annual, postauction prudence review by the ICC.

On January 26, 2006, CILCO, CIPS and IP filed with the ICC a request for rehearing with regard to the provision of the January 2006 order, which requires an annual, postauction prudence review to be performed by the ICC. CILCO, CIPS and IP asserted in their request that there is no basis for such a prudence review. In February 2006, the ICC denied this request for rehearing, and CILCO, CIPS and IP filed an appeal in the appellate court for the Fourth District in Illinois on February 9, 2006.

Certain Illinois legislators, the Illinois attorney general, the Illinois governor and other parties have sought and continue to seek to block the power procurement auction and/or the recovery of related costs for power supply resulting from the auction through rates to customers. In May 2005, the Illinois attorney general, the Citizens Utility Board (CUB) and the Environmental Law and Policy Center (ELPC) filed a motion to dismiss the Ameren Illinois utilities’ proposed power procurement auction with the ICC on the basis that the ICC did not have authority to approve market-based rates for electric service that have not been “declared competitive” pursuant to Section 16-113 of the Illinois Public Utilities Act (PUA). This motion and a subsequent appeal were denied by the administrative law judge in the case and by the ICC, respectively.

In September 2005, Illinois Governor Rod Blagojevich sent a letter to the ICC expressing his opposition to CIPS’, CILCO’s and IP’s proposed power procurement auction process and requested dismissal of the pending proceeding for approval of such process. CIPS, CILCO and IP responded to the governor’s letter citing legal deficiencies in his position and the potential adverse consequences that could result if his position is ultimately sustained. Copies of the governor’s letter and the Ameren Illinois utilities’ response letter appear as Exhibits 99.1 and 99.2, respectively, to the Current Report on Form 8-K dated September 15, 2005. Also in September 2005, the Illinois attorney general, the Cook County state’s attorney, the CUB, and the ELPC filed a complaint in the Circuit Court of Cook County, Illinois, against the ICC and the individual ICC commissioners making claims similar to those included in their motion to dismiss that was denied. The complaint asked the court to determine that the ICC lacks authority to approve the auction proposal. It sought injunctive relief prohibiting the ICC from approving the proposals by CIPS, CILCO and IP. On January 20, 2006, the Circuit Court of Cook County, Illinois, entered an order dismissing the complaint with prejudice.

 

51

Both the Illinois governor’s letter and the attorney general’s lawsuit assert that the energy component of CIPS’, CILCO’s and IP’s retail rates for electricity should not be based on the costs to procure energy and capacity in the wholesale market. Although CIPS, CILCO and IP have received favorable rulings from the ICC and the Circuit Court of Cook County with respect to their proposals, we anticipate that certain Illinois legislators, the Illinois attorney general, the Illinois governor, and others will persist in their efforts to block the power procurement auction and the recovery of related costs through rates to customers. In February 2006, the Illinois attorney general, CUB and ELPC filed with the ICC applications for a rehearing of the ICC’s January 24, 2006 order approving the Ameren Illinois utilities power procurement auction and related tariffs. Their arguments for a rehearing are generally similar to those that they have previously raised as discussed above. The ICC has until March 2006 to rule upon these applications for rehearing. We are unable to predict whether such efforts will ultimately be successful. However, 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 could result in material adverse consequences to the Ameren Illinois utilities. As noted in their response letter to the Illinois governor, these consequences could include a significant drop in credit ratings (possibly to below investment-grade status), a loss of access to the capital markets, higher borrowing costs, higher power supply costs, an inability to make timely energy infrastructure investments, reduced customer service, job losses, and financial insolvency. 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 for a discussion of the credit rating changes issued in response to actions in Illinois.

With regard to the delivery service component of customer rates, 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 rates for electric delivery service by $14 million, $43 million and $145 million, respectively. To mitigate the impact of these requested increases on residential customers, CILCO and IP proposed a two-year phase-in with increases for average residential delivery rates capped in the first year. The phase-in would decrease requested rate increases by $10 million and $36 million for CILCO and IP, respectively, in the first year. The ICC has until November 2006 to render a decision in these rate cases.

The Illinois legislature held hearings in 2005 and 2006 regarding the framework for retail rate determination and power procurement. In February 2006, legislation was introduced that would extend the electric rate freeze in Illinois through 2010. We cannot predict what actions, if any, the Illinois legislature may ultimately take. Any decision or action that impairs CIPS’, CILCO’s and IP’s ability to fully recover purchased power costs from their electric customers in a timely manner could result in material adverse consequences for these companies and for Ameren. CIPS, CILCO and IP have indicated to stakeholders in Illinois that they would be willing to consider a rate increase phase-in plan for residential customers if such plan allowed for full and timely recovery of all costs and did not result in further reductions in credit ratings from December 31, 2005 levels. We believe a rate increase phase-in plan, with full and timely recovery of any deferred costs, would require legislation in Illinois.

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. There can be no assurance that Ameren and the Ameren Illinois utilities will prevail over the stated opposition by certain 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.

Gas

In May 2005, the ICC issued an order awarding IP increases in annual natural gas delivery rates of $11 million. In the order approving Ameren’s acquisition of IP, the ICC prohibited IP from filing for any proposed increase in gas delivery rates to be effective before January 1, 2007, beyond this recently authorized gas delivery rate increase. IP filed an appeal in the appellate court for the Third District in Illinois regarding certain disallowances issued by the ICC in its May 2005 order. Ameren sought indemnification from Dynegy for the disallowances under the stock purchase agreement covering Ameren’s acquisition of IP from Dynegy. In July 2005, Dynegy paid to Ameren $8 million in full settlement of this indemnification claim. Under the terms of the settlement, IP will retain the benefits of any successful appeal of the May 2005 ICC order with no refund obligation to Dynegy.

Federal

Regional Transmission Organization

In early 2004, UE received authorization from the MoPSC and FERC to participate in the MISO for a five-year period, with participation after that period subject to further approvals by the MoPSC. Consistent with the orders issued by the MoPSC and FERC, the MoPSC would continue to set the transmission component of UE’s rates to serve its bundled retail load.

 

52

On May 1, 2004, functional control, but not ownership, of UE’s and CIPS’ transmission systems was transferred to the MISO. On September 30, 2004, prior to the completion of Ameren’s acquisition of IP as required by FERC’s order approving the acquisition, IP transferred functional control, but not ownership, of its transmission system to the MISO. These transfers had no accounting impact on UE, CIPS and IP because they continue to own the transmission assets.

In 2004, as part of the transfer of functional control of UE’s and CIPS’ transmission system to MISO, Ameren received $26 million, which represented the refund of the $13 million exit fee paid by UE and the $5 million exit fee paid by CIPS, both of which were expensed when they left the MISO in 2001, plus $1 million interest on the exit fees and the reimbursement of $7 million that was invested in the proposed Alliance RTO. These refunds resulted in aftertax gains of $11 million, $8 million, and $3 million for Ameren, UE, and CIPS respectively, which were recorded in other operations and maintenance expenses during the quarter ended June 30, 2004. As part of the transfer of functional control of IP’s transmission system to the MISO at the end of September 2004, predecessor IP also received a refund of its MISO exit fee, plus interest on the exit fee, and RTO development costs resulting in aftertax gains of $9 million during the quarter ended September 30, 2004.

Before our acquisition of it, CILCO was already a member of the MISO, and it had transferred functional control of its transmission system to the MISO. Genco does not own transmission assets, but pays the MISO to use the transmission system to transmit power from the Genco generating plants.

On April 1, 2005, the MISO Day Two Energy Market began operating. The MISO Day Two Energy Market presents an opportunity for increased power sales from UE, Genco and CILCO power plants and improved access to power for UE, CIPS, CILCO and IP. The MISO Day Two Energy Market also presents the risk of significantly higher MISO-related costs. Due to the MISO Day Two Energy Market, we incurred higher operating expenses in 2005. In part, these higher charges were due to volatile summer weather patterns and related loads. In addition, we attribute some of these higher charges to the relative infancy of the MISO Day Two Energy Market, suboptimal dispatching of power plants, and price volatility. We will continue to optimize our operations and work closely with MISO to ensure that the MISO Day Two Energy Market operates more efficiently and effectively in the future.

Pursuant to a series of FERC orders, FERC put into effect on December 1, 2004, Seams Elimination Cost Adjustment (SECA) charges, subject to refund and hearing procedures, which were filed in late November 2004 by UE, CIPS, CILCO and IP. The SECAs are a transition mechanism that is in place for the period December 1, 2004, to March 31, 2006, to compensate transmission owners in MISO and PJM for revenues lost when FERC eliminated regional through-and-out rates, previously applicable to transactions crossing the border between the MISO and PJM. The SECA charge is a nonbypassable surcharge payable by load-serving entities in proportion to the benefit they realized from the elimination of the regional through-and-out rates. In 2005, Ameren, UE, CIPS and IP have received net revenues from the SECA charge of $12 million, $3 million, $2 million and $7 million, respectively. CILCO’s net SECA charges were less than $1 million. Until the SECA filings have been finally approved by FERC, we cannot predict the ultimate impact that such rate structure will have on UE’s, CIPS’, CILCO’s and IP’s costs and revenues.

Hydroelectric License Renewal

In May 2005, UE, the U.S. Department of the Interior and various state agencies reached a settlement agreement that is expected to lead to FERC’s relicensing of UE’s Osage hydroelectric plant for another 40 years. The settlement must be approved by FERC. Approval and relicensure are expected in 2006. The current FERC license expired on February 28, 2006. Operations are permitted to continue under the expired license until the license renewal is approved.

EEI Market-based Rate Authority

In September 2005, EEI submitted to FERC a filing seeking authority to sell power at market-based rates after the expiration of its contracts with UE, CIPS (which had resold its power entitlement to Marketing Company), IP, Kentucky Utilities Company, and the DOE on December 31, 2005. The Missouri OPC filed a protest with FERC of EEI’s filing in October 2005, which contended that FERC should reject EEI’s request and instead compel EEI to sell power to UE under the terms of their contract, which expired on December 31, 2005. EEI subsequently filed a response to the protest, which contended that the OPC had not presented any evidence that would justify a rejection of EEI’s request and that the OPC was, in effect, improperly requesting a continuation of the contract, which was set to terminate on December 31, 2005. In December 2005, FERC issued an order that rejected the arguments of the OPC and granted market-based rate authorization to EEI. EEI’s market rate tariff was accepted as proposed and was given a November 14, 2005, effective date as requested.

Proposed Amendments to Joint Dispatch Agreement

As a result of the MoPSC order approving the transfer of UE’s Illinois service territory to CIPS, the provision in the

 

53

joint dispatch agreement which determines the allocation between UE and Genco of margins or profits from short-term sales of excess generation to third parties must be modified. Specifically the MoPSC order required an amendment so that margins on third-party short-term power sales of excess generation would be allocated between UE and Genco based on generation output, not on load requirements, as the agreement had provided. In compliance with the MoPSC order, UE, CIPS and Genco on January 9, 2006, filed this amendment to the joint dispatch agreement with FERC. This amendment was to become effective January 10, 2006, subject to acceptance and approval by FERC. If this allocation change had been effective in 2005, it probably would have resulted in a transfer of electric margins from Genco to UE.

The Missouri OPC intervened in the FERC proceeding and requested that the joint dispatch agreement be further amended to price all transfers of power at market prices rather than incremental cost, which could transfer additional electric margins from Genco to UE. In February 2006, UE, CIPS and Genco made a filing with FERC opposing the Missouri OPC’s position. Should FERC, or the MoPSC in some future ratemaking proceeding, require that transfers under the joint dispatch agreement be priced at market, an evaluation of the continued benefits of the joint dispatch agreement would have to be made by UE, CIPS and Genco. Depending on the outcome of the evaluations, one or more of these companies may decide to terminate the agreement. UE, CIPS and Genco have the right to terminate this agreement with one year’s notice, unless terminated earlier by mutual consent.

In 2005, Genco received net transfers of 9.3 million megawatthours of power from UE. Genco sold 3.5 million megawatthours of power to UE, generating revenue of $74 million, and purchased 12.8 million megawatthours from UE at a cost of $215 million. While it cannot be predicted what level of power purchases and sales will occur between the two companies in the future, UE and Genco believe that under normal operating conditions, the level of net transfers under the joint dispatch agreement from UE to Genco will decline in 2006 from 2005 levels, which was a historical high, due to less excess generation being available at UE. This is expected to result from greater native load demand in 2006 at UE, resulting from the addition of Noranda as a customer in June 2005 and continued organic growth, and the expiration of a cost-based EEI power supply contract with UE, among other things. A cost-based EEI power supply contract with CIPS (which had been assigned to Genco through Marketing Company) also expired on December 31, 2005. CIPS load previously served by EEI and additional CIPS load created by the transfer of UE’s Illinois service territory to CIPS in May 2005 is being served by other available Genco resources, including the joint dispatch agreement, beginning January 1, 2006.

 

By the end of 2006, Genco’s electric power supply agreements with its primary customer, CIPS (through Marketing Company), and most of its wholesale and retail customers will expire. Strategies for participation in the expected CIPS, CILCO and IP September 2006 power procurement auction and for sales to other customers for 2006 and beyond are currently being developed and implemented. In the event the joint dispatch agreement is terminated or amended to price all transfers at market prices, the amount of generation available to Genco from its own power plants will determine the amount of power it will offer into the power procurement auction and to wholesale, retail and interchange customers. As a result, we would expect future sales volumes from Genco to be lower than prior years, and related fuel and purchased power costs to increase. However, Genco believes that future sales may be contracted at higher prices since the power supply agreement between CIPS and Genco and substantially all of the other wholesale and retail contracts that expire in 2006 are below market prices for similar contracts in early 2006. Due to all of these factors, the ultimate impact of the potential changes to Genco’s results of operations, financial position, and liquidity are unable to be determined at this time; however, the impact could be material.

If the joint dispatch agreement did not exist or was amended to price all transfers at market prices, UE may be able to retain the net transfers of power that are currently going to Genco under the joint dispatch agreement and could sell this power in the interchange market at market prices, instead of incremental cost. At certain times, UE may also be required to use power from its own higher-cost power plants or purchase power to meet its load requirements. The margin impact to UE of the potential termination of the joint dispatch agreement or amendment to price all transfers at market prices has not been quantified, but UE believes it would significantly increase its electric margins. Any increase in UE’s electric margins as a result of actual or imputed changes to the joint dispatch agreement would likely result in a decrease in UE’s revenue requirements in its next rate adjustment proceeding. The ultimate ratemaking treatment for the joint dispatch agreement will be determined in a future rate proceeding.

While UE’s and Genco’s results of operations, financial position, and liquidity could be materially impacted by these proposed amendments, the amendment or termination of the joint dispatch agreement would not have a material impact on CIPS. Further, Ameren’s earnings would be unaffected until electric rates for UE are adjusted by the MoPSC to reflect the impact of the proposed amendments or other changes to the joint dispatch agreement. Ameren, UE, CIPS and Genco cannot predict whether FERC will approve their proposed amendment or the Missouri OPC’s proposed amendment to the joint dispatch agreement, or whether any

 

54

additional actions may be taken by FERC or the MoPSC in this matter. The ultimate impact of the Missouri OPC’s proposed amendment, or the amendment proposed by UE, CIPS and Genco in the existing FERC proceeding, will be determined by whether the joint dispatch agreement continues to exist, future native load demand, the availability of electric generation at UE and Genco and market prices, among other things. See Note 14 – Related Party Transactions for a further discussion of the joint dispatch agreement.

Leveraged Leases

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

Ameren also owns interests in certain assets, acquired through the acquisition of CIPSCO, that have been financed as leveraged leases. One of these is an investment by an Ameren subsidiary involving an aircraft leased to Delta Air Lines, Inc. In September 2005, Delta Air Lines, Inc. filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Although Ameren continues in its ownership of the lease, Ameren cannot predict the ultimate ability of Delta Air Lines to service debt and pay future rentals required under the lease, or the outcome of the bankruptcy process. Accordingly, Ameren recorded an impairment of $10 million ($6 million, net of tax), in the third quarter of 2005. By an order dated December 13, 2005 issued pursuant to PUHCA 1935, the SEC determined that CIPSCO’s interest in the Delta Air Lines leveraged lease should be divested. The SEC approved the divestiture transaction structure proposed by Ameren.

Ameren and several of its registrant and nonregistrant subsidiaries sold leveraged lease assets in December 2005. The net aftertax gain (loss) recognized by Ameren and CILCO on the sale of the four assets was $22 million and $(2.5) million, respectively. Certain of CILCORP’s lease investments were transferred to Resources Company prior to the sale of these investments to an unaffiliated party. Resources Company was required to remit the proceeds from the sale of these investments to CILCORP. CILCORP recorded a capital contribution for the amount of sale proceeds that exceeded the carrying value of the leveraged leases. As of December 31, 2005, CILCORP has a note receivable for the sales proceeds due from Resources Company.

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

 

Regulatory Assets and Liabilities

In accordance with SFAS No. 71, UE, CIPS, CILCO and IP defer certain costs pursuant to actions of regulators and are currently recovering such costs in rates charged to customers.

The following table presents our regulatory assets and regulatory liabilities at December 31, 2005 and 2004:

 

        Ameren(a)      UE      CIPS      CILCORP      CILCO      IP

2005:

                              

Regulatory assets:

                              

Income taxes(b)(c)

     $ 297      $ 290      $ 5      $ 1      $ 1      $ 1

Asset retirement obligation(c)(d)

       188        184        2        1        1        2

Callaway costs(e)

       69        69        -        -        -        -

Unamortized loss on reacquired debt(c)(f)

       74        34        5        5        5        30

Recoverable costs – contaminated facilities(c)(g)

       84        -        23        4        4        57

IP integration(h)

       67        -        -        -        -        67

Recoverable costs – debt fair value adjustment(i)

       37        -        -        -        -        37

Other(c)(j)

       15        13        1        -        -        -

Total regulatory assets

      $ 831      $ 590      $ 36      $ 11      $ 11      $ 194

Regulatory liabilities:

                              

Income taxes(k)

     $ 193      $ 165      $ 14      $ 14      $ 14      $ -

Removal costs(l)

       864        573        188        24        170        79

Emission Allowances(m)

        63        63        -        -        -        -

Other

        12        1        6        3        3        1

Total regulatory liabilities

      $ 1,132      $ 802      $ 208      $ 41      $ 187      $ 80

 

55

        Ameren(a)      UE      CIPS      CILCORP      CILCO      IP  

2004:

                              

Regulatory assets:

                              

Income taxes(b)(c)

     $ 335      $ 332      $ 2      $ 1      $ 1      $ -  

Asset retirement obligation(c)(d)

       124        124        -        -        -        -  

Callaway costs(e)

       73        73        -        -        -        -  

Unamortized loss on reacquired debt(c)(f)

       89        37        6        5        5        41  

Recoverable costs – contaminated facilities(c)(g)

       87        1        25        4        4        57  

IP integration(h)

       59        -        -        -        -        59  

Recoverable costs – debt fair value adjustment(i)

       40        -        -        -        -        40  

Other(c)(j)

       22        18        -        1        1        1  

Total regulatory assets

      $ 829      $ 585      $ 33      $ 11      $ 11      $ 198  

Regulatory liabilities:

                              

Income taxes(k)

     $ 219      $ 189      $ 13      $ 17      $ 17      $ (1 )

Removal costs(l)

       823        587        138        21        159        77  

Total regulatory liabilities

      $ 1,042      $ 776      $ 151      $ 38      $ 176      $ 76  

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Amount represents SFAS No. 109 deferred tax asset. See Note 13 – Income Taxes for amortization period.
(c) These assets do not earn a return.
(d) Represents recoverable costs for AROs at our rate-regulated operations. See SFAS No. 143 discussion in Note 1 – Summary of Significant Accounting Policies.
(e) Represents UE’s Callaway nuclear plant operations and maintenance expenses, property taxes, and carrying costs incurred between the plant in-service date and the date the plant was reflected in rates. These costs are being amortized over the remaining life of the plant’s current operating license through 2024.
(f) Represents losses related to repaid debt. These amounts are being amortized over the lives of the related new debt issuances or the remaining lives of the old debt issuances if no new debt was issued.
(g) Represents the recoverable portion of accrued environmental site liabilities, primarily collected from electric and gas customers through ICC-approved cost recovery riders in Illinois.
(h) Represents reorganization costs related to the integration of IP into the Ameren system and the restructuring of IP. Per the ICC order approving Ameren’s acquisition of IP, these costs are recoverable over four years after 2006 through rates.
(i) Represents a portion of IP’s unamortized debt fair value adjustment recorded upon Ameren’s acquisition of IP at September 30, 2004. This portion will be amortized over the remaining life of the related debt upon expiration of the electric rate freeze in Illinois in 2006.
(j) Represents Y2K expenses being amortized over six years starting in 2002, in conjunction with the 2002 settlement of UE’s Missouri electric rate case and a DOE decommissioning assessment being amortized over 14 years through 2007. In addition, this amount includes the portion of merger-related expenses applicable to the Missouri retail jurisdiction, which are being amortized through 2007 based on a MoPSC order.
(k) Represents unamortized portion of investment tax credit and federal excess taxes. See Note 13 – Income Taxes for amortization period.
(l) Represents estimated funds collected for the eventual dismantling and removing plant from service, net of salvage value, upon retirement related to our rate-regulated operations. See SFAS No. 143 discussion in Note 1 – Summary of Significant Accounting Policies.
(m) Represents the fair value of emission allowance vintage swaps UE entered into during 2005.

UE, CIPS, CILCO and IP continually assess the recoverability of their regulatory assets. Under current accounting standards, regulatory assets are written off to earnings when it is no longer probable that such amounts will be recovered through future revenues. Electric industry restructuring legislation may affect the recoverability of electric regulatory assets in the future.

IP’s predecessor financial statements included a cost-recovery asset related to the recovery of certain stranded costs during the Illinois Customer Choice Law transition period, which extends until December 31, 2006. IP had recorded a regulatory asset of $341 million in 1998 for the portion of stranded costs it expected to recover during the transition period. The transition period cost recovery asset amortization reflected in IP’s predecessor statement of income was $29 million during the nine months ended September 30, 2004 and $39 million in 2003. No value was assigned to the transition period cost recovery asset in the allocation of the purchase price for IP upon the acquisition by Ameren on September 30, 2004. See Note 2 – Acquisitions for more information regarding the purchase price allocation.

 

56

NOTE 4 – PROPERTY AND PLANT, NET

The following table presents property and plant, net for each of the Ameren Companies at December 31, 2005 and 2004:

 

      Ameren(a)    UE    CIPS    Genco    CILCORP    CILCO    IP

2005:

                     

Property and plant, at original cost:

                     

Electric

    $ 18,783    $ 11,671    $ 1,577    $ 2,326    $ 1,081    $ 1,633    $ 1,530

Gas

      1,303      300      338      -      189      468      476

Other

      319      46      6      2      44      2      29
     20,405      12,017      1,921      2,328      1,314      2,103      2,035

Less: Accumulated depreciation and amortization

      7,228      4,875      808      864      148      935      35
     13,177      7,142      1,113      1,464      1,166      1,168      2,000

Construction work in progress:

                     

Nuclear fuel in process

      64      64      -      -      -      -      -

Other

      331      173      17      50      46      46      35

Property and plant, net

    $ 13,572    $ 7,379    $ 1,130    $ 1,514    $ 1,212    $ 1,214    $ 2,035

2004:

                     

Property and plant, at original cost:

                     

Electric

    $ 18,050    $ 11,082    $ 1,314    $ 2,538    $ 1,008    $ 1,560    $ 1,490

Gas

      1,248      312      302      -      176      455      458

Other

      262      39      5      -      48      2      1
     19,560      11,433      1,621      2,538      1,232      2,017      1,949

Less: Accumulated depreciation and amortization

      6,994      4,885      673      831      105      904      30
     12,566      6,548      948      1,707      1,127      1,113      1,919

Construction work in progress:

                     

Nuclear fuel in process

      90      90      -      -      -      -      -

Other

      641      437      5      42      52      52      65

Property and plant, net

    $ 13,297    $ 7,075    $ 953    $ 1,749    $ 1,179    $ 1,165    $ 1,984

 

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

NOTE 5 – SHORT-TERM BORROWINGS AND LIQUIDITY

Short-term borrowings typically consist of commercial paper issuances and drawings under committed bank credit facilities with maturities generally within 1 to 45 days.

The following table summarizes the short-term borrowing activity and relevant interest rates for the years ended December 31, 2005 and 2004, respectively:

 

        Ameren(a)        UE  

2005:

          

Average daily borrowings outstanding during the year

      $ 162        $ 135  

Weighted-average interest rate during 2005

        3.02 %        2.87 %

Peak short-term borrowings during 2005

        578          424  

Peak interest rate during 2005

        4.71 %        4.52 %

2004:

          

Average daily borrowings outstanding during the year

      $ 47        $ 33  

Weighted-average interest rate during 2004

        2.19 %        1.56 %

Peak short-term borrowings during 2004

        419          375  

Peak interest rate during 2004

        2.97 %        2.40 %

 

(a) Excludes amounts for IP before the acquisition date of September 30, 2004; includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

 

In July 2005, Ameren, UE, CIPS, CILCO, Genco and IP entered into a five-year revolving credit agreement, maturing on July 14, 2010, with various lenders which provides for loans to, and letters of credit issued for, the accounts of Ameren, UE, CIPS, CILCO, Genco and IP in an amount up to $1.15 billion. The entire amount of the facility is available to Ameren; UE may directly borrow under this facility up to $500 million on a 364-day basis; and CIPS, Genco, CILCO

 

57

and IP may also each directly borrow under this facility up to $150 million, also on a 364-day basis. The interest rates applicable under the facility are based on 1) a Eurodollar rate plus a margin applicable to the particular borrowing company, 2) a competitive-rate bid by the lenders, or 3) a rate equal to the higher of the prime rate at JPMorgan Chase Bank, N.A. or the sum of the federal funds effective rate plus  1/2% per year, plus the margin applicable to the particular borrowing company. The credit agreement contains customary terms and conditions (see Indebtedness Provisions and Other Covenants below for financial covenant provisions). The Ameren Companies will use the proceeds of any borrowings under this facility for general corporate purposes, including working capital, commercial paper liquidity support, and the funding of loans under the money pool arrangements. The obligations of Ameren, UE, CIPS, Genco, CILCO and IP under this facility are several and not joint meaning the obligation of one subsidiary is not guaranteed by any other subsidiary. See Exhibit 10.1 to the Current Report on Form 8-K dated July 15, 2005, for the full agreement.

Upon execution of the new $1.15 billion credit agreement, Ameren terminated its $235 million amended and restated three-year revolving credit agreement, dated September 21, 2004, and its $350 million three-year revolving credit agreement dated July 14, 2004. In addition, this agreement replaced UE’s bilateral credit agreements in an aggregate amount of $153.5 million, CIPS’ bilateral credit agreements in an aggregate amount of $15 million, CILCO’s bilateral credit agreements in an aggregate amount of $60 million, and EEI’s bilateral credit agreement in an aggregate amount of $25 million.

Also in July 2005, Ameren, as sole borrower, entered into an amended and restated credit agreement that revised its existing $350 million five-year revolving credit agreement dated July 14, 2004. The changes to this facility made the entire amount of commitments available in the form of letters of credit as well as loans and extended the maturity date to July 2010. It also conformed, as applicable, the affirmative and negative covenants, events of default, and representations and warranties to the July 2005 $1.15 billion revolving credit agreement discussed above. See Exhibit 10.2 to the Current Report on Form 8-K, dated July 15, 2005, for the full amended and restated credit agreement.

After giving effect to these changes, at December 31, 2005, Ameren had $1.5 billion of committed credit facilities, consisting of two facilities each maturing in July 2010, $1.3 billion of which was available for use. These facilities are available for use by UE, CIPS, CILCO, IP and Ameren Services through a utility money pool arrangement. These facilities are available for use, subject to applicable regulatory short-term borrowing authorizations, by Ameren directly, by CILCORP and EEI through direct short-term borrowings from Ameren, and by most of Ameren’s non-rate-regulated subsidiaries including, but not limited to, Ameren Services, Resources Company, Genco, Marketing Company, AFS, AERG and Ameren Energy, through a non-state-regulated subsidiary money pool agreement. The committed bank credit facilities are used to support our commercial paper programs that include all outstanding short-term debt of Ameren and UE as of December 31, 2005 and 2004. Access to these credit facilities for the Ameren Companies is subject to reduction as they are used by affiliates.

In April 2005, EEI renewed a $20 million bank credit facility, which is scheduled to mature in the second quarter of 2006.

Money Pools

Ameren has money pool agreements with and among its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state-regulated entities. Ameren Services is responsible for operation and administration of the money pool agreements.

Utility

CIPS, CILCO and IP borrow from Ameren and from each other through a utility money pool agreement subject to applicable regulatory short-term borrowing authorizations. While UE and Ameren Services are parties to the utility money pool agreement, they are not currently borrowing or lending under the agreement. Ameren Services administers the utility money pool and tracks internal and external funds separately. Ameren and AERG may participate in the utility money pool only as lenders. Internal funds are surplus funds contributed to the utility money pool from participants. The primary source of external funds for the utility money pool is the Ameren commercial paper program. Through the utility money pool, the pool participants can access committed credit facilities at Ameren that totaled $1.5 billion at December 31, 2005. Based on outstanding Ameren and UE commercial paper borrowings, at December 31, 2005, $1.3 billion was available for borrowing under Ameren credit facilities through the utility money pool agreement. The total amount available to the pool participants from the utility money pool at any given time is reduced by the amount of borrowings by their affiliates, but increased to the extent that the pool participants have surplus funds or other external sources. The availability of funds is also determined by funding requirement limits established by regulatory authorizations. CIPS, CILCO and IP rely on the utility money pool to coordinate and provide for certain short-term cash and working capital requirements. Borrowers receiving a loan under the utility money pool agreement must repay the

 

58

principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the utility money pool. The average interest rate for borrowing under the utility money pool for the year ended December 31, 2005 was 3.25% (2004 – 1.38%).

Non-state-regulated subsidiaries

Ameren Services, Resources Company, Genco, AERG, Marketing Company, AFS, Ameren Energy and other non-state-regulated Ameren subsidiaries have the ability to borrow up to $1.5 billion in total from Ameren through a non-state-regulated subsidiary money pool agreement subject to applicable regulatory short-term borrowing authorizations. However, the total amount available to the pool participants at any time is reduced by borrowings from Ameren made by its subsidiaries and is increased to the extent that other pool participants advance surplus funds to the non-state-regulated subsidiary money pool or other external sources. At December 31, 2005, $1.3 billion was available through the non-state-regulated subsidiary money pool, excluding additional funds available through excess cash balances. The non-state-regulated subsidiary money pool was established to coordinate and to provide for short-term cash and working capital requirements of Ameren’s non-state-regulated activities. It is administered by Ameren Services. Borrowers receiving a loan under the non-state-regulated subsidiary money pool agreement must repay the principal amount of such loan, together with accrued interest. The rate of interest depends on the composition of internal and external funds in the non-state-regulated subsidiary money pool. These rates are based on the cost of funds used for money pool advances. Ameren and CILCORP are authorized to act only as lenders to the non-state-regulated subsidiary money pool. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the year ended December 31, 2005 was 5.49% (2004 – 8.84%).

See Note 14 – Related Party Transactions for the amount of interest income and expense from the money pool arrangements recorded by the Ameren Companies for the years ended December 31, 2005, 2004, and 2003.

In addition, a unilateral borrowing agreement exists between Ameren, IP and Ameren Services, which enables IP to make short-term borrowings directly from Ameren. The aggregate amount of borrowings outstanding at any time by IP under the unilateral borrowing agreement and the utility money agreement, together with any outstanding external short-term borrowings by IP, may not exceed $500 million, pursuant to authorization from the ICC. Ameren Services is responsible for operation and administration of the agreements.

Indebtedness Provisions and Other Covenants

Ameren’s bank credit agreements contain provisions which, among other things, place restrictions on the ability to incur liens, sell assets, and merge with other entities. The $1.15 billion July 2005 revolving credit agreement discussed above also contains a provision that limits Ameren’s, UE’s, CIPS’, Genco’s and IP’s total indebtedness to 65% of total capitalization and CILCO’s total indebtedness to 60% of total capitalization pursuant to a calculation defined in the agreement. The $350 million July 2005 amended and restated credit agreement contains a similar provision with respect to Ameren only. Exceeding these debt levels would result in a default under the credit arrangements. As of December 31, 2005, the ratio of total indebtedness to total capitalization (calculated in accordance with this provision) for Ameren, UE, CIPS, Genco, CILCO, and IP was 47%, 47%, 42%, 52%, 30% and 45%, respectively (2004: Ameren 50%, UE 44%, CIPS 53%, CILCO 43%, covenant not in effect for Genco or IP). These credit agreements also require us to meet minimum ERISA funding rules. In addition, these credit agreements contain cross-default provisions that could trigger a default under the facilities if Ameren’s subsidiaries (subject to the definition in the underlying credit agreements), other than certain project finance subsidiaries, default in indebtedness of $50 million or greater, fail to pay the amounts drawn (as a direct borrower) under an Ameren credit facility, or enter bankruptcy proceedings. A CILCO bankruptcy would also cause a default under CILCORP’s debt agreements. In addition, a default in indebtedness of $50 million or greater or a bankruptcy would cause a default under the International Swap and Derivatives Association agreements supporting $100 million of Ameren LIBOR swaps.

None of Ameren’s revolving short-term credit agreements or financing arrangements contain credit rating triggers. EEI’s credit agreement contains a credit rating trigger under which there will be an immediate acceleration of the requirement for repayment and the termination of the facility in the event that any of the senior unsecured long-term debt ratings of EEI’s sponsors (UE, CIPS, IP and Kentucky Utilities Company) fall below Baa3 or BBB- ratings by Moody’s and S&P, respectively, and the sponsors do not cure a payment default. At December 31, 2005, the Ameren Companies and EEI were in compliance with their credit agreement provisions and covenants.

 

59

NOTE 6 – LONG-TERM DEBT AND EQUITY FINANCINGS

The following table presents long-term debt outstanding for the Ameren Companies and EEI as of December 31, 2005 and 2004:

 

        2005        2004  

Ameren Corporation (parent):

          

2002 5.70% notes due 2007

      $ 100        $ 100  

Senior notes due 2007

        250          345  

Long-term debt, net

      $ 350        $ 445  

UE:

          

First mortgage bonds:(a)

          

6.75% Series due 2008

      $ 148        $ 148  

5.25% Senior secured notes due 2012(b)

       173          173  

4.65% Senior secured notes due 2013(b)

       200          200  

5.50% Senior secured notes due 2014(b)

       104          104  

4.75% Senior secured notes due 2015(b)

       114          114  

5.40% Senior secured notes due 2016(b)

        260          -  

5.10% Senior secured notes due 2018(b)

       200          200  

5.10% Senior secured notes due 2019(b)

       300          300  

5.00% Senior secured notes due 2020(b)

       85          -  

5.45% Series due 2028(c)

       44          44  

5.50% Senior secured notes due 2034(b)

       184          184  

5.30% Senior secured notes due 2037(b)

       300          -  

Environmental improvement and pollution control revenue bonds: (a)(b)(c)(d)

         

1991 Series due 2020

        43          43  

1992 Series due 2022

        47          47  

1998 Series A due 2033

        60          60  

1998 Series B due 2033

        50          50  

1998 Series C due 2033

        50          50  

2000 Series A due 2035

        64          64  

2000 Series B due 2035

        63          63  

2000 Series C due 2035

        60          60  

Subordinated deferrable interest debentures:

          

7.69% Series A due 2036(e)

       66          66  

Capital lease obligations:

          

City of Bowling Green capital lease (Peno Creek CT)

        93          96  

Total long-term debt, gross

        2,708          2,066  

Less: Unamortized discount and premium

        (6 )        (4 )

Less: Maturities due within one year

        (4 )        (3 )

Long-term debt, net

      $ 2,698        $ 2,059  

CIPS:

          

First mortgage bonds:(a)

          

6.49% Series 1995-1 due 2005

      $ -        $ 20  

7.05% Series 1997-2 due 2006

        20          20  

5.375% Series due 2008(b)

       15          15  

6.625% Series due 2011(b)

       150          150  

7.61% Series 1997-2 due 2017

        40          40  

6.125% Series due 2028(b)

       60          60  

Environmental improvement and pollution control revenue bonds:(c)

          

2004 Series due 2025(b)(d)

       35          35  

2000 Series A 5.50% due 2014(f)

       51          51  

1993 Series C-1 5.95% due 2026(f)

       35          35  

1993 Series C-2 5.70% due 2026

        8          8  

1993 Series B-1 5.00% due 2028(f)

       17          17  

Total long-term debt, gross

        431          451  

Less: Unamortized discount and premium

        (1 )        (1 )

Less: Maturities due within one year

        (20 )        (20 )

Long-term debt, net

      $ 410        $ 430  

 

60

        2005        2004  

Genco:

          

Unsecured notes:

          

Senior notes Series C 7.75% due 2005

      $ -        $ 225  

Senior notes Series D 8.35% due 2010

        200          200  

Senior notes Series F 7.95% due 2032

        275          275  

Total long-term debt, gross

        475          700  

Less: Unamortized discount and premium

        (1 )        (2 )

Less: Maturities due within one year

        -          (225 )

Long-term debt, net

      $ 474        $ 473  

CILCORP (parent):(g)

          

8.70% Senior notes due 2009

      $ 124        $ 198  

9.375% Senior notes due 2029

       220          220  

Fair market value adjustments

        68          83  

Long-term debt, net

      $ 412        $ 501  

CILCO:

          

First mortgage bonds:(a)

          

7.50% Series due 2007

      $ 50        $ 50  

Medium-term notes:(a)

          

6.13% Series due 2005

        -          16  

7.73% Series due 2025

        20          20  

Environmental improvement and pollution control revenue bonds:(a)(c)

          

Series 2004 due 2039(b)(d)

       19          19  

6.20% Series 1992B due 2012

        1          1  

5.90% Series 1993 due 2023

        32          32  

Total long-term debt, gross

        122          138  

Less: Maturities due within one year

        -          (16 )

Long-term debt, net

      $ 122        $ 122  

CILCORP consolidated long-term debt, net

      $ 534        $ 623  

IP:

          

First mortgage bonds:(a)

          

6.75% Series due 2005

      $ -        $ 70  

7.50% Series due 2009

        250          250  

11.50% Series due 2010

        (i )        (i )

Pollution control revenue bonds:(a)(c)

          

5.70% 1994A Series due 2024

        36          36  

5.40% 1998A Series due 2028

        19          19  

5.40% 1998B Series due 2028

        33          33  

Adjustable rate series due 2032 (1997 Series A, B and C)(d)

       150          150  

Adjustable rate series due 2028 (Series 2001)(d)

       112          112  

Adjustable rate series due 2017 (Series 2001)(d)

       75          75  

Fair market value adjustments

        34          43  

Total long-term debt, gross

        709          788  

Less: Unamortized discount and premium

        (5 )        (5 )

Less: Maturities due within one year

        -          (70 )

Long-term debt, net

      $ 704        $ 713  

Long-term debt payable to IP SPT:

          

5.38% due 2005 A-5

      $ -        $ 20  

5.54% due 2007 A-6

        106          175  

5.65% due 2008 A-7

        139          139  

Fair market value adjustments

        11          18  

Total long-term debt payable to IP SPT(h)

       256          352  

Less: Maturities due within one year

        (72 )        (74 )

Long-term debt payable to IP SPT, net

      $ 184        $ 278  

 

61

        2005      2004

EEI:

          

Senior medium term notes 8.60% due through 2005

      $ -      $ 7

Senior medium term notes 6.61% due through 2005

        -        8

Total long-term debt, gross

        -        15

Less: Maturities due within one year

        -        15

Long-term debt, net

      $ -      $ -

Ameren consolidated long-term debt, net

      $ 5,354      $ 5,021

 

(a) At December 31, 2005, most property and plant was mortgaged under, and subject to liens of, the respective indentures pursuant to which the bonds were issued: substantially all of the long-term debt issued by UE, CIPS (excluding the tax-exempt debt), CILCO and IP is secured by a lien on substantially all of its property and franchises.
(b) These notes are collaterally secured by first mortgage bonds issued by UE, CIPS or CILCO, respectively, and will remain secured at each company until the following series are no longer outstanding with respect to that company: UE – 6.75% Series due 2008 and 5.45% Series due 2028 (callable in October 2008 at 102% of par declining to 101% of par in October 2009 and 100% of par in October 2010); CIPS – 7.05% Series 1997-2 due 2006 and 7.61% Series 1997-2 due 2017 (callable in June 2007 at 103.81% of par declining annually thereafter to 100% of par in June 2012); CILCO – 7.50% Series due 2007, 7.73% Series due 2025 (currently callable at 103.87% of par declining annually each May to 100% of par in May 2016), 6.20% Series 1992B due 2012 (currently callable at 100% of par) and 5.90% Series 1993 due 2023 (currently callable at 100% of par).
(c) Environmental Improvement or Pollution Control Series secured by first mortgage bonds. In addition, UE’s 1991, 1992, 1998 and 2000 series, CIPS’ 2004 series and CILCO’s 2004 series bonds are backed by an insurance guarantee policy.
(d) Interest rates, and the periods during which such rates apply, vary depending on our selection of certain defined rate modes. The average interest rates for the years 2005 and 2004 were as follows:
       2005      2004             2005      2004  

UE 1991 Series

      2.28 %    1.39 %    CIPS Series 2004      2.37 %    1.56 %

UE 1992 Series

      2.34 %    1.43 %    CILCO Series 2004      2.37 %    1.55 %

UE 1998 Series A

      2.33 %    1.30 %    IP 1997 Series A      2.69 %    1.68 %

UE 1998 Series B

      2.31 %    1.28 %    IP 1997 Series B      2.50 %    1.55 %

UE 1998 Series C

      2.28 %    1.26 %    IP 1997 Series C      2.61 %    1.54 %

UE 2000 Series A

      2.24 %    1.19 %    IP Series 2001 due 2017      2.49 %    1.56 %

UE 2000 Series B

      2.23 %    1.24 %    IP Series 2001 due 2028      2.43 %    1.58 %

UE 2000 Series C

      2.25 %    1.23 %           

 

(e) Under the terms of the subordinated debentures, UE may, under certain circumstances, defer the payment of interest for up to five years. Upon the election to defer interest payments, UE dividend payments to Ameren are prohibited.
(f) Variable-rate tax-exempt pollution control indebtedness that was converted to long-term fixed rates.
(g) CILCORP’s long-term debt is secured by a pledge of all of the common stock of CILCO.
(h) IP’s long-term debt payable to IP SPT was reduced by $15 million and $12 million of overfunding at December 31, 2005 and 2004, respectively.
(i) Less than $1 million.

The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren Companies at December 31, 2005:

 

        Ameren
(parent)		      UE      CIPS      Genco     

CILCORP

(parent)

      CILCO      IP    

Ameren

Consolidated

2006

      $ -      $ 4      $ 20      $ -      $ -      $ -      $ 72     $ 96

2007

        350        4        -        -        -        50        86       490

2008

        -        152        15        -        -        -        87       254

2009

        -        4        -        -        124        -        250       378

2010

        -        3        -        200        -        -        -       203

Thereafter

        -        2,541        396        275        220        72        425       3,929

Total

      $ 350      $ 2,708 (a)    $ 431 (a)    $ 475 (a)    $ 344 (b)    $ 122      $ 920 (a)(c)   $ 5,350

 

(a) Excludes unamortized discount and premium of $6 million, $1 million, $1 million, and $5 million at UE, CIPS, Genco, and IP, respectively.
(b) Excludes $68 million related to CILCORP’s long-term debt fair market value adjustments.
(c) Excludes $45 million related to IP’s long-term debt fair market value adjustments and includes $15M for TFN overfunding.

All of the Ameren Companies expect to fund maturities of long-term debt and contractual obligations through a combination of cash flow from operations and external financing. See Note 5 – Short-term Borrowings and Liquidity for a discussion of external financing availability.

The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for Ameren Companies that have authorized amounts as of December 31, 2005:

 

        Effective Date      Authorized Amount      Issued      Available

Ameren

      June 2004      $ 2,000      $ 459      $ 1,541

UE

      October 2005        1,000        260        740

CIPS

      May 2001        250        150        100

 

62

Ameren

In February 2004, Ameren issued, pursuant to an August 2002 SEC Form S-3 shelf registration statement, 19.1 million shares of its common stock at $45.90 per share, for net proceeds of $853 million. This issuance substantially depleted the capacity under the August 2002 shelf registration statement. In June 2004, the SEC declared effective a Form S-3 shelf registration statement filed by Ameren and its subsidiary trusts covering the offering from time to time of up to $2 billion of various types of securities, including long-term debt, trust preferred securities, and equity securities. In July 2004, Ameren issued, pursuant to the June 2004 Form S-3 shelf registration statement, 10.9 million shares of its common stock at $42.00 per share, for net proceeds of $445 million. The proceeds from both of these offerings were used to pay the cash portion of the purchase price for our acquisition of IP and Dynegy’s 20% interest in EEI and, as described below under IP, to reduce IP debt assumed as part of the acquisition and to pay related premiums.

The purchase of IP on September 30, 2004, included the assumption of IP debt and preferred stock at closing of $1.8 billion. The assumed debt and preferred stock included $936 million of mortgage bonds, $509 million of pollution control indebtedness supported by mortgage bonds, $352 million of TFNs issued by IP SPT, and $13 million of preferred stock not acquired and owned by Ameren. Upon acquisition, total IP debt was increased to fair value by $191 million. The adjustment to the fair value of each debt series is being amortized to interest expense over its remaining life, or to the expected redemption date.

In March 2004, the SEC declared effective a Form S-3 registration statement filed by Ameren in February 2004, authorizing the offering of 6 million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares or treasury shares, or shares purchased in the open market or in privately negotiated transactions. Ameren is currently selling newly issued shares of its common stock under DRPlus. In December 2001, Ameren began issuing new shares of common stock in connection with certain of our 401(k) plans pursuant to effective Form S-8 registration statements. Under DRPlus and its 401(k) plans, Ameren issued 2.1 million, 2.3 million, and 2.5 million shares of common stock in 2005, 2004, and 2003, respectively, which were valued at $109 million, $107 million, and $105 million for the respective years.

In March 2002, Ameren issued $345 million of adjustable conversion-rate equity security units and $227 million (gross proceeds) of common stock (5 million shares at $39.50 per share and 750,000 shares, pursuant to the exercise of an option granted to the underwriters, at $38.865 per share). The $25 adjustable conversion-rate equity security units each consisted of an Ameren senior unsecured note with a principal amount of $25 and a contract to purchase, for $25, a fraction of a share of Ameren common stock on May 15, 2005. The senior unsecured notes were recorded at their fair value of $345 million; they will mature on May 15, 2007. Total distributions on the equity security units were originally made at an annual rate of 9.75%, consisting of quarterly interest payments on the senior unsecured notes at the initial annual rate of 5.20% and contract adjustment payments under the stock purchase contracts at the annual rate of 4.55%. In February 2005, the annual interest rate on the $345 million principal amount of Ameren’s senior unsecured notes due May 15, 2007, was reset from 5.20% to 4.263%. The stock purchase contracts required holders to purchase 8.7 million to 7.4 million shares of Ameren common stock on May 15, 2005, at the market price at that time, subject to a minimum share purchase price of $39.50 and a maximum of $46.61. The stock purchase contracts included a pledge of the related senior unsecured notes as collateral for the stock purchase obligation. As a result of the February 2005 remarketing of the senior unsecured notes, treasury securities were substituted for the senior unsecured notes. The treasury securities were pledged as collateral for the stock purchase obligation, and the senior unsecured notes were released from the pledge. In May 2005, settlement of the stock purchase contracts resulted in Ameren issuing 7.4 million shares of common stock in exchange for $345 million of proceeds. In 2002, we recorded the net present value of the stock purchase contract adjustment payments of $46 million as an increase in Other Deferred Credits and Liabilities to reflect our obligation and a decrease in Other Paid-in Capital to reflect the fair value of the stock purchase contract. The liability for the stock purchase contract adjustment payments (December 31, 2005 – $0; December 31, 2004 – $6 million) was reduced as such payments were made through May 15, 2005.

As discussed above, in February 2005, the annual interest rate on the $345 million principal amount of Ameren’s senior unsecured notes due May 15, 2007 was reset from 5.20% to 4.263%. These senior unsecured notes were originally issued in March 2002 as a component of Ameren’s publicly traded adjustable conversion-rate equity security units. As required by the original terms of the agreement, the interest rate was reset because Ameren remarketed these senior unsecured notes. The proceeds from the remarketing of the senior unsecured notes were used by the former holders of the adjustable conversion-rate equity security units to purchase treasury securities to secure their obligations to purchase Ameren common stock pursuant to the stock purchase contracts in May 2005. As part of this remarketing, Ameren also repurchased $95 million in principal amount of the senior unsecured notes, which it subsequently retired.

 

63

UE

In 2004, UE received a capital contribution from Ameren totaling $16 million, as a result of an allocation of income tax benefit in 2004 and 2003, pursuant to the tax allocation agreement among the Ameren Companies.

UE had a lease agreement scheduled to expire on August 31, 2031, that provided for the financing of a portion of the nuclear fuel processed for use or consumed at UE’s Callaway nuclear plant. In February 2004, UE terminated this lease with a final payment of $67 million made in January 2004.

In February and March 2004, in connection with the delivery of bond insurance policies to secure the environmental improvement and pollution control revenue bonds (Series 1991, 1992, 1998A, 1998B, 1998C, 2000A, 2000B and 2000C) previously issued by the Missouri Environmental Authority, UE delivered separate series of its first mortgage bonds. These bonds (which are subject to fallaway provisions, as defined in the related financing agreements, similar to those included in the first mortgage bonds that secure UE’s senior secured notes) now secure UE’s respective obligations under existing loan agreements with the Missouri Environmental Authority relating to such environmental improvement and pollution control revenue bonds. As a result, the environmental improvement and pollution control revenue bonds were rated Aaa, AAA, and AAA by Moody’s, S&P, and Fitch, respectively.

In May 2004, UE issued, pursuant to its then-effective September 2003 SEC Form S-3 shelf registration statement, $104 million of 5.50% senior secured notes due May 15, 2014, with interest payable semi-annually on May 15 and November 15 of each year beginning in November 2004. UE received net proceeds of $103 million, which were used to redeem its $100 million 7.00% first mortgage bonds due 2024.

In September 2004, UE issued, pursuant to its then-effective September 2003 SEC Form S-3 shelf registration statement, $300 million of 5.10% senior secured notes due October 1, 2019, with interest payable semi-annually on April 1 and October 1 of each year, beginning in April 2005. UE received net proceeds of $298 million, which were used to repay short-term debt temporarily incurred to fund the maturity of UE’s $188 million 6.875% first mortgage bonds on August 1, 2004, and to repay other short-term debt, which consisted of borrowings under the utility money pool arrangement.

In January 2005, UE issued, pursuant to its then-effective September 2003 SEC Form S-3 shelf registration statement, $85 million of 5.00% senior secured notes due February 1, 2020, with interest payable semi-annually on February 1 and August 1 of each year, beginning in August 2005. UE received net proceeds of $83 million, which were used to repay short-term debt temporarily incurred to fund the maturity of UE’s $85 million 7.375% first mortgage bonds due 2004.

In July 2005, UE issued, pursuant to its then-effective September 2003 SEC Form S-3 shelf registration statement, $300 million of 5.30% senior secured notes due August 1, 2037, with interest payable semi-annually on February 1 and August 1 of each year, beginning in February 2006. UE received net proceeds of $296 million, which were used to repay short-term debt.

On October 20, 2005, the SEC declared effective a Form S-3 shelf registration statement filed by UE and its subsidiary trust on September 23, 2005, amended on October 12, 2005, covering the offering from time to time of up to $1 billion of various forms of long-term debt and preferred securities.

In December 2005, UE issued, pursuant to its October 2005 SEC Form S-3 shelf registration statement, $260 million of 5.40% senior secured notes due February 1, 2016, with interest payable semi-annually on February 1 and August 1 of each year, beginning in August 2006. UE received net proceeds of $256 million, which were used to repay short-term debt.

CIPS

In November 2004, CIPS issued, through the Illinois Finance Authority, $35 million of Series 2004 environmental improvement revenue refunding bonds due in 2025, currently in a variable-rate Dutch auction interest rate mode. These bonds are insured by a bond insurance policy and secured by first mortgage bonds (which are subject to fallaway provisions, as defined in the related financing agreements, similar to those which secure CIPS’ senior secured notes). As a result, the environmental improvement revenue refunding bonds were rated Aaa, AAA, and AAA by Moody’s, S&P, and Fitch, respectively. The proceeds received from the issuance of the $35 million Series 2004 bonds were used to redeem, at par, CIPS’ $35 million 6.375% 1993 Series A due 2028 pollution-control revenue bonds.

In December 2004, CIPS redeemed, prior to maturity, $18 million of its 5.90% 1993 Series B-2 pollution control bonds due 2028 and $17 million of its $25 million 5.70% 1993 Series C-2 pollution control bonds due 2026. These redemptions were made with available cash and borrowings from the utility money pool agreement.

In June 2005, $20 million of CIPS’ 6.49% first mortgage bonds matured and were retired.

 

64

Genco

In November 2005, $225 million of Genco’s 7.75% senior notes matured and were retired with available cash and short-term borrowings.

CILCORP

In conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was recorded at fair value. This resulted in recognition of fair value adjustment increases of $71 million related to CILCORP’s 9.375% senior bonds due 2029 and $40 million related to its 8.70% senior notes due 2009. Amortization related to these fair value adjustments was $7 million for the year ended December 31, 2005 (2004 – $8 million), and was included in interest expense in the Consolidated Statements of Income of Ameren and CILCORP.

In 2004, CILCORP repurchased $17 million in principal amount of its 9.375% senior bonds. In conjunction with this debt repurchase, the fair value adjustment on these bonds was reduced by $5 million for the year ended December 31, 2004.

In 2005, CILCORP paid $85 million to repurchase $74 million, in principal amount of its 8.70% senior notes due 2009.

CILCO

In February 2004, CILCO repaid its secured bank term loan totaling $100 million with borrowings from the utility money pool agreement.

In both July 2004 and July 2005, CILCO redeemed 11,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. These redemptions satisfied CILCO’s mandatory sinking fund redemption requirement for this series of preferred stock for 2004 and 2005.

In November 2004, CILCO issued, through the Illinois Finance Authority, $19 million of Series 2004 environmental improvement revenue refunding bonds due in 2039, currently in a variable-rate Dutch auction interest rate mode. These bonds are insured by a bond insurance policy and are secured by first mortgage bonds (which are subject to fallaway provisions, as defined in the related financing agreements, similar to those included in the first mortgage bonds which secure UE’s and CIPS’ senior secured notes). As a result, the environmental improvement revenue refunding bonds were rated Aaa, AAA, and AAA by Moody’s, S&P, and Fitch, respectively. The Series 2004 bonds are subject to a mandatory sinking fund redemption totaling $5 million at par on October 1, 2026, with the remaining $14 million in principal amount due October 1, 2039. The proceeds received from the issuance were used to redeem CILCO’s pollution control revenue bonds as follows: $14 million 6.50% Series 1992A due 2018 and $5 million 6.50% Series 1992C due 2010.

In December 2005, $16 million of CILCO’s 6.13% first mortgage bonds matured and were retired.

IP

In conjunction with Ameren’s acquisition of IP, IP’s long-term debt was increased to fair value by $195 million. Amortization related to fair value adjustments was $16 million for the year ended December 31, 2005 (2004 – $14 million) and was included in interest expense in the Consolidated Statements of Income of Ameren and IP.

In November 2004, pursuant to an equity clawback provision in the related bond indenture, IP redeemed $192.5 million principal amount of its 11.50% Series mortgage bonds due 2010. The redemption price was equal to $1,115 per $1,000 principal amount, plus accrued and unpaid interest. Also in November 2004, IP completed a cash tender offer for $351 million of these bonds. The tender offer consideration paid was $1,214 per $1,000 principal amount plus accrued and unpaid interest. This tender offer satisfied IP’s indenture obligation to offer to purchase the bonds resulting from the change of control of IP upon its acquisition by Ameren. In December 2004, IP repurchased an additional $6.5 million principal amount of these bonds at a redemption price of $1,207 per $1,000 principal amount plus accrued unpaid interest. At December 31, 2005, only $33,000 principal amount of these bonds remained outstanding.

In December 2004, IP redeemed $66 million principal amount of its 7.50% Series mortgage bonds due 2025 at a redemption price of 103.105% of the principal amount plus accrued interest, and $84 million in principal amount of its 7.40% Series 1994 B pollution control bonds due 2024 at a redemption price of 102% of the principal amount plus accrued and unpaid interest. This indebtedness, along with the redemption and repurchase of the 11.50% Series mortgage bonds due 2010 described above, was funded by IP through equity contributions made by Ameren in the fourth quarter of 2004 totaling $865 million. In conjunction with these debt repurchases, the fair value adjustment on IP’s long-term debt was reduced by $103 million for the year ended December 31, 2004.

In March 2005, $70 million of IP’s 6.75% mortgage bonds matured and were retired with available cash.

In December 1998, the IP SPT issued $864 million of TFNs as allowed under the Illinois Electric Utility Transition

 

65

Funding Law. In accordance with the Transitional Funding Securitization Financing Agreement, IP must designate a portion of the cash received from customer billings to fund payment of the TFNs. The amounts received are remitted to the IP SPT and are restricted for the sole purpose of paying down the TFNs. Due to the adoption of FIN No. 46R and resulting deconsolidation of IP SPT, certain amounts of restricted cash are netted against the current portion of IP’s long-term debt payable to IP SPT on IP’s December 31, 2005 and 2004, consolidated balance sheets.

In September 1999, IP entered into an operating lease for four gas turbines located in Tilton, Illinois, and a separate land lease at the Tilton site. IP sublet the turbines to a predecessor of DMG in October 1999. In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, IP terminated its lease with the original lessor. DMG then executed a transfer agreement under which the original lessor sold the turbine assets to DMG for the full contract price of $81 million. Additionally, IP assigned its associated land lease on the Tilton site to a predecessor of DMG.

EEI

In June 2004, EEI repaid its $40 million bank term loan at maturity with proceeds received from EEI’s credit facilities.

In December 2004, EEI repaid $6 million of its 8.60% medium-term notes and $8 million of its 6.61% medium-term notes with proceeds received from short-term borrowings from Ameren.

In December 2005, $8 million and $7 million of EEI’s 6.61% and 8.60% senior medium term notes, respectively, matured and were retired.

 

Indenture Provisions and Other Covenants

UE’s, CIPS’, CILCO’s and IP’s indenture provisions and articles of incorporation include covenants and provisions related to the issuances of first mortgage bonds and preferred stock. The following table includes the required and actual earnings coverage ratios for interest charges and preferred dividends and bonds and preferred stock issuable for the 12 months ended December 31, 2005, at an assumed interest and dividend rate of 7%.

 

      Required Interest
Coverage Ratio(a)		     Actual Interest
Coverage Ratio		    Bonds
Issuable(b)		     Required Dividend
Coverage Ratio(c)		    Actual Dividend
Coverage Ratio		    Preferred Stock
Issuable

UE

    2.0     5.1    $ 2,846     2.5    56.3    $ 1,827

CIPS

    2.0 (d)   4.7      235     1.5    2.5      215

CILCO

    2.0 (d)(e)   9.9      602     2.5    12.7      116

IP

    2.0     7.8      931 (f)   1.5    3.2      684

 

(a) Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued.
(b) Amount of bonds issuable based on meeting required coverage ratios.
(c) Coverage required on the annual interest charges on all long-term debt (CIPS only) and the annual dividend on preferred stock outstanding and to be issued, as required in the respective company’s articles of incorporation. For CILCO, this ratio must be met for a period of 12 consecutive calendar months within the 15 months immediately preceding the issuance.
(d) Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.
(e) In lieu of meeting the interest coverage ratio requirement, CILCO may attempt to meet an earnings requirement of at least 12% of the principal amount of all mortgage bonds outstanding and to be issued. For the 12 months ended December 31, 2005, CILCO had earnings equivalent to at least 71% of the principal amount of all mortgage bonds outstanding.
(f) In addition to the coverage test based on property additions, IP has the ability to issue bonds based upon retired bond capacity, for which no earnings coverage test is required.

 

In addition, UE’s mortgage indenture contains certain provisions that restrict the amount of common dividends that can be paid by UE. Under this mortgage indenture, $31 million of total retained earnings was restricted against payment of common dividends, except those dividends payable in common stock, which left $1.7 billion of free and unrestricted retained earnings at December 31, 2005.

The IP SPT TFNs contain restrictions that prohibit IP LLC from making any loan or advance to, or certain investments in, any other person. Also, as long as the TFNs are outstanding, the IP SPT shall not, directly or indirectly, pay any dividend or make any distribution (by reduction of capital or otherwise) to any owner of a beneficial interest in the IP SPT.

 

The ICC order approving Ameren’s acquisition of IP contains a provision that gives IP the ability to declare and pay $80 million of dividends on its common stock in 2005 and $160 million of dividends on its common stock cumulatively through 2006, provided IP has achieved an investment-grade credit rating from S&P or Moody’s. If, however, IP’s $550 million principal amount of 11.50% Series mortgage bonds due 2010 are not eliminated by December 31, 2006, IP may not thereafter declare or pay common dividends without seeking authority from the ICC. As of December 31, 2005, $33,000 of the 11.50% Series mortgage bonds due 2010 were outstanding. The bonds are callable at the end of 2006.

 

66

Genco’s and CILCORP’s indentures include provisions that require the companies to maintain certain debt service coverage and debt-to-capital ratios in order for the companies to pay dividends, make certain principal or interest payments, make certain loans to affiliates, or incur additional indebtedness. The following table summarizes these ratios for the 12 months ended December 31, 2005:

 

     

Required

Interest
Coverage
Ratio

    

Actual

Interest
Coverage
Ratio

   

Required

Debt to
Capital
Ratio

    

Actual

Debt to
Capital
Ratio

  

Genco(a)

    1.75 (c)   5.7    60 %   51 %

CILCORP(b)

    2.2       2.4    67 %   53 %

 

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

Genco’s ratio restrictions may be disregarded if both Moody’s and S&P reaffirm the ratings of Genco in place at the time of the debt incurrence after considering the additional indebtedness. In the event CILCORP is not in compliance with these tests, CILCORP may make such payments of dividends or intercompany loans if its senior long-term debt rating is at least BB+ from S&P, Baa2 from Moody’s, and BBB from Fitch. At December 31, 2005, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were BBB, Baa3, and BBB+, respectively. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior notes and bonds.

 

The ability for the Ameren Companies to issue securities in the future will depend on such tests at that time.

Off-Balance-Sheet Arrangements

At December 31, 2005, none of the Ameren Companies had any off-balance-sheet financing arrangements, other than operating leases entered into in the ordinary course of business. None of the Ameren Companies expect to engage in any significant off-balance-sheet financing arrangements in the near future.

NOTE 7 – RESTRUCTURING CHARGES AND OTHER SPECIAL ITEMS

Ameren and UE recorded a pretax coal contract settlement gain of $51 million in 2003. This gain represented a return of coal costs plus accrued interest accumulated by a coal supplier for reclamation of a coal mine that supplied a UE power plant. UE entered into a settlement agreement with the coal supplier to return the accumulated reclamation funds, which were paid to UE ratably through December 2004.

CILCO recorded $2 million and $21 million in acquisition integration costs in 2004 and 2003, respectively. The 2004 costs primarily represented employee severance and relocation amounts. The 2003 costs represented write-offs of software without future benefit as of the acquisition date ($13 million), severance and relocation costs ($5 million), and an increase in the bad-debt reserve related to one customer for which there was significant collection concern at the acquisition date ($3 million). These amounts were offset against goodwill at CILCORP through purchase accounting. Therefore, there was no impact to Ameren’s Consolidated Statement of Income.

 

67

NOTE 8 – OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the years ended December 31, 2005, 2004 and 2003:

 

        2005        2004        2003  

Ameren:(a)

               

Miscellaneous income:

               

Interest and dividend income

      $ 13        $ 18        $ 10  

Allowance for equity funds used during construction

        12          10          4  

Other

        4          4          13  

Total miscellaneous income

      $ 29        $ 32        $ 27  

Miscellaneous expense:

               

Donations

      $ (6 )      $ (5 )      $ (5 )

Other

        (6 )        -          (10 )

Total miscellaneous expense

      $ (12 )      $ (5 )      $ (15 )

UE:

               

Miscellaneous income:

               

Interest and dividend income

      $ 7        $ 8        $ 7  

Equity in earnings of subsidiary

        6          5          7  

Allowance for equity funds used during construction

        11          10          4  

Other

        4          2          5  

Total miscellaneous income

      $ 28        $ 25        $ 23  

Miscellaneous expense:

               

Donations

      $ (1 )      $ (3 )      $ (2 )

Other

        (6 )        (4 )        (5 )

Total miscellaneous expense

      $ (7 )      $ (7 )      $ (7 )

CIPS:

               

Miscellaneous income:

               

Interest and dividend income

      $ 17        $ 24        $ 27  

Other

        1          -          -  

Total miscellaneous income

      $ 18        $ 24        $ 27  

Miscellaneous expense:

               

Other

      $ (4 )      $ (1 )      $ (3 )

Total miscellaneous expense

      $ (4 )      $ (1 )      $ (3 )

Genco:

               

Miscellaneous income:

               

Interest and dividend income

      $ 1        $ -        $ -  

Total miscellaneous income

      $ 1        $ -        $ -  

Miscellaneous expense:

               

Other

      $ -        $ -        $ (1 )

Total miscellaneous expense

      $ -        $ -        $ (1 )

CILCORP:(b)

               

Miscellaneous income:

               

Interest and dividend income

      $ -        $ 1        $ 1  

Total miscellaneous income

      $ -        $ 1        $ 1  

Miscellaneous expense:

               

Other

      $ (6 )      $ (5 )      $ (3 )

Total miscellaneous expense

      $ (6 )      $ (5 )      $ (3 )

CILCO:

               

Miscellaneous expense:

               

Other

      $ (5 )      $ (5 )      $ (4 )

Total miscellaneous expense

      $ (5 )      $ (5 )      $ (4 )

IP:(c)

               

Miscellaneous income:

               

Interest income from former affiliates

      $ -        $ 128        $ 170  

Interest and dividend income

        4          11          7  

Allowance for equity funds used during construction

        1          1          1  

Other

        2          5          5  

Total miscellaneous income

      $ 7        $ 145        $ 183  

 

68

        2005        2004        2003  

Miscellaneous expense:

               

Other

      $ (3 )      $ (1 )      $ (4 )

Total miscellaneous expense

      $ (3 )      $ (1 )      $ (4 )

 

(a) Excludes amounts for IP before the acquisition date of September 30, 2004; excludes amounts for CILCORP before the acquisition date of January 31, 2003; and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) January 2003 predecessor amounts were zero. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(c) The 2003 amounts represent predecessor information. January through September 2004 predecessor miscellaneous income and expense amounts were $144 million and $1 million, respectively.

 

NOTE 9 – DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity, and emission credits. Price fluctuations in natural gas, fuel, and electricity cause any of the following:

 

•   an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sale prices under the commitments are compared with current commodity prices;
•   market values of fuel and natural gas inventories or purchased power that differ from the cost of those commodities in inventory under contracted commitment; or
•   actual cash outlays for the purchase of these commodities that differ from anticipated cash outlays.

The derivatives that we use to hedge these risks are governed by our risk management policies for forward contracts, futures, options, and swaps. Our net positions are continually assessed within our structured hedging programs to determine whether new or offsetting transactions are required. The goal of the hedging program is generally to mitigate financial risks while ensuring that sufficient volumes are available to meet our requirements.

Certain derivative contracts are entered into on a regular basis as part of our risk management program but do not qualify for hedge accounting or the normal purchase and sale exceptions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Accordingly, such contracts are recorded at fair value with changes in the fair value charged or credited to the income statement in the period in which the change occurred. Contracts we enter into as part of our risk management program may be settled financially, by physical delivery, or net settled with the counterparty.

Cash Flow Hedges

Our risk management processes identify the relationships between hedging instruments and hedged items, as well as the risk management objective and strategy for undertaking various hedge transactions. The mark-to-market value of cash flow hedges will continue to fluctuate with changes in market prices up to contract expiration.

We monitor and value derivative positions daily as part of our risk management processes. We use published sources for pricing when possible to mark positions to market. We rely on modeled valuations only when no other method exists.

Depending on the nature of the hedge, the pretax net gain or loss on power forward derivative instruments is included in Operating Revenues – Electric or Operating Expenses – Fuel and Purchased Power at Ameren, UE and Genco. This represents the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, and the reversal of amounts previously recorded in OCI due to transactions going to delivery or settlement, resulting in less than a $1 million gain for Ameren, UE and Genco for the year ended December 31, 2005 (2004 and 2003 – less than $1 million loss for Ameren, UE and Genco).

 

The following table presents the carrying value of all derivative instruments and the amount of pretax net gains on derivative instruments in Accumulated OCI for cash flow hedges as of December 31, 2005 and 2004:

 

        Ameren(a)      UE      CIPS      Genco      CILCORP      CILCO      IP  

2005:

                               

Derivative instruments carrying value:

                               

Other assets

      $ 130      $ 12      $ 26      $ -      $ 57      $ 57      $ 19  

Other deferred credits and liabilities

        61        17        14        1        7        7        21  

Gains (Losses) deferred in Accumulated OCI:

                               

Power forwards(b)

       (3 )      -        -        (1 )      -        -        (2 )

Interest rate swaps(c)

       4        -        -        4        -        -        -  

Gas swaps and future contracts(d)

       65        9        12        -        41        41        -  

 

69

        Ameren(a)      UE      CIPS      Genco      CILCORP      CILCO      IP

2004:

                                   

Derivative instruments carrying value:

                                   

Other assets

      $ 35      $ 4      $ 6      $ 6      $ 14      $ 14      $ -

Other deferred credits and liabilities

        14        14        -        -        -        -        -

Gains deferred in Accumulated OCI:

                                   

Interest rate swaps(c)

       4        -        -        4        -        -        -

Gas swaps and futures contracts(d)

       26        4        6        -        11        11        -

 

(a) Excludes amounts for IP before the acquisition date of September 30, 2004; includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) Represents the mark-to-market value for the hedged portion of electricity price exposure for periods generally less than one year.
(c) Represents a gain associated with interest rate swaps at Genco that were a partial hedge of the interest rate on debt issued in June 2002. The swaps cover the first 10 years of debt that has a 30-year maturity and the gain in OCI is amortized over a 10-year period that began in June 2002.
(d) Represents a gain associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements through March 2008.

Other Derivatives

The following table represents the net change in market value of option transactions, which are used to manage our positions in SO2 allowances, coal, heating oil, and electricity or power. Certain of these transactions are treated as nonhedge transactions under SFAS No. 133. The net change in the market value of power options is recorded in Operating Revenues – Electric, while the net changes in the market value of coal, heating oil and SO2 options and swaps is recorded as Operating Expenses – Fuel and Purchased Power.

 

Gains (Losses)(a)      2005        2004        2003  

SO2 options and swaps:

               

Ameren(b)

     $ 2        $ (8 )      $ 1  

UE

        4          (10 )        (2 )

Genco

        (2 )        2          3  

Coal options:

               

Ameren(b)

       (1 )        -          1  

UE

        (1 )        -          2  

 

(a) Heating oil option gains and losses were less than $1 million for all periods shown above.
(b) Excludes amounts for IP before the acquisition date of September 30, 2004; excludes amounts for CILCORP before the acquisition date of January 31, 2003; and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

Through the market allocation process, UE, CIPS, Genco, CILCO and IP have been granted FTRs associated with the MISO Day Two Energy Market. Marketing Company has acquired FTRs for its participation in the PJM-Northern Illinois portion of the market. The FTRs are intended to hedge electric transmission congestion charges related to our physical electricity business. Depending on the congestion on the electric transmission grid and prices at various points on such grid, FTRs could result in either charges or credits. We use complex grid modeling tools to determine which FTRs we wish to nominate in the FTR allocation process. There is risk that we may incorrectly model the amount of FTRs we need, and there is the potential that some of the FTR hedges could be ineffective. FTRs are considered derivatives. The valuation of FTRs is complex due to the lack of available historical market data. As of December 31, 2005, the net value of FTRs held by the Ameren Companies was determined to be immaterial.

 

70

NOTE 10 – STOCKHOLDER RIGHTS PLAN AND PREFERRED STOCK

Stockholder Rights Plan

Ameren’s board of directors has adopted a share purchase rights plan designed to assure stockholders of fair and equal treatment in the event of a proposed takeover. The rights are exercisable only if a person or group acquires 15% or more of Ameren’s outstanding common stock or announces a tender offer that would result in ownership by a person or group of 15% or more of the Ameren common stock. Each right will entitle the holder to purchase one one-hundredth of a newly issued preferred stock at an exercise price of $180. If a person or group acquires 15% or more of Ameren’s outstanding common stock, each right will entitle its holder (other than such person or members of such group) to purchase, at the right’s then-current exercise price, a number of Ameren’s common shares having a market value of twice such price. In addition, if Ameren is acquired in a merger or other business combination transaction after a person or group has acquired 15% or more of Ameren’s outstanding common stock, each right will entitle its holder to purchase, at the right’s then-current exercise price, a number of the acquiring company’s common shares having a market value of twice such price. The acquiring person or group will not be entitled to exercise these rights. These rights expire in 2008. One right will accompany each new share of Ameren common stock prior to such expiration date.

Preferred Stock

All classes of UE’s, CIPS’, CILCO’s and IP’s preferred stock are entitled to cumulative dividends and have voting rights. Ameren has 100 million shares of $0.01 par value preferred stock authorized, with no shares outstanding. CIPS has 2.6 million shares of no par value preferred stock authorized, with no shares outstanding. UE has 7.5 million shares authorized of $1 par value preference stock and CILCO has 2 million shares authorized of no par value preference stock, with no such preference stock outstanding. IP has 5 million shares authorized of no par value serial preferred stock and 5 million shares authorized of no par value preference stock, with no such serial preferred stock and preference stock outstanding. No shares of preference stock have been issued by any of the Ameren Companies.

 

The following table presents the outstanding preferred stock of UE, CIPS, CILCO and IP that is not subject to mandatory redemption. The preferred stock is entitled to cumulative dividends and is redeemable, at the option of the issuer, at the prices presented as of December 31, 2005 and 2004:

 

      Redemption Price (per share)    2005    2004

UE:

         

Without par value and stated value of $100 per share, 25 million shares authorized

$3.50 Series

   130,000 shares    $ 110.00    $ 13    $ 13

$3.70 Series

     40,000 shares      104.75      4      4

$4.00 Series

   150,000 shares      105.625      15      15

$4.30 Series

     40,000 shares      105.00      4      4

$4.50 Series

   213,595 shares      110.00(a)      21      21

$4.56 Series

   200,000 shares      102.47      20      20

$4.75 Series

     20,000 shares      102.176      2      2

$5.50 Series A

     14,000 shares      110.00      1      1

$7.64 Series

   330,000 shares      103.82(b)      33      33

Total

           $ 113    $ 113

CIPS:

           

With par value of $100 per share, 2 million shares authorized

         

4.00% Series

   150,000 shares    $ 101.00    $ 15    $ 15

4.25% Series

     50,000 shares      102.00      5      5

4.90% Series

     75,000 shares      102.00      8      8

4.92% Series

     50,000 shares      103.50      5      5

5.16% Series

     50,000 shares      102.00      5      5

6.625% Series

   125,000 shares      100.00      12      12

Total

           $ 50    $ 50

CILCO:

         

With par value of $100 per share, 1.5 million shares authorized

         

4.50% Series

   111,264 shares    $ 110.00    $ 11    $ 11

4.64% Series

     79,940 shares      102.00      8      8

Total

           $ 19    $ 19

 

71

      Redemption Price (per share)    2005     2004  

IP:

          

With par value of $50 per share, 5 million shares authorized

        

4.08% Series

   225,510 shares    $   51.50    $ 12     $ 12  

4.20% Series

   143,760 shares      52.00      7       7  

4.26% Series

   104,280 shares      51.50      5       5  

4.42% Series

   102,190 shares      51.50      5       5  

4.70% Series

   145,170 shares      51.50      7       7  

7.75% Series

   191,765 shares      50.00      10       10  

Total

           $ 46     $ 46  

Less: Shares of IP preferred stock owned by Ameren(c)

            (33 )     (33 )

Total Ameren

           $ 195     $ 195  
(a) In the event of voluntary liquidation, $105.50.
(b) Beginning February 15, 2003, declining to $100 per share in 2012.
(c) Ameren purchased 662,924 shares of IP’s preferred stock on September 30, 2004. See Note 2 – Acquisitions for additional information.

The following table presents the outstanding preferred stock of CILCO that is subject to mandatory redemption. The preferred stock is entitled to cumulative dividends and is redeemable, at a determinable price on a fixed date or dates, at the prices presented as of December 31, 2005 and 2004, respectively:

 

      Redemption Price (per share)     2005    2004

CILCO:(a)

        

Without par value and stated value of $100 per share, 3.5 million shares authorized:

        

5.85% Series

   190,000 shares    $ 100.00 (b)   $ 19    $ 20
(a) Beginning July 1, 2003, this preferred stock became redeemable, at the option of CILCO, at $100 per share. A mandatory redemption fund was established on July 1, 2003. The fund provides for the redemption of 11,000 shares for $1.1 million on July 1 of each year through July 1, 2007. On July 1, 2008, the remaining shares outstanding will be retired for $16.5 million.
(b) In the event of voluntary or involuntary liquidation, the stockholder receives $100 per share plus accrued dividends.

 

NOTE 11 – RETIREMENT BENEFITS

We offer defined benefit and postretirement benefit plans covering substantially all employees of UE, CIPS, CILCORP, CILCO, IP, EEI and Ameren Services and certain employees of Resources Company and its subsidiaries, including Genco. Ameren uses a measurement date of December 31 for its pension and postretirement benefit plans.

IP merged into the Ameren pension and postretirement plans during the fourth quarter of 2004. Previously, IP had been part of the Dynegy benefit plans, so the IP predecessor amounts below represent the components of IP’s participation in the Dynegy plans prior to Ameren’s acquisition of IP. Plan participants included not only employees of IP, but certain Illinova and DMG employees. IP was reimbursed by participating Dynegy subsidiaries for their respective shares of the expenses of these benefit plans. Effective with Ameren’s acquisition of IP, employees of the other Dynegy subsidiaries were not transferred into the Ameren plans and, therefore, are not included in successor information presented.

Investment Strategy and Return on Asset Assumption

The primary objective of the Ameren Retirement Plan and postretirement benefit plans is to provide eligible employees with pension and postretirement health care benefits. Ameren manages plan assets in accordance with the “prudent investor” guidelines contained in ERISA. Ameren’s goal is to earn the highest possible return on plan assets consistent with its tolerance for risk. Ameren delegates investment management to specialists in each asset class. Where appropriate, Ameren provides the investment manager with guidelines that specify allowable and prohibited investment types. Ameren regularly monitors manager performance and compliance with investment guidelines.

The expected return on plan assets is based on historical and projected rates of return for current and planned asset classes in the investment portfolio. Assumed projected rates of return for each asset class were selected after an analysis of historical experience, future expectations, and the volatility of the various asset classes. After considering the target asset allocation for each asset class, we adjusted the overall expected rate of return for the portfolio for historical and expected experience of active portfolio management results compared to benchmark returns and for the effect of expenses paid from plan assets.

Pension benefits are based on the employees’ years of service and compensation. Our plans are funded in compliance with income tax regulations and federal funding requirements. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.

 

72

The following table presents the minimum pension liability and accumulated OCI amounts, after taxes, as of December 31, 2005 and 2004:

 

        2005      2004

Ameren(a)

     $ 64      $ 62

UE

        35        36

CIPS

        6        8

Genco

        6        4

CILCORP

        2        -

CILCO

        16        17

IP

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

The following table presents the funded status of our pension and postretirement benefit plans for the years ended December 31, 2005 and 2004:

 

      2005     2004  
     Pension
Benefits		     Postretirement
Benefits		    

Pension

Benefits

    

Postretirement

Benefits

  
      Ameren(a)     Ameren(a)     Ameren(b)     IP(c)     Ameren(b)     IP(c)  

Change in benefit obligation:

             

Net benefit obligation at beginning of year

   $ 2,980     $ 1,298     $ 2,142     $ 629     $ 1,063     $ 190  

Service cost

     59       21       46       12       17       4  

Interest cost

     169       73       142       28       65       8  

Plan amendments

     2       (6 )     16       -       (23 )     -  

Participant contributions

     -       8       -       -       5       1  

Actuarial loss (gain)

     62       (4 )     150       (38 )     109       1  

Reflection of Medicare Part D

     -       -       -       -       (71 )     -  

Transfer of IP into Ameren plan

     -       -       606       (606 )     197       (197 )

Special termination benefits

     -       -       4       -       1       -  

Benefits paid

     (166 )     (73 )     (126 )     (25 )     (65 )     (7 )

Net benefit obligation at end of year(d)

     3,106       1,317       2,980       -       1,298       -  

Change in plan assets:

             

Fair value of plan assets at beginning of year

     2,365       604       1,493       542       476       79  

Adjustment to IP for ERISA Section 4044

     4       -       -       -       -       -  

Actual return on plan assets

     175       40       216       13       43       -  

Transfer of IP into Ameren plan

     -       -       485       (485 )     73       (73 )

Allocated to Dynegy per ERISA Section 4044

      -       -       -       (52 )     -       -  

Employer contributions

     88       70       295       7       69       -  

Participant contributions

     -       9       -       -       5       1  

Benefits paid(e)

     (164 )     (70 )     (124 )     (25 )     (62 )     (7 )

Fair value of plan assets at end of year

      2,468       653       2,365       -       604       -  

Funded status – deficiency

      638       664       615       -       694       -  

Unrecognized net actuarial loss

      (342 )     (368 )     (311 )     -       (406 )     -  

Unrecognized prior service cost

      (76 )     74       (85 )     -       75       -  

Unrecognized net transition asset (obligation)(f)

     -       (14 )     1       -       (16 )     -  

Accrued benefit cost at December 31

    $ 220     $ 356     $ 220     $ -     $ 347     $ -  
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b) Excludes amounts for IP before the acquisition date of September 30, 2004; includes amounts for Ameren registrant and nonregistrant subsidiaries.
(c) Represents predecessor information for period prior to September 30, 2004.
(d) Accumulated benefit obligation was $2,872 million and $2,775 million as of December 31, 2005 and 2004, respectively.
(e) Excludes amounts paid from company funds.
(f) Ameren’s transition obligation at December 31, 2005, is being amortized over the next 10 years.

Ameren’s current reconciliation of funded status shows certain amounts that will be recognized as a benefit cost in future years. The unrecognized losses are largely a result of declining discount rates over the past several years, higher than expected increases in medical costs, and market losses on plan assets.

 

73

The following table presents the cash contributions made to our defined benefit retirement plan qualified trusts and to our postretirement plans during 2005 and 2004.

 

      Pension Benefits    Postretirement Benefits
      2005    2004    2005    2004

Ameren(a)

   $ 88    $ 295    $ 70    $ 69

UE

      56      186      47      44

CIPS

      10      33      8      8

Genco

      9      29      3      3

CILCORP

      11      41      5      8

CILCO

      11      41      5      8

IP(b)

     -      -      8      6

 

(a) Excludes amounts for IP before the acquisition date of September 30, 2004; includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) There were no postretirement benefit contributions made by predecessor IP during the first nine months of 2004.

Based on our assumptions at December 31, 2005, and assuming continuation of the recently expired federal interest rate relief beyond 2006, in order to maintain minimum funding levels for Ameren’s pension plans, we do not expect future contributions to be required until 2011 at which time we would expect a required contribution of $100 million to $150 million. If federal interest rate relief is not continued in its most recent form, $200 million to $300 million may need to be funded in 2009 to 2010 based on other recent federal legislative proposals. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 64%, 10%, 10%, 9%, and 7%, respectively. These amounts are estimates. They may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions.

The following table presents the assumptions used to determine our benefit obligations at December 31, 2005 and 2004:

 

      Pension Benefits     Postretirement Benefits  
      2005     2004     2005     2004  

Discount rate at measurement date

    5.60 %   5.75 %   5.60 %   5.75 %

Increase in future compensation

    3.25     3.00     3.25     3.00  

Medical cost trend rate (initial)

    -     -     8.00     9.00  

Medical cost trend rate (ultimate)

    -     -     5.00     5.00  

Ameren uses plan actuaries to determine discount rate assumptions. Ameren’s actuaries have developed an interest rate yield curve to make judgments pursuant to EITF No. D-36, “Selection of Discount Rates Used for Measuring Defined Benefit Pension Obligations and Obligations of Postretirement Benefit Plans Other Than Pensions.” The yield curve is constructed based on the yields of more than 500 high-quality, non-callable corporate bonds with maturities between zero and 30 years. A theoretical spot-rate curve constructed from this yield curve is then used to discount the annual benefit cash flows of the Ameren pension plan and postretirement plans and develop a single-point discount rate matching the plans’ payout structure.

In determining the current year market-related asset value, the prior year market-related value of assets is adjusted by contributions, disbursements, and expected return, plus 25% of the actual return in excess of (or less than) expected return for the four prior years.

The following tables present the pension amounts recorded in Ameren’s Consolidated Balance Sheets as of December 31, 2005 and 2004:

 

      2005     2004  

Accrued pension liability

    $ 404     $ 409  

Intangible asset

      (79 )     (88 )

Accumulated OCI

      (105 )     (101 )

Accrued pension cost at December 31

    $ 220     $ 220  

 

74

The following table presents our target allocations for 2006 and our pension and postretirement plan asset categories as of December 31, 2005 and 2004:

 

Asset    Target Allocation     Percentage of Plan Assets at December 31,  
Category    2006     2005     2004  

Pension Plan

       

Equity securities

    40% – 80 %   62 %   62 %

Debt securities

    15 – 50     31     30  

Real estate

    0 – 10     5     5  

Other

    0 – 15     2     3  

Total

          100 %   100 %

Postretirement Plan

       

Equity securities

    40% – 80 %   63 %   62 %

Debt securities

    15 – 55     33     34  

Other

    0 – 15     4     4  

Total

          100 %   100 %

The following table presents the components of the net periodic benefit cost (income) for our pension and postretirement benefit plans during 2005, 2004 and 2003:

 

      Pension Benefits     Postretirement Benefits  
      Ameren(a)     Ameren(a)  

2005:

     

Service cost

    $ 59     $    21  

Interest cost

      169       73  

Expected return on plan assets

      (186 )     (46 )

Amortization of:

     

Transition obligation (asset)

     (1 )     2  

Prior service cost

     11       (7 )

Actuarial loss

     38       39  
Net periodic benefit cost    $ 90     $ 82  
        Ameren(b)      IP(c)      Ameren(b)      IP(c)  

2004:

              

Service cost

      $ 46      $    12      $    17      $    4  

Interest cost

        142        28        65        8  

Expected return on plan assets

        (133 )      (35 )      (39 )      (5 )

Amortization of:

              

Transition obligation (asset)

       (1 )      (1 )      2        1  

Prior service cost

       11        1        (4 )      -  

Actuarial loss

       24        2        33        4  

Net periodic benefit cost

        89        7        74        12  

Net periodic benefit cost, including special termination benefits(e)

     $ 93      $ 7      $ 74      $ 12  
        Ameren(b)(d)      IP(f)      Ameren(b)(d)      IP(f)  

2003:

              

Service cost

      $ 39      $    13      $    14      $    4  

Interest cost

        131        36        64        10  

Expected return on plan assets

        (127 )      (50 )      (36 )      (6 )

Amortization of:

              

Transition obligation (asset)

        (1 )      (1 )      2        2  

Prior service cost

        9        1        (3 )      -  

Actuarial loss

        8        -        34        5  

Net periodic benefit cost (income)

        59        (1 )      75        15  

Net periodic benefit cost (income), including special termination benefits(e)

     $ 61      $ (1 )    $ 75      $ 15  

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries.
(b) Excludes amounts for IP before the acquisition date of September 30, 2004; includes amounts for Ameren registrant and nonregistrant subsidiaries.
(c) Represents predecessor information for the first nine months of 2004.
(d) Excludes amounts for CILCORP before the acquisition date of January 31, 2003; includes amounts for Ameren registrant and nonregistrant subsidiaries.

 

75

(e) Special termination benefits are deferred as a regulatory asset. See Note 3 – Rate and Regulatory Matters.
(f) Represents predecessor information.

Prior service cost is amortized on a straight-line basis over the average future service of active participants benefiting under the plan. The net actuarial loss (gain) subject to amortization is amortized on a straight-line basis over 10 years.

Ameren adopted FSP SFAS 106-2 during the second quarter of 2004, retroactive to January 1, 2004, which resulted in the recognition of a federal subsidy for postretirement benefit costs related to prescription drug benefits. See Note 1 – Summary of Significant Accounting Policies. The effect of this subsidy was a reduction of various components of Ameren’s and principally UE’s net periodic postretirement benefit costs. Interest costs were reduced by $4 million, and amortization of losses was reduced by $7 million. The impact of the subsidy on the expected return on plan assets was minimal.

UE, CIPS, Genco, CILCORP, CILCO and IP are responsible for their proportional share of the pension and postretirement costs. The following table presents the pension costs (benefits) and the postretirement benefit costs incurred for the years ended December 31, 2005, 2004 and 2003:

 

        Pension Costs        Postretirement Costs
        2005      2004      2003        2005      2004      2003

UE

      $    54      $    54      $    35        $    44      $    44      $    52

CIPS

        10        11        7          9        9        9

Genco

        7        8        5          4        3        2

CILCORP(a)

       10        14        7          9        14        10

CILCO

        15        22        17          16        23        18

IP(b)

       8        9        (1 )        15        15        15

 

(a) Includes predecessor information for periods prior to the acquisition date of January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.
(b) Includes predecessor information for periods prior to the acquisition date of September 30, 2004. Predecessor amount for pension costs and postretirement costs in 2004 are $7 million and $12 million, respectively.

The expected pension and postretirement benefit payments from qualified trust and company funds, which reflect expected future service, are as follows:

 

        Pension from
Qualified Trust		      Pension from
Company Funds		      Benefits from
Qualified Trust		      Benefits from
Company Funds

2006

      $ 172      $    2      $    82      $    3

2007

        174        2        85        3

2008

        178        2        87        3

2009

        183        2        88        3

2010

        187        2        92        3

2011 - 2015

        1,016        9        501        13

The following table presents the assumptions used to determine net periodic benefit cost for our pension and postretirement benefit plans for the years ended December 31, 2005, 2004 and 2003:

 

        Pension Benefits      Postretirement Benefits  
        2005      2004      2003      2005      2004      2003  

Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP(a):

                    

Discount rate at measurement date

      5.75 %    6.25 %    6.75 %    5.75 %    6.25 %    6.75 %

Expected return on plan assets

      8.50      8.50      8.50      8.50      8.50      8.50  

Increase in future compensation

      3.00      3.25      3.75      3.00      3.25      3.75  

Medical cost trend rate (initial)

      -      -      -      9.00      9.00      10.00  

Medical cost trend rate (ultimate)

      -      -      -      5.00      5.00      5.00  

IP(b):

                    

Discount rate at measurement date

      (b )    6.00 %    6.50 %    (b )    6.00 %    6.00 %

Expected return on plan assets

      (b )    8.75      9.00      (b )    8.75      9.00  

Increase in future compensation

      (b )    4.50      4.50      (b )    4.50      4.50  

Medical cost trend rate (initial)

      -      -      -      (b )    10.00      10.00  

Medical cost trend rate (ultimate)

      -      -      -      (b )    5.50      5.50  

 

(a) The 2003 amounts do not include IP.
(b) Included in Ameren’s plan for 2004 and 2005. Represents predecessor information for 2003.

 

76

The table below reflects the sensitivity of Ameren’s plans to potential changes in key assumptions:

 

      Pension    Postretirement
      Net Periodic
Benefit Cost		    Projected Benefit
Obligation		    Net Periodic
Benefit Cost		    Projected
Postretirement
Benefit Obligation

0.25% decrease in discount rate

    $ 10    $ 95    $ 3    $ 35

0.25% increase in salary scale

      5      30      -      -

0.25% decrease in expected return on assets

      6      -      1      -

1.00% increase in annual medical trend

      -      -      11      60

 

Other

Ameren and CIPS sponsor 401(k) plans for eligible employees. The CIPS 401(k) plan is only available to employees represented by IBEW Local 702. All other CIPS employees are eligible to participate in the Ameren 401(k) plan. The former CIPS IUOE Local 148 plan was merged into the Ameren plan during the first quarter of 2005. IP employees began participating in the Ameren plan during the fourth quarter of 2004. The former CILCO plan was merged into the Ameren plan at the beginning of 2004. The plans allow employees to contribute a portion of their base pay in accordance with specific guidelines. Ameren and CIPS match a percentage of the employee contributions up to certain limits. Ameren’s matching contribution to the 401(k) plan totaled $18 million in 2005. Ameren’s and IP’s matching contributions to the 401(k) plans totaled $15 million and $2 million (predecessor), respectively, in 2004. Matching contributions to the Ameren, predecessor IP, and predecessor CILCO plans were $14 million, $2 million, and $1 million, respectively, in 2003. CIPS’ matching contributions to its 401(k) plan were less than $1 million annually in 2005, 2004 and 2003.

The following table presents the portion of the 401(k) matching contribution to the Ameren plan for each of the Ameren Companies for the years ended December 31, 2005, 2004 and 2003:

        2005      2004      2003

Ameren(a)

      $ 18      $ 15      $ 14

UE

        12        11        12

CIPS

        1        -        -

Genco

        1        1        1

CILCORP

        2        1        1

CILCO

        2        1        1

IP

        2        1        -
(a) Excludes amounts for IP prior to the acquisition date of September 30, 2004; excludes amounts for CILCORP and CILCO prior to the acquisition date of January 31, 2003; includes amounts for Ameren registrant and nonregistrant subsidiaries.

NOTE 12 – STOCK-BASED COMPENSATION

Ameren’s long-term incentive plan for eligible employees, called the Long-term Incentive Plan of 1998, provides for the grant of options, performance awards, restricted stock, dividend equivalents, and stock appreciation rights.

 

Restricted Stock

Restricted stock awards in Ameren common stock may be granted under the Long-term Incentive Plan of 1998. Upon the achievement of certain performance levels, the eligible employee receives the restricted stock award. The restricted stock award vests over a period of seven years, beginning at the date of grant. An accelerated vesting provision included in this plan reduces the vesting period from seven years to three years. In February 2006, Ameren’s board of directors approved the adoption of a new incentive compensation plan, called the 2006 Omnibus Incentive Compensation Plan, subject to approval by Ameren’s shareholders at its annual meeting on May 2, 2006. This new plan, which will replace Ameren’s Long-term Incentive Plan of 1998 prospectively, is described in and provided with Ameren’s definitive proxy statement for its 2006 annual meeting filed pursuant to SEC Regulation 14A. During 2005, 2004, and 2003, respectively, 154,086, 135,340, and 152,956 restricted stock awards were granted. The weighted-average fair value for restricted stock awards granted in 2005, 2004, and 2003 was $51.21, $46.34, and $39.74 per share, respectively. We record unearned compensation (as a component of stockholders’ equity) equal to the market value of the restricted stock on the date of grant. We charge the unearned compensation to expense over the vesting period.

Stock Options

Ameren

Options in Ameren common stock may be granted under the Long-term Incentive Plan of 1998 at a price not less than the fair-market value of the common shares at the date of grant. Granted options vest over a period of five years, beginning at the date of grant, and they permit accelerated exercising upon the occurrence of certain events, including retirement. Outstanding options expire on various dates through 2010. Subject to adjustment, 4 million shares have been authorized to be issued or delivered under the Long-term Incentive Plan of 1998. We applied APB Opinion No. 25 in accounting for our stock-based compensation for years prior to 2003. There have not been any stock options granted since December 31, 2000. Effective January 1, 2003, we prospectively adopted accounting for our stock-based compensation plans using the fair value recognition provisions of SFAS No. 123. See Note 1 – Summary of Significant Accounting Policies for further information.

 

77

The following table presents Ameren stock option activity during 2005, 2004 and 2003:

 

      2005      2004      2003
     

Number

of Shares

   

Weighted-average

Option Price

     

Number

of Shares

   

Weighted-average

Option Price

     

Number

of Shares

   

Weighted-average

Option Price

Outstanding at beginning of year

    411,239    $ 33.38         1,499,676    $ 34.88         1,977,453    $ 35.10

Exercised

    272,747      33.10      1,088,437      35.44      477,777      35.78

Cancelled or expired

    2,500      43.00      -      -      -      -

Outstanding at end of year

    135,992      33.76      411,239      33.38      1,499,676      34.88

Exercisable at end of year

    135,992    $ 33.76      272,439    $ 34.59      1,032,001    $ 36.00

The following table presents additional information about Ameren stock options outstanding at December 31, 2005:

 

Options Outstanding     Options Exercisable

Exercise

Price

   

Outstanding

Shares

   

Weighted-average

Life (Years)

   

Weighted-average

Exercise Price

    

Exercisable

Shares

   

Weighted-average

Exercise Price

$31.00

    77,900    3.9    $ 31.00     77,900    $ 31.00

  36.625

    40,750    2.8      36.625        40,750      36.625

  39.25

    16,512    1.9      39.25     16,512      39.25

  43.00

    830    0.1      43.00     830      43.00

The fair values of stock options were estimated using a binomial option-pricing model with the following assumptions:

 

Grant Date   Risk-free Interest Rate   Option Term   Expected Volatility   Expected Dividend Yield

2/11/00

   6.81%   10 years   17.39%   6.61%

2/12/99

   5.44      10 years   18.80      6.51   

6/16/98

   5.63      10 years   17.68     6.55   

4/28/98

   6.01      10 years   17.63     6.55   

2/10/97

   5.70      10 years   13.17     6.53   

2/7/96

   5.87      10 years   13.67     6.32   

CILCORP

Prior to Ameren’s acquisition of CILCORP, employees of CILCORP and CILCO participated in the AES Stock Option Plan, which granted AES common stock options to eligible participants. Under the terms of the plan, options were issued to purchase shares of AES common stock at a price equal to 100% of the market price at the date the option was granted. The options became eligible for exercise under various schedules.

Provisions of CILCORP bonus programs allowed for the cash-out of certain AES stock options in the event of an acquisition of CILCORP. CILCORP paid $3 million during 2003 for the cash-out of the entire 73,502 shares that were eligible under these provisions. All other outstanding options under the AES Stock Option Plan remain the sole obligation of AES.

Predecessor IP

Prior to Ameren’s acquisition of IP, certain IP employees participated in the equity compensation plans of Dynegy. On October 1, 2004, as a result of the acquisition, all unvested stock options granted to IP employees became null and void. The following table presents IP stock option activity:

 

       

    January 1, 2004 to    

    September 30, 2004    

     

    For the year ended    

    December 31, 2003    

       

Number

of Shares

     

Weighted-average

Option Price

     

Number

of Shares

     

Weighted-average

Option Price

Outstanding at beginning of period

      1,739,592      $ 24.59         1,606,086      $ 29.94

Granted

      42,987        3.06      335,500        1.77

Exercised

      (143,141 )      1.77      -        -

Cancelled, forfeited or expired

      (1,616,844 )      2.05      (201,994 )      29.22

Outstanding at end of period(a)

     22,594        26.02      1,739,592        24.59

Exercisable at end of period(a)

     22,594        1.77      1,291,010        29.76

Weighted average fair value of options granted at market

      -        4.07      -        1.54

 

(a) The 22,594 exercisable options as of September 30, 2004, are an obligation of Dynegy; therefore, additional successor information is not presented.

 

78

The following table presents the assumptions that were used in the Black-Scholes valuation method for shares of Dynegy common stock granted:

 

Year of Grant(a)   Risk-free Interest Rate   Option Term   Expected Volatility   Expected Dividend Yield

2003

   3.92%   10 years   90%   n/a

2001

   4.82      10 years   46      1%

 

(a) Assumptions for the 2004 grant are not presented as the expense associated with the options was negligible and the options were either cancelled or assumed by Dynegy.

NOTE 13 – INCOME TAXES

The following table presents the principal reasons why the effective income tax rate differed from the statutory federal income tax rate for the years ended December 31, 2005, 2004 and 2003:

 

        Ameren(a)      UE      CIPS      Genco      CILCORP      CILCO      IP(b)  

2005:

                       

Statutory federal income tax rate:

      35 %    35 %    35 %    35 %    35 %    35 %    35 %

Increases (decreases) from:

                       

Permanent items(c)

     (1 )    -      (1 )    -      (d )    (5 )    -  

Leveraged lease sale

      (1 )    -      -      -      (d )    -      -  

Depreciation differences

      1      2      (1 )    -      (d )    (4 )    -  

Amortization of investment tax credit

      (1 )    (1 )    (2 )    (1 )    (d )    (3 )    -  

State tax

      3      3      4      5      (d )    5      3  

Other(e)

     (1 )    (3 )    1      -      (d )    8      2  

Effective income tax rate

      35 %    36 %    36 %    39 %    (d )    36 %    40 %

2004:

                       

Statutory federal income tax rate:

      35 %    35 %    35 %    35 %    35 %    35 %    35 %

Increases (decreases) from:

                       

Permanent items(f)

     (2 )    -      (1 )    -      (d )    (16 )    -  

Depreciation differences

      1      1      (1 )    -      (d )    (4 )    1  

Amortization of investment tax credit

      (1 )    (1 )    (3 )    (1 )    (d )    (3 )    (1 )

State tax

      3      4      5      5      (d )    3      5  

Other

      (2 )    (3 )    (2 )    (2 )    (d )    (1 )    (1 )

Effective income tax rate

      34 %    36 %    33 %    37 %    (d )    14 %    39 %

2003:

                       

Statutory federal income tax rate:

      35 %    35 %    35 %    35 %    35 %    35 %    35 %

Increases (decreases) from:

                       

Depreciation differences

      1      1      1      -      (1 )    (1 )    2  

Amortization of investment tax credit

      -      -      (4 )    (1 )    (4 )    (2 )    (1 )

State tax

      3      3      7      5      6      3      5  

Resolution of state income tax matters

      (1 )    -      (21 )    -      -      -      -  

Other(g)

     (1 )    (3 )    -      1      (5 )    3      (2 )

Effective income tax rate

      37 %    36 %    18 %    40 %    31 %    38 %    39 %

 

(a) Excludes amounts for IP before the acquisition date of September 30, 2004; excludes amounts for CILCORP before the acquisition date of January 31, 2003.
(b) Represents predecessor information for January through September 2004 and all of 2003.
(c) Primarily includes life insurance for CILCO and miscellaneous items for other registrants.
(d) The 2005 difference between the reported federal income tax benefit and income tax expense calculated using the statutory rate resulted primarily from tax benefits from plant-related depreciation differences ($2 million), low-income housing credits ($1 million), and investment tax credit amortization ($1 million) that were partially offset by prior period tax matters ($1 million). The 2004 difference between the reported federal income tax benefit and income tax expense calculated using the statutory rate resulted primarily from the permanent effect of a litigation settlement ($6 million), plant-related depreciation differences ($2 million), and investment tax credit amortization ($2 million).
(e) CILCO Other for 2005 primarily includes low-income housing tax credits and resolution of prior period tax matters.
(f) Permanent items primarily include SFAS No. 106-2 Medicare Part D for Ameren, UE, CIPS, CILCORP and CILCO and a litigation settlement at CILCORP and CILCO.
(g) CILCORP Other primarily includes low-income housing tax credits.

 

79

The following table presents the components of income tax expense for the years ended December 31, 2005, 2004 and 2003:

 

        Ameren(a)      UE      CIPS      Genco      CILCORP      CILCO      IP(b)  

2005:

                       

Current taxes

                       

Federal

      $ 232      $ 148      $ 32      $ 41      $ 3      $ 28      $ 12  

State

        66        13        8        11        19        13        14  

Deferred taxes

                       

Federal

        114        62        (8 )      19        (4 )      (15 )      41  

State

        (46 )      (24 )      (5 )      2        (19 )      (9 )      (2 )

Deferred investment tax credits, amortization

        (10 )      (6 )      (2 )      (1 )      (2 )      (1 )      -  

Included in Income Taxes on Statement of Income

      $ 356      $ 193      $ 25      $ 72      $ (3 )    $ 16      $ 65  

Included in cumulative effect of change in accounting principle

                       

Federal - deferred

      $ (12 )    $ -      $ -      $ (8 )    $ (1 )    $ (1 )    $ -  

State - deferred

        (3 )      -        -        (2 )      -        -        -  

Total income tax expense (benefit)

      $ 341      $ 193      $ 25      $ 62      $ (4 )    $ 15      $ 65  

2004:

                       

Current taxes

                       

Federal

      $ (60 )    $ 75      $ 2      $ 6      $ (44 )    $ (31 )    $ 39  

State

        3        22        4        -        (7 )      (4 )      11  

Deferred taxes

                       

Federal

        303        108        10        49        37        35        33  

State

        47        9        1        11        8        8        7  

Deferred investment tax credits, amortization

        (11 )      (6 )      (1 )      (2 )      (2 )      (2 )      (1 )

Total income tax expense (benefit)

      $ 282      $ 208      $ 16      $ 64      $ (8 )    $ 6      $ 89  

2003:

                       

Current taxes

                       

Federal

      $ 273      $ 226      $ 26      $ 10      $ 13      $ 30      $ 78  

State

        28        28        (1 )      -        4        7        21  

Deferred taxes

                       

Federal

        3        -        (15 )      24        (7 )      (19 )      (19 )

State

        8        3        (3 )      6        1        (4 )      (4 )

Deferred investment tax credits, amortization

        (11 )      (6 )      (1 )      (2 )      (2 )      (2 )      (1 )

Included in Income Taxes on Statement of Income

      $ 301      $ 251      $ 6      $ 38      $ 9      $ 12      $ 75  

Included in cumulative effect of change in accounting principle

                       

Federal - current

      $ 10      $ -      $ -      $ 10      $ 2      $ 13      $ 2  

State - current

        2        -        -        2        -        3        -  

Total income tax expense

      $ 313      $ 251      $ 6      $ 50      $ 11      $ 28      $ 77  
(a) Excludes amounts for IP before the acquisition date of September 30, 2004; excludes amounts for CILCORP before the acquisition date of January 31, 2003.
(b) Represents predecessor information for January through September 2004 and all of 2003.

 

80

The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2005 and 2004:

 

      Ameren(a)      UE      CIPS      Genco      CILCORP(b)      CILCO      IP  

2005:

                     

Accumulated deferred income taxes, net liability (asset):

                     

Plant related

    $ 1,960      $ 1,206      $ 183      $ 253      $ 202      $ 202      $ 89  

Deferred intercompany tax gain/basis step-up

      6        -        135        (136 )      -        -        -  

Regulatory assets (liabilities), net

      108        118        1        -        (10 )      (10 )      -  

Deferred benefit costs

      (175 )      (62 )      2        -        (94 )      (52 )      (8 )

Purchase accounting

      (57 )      -        -        -        (10 )      -        (84 )

Leveraged leases

      60        -        -        -        19        19        -  

Other

      28        (19 )      (29 )      39        53        -        (16 )

Total net accumulated deferred income tax liabilities(c)

   $ 1,930      $ 1,243      $ 292      $ 156      $ 160      $ 159      $ (19 )

2004:

                     

Accumulated deferred income taxes, net liability (asset):

                     

Plant related

    $ 2,043      $ 1,251      $ 156      $ 294      $ 217      $ 190      $ 115  

Deferred intercompany tax gain/basis step-up

      -        -        149        (149 )      -        -        -  

Regulatory assets (liabilities), net

      45        55        (4 )      -        (6 )      (6 )      -  

Deferred benefit costs

      (265 )      (46 )      2        2        (122 )      (64 )      (110 )

Purchase accounting

      (4 )      -        -        -        54        -        (94 )

Leveraged leases

      103        -        -        -        77        -        -  

Other

      (24 )      (43 )      (3 )      (3 )      (1 )      14        24  

Total net accumulated deferred income tax liabilities(d)

   $ 1,898      $ 1,217      $ 300      $ 144      $ 219      $ 134      $ (65 )
(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) CILCORP consolidates CILCO and therefore includes CILCO in its balances.
(c) Includes $39 million, $34 million, $4 million, and $8 million recorded as current assets in the consolidated balance sheet for Ameren, UE, CILCORP, and CILCO, respectively.
(d) Includes $16 million, $(5) million, and $(4) million recorded as current asset (liability) in the consolidated balance sheet of Ameren, CILCORP, and CILCO.

Upon Ameren’s acquisition of IP, IP’s net accumulated deferred income tax liabilities and unamortized accumulated investment tax credits were eliminated.

 

NOTE 14 – RELATED PARTY TRANSACTIONS

The Ameren Companies have engaged in, and may in the future engage in, affiliate transactions in the normal course of business. These transactions primarily consist of gas and power purchases and sales, services received or rendered, and borrowings and lendings. Transactions between affiliates are reported as intercompany transactions on their financial statements, but are eliminated in consolidation for Ameren’s financial statements. Below are the material related-party agreements.

Electric Power Supply Agreements

Under two electric power supply agreements, Genco is obliged to supply power to Marketing Company. Marketing Company, in turn, is obliged to supply to CIPS all of the energy and capacity CIPS needs to offer service for resale to its native load customers at ICC-related rates and to fulfill its other obligations under all applicable federal and state tariffs or contracts. Any power not used by CIPS is sold by Marketing Company under various long-term wholesale and retail contracts. For native load, CIPS pays an annual capacity charge per megawatt for its forecasted peak demand or actual demand, whichever is greater, plus an energy charge per megawatthour to Marketing Company. For fixed-price retail customers outside of the tariff, CIPS pays Marketing Company the price it receives under these contracts. The fees paid by CIPS to Marketing Company for native load and fixed-price retail customers and any other sales by Marketing Company under various long-term wholesale and retail contracts are passed through to Genco. In addition, under the power supply agreement between Genco and Marketing Company, Genco bears all generation-related operating risks, including plant performance, operations, maintenance, efficiency, employee retention, and other matters. There are no guarantees, bargain purchase options, or other terms that convey to CIPS the right to use the property and plant of Genco. The expiration date for the agreement between CIPS and Marketing Company is December 31, 2006. The agreement between Genco and Marketing Company can be terminated by either party upon one year’s notice.

In October 2003, in conjunction with CILCO’s transfer to AERG of substantially all of its generating assets, AERG entered into an electric power supply agreement to supply CILCO with sufficient power to meet its native load requirements. CILCO pays a monthly capacity charge per

 

81

megawatt based on its system capacity requirements, plus an energy charge per megawatthour. The expiration date for this agreement is December 31, 2006. Also in conjunction with CILCO’s generating asset transfer, a bilateral power supply agreement was entered into between AERG and Marketing Company. This agreement provides for AERG to sell excess power to Marketing Company for sales outside the CILCO control area, and it also allows Marketing Company to sell power to AERG to fulfill CILCO’s native load requirements.

CILCO had an agreement with CIPS for the purchase of 100 megawatts of capacity and firm energy for January and the months of June through September under a contract that commenced in January 2000 and expired in September 2003. In 2003, $8 million of Operating Revenues and Purchased Power were recorded by CIPS and CILCO, respectively, from this agreement. This power was supplied by Genco through the Marketing Company, CIPS, and Genco electric power supply agreements discussed above.

UE, CIPS, IP and a nonaffiliated company were parties to a power supply agreement with EEI to purchase and sell capacity and energy. This agreement expired on December 31, 2005. Under a separate agreement that expired on December 31, 2005, CIPS resold its entitlements under the agreement with EEI to Marketing Company. Marketing Company and certain nonaffiliated companies are parties to a power supply agreement with Midwest Electric Power, Inc., a subsidiary of EEI, to purchase capacity and energy. This agreement’s term is year-to-year on a calendar basis, unless the purchasing parties unanimously agree to terminate their participation. On December 22, 2005, Marketing Company entered into a power supply agreement with EEI, whereby EEI will sell 100% of its capacity and energy to Marketing Company. This agreement expires on December 31, 2015. See Note 3 – Rate and Regulatory Matters for discussion regarding a FERC ruling allowing EEI to sell power at market-based rates.

UE had a 150-megawatt power supply agreement with Marketing Company that expired May 31, 2005. UE also had a one-year 200-megawatt power supply agreement with Marketing Company that expired in May 2003. Power supplied by Marketing Company to UE through these agreements was obtained from Genco.

In December 2003, AERG and Marketing Company entered into an agency agreement that authorizes Marketing Company, on behalf of AERG, to sell AERG’s excess generation or to purchase power needed to supply AERG customers.

In December 2004, Marketing Company and IP entered into an agency agreement that authorizes Marketing Company, on behalf of IP, to sell or purchase, as necessary, electric energy and capacity in the wholesale market for 2005 and 2006.

IP had a contract that expired at the end of 2004 with a former affiliate, DMG, to supply power via purchase agreements. The purchased power agreement with DMG obliged DMG to provide power to IP up to the reservation amount, and at the same prices, even if DMG had individual units unavailable at various times.

IP is party to several commercial and industrial electric and gas sales agreements with DMG, which were entered into before Ameren’s acquisition of IP. These are typically yearly contracts that renew automatically unless cancelled by either party pursuant to a 30-day written notice.

Also before Ameren’s acquisition, IP purchased natural gas from Dynegy to serve its gas distribution business under a Gas Industry Standards Board master base contract that terminated October 1, 2004. Under this agreement, IP executed multiple transactions in 2003 that covered deliveries for the yearly winter peak season from November through March. One transaction was executed in 2004 to provide deliveries from January to March 2004.

Interconnection and Transmission Agreements

UE, CIPS and IP are parties to an interconnection agreement for the use of their respective transmission lines and other facilities for the distribution of power. In addition, CILCO and IP and CILCO and CIPS are parties to similar interconnection agreements. These agreements have no contractual expiration date, but may be terminated by any party with three year’s notice.

IP was a party to transmission and interconnection sales agreements with DYPM, a former affiliate, for the use of IP’s transmission lines and other facilities. The transmission sales agreements expired in April and June 2005. The interconnection sales agreements expired January 1, 2006. On October 1, 2004, pursuant to the sale of IP to Ameren, all continuing contracts with Dynegy and its affiliates became third-party agreements.

Joint Dispatch Agreement

UE and Genco jointly dispatch electric generation under a joint dispatch agreement among UE, CIPS and Genco. UE and Genco have the option to serve their load requirements from their own generation first, and then each may give its affiliates access to any available generation at incremental cost. Any excess generation not used by UE or Genco to serve load requirements is sold to third parties on a short-term basis through Ameren Energy, which serves as each

 

82

affiliate’s agent. To allocate power costs between UE and Genco, an intercompany sale is recorded by the company sourcing the power to the other company. Ameren Energy also acts as agent on behalf of UE and Genco to purchase power when they require it. The joint dispatch agreement can be terminated by UE, CIPS or Genco upon one year’s notice unless terminated earlier by mutual consent.

See Note 3 – Rate and Regulatory Matters for a further discussion of the amendment to the joint dispatch agreement ordered by the MoPSC and further amendments sought by the Missouri OPC in a related FERC proceeding.

The following table presents the amount of gigawatthour sales under the joint dispatch agreement.

 

        2005      2004      2003

UE sales to Genco

      12,806      8,466      8,391

Genco sales to UE

      3,487      2,482      2,369

The following table presents the short-term power sales margins under the joint dispatch agreement for UE and Genco.

 

        2005      2004      2003

Short-term power sales margins:

               

UE

      $ 128      $ 124      $ 102

Genco

        79        66        53

Total

      $ 207      $ 190      $ 155

Support Services Agreements

Costs of support services provided by Ameren Services, Ameren Energy, and AFS to their affiliates, including wages, employee benefits, professional services, and other expenses are based on, or are an allocation of, actual costs incurred. Effective September 30, 2004, IP was added to the support services agreements with Ameren Services and AFS. Before that, IP operated under Dynegy’s consolidated group’s Services and Facilities Agreement, whereby other Dynegy affiliates exchanged with IP services such as financial, legal, information technology, and human resources, as well as shared facility space. IP services were exchanged at fully distributed costs, and revenues were not recorded under this agreement. This agreement was terminated in conjunction with IP’s sale to Ameren.

Executory Tolling, Gas Sales, and Transportation Agreements

Under an executory tolling agreement, CILCO purchases steam, chilled water, and electricity from Medina Valley. In connection with this agreement, Medina Valley purchases gas to fuel its generating facility from AFS under a fuel supply and services agreement. Before September 2003, Medina Valley purchased gas from CILCORP Energy Services, Inc., a subsidiary of CILCORP that operated gas management services including commodity procurement and redelivery to retail customers, and gas transportation from CILCO.

Under a gas transportation agreement, Genco acquires gas transportation service from UE for its Columbia, Missouri, CTs. This agreement expires in February 2016.

Note Receivable from Former Affiliate

In September 2004, IP’s $2.3 billion note receivable from a former affiliate was eliminated in connection with the sale of IP to Ameren. In July, September, October and December 2003, Dynegy made interest payments totaling $256 million on its $2.3 billion intercompany note payable to Illinova, which in turn made interest payments totaling $256 million to IP under the note receivable. These interest payments represented accrued interest on the notes for the months of April through December 2003, and prepaid interest for the months of January 2004 through September 2004. In January 2004, IP received an additional interest prepayment of $43 million. These notes contained payment provisions pursuant to which semi-annual interest payments of $86 million were due on April 1 and October 1 of each year.

Transitional Funding Securitization Financing Agreement

IP’s financial statements include related party transactions with IP SPT, its wholly owned unconsolidated subsidiary, which was deconsolidated in accordance with the adoption of FIN 46R effective on December 31, 2003. In accordance with the Transitional Funding Securitization Financing Agreement, IP must designate a portion of the cash received from customer billings to fund payment of the TFNs. The amounts received are remitted to the IP SPT and are restricted for the sole purpose of paying down the TFNs. Due to the adoption of FIN 46R and resulting deconsolidation of IP SPT, these amounts are netted against the current portion of IP’s long-term debt payable to IP SPT on IP’s December 31, 2005, Consolidated Balance Sheet. See Note 1 – Summary of Significant Accounting Policies for further information.

Money Pools

See Note 5 – Short-term Borrowings and Liquidity for discussion of affiliate borrowing arrangements.

Intercompany Promissory Notes

In November 2004, Genco made a $75 million principal prepayment under its note payable to CIPS. The note

 

83

payable to CIPS was issued in conjunction with the transfer of CIPS’ electric generating assets and related liabilities to Genco. On May 1, 2005, Genco and CIPS amended the maturity date and interest rate of the subordinated note payable to CIPS by Genco issuing to CIPS an amended and restated subordinated promissory note in the principal amount of $249 million with an interest rate of 7.125% a year, a 5-year amortization schedule, and a maturity date of May 1, 2010. Interest income and expense for this note recorded by CIPS and Genco, respectively, was $15 million, $23 million, and $27 million for the years ended December 31, 2005, 2004, and 2003, respectively.

Also on May 1, 2005, the remaining principal balance under Genco’s note payable to Ameren of $34 million was repaid. Genco recorded interest expense of $1 million, $2 million, and $3 million from this note payable to Ameren for the years ended December 31, 2005, 2004, and 2003, respectively.

On May 2, 2005, CIPS issued to UE a subordinated promissory note in the principal amount of $67 million as consideration for 50% of UE’s Illinois-based utility assets transferred to CIPS on that date. The note bears interest at 4.70% a year and has a 5-year amortization schedule and a maturity date of May 2, 2010. UE and CIPS recorded interest income and expense, respectively, of $2 million for the year ended December 31, 2005. See Note 3 – Rate and Regulatory Matters for a discussion of this intercompany transfer.

CILCORP has been granted authority by the SEC under PUHCA 1935 to borrow up to $250 million directly from Ameren. The outstanding borrowings were $186 million and $72 million at December 31, 2005 and 2004, respectively. The average interest rate on these borrowings was 5.48% for the year ended December 31, 2005 (2004 – 8.84%). CILCORP recorded interest expense of $6 million, $5 million, and $1 million for these borrowings for the years ended December 31, 2005, 2004, and 2003, respectively.

 

Operating Leases

Under an operating lease agreement, Genco is leasing certain CTs at a Joppa, Illinois, site to its parent, Development Company, for a minimum term of 15 years, expiring September 30, 2015. Genco recorded operating revenues from the lease agreement of $10 million for each of the three years ended December 31, 2005, 2004, and 2003. Under an electric power supply agreement with Marketing Company, Development Company supplies the capacity and energy from these leased units to Marketing Company, which in turn supplies the energy to Genco.

In September 1999, IP entered into an operating lease on four gas turbines located in Tilton, Illinois, and a separate land lease at the Tilton site. IP sublet the turbines to its former affiliate, DMG, in October 1999. In July 2004, subsequent to the expiration of a statutory notice period after a filing at the ICC, IP terminated its lease with the original lessor. DMG then executed a transfer agreement under which the original lessor sold the turbine assets to DMG for the full contract price of $81 million. Additionally, IP assigned its associated land lease on the Tilton site to DMG. For IP, the Tilton lease was a complete pass-through, with no revenue or expense to IP, as DMG made all of the payments on IP’s behalf. The receivable from DMG was offset by a corresponding payable to the lessor.

 

84

The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the years ended December 31, 2005, 2004 and 2003. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 5—Short-term Borrowings and Liquidity.

 

Agreement   Financial Statement Line Item         UE      CIPS      Genco      CILCORP(a)      IP(b)  

Operating Revenues:

                   

Power supply agreement with Marketing Company

   Operating Revenues   2005    $ (c )    $ 36      $ 793      $ 24      $ (c )
    2004      (c )      34        693        45        (c )
        2003      (c )      29        632        5        (c )

Power supply agreement with EEI

   Operating Revenues   2005      1        (c )      1        (c )      (c )
    2004      7        (c )      3        (c )      (c )
        2003      6        (c )      4        (c )      (c )

UE and Genco gas transportation agreement

   Operating Revenues   2005      1        (c )      (c )      (c )      (c )
    2004      1        (c )      (c )      (c )      (c )
        2003      1        (c )      (c )      (c )      (c )

Joint dispatch agreement

   Operating Revenues   2005      215        (c )      74        (c )      (c )
    2004      117        (c )      46        (c )      (c )
        2003      112        (c )      40        (c )      (c )

Total Operating Revenues

     2005    $ 217      $ 36      $ 868      $ 24      $ (c )
    2004      125        34        742        45        (c )
        2003      119        29        676        5        (c )

Fuel and Purchased Power:

                   

Joint dispatch agreement

   Fuel and Purchased   2005    $ 74      $ (c )    $ 215      $ (c )    $ (c )
  Power   2004      46        (c )      117        (c )      (c )
        2003      40        (c )      112        (c )      (c )

Power supply agreement with Marketing Company

   Fuel and Purchased   2005      4        401        4        11        (c )
  Power   2004      9        291        (d )      10        (c )
        2003      9        312        2        1        (c )

Power supply agreement with EEI

   Fuel and Purchased   2005      65        36        (c )      (c )      46  
  Power   2004      68        34        (c )      (c )      3  
        2003      58        29        (c )      (c )      (c )

Executory tolling agreement with Medina Valley

   Fuel and Purchased   2005      (c )      (c )      (c )      37        (c )
  Power   2004      (c )      (c )      (c )      30        (c )
        2003      (c )      (c )      (c )      26        (c )

UE and Genco gas transportation agreement

   Fuel and Purchased   2005      (c )      (c )      1        (c )      (c )
  Power   2004      (c )      (c )      1        (c )      (c )
        2003      (c )      (c )      1        (c )      (c )

Total Fuel and Purchased Power

     2005    $ 143      $ 437      $ 220      $ 48      $ 46  
    2004      123        325        118        40        3  
        2003      107        341        115        27        (c )

Other Operating Expense:

                   

Ameren Services support services agreement

   Other Operating   2005    $ 153      $ 42      $ 20      $ 41      $ 64  
  Expenses   2004      158        48        18        54        (c )
        2003      165        54        18        15        (c )

Ameren Energy support services agreement

  Other Operating   2005      5        (c )      3        (c )      (c )
  Expenses   2004      2        (c )      2        (c )      (c )
        2003      22        (c )      11        (c )      (c )

AFS support services agreement

   Other Operating   2005      4        1        2        2        2  
  Expenses   2004      4        1        2        2        (c )
        2003      6        1        2        2        (c )

Total Other Operating Expenses

     2005    $ 162      $ 43      $ 25      $ 43      $ 66  
    2004      164        49        22        56        (c )
        2003      193        55        31        17        (c )

Money pool borrowings (advances)

   Interest (Expense)   2005    $ 4      $ (1 )    $ 3      $ 4      $ (3 )
  Income   2004      3        (d )      12        5        (1 )
        2003      2        (d )      15        (d )      (c )

 

(a) Amounts represent CILCORP and CILCO activity, except as follows: CILCORP 2003 includes January 2003 predecessor amount of $3 million for purchased power from Medina Valley; and CILCORP has $12 million of operating revenues from Medina Valley in 2003, of which $2 million is predecessor activity.
(b) Includes Ameren affiliate transactions subsequent to acquisition date of September 30, 2004.
(c) Not applicable.
(d) Amount less than $1 million.

 

85

Predecessor IP

The following table presents the impact of related party transactions on predecessor IP’s Consolidated Statement of Income for the nine-month period ended September 30, 2004, and the year ended December 31, 2003, based primarily on the various predecessor agreements discussed above:

 

Consolidated Statement of Income     

Nine Months Ended

September 30, 2004

      2003  

Operating revenues with former affiliates:

        

Retail electricity sales to DMG

      $ 1      $ 3  

Retail natural gas sales DMG

        5        9  

Transmission sales to DYPM

        10        14  

Interconnection transmission with DYPM

        3        2  

Interest income from former affiliates

        128        170  

Total operating revenues with former affiliates

      $ 147      $ 198  

Fuel and purchased power expenses:

        

Power supply from DMG

      $ 346      $ 472  

Gas purchased from Dynegy

        6        50  

Total fuel and purchase power expenses

      $ 352      $ 522  

Other operating expenses:

        

Services and facilities agreement – Dynegy

      $ 11      $ 16  

Interest expense (income):

        

Interest expense for IP SPT

      $ 17      $ -  

Interest expense on Tilton lease

        8        4  

Interest income on Tilton lease

        (8 )      (4 )

NOTE 15 – COMMITMENTS AND CONTINGENCIES

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

Capital Expenditures

See Note 3 – Rate and Regulatory Matters for information regarding Ameren’s capital expenditure commitment with respect to IP, which was included in the ICC order approving Ameren’s acquisition of IP; Ameren’s and UE’s capital expenditure commitments, which were agreed upon in relation to UE’s 2002 Missouri electric rate case settlement and UE’s 2003 Missouri gas rate case settlement; and information on UE’s pending purchases of CT generating facilities with about 1,490 megawatts of capacity.

Callaway Nuclear Plant

The following table presents insurance coverage at UE’s Callaway nuclear plant at December 31, 2005. This coverage was renewed on October 1, 2005:

 

Type and Source of Coverage    Maximum Coverages     Maximum Assessments for Single Incidents  

Public liability:

     

American Nuclear Insurers

    $ 300     $ -  

Pool participation

      10,461       101 (a)
                
   $ 10,761 (b)   $ 101  

Nuclear worker liability:

     

American Nuclear Insurers

    $ 300 (c)   $ 4  

Property damage:

     

Nuclear Electric Insurance Ltd.

    $ 2,750 (d)   $ 21  

Replacement power:

     

Nuclear Electric Insurance Ltd.

    $ 490 (e)   $ 7  

 

(a) Retrospective premium under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. This is subject to retrospective assessment with respect to a covered loss in excess of $300 million from an incident at any licensed U.S. commercial reactor, payable at $15 million per year. Renewal of Price-Anderson was part of the Energy Policy Act of 2005.

 

86

(b) Limit of liability for each incident under Price-Anderson.
(c) Industry limit for potential liability from workers claiming exposure to the hazards of nuclear radiation.
(d) Includes premature decommissioning costs.
(e) Weekly indemnity of $4.5 million for 52 weeks, which commences after the first eight weeks of an outage, plus $3.6 million per week for 71.1 weeks thereafter.

Price-Anderson limits the liability for claims from an incident involving any licensed United States nuclear facility. The limit is based on the number of licensed reactors and is adjusted at least every five years to reflect changes in the Consumer Price Index. Utilities owning a nuclear reactor cover this exposure through a combination of private insurance and mandatory participation in a financial protection pool, as established by Price-Anderson.

If losses from a nuclear incident at the Callaway nuclear plant exceed the limits of, or are not subject to, insurance, or if coverage is unavailable, UE self-insures the risk. If a serious nuclear incident occurred, it could have a material but indeterminable adverse effect on our results of operations, financial position, or liquidity.

Leases

The following table presents our lease obligations at December 31, 2005:

 

        Total      Less than 1 Year      1 – 3 Years      3 – 5 Years      After 5 Years

Ameren:(a)

                         

Capital leases(b)

     $ 93      $ 3      $ 8      $ 9      $ 73

Operating leases(c)

       265        29        45        39        152

Total lease obligations

      $ 358      $ 32      $ 53      $ 48      $ 225

UE:

                         

Capital leases(b)

     $ 93      $ 3      $ 8      $ 9      $ 73

Operating leases(c)

       122        10        19        18        75

Total lease obligations

      $ 215      $ 13      $ 27      $ 27      $ 148

CIPS:

                         

Operating leases(c)

     $ 2      $ -      $ 1      $ 1      $ -

Genco:

                         

Operating leases(c)

     $ 86      $ 5      $ 9      $ 9      $ 63

CILCORP:

                         

Operating leases(c)

     $ 21      $ 1      $ 3      $ 2      $ 15

CILCO:

                         

Operating leases(c)

     $ 21      $ 1      $ 3      $ 2      $ 15

IP:

                         

Operating leases

      $ 18      $ 5      $ 7      $ 6      $ -

 

(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) See Note 6 – Long-term Debt and Equity Financings for further discussion.
(c) Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. The amounts for these items are included in the Less than 1 Year, 1 – 3 Years, and 3 – 5 Years columns. Amounts for after 5 years are not included in the total amount because the period is indefinite. Ameren’s estimated obligation for after 5 years is $1 million annually for both the real estate leases and the railroad licenses.

We lease various facilities, office equipment, plant equipment, and rail cars under operating leases. We also have a capital lease relating to UE’s Peno Creek CT facility. In addition, subject to the receipt of regulatory agency authorizations, UE has an asset purchase and sale agreement with NRG for the purchase of a 640-megawatt CT facility which also includes a capital lease. See Note 3 – Rate and Regulatory Matters for additional information on this pending transaction. The following table presents total rental expense, included in Other Operations and Maintenance expenses, for the periods ending December 31, 2005, 2004 and 2003:

 

        2005      2004      2003

Ameren(a)

     $ 20      $ 21      $ 61

UE

        18        25        59

CIPS

        6        8        9

Genco

        2        2        2

CILCORP(b)

       4        5        5

CILCO

        4        5        5

IP(c)

       8        5        6

 

(a) Excludes amounts for IP before the acquisition date of September 30, 2004; excludes amounts for CILCORP and CILCO before the acquisition date of January 31, 2003; and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

 

87

(b) January 2003 predecessor amount was less than $1 million.
(c) 2003 amount represents predecessor information. January through September 2004 predecessor amount was $4 million.

Other Obligations

To supply a portion of the fuel requirements of our generating plants, we have entered into various long-term commitments for the procurement of coal, natural gas, and nuclear fuel. In addition, we have entered into various long-term commitments for the purchase of electricity and natural gas for distribution. The following table presents the total estimated fuel, power purchase, and natural gas commitments at December 31, 2005:

 

        Coal      Gas      Nuclear      Electric Capacity(a)      Total

Ameren:(b)

                         

2006

      $ 601      $ 585      $ 32      $ 165      $ 1,383

2007

        511        330        17        22        880

2008

        515        233        10        22        780

2009

        383        106        9        13        511

2010

        220        33        2        -        255

Thereafter(c)

       77        32        -        -        109

Total

      $ 2,307      $ 1,319      $ 70      $ 222      $ 3,918

UE:

                         

2006

      $ 348      $ 66      $ 32      $ 22      $ 468

2007

        300        45        17        22        384

2008

        263        24        10        22        319

2009

        207        11        9        13        240

2010

        150        6        2        -        158

Thereafter(b)

       77        7        -        -        84

Total

      $ 1,345      $ 159      $ 70      $ 79      $ 1,653

CIPS:

                         

2006

      $ -      $ 95      $ -      $ 122      $ 217

2007

        -        64        -        -        64

2008

        -        58        -        -        58

2009

        -        34        -        -        34

2010

        -        10        -        -        10

Thereafter(c)

       -        1        -        -        1

Total

      $ -      $ 262      $ -      $ 122      $ 384

Genco:

                         

2006

      $ 117      $ 24      $ -      $ -      $ 141

2007

        91        26        -        -        117

2008

        144        20        -        -        164

2009

        123        8        -        -        131

2010

        38        8        -        -        46

Thereafter(c)

       -        12        -        -        12

Total

      $ 513      $ 98      $ -      $ -      $ 611

CILCORP and CILCO:

                         

2006

      $ 59      $ 194      $ -      $ 89      $ 342

2007

        43        105        -        4        152

2008

        37        69        -        4        110

2009

        25        40        -        4        69

2010

        16        4        -        4        24

Thereafter(c)

       -        -        -        -        -

Total

      $ 180      $ 412      $ -      $ 105      $ 697

IP:

                         

2006

      $ -      $ 195      $ -      $ 142      $ 337

2007

        -        90        -        -        90

2008

        -        61        -        -        61

2009

        -        12        -        -        12

2010

        -        4        -        -        4

Thereafter(c)

       -        11        -        -        11

Total

      $ -      $ 373      $ -      $ 142      $ 515

 

(a) Beginning in 2007, CIPS, CILCO and IP expect to purchase all electric capacity and energy through a power procurement auction approved by the ICC. See Note 3 – Rate and Regulatory Matters for a discussion of this matter.
(b) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(c) Commitments for coal, natural gas, nuclear fuel and the purchase of electricity are until 2011, 2016, 2010 and 2010, respectively.

 

88

Other obligations also include decontamination and decommissioning charges associated with IP’s use of a DOE facility that enriched uranium for its former Clinton nuclear plant. IP was assessed an amount to be paid over 15 years that would be used by the DOE for decontamination and decommissioning of its facility. The remaining obligation is $1 million and the final payment is due in 2006.

Environmental Matters

We are subject to various environmental laws and regulations by federal, state and local authorities. From the beginning phases of siting and development to the ongoing operation of existing or new electric generating, transmission and distribution facilities, and natural gas storage plants, transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise, emissions, and impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological and historical resources), and chemical and waste handling. Our activities often require complex and lengthy processes as we obtain approvals, permits or licenses for new, existing or modified facilities. Additionally, the use and handling of various chemicals or hazardous materials (including wastes) requires preparation of release prevention plans and emergency response procedures. As new laws or regulations are promulgated, we assess their applicability and implement the necessary modifications to our facilities or our operations, as required. The more significant matters are discussed below.

Clean Air Act

In May 2005, the EPA issued final regulations with respect to SO2 and NOx emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule) from coal-fired power plants. The new rules will require significant additional reductions in these emissions from UE, Genco, CILCO and EEI power plants in phases, beginning in 2009. States are required to finalize rules to implement the federal Clean Air Interstate Rule and Clean Air Mercury Rule by September and November 2006, respectively. While the federal rules mandate a specific emissions cap for SO2, NOx, and mercury emissions by state from utility boilers, the states have considerable flexibility in allocating emission allowances to individual utility boilers. In addition, a state may choose to hold back certain emission allowances for growth or other reasons, and it may implement a more stringent program than the federal program. Illinois and Missouri are developing proposed rules that will be subjected to public review and comment. We do not expect the state regulations to be finalized until late 2006. In January 2006, the Illinois governor recommended that the Illinois EPA adopt rules for mercury significantly stricter than the federal rules. The process by which state rules will be drafted and determined is still in its early stages, but should stricter rules be adopted, they would change the overall environmental compliance strategy for UE’s, Genco’s, CILCO’s and EEI’s coal-fired power plants and increase related costs from previous estimates. An implementation plan from Missouri regulators is still under review and consideration. The table below presents preliminary estimated capital costs based on current technology to comply with the federal Clean Air Interstate Rule and Clean Air Mercury Rule. The timing of estimated capital costs between periods at UE will be influenced by whether excess emission credits are used to comply with the proposed rules, thereby deferring capital investment.

 

     2006   2007 – 2010   2011 – 2016   Total

Ameren

   $ 75   $ 1,020 – $1,405   $ 1,015 – $1,400   $ 2,110 – $2,880

UE

     60     365 –      505     750 –   1,040     1,175 –   1,605

Genco

     10     430 –      595     10 –        20     450 –      625

CILCO

     5     175 –      245     145 –      200     325 –      450

EEI

     5     55 –        75     130 –      180     190 –      260

The costs reflected in the table assume that each Ameren generating unit will be allocated allowances based on the model “cap and trade” rule guidelines issued by the EPA. Should either Missouri or Illinois develop alternative allowance allocations for utility units, the cost impact could be material. At this time, we are unable to determine the impact such a state decision would have on our results of operations, financial position, or liquidity.

Emission Credits

Both federal and state laws require significant reductions in SO2 and NOx emissions that result from burning fossil fuels. The Clean Air Act and NOx Budget Trading Program created marketable commodities called allowances. Each allowance gives the owner the right to emit one ton of SO2 or NOx. All existing generating facilities have been allocated allowances that are based on past production and the statutory emission reduction goals. If additional allowances are needed for new generating facilities, they can be purchased from facilities that have excess allowances or from allowance banks. Our generating facilities comply with the SO2 limits through the use and purchase of allowances, through the use of low-sulfur fuels, and through the application of pollution control technology. The NOx Budget Trading Program limits emissions of NOx during the ozone season (May through September). The NOx Budget Trading Program applies to all electric generating units in Illinois beginning in 2004; it applies to the eastern third of Missouri, where UE’s coal-fired power plants are located, beginning in 2007. Our generating facilities are expected to comply with the NOx limits through the use and purchase of allowances or through the application of pollution control technology,

 

89

including low-NOx burners, over-fire air systems, combustion optimization, rich reagent injection, selective noncatalytic reduction and selective catalytic reduction systems.

As of December 31, 2005, UE, Genco, CILCO and EEI held 1.92 million, 0.70 million, 0.34 million and 0.37 million tons, respectively, of SO2 emission allowances, with vintages from 2005 to 2016. Each company possesses additional allowances for use in periods beyond 2016. As of December 31, 2005, UE, Genco, CILCO, and EEI Illinois facilities held 272 tons, 11,977 tons, 2,178 tons, and 2,859 tons, respectively, of NOX emission allowances, with vintages from 2005 to 2008. As of December 31, 2005, the SO2 and NOx emission allowances for UE, Genco, CILCO and EEI were carried in inventory at a book value of $62 million, $79 million, $58 million and $42 million, respectively. The Illinois EPA has not yet issued any NOx emission allowance allocations for 2007 and 2008. UE, Genco, CILCO and EEI expect to use a substantial portion of the SO2 and NOx allowances for ongoing operations. Allocations of NOx allowances for Missouri facilities will be 10,178 tons per season in 2007 and 2008 according to rules finalized in May 2005. New environmental regulations, including the Clean Air Interstate Rule, the timing of the installation of pollution control equipment and the level of operations will have a significant impact on the amount of allowances actually required for ongoing operations. The Clean Air Interstate Rule requires a reduction in SO2 emissions by requiring a change in the way Acid Rain Program allowances are surrendered. The current Acid Rain Program requires the surrender of one SO2 allowance for every ton of SO2 that is emitted. The CAIR program will require that SO2 allowances be surrendered at a ratio of 2 allowances for every ton of emission in 2010 through 2014. Beginning in 2015, SO2 allowances will be surrendered at a ration of 2.86 allowances for every ton of emission.

Multipollutant Legislation

The U.S. Congress has been working on legislation to consolidate the numerous air pollution regulations facing the utility industry. Continued deliberation on this “Clear Skies” legislation is expected in 2006. Our cost to comply with such legislation, if enacted, is expected to be covered by the modifications to our facilities as required by the combined Clean Air Interstate Rule and Clean Air Mercury Rule described above.

Global Climate

Future initiatives regarding greenhouse gas emissions and global warming are the subjects of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies. Coal-fired power plants are significant sources of carbon dioxide, a principal greenhouse gas. The related Kyoto Protocol was signed by the United States, but it has since been rejected by the president, who instead has asked for an 18% voluntary decrease in carbon intensity. In response to the administration’s request, 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 from the utility sector between 2002 and 2012. Currently, Ameren is considering various initiatives to comply with the MOU, including enhanced generation at our nuclear and hydroelectric power plants, increased efficiency measures at our coal-fired units, and investments in renewable energy and carbon sequestration projects.

Ameren has already taken actions to address the global climate issue. These include implementing efficiency improvements at our power plants; participating in the PowerTree Carbon Company, LLC, whose purpose is to reforest acreage in the lower Mississippi valley to sequester carbon; using coal combustion by-products as a direct replacement for cement, thereby reducing carbon emissions at cement kilns; participating in “Missouri Schools Going Solar,” a project that will install photovoltaic solar arrays on school grounds; and partnering with other utilities, the Electric Power Research Institute, and the Illinois State Geological Survey in the DOE Illinois Basin Initiative, which will examine the feasibility and methods of storing carbon dioxide within deep unused coal seams, mature oil fields, and saline reservoirs.

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

Clean Water Act

In July 2004, the EPA issued rules under the Clean Water Act that require cooling-water intake structures to have the best technology available for minimizing adverse environmental impacts. These rules pertain to existing generating facilities that currently employ a cooling-water intake structure whose flow exceeds 50 million gallons per day. The rules may require us to install additional intake screens or other protective measures and to do extensive site-specific study and monitoring. There is also the possibility that the rules may lead to the installation of cooling towers on some of our facilities. We estimate our compliance costs associated with conducting field studies and installing

 

90

fish collection systems to determine the aquatic impact of our intake structures to be approximately $3 million to $4 million dollars over the next three to four years. These studies will determine what, if any, additional technology must be applied at nine of our existing power plants. At this time, we are unable to estimate the costs of complying with these rules. Such costs are not expected to be incurred prior to 2008.

New Source Review

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

In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act seeking detailed operating and maintenance history data with respect to its Meredosia, Hutsonville, Coffeen and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. All of these facilities are coal-fired power plants. The information request required Genco to provide responses to specific EPA questions regarding certain projects and maintenance activities to determine compliance with certain Illinois air pollution and emissions rules and with the New Source Performance Standard requirements of the Clean Air Act. This information request is being complied with, but we cannot predict the outcome of this matter.

Remediation

We are involved in a number of remediation actions to clean up hazardous waste sites as required by federal and state law. Such statutes require that responsible parties fund remediation actions regardless of degree of fault, legality of original disposal, or ownership of a disposal site. UE, CIPS, CILCO and IP have each been identified by the federal or state governments as a potentially responsible party at several contaminated sites. Several of these sites involve facilities that were transferred by CIPS to Genco in May 2000 and were transferred by CILCO to AERG in October 2003. As part of each transfer, CIPS or CILCO has contractually agreed to indemnify Genco or AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of December 31, 2005, CIPS, CILCO and IP owned or were otherwise responsible for 14, four and 25 former MGP sites, respectively, in Illinois. All of these sites are in various stages of investigation, evaluation and remediation. Under its current schedule, Ameren anticipates that remediation at these sites should be completed by 2015. The ICC permits each company to recover remediation and litigation costs associated with their former MGP sites in Illinois from their Illinois electric and natural gas utility customers through environmental adjustment rate riders. To be recoverable, such costs must be prudently and properly incurred, and costs are subject to annual reconciliation review by the ICC. As of December 31, 2005, CIPS, CILCO and IP had recorded liabilities of $24 million, $4 million and $62 million, respectively, to represent estimated minimum obligations. On May 2, 2005, as a part of its Illinois utility service territory transfer, UE transferred its one Illinois-based former MGP site to CIPS. In connection with the transfer, CIPS succeeded to UE’s ICC-approved environmental adjustment rate rider, which permits CIPS to recover remediation and litigation costs associated with UE’s former MGP site from UE’s transferred Illinois electric and natural gas utility customers. For a discussion of the Illinois utility service territory transfer, see Note 3 – Rate and Regulatory Matters in this report.

In addition, UE owns or is otherwise responsible for 10 MGP sites in Missouri and one in Iowa. UE does not currently have in effect in Missouri a rate rider mechanism that permits remediation costs associated with MGP sites to be recovered from utility customers. See Note 3 – Rate and Regulatory Matters for information on a recently enacted law in Missouri enabling the MoPSC to put in place environmental cost recovery mechanisms for Missouri utilities. UE does not have any retail utility operations in Iowa which would provide a source of recovery of these remediation costs. Because of the unknown and unique characteristics of each site (such as amount and type of residues present, physical characteristics of the site, and the environmental risk) and uncertain regulatory requirements, we are not able to determine the maximum liability for the remediation of these sites. As of December 31, 2005, UE had recorded $10 million to represent its estimated minimum obligation of its MGP sites. UE also is responsible for four electric sites in Missouri that have corporate cleanup liability, most as a result of federal agency mandates. As of December 31, 2005, UE had recorded $5 million to represent its estimated minimum obligation for these sites. At this time, we are unable to determine what portion of these costs, if any, will be eligible for recovery from insurance carriers.

In June 2000, the EPA notified UE and numerous other companies that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From approximately 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2. UE currently owns a parcel of property that was used as a landfill. Under

 

91

the terms of an Administrative Order and Consent, UE has joined with other potentially responsible parties to evaluate the extent of potential contamination with respect to Sauget Area 2.

In October 2002, UE was included in a Unilateral Administrative Order issued by the EPA listing potentially liable parties for groundwater contamination for a portion of the Sauget Area 2 site. The Unilateral Administrative Order encompasses the groundwater contamination releasing to the Mississippi River adjacent to Solutia’s former chemical waste landfill and the resulting impact area in the Mississippi River. UE was asked to participate in response activities that involve the installation of a barrier wall around a chemical waste site and three recovery wells to divert groundwater flow. The projected cost for this remedy method ranges from $25 million to $30 million. In November 2002, UE sent a letter to the EPA asserting its defenses to the Unilateral Administrative Order and requesting its removal from the list of potentially responsible parties under the Unilateral Administrative Order. Solutia agreed to comply with the Unilateral Administrative Order. However, in December 2003, Solutia filed for bankruptcy protection; it is now seeking to discharge its environmental liabilities. In March 2004, Pharmacia Corporation, the former parent company of Solutia, confirmed its intent to comply with the EPA’s Unilateral Administrative Order.

The status of future remediation at Sauget Area 2 and compliance with the Unilateral Administrative Order is uncertain, so we are unable to predict the ultimate impact of the Sauget Area 2 site on our results of operations, financial position, or liquidity. In December 2004, the U.S. Supreme Court, in Cooper Industries, Inc., vs. Aviall Services, Inc., limited the circumstances under which potentially responsible parties could assert cost-recovery claims against other potentially responsible parties. As a result of this ruling, it is possible that UE may not be able to recover from other potentially responsible parties the costs it incurs in complying with EPA orders. Any liability or responsibility that may be imposed on UE as a result of this Sauget, Illinois, environmental matter was not transferred to CIPS as a part of UE’s May 2005 Illinois utility service territory transfer discussed above and in Note 3 – Rate and Regulatory Matters.

In December 2004, AERG submitted a comprehensive package to the Illinois EPA to address groundwater and surface water issues associated with the recycle pond, ash ponds, and reservoir at the Duck Creek power plant facility. Information submitted by AERG is currently under review by the Illinois EPA. CILCORP and CILCO both have a liability of $3 million at December 31, 2005, included on their Consolidated Balance Sheets for the estimated cost of the remediation effort, which involves treating and discharging recycle-system water in order to address these groundwater and surface water issues.

 

In addition, our operations, or those of our predecessor companies, involve the use, disposal and, in appropriate circumstances, the cleanup of substances regulated under environmental protection laws. We are unable to determine the impact these actions may have on our results of operations, financial position, or liquidity.

Pumped-storage Hydroelectric Facility Breach

In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. UE has hired outside experts to review the cause of the incident. Additionally, the incident is being investigated by FERC and state authorities. UE expects the results of these reviews later in 2006. The facility will remain out of service until these reviews are concluded, further analyses are completed, and input is received from key stakeholders as to how and whether to rebuild the facility.

UE has accepted responsibility for the incident. At this time, 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 experts hired by UE and state and federal authorities have concluded, the insurance review is completed, and future regulatory treatment for the plant is determined, among other things, we are unable to determine the entire impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity.

Waste Disposal

In July 2002, the Illinois Attorney General’s Office advised us that it would be commencing an enforcement action concerning an inactive waste disposal site near Coffeen, Illinois. This is the location of a disposal facility that is permitted by the Illinois EPA to receive fly ash from Genco’s Coffeen power plant. The Illinois attorney general also notified the disposal facility’s current and former owners about the proposed enforcement action. The Attorney General’s Office advised us that it may initiate an action under CERCLA (Superfund) to recover past costs incurred at the site ($0.3 million) and to obtain a declaratory judgment as to liability for future costs. Neither Genco, the current owner of the Coffeen power plant, nor CIPS, the prior owner of the Coffeen power plant, owned or operated the disposal facility. We do not expect that this matter will have a material adverse effect on Ameren’s, CIPS’ or Genco’s results of operations, financial position, or liquidity.

Sustainable Energy Plan

In July 2005, the ICC entered a resolution affirming the Illinois governor’s Sustainable Energy Plan as well as an ICC

 

92

staff report dated July 7, 2005. CIPS, CILCO and IP were requested to file documentation explaining how they intend to implement the plan. The Ameren Illinois utilities continue to give consideration to this plan. The plan calls for, among other things, a renewable portfolio standard whereby 2% of the bundled retail load will be supplied by renewable energy resources in 2007, 3% in 2008, 4% in 2009, 5% in 2010, 6% in 2011, 7% in 2012 and 8% in 2013; and an energy efficiency portfolio standard whereby there will be a 10% reduction in projected annual load growth by 2007-2008, 15% by 2009-2011, 20% by 2012-2014, and 25% by 2015-2017.

Asbestos-related Litigation

Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case is significant; as many as 166 parties are named in some pending cases and as few as five in others. However, in the cases that were pending as of December 31, 2005, the average number of parties is 65.

The claims filed against Ameren, UE, CIPS, Genco, CILCO and IP allege injury from asbestos exposure during the plaintiffs’ activities at our present or former electric generating plants. Former CIPS plants are now owned by Genco, and most former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a Dynegy subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS or CILCO has contractually agreed to indemnify Genco or AERG for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages in excess of $50,000, which, if proved, typically would be shared among the named defendants.

 

From October 1, 2005, through December 31, 2005, 11 additional asbestos-related lawsuits were filed against UE, CIPS, CILCO and IP, mostly in the Circuit Court of Madison County, Illinois. Two lawsuits were dismissed and three were settled. The following table presents the status as of December 31, 2005, of the asbestos-related lawsuits that have been filed against the Ameren Companies:

 

                Specifically Named as Defendant
        Total(a)          Ameren      UE      CIPS      Genco      CILCO      IP

Filed

      296          29      157      116      2      30      137

Settled

      90          -      48      37      -      8      44

Dismissed

      137          21      90      44      2      4      61

Pending

      69          8      19      35      -      18      32

 

(a) Addition of the numbers in the individual columns does not equal the total column because some of the lawsuits name multiple Ameren entities as defendants.

 

In January 2005, UE filed suit in the Circuit Court of Madison County, Illinois, alleging that four of its historic liability insurers have failed to pay more than $2 million in fees and costs relating to the defense and investigation of more than 120 asbestos lawsuits filed against UE. The defendant insurers are American Automobile Insurance Co., Pacific Insurance Co., Royal Insurance Co. of America, and Royal Indemnity Co. These insurers insured UE from the late 1940s through the early 1970s for liability arising out of the work of independent contractors working at UE’s facilities. We are unable to predict the outcome of this lawsuit.

As of December 31, 2005, four asbestos-related lawsuits were pending against EEI. The general liability insurance maintained by EEI provides coverage with respect to liabilities arising from asbestos-related claims.

The ICC order approving Ameren’s acquisition of IP effective September 30, 2004, also approved a tariff rider to recover the costs of asbestos-related litigation claims, subject to the following terms. Beginning in 2007, 90% of cash expenditures in excess of the amount included in base electric rates will 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.

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

Other Matters

Retiree Medical Plan Litigation

In June 2003, 20 retirees and surviving spouses of retirees of various Ameren companies (the plaintiffs) filed a complaint in the U.S. District Court, Southern District of Illinois, against Ameren, UE, CIPS, Genco and Ameren

 

93

Services, and against our Retiree Medical Plan, and by an amended complaint, against our Group Medical Plan (the defendants). The retirees were members of various local labor unions of the IBEW and the IUOE. The complaint, referred to as Barnett et al. vs. Ameren Corporation, et al., alleged, among other things, that the defendants’ recent actions requiring retirees to pay a portion of their own health care premiums or increasing the premiums paid by dependents or surviving spouses of retirees violate ERISA and Labor Management Relations Act of 1947 and constitute a breach of the defendants’ fiduciary duties.

In July 2004, the district court denied the plaintiffs’ motion to certify this lawsuit as a class action. In September 2004, the U.S. Seventh Circuit Court of Appeals denied the plaintiffs’ application to appeal the district court’s decision. In January 2005, the district court granted the defendants’ motion for summary judgment, which dismissed the plaintiffs’ complaint with prejudice. In February 2005, the plaintiffs filed a notice of appeal of the district court’s ruling with the U.S. Seventh Circuit Court of Appeals. On February 8, 2006, the Court of Appeals affirmed the district court’s granting of summary judgment in favor of the defendants. This decision is subject to further appeal. We do not believe that the final resolution of this matter will have a material adverse effect on our results of operations, financial position, or liquidity.

Regulation

Regulatory changes enacted and being considered at the federal and state levels continue to change the structure of the utility industry and utility regulation, as well as to encourage increased competition. At this time, we are unable to predict the impact of these changes on our future results of operations, financial position, or liquidity. See Note 3 – Rate and Regulatory Matters for further information.

NOTE 16 – CALLAWAY NUCLEAR PLANT

Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the permanent storage and disposal of spent nuclear fuel. The DOE currently charges one mill, or  1/10 of one cent, per nuclear-generated kilowatthour sold for future disposal of spent fuel. Pursuant to this act, UE collects one mill from its electric customers for each kilowatthour of electricity that it generates and sells from its Callaway nuclear plant. Electric utility rates charged to customers provide for recovery of such costs. The DOE is not expected to have its permanent storage facility for spent fuel available until at least 2015. UE has sufficient installed storage capacity at its Callaway nuclear plant until 2020. It has the capability for additional storage capacity through the licensed life of the plant. The delayed availability of the DOE’s disposal facility is not expected to adversely affect the continued operation of the Callaway nuclear plant through its currently licensed life.

 

Electric utility rates charged to customers provide for the recovery of the Callaway nuclear plant’s decommissioning costs, which include decontamination, dismantling, and site restoration costs, over an assumed 40-year life of the plant, ending with the expiration of the plant’s operating license in 2024. It is assumed that the Callaway nuclear plant site will be decommissioned based on immediate dismantlement method and removal from service. Ameren and UE have recorded an ARO for the Callaway nuclear plant decommissioning costs at fair value, which represents the present value of estimated future cash outflows. See the discussion of AROs in Note 1 – Summary of Significant Accounting Policies. Decommissioning costs are charged to the costs of service used to establish electric rates for UE’s customers. These costs amounted to $7 million in each of the years 2005, 2004 and 2003. Every three years, the MoPSC requires UE to file an updated cost study for decommissioning its Callaway nuclear plant. Electric rates may be adjusted at such times to reflect changed estimates. An updated cost study for decommissioning UE’s Callaway nuclear plant was filed in August 2005. With the results of this updated cost study and associated financial analysis, UE has determined that the current deposits to the trust fund are appropriate and do not need to be changed. The MoPSC has reviewed the updated cost study and UE’s application, and it has ordered UE to keep the current deposits to the trust fund unchanged. Also as a result of the cost study, the ARO for the Callaway nuclear plant decommissioning costs was revised. Costs collected from customers are deposited in an external trust fund to provide for the Callaway nuclear plant’s decommissioning. If the assumed return on trust assets is not earned, we believe that it is probable that any such earnings deficiency will be recovered in rates. The fair value of the nuclear decommissioning trust fund for UE’s Callaway nuclear plant is reported in Nuclear Decommissioning Trust Fund in Ameren’s and UE’s Consolidated Balance Sheets. This amount is legally restricted. It may be used only to fund the costs of nuclear decommissioning. Changes in the fair value of the trust fund are recorded as an increase or decrease to the nuclear decommissioning trust fund and to the regulatory asset recorded in connection with the adoption of SFAS No. 143. In connection with UE’s transfer of its Illinois service territory to CIPS on May 2, 2005, the Illinois jurisdictional assets of the decommissioning trust fund were transferred to the Missouri and FERC jurisdictions. The decommissioning liability formerly borne by the Illinois jurisdiction was assumed by the Missouri and FERC jurisdictions subsequent to the transfer. See Note 3 – Rate and Regulatory Matters for further information about this intercompany transfer.

 

94

NOTE 17 – FAIR VALUE OF FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which such estimates are practicable to estimate that value:

Cash, Temporary Investments and Short-term Borrowings

The carrying amounts approximate fair value because of the short-term maturity of these instruments.

Marketable Securities

The fair value is based on quoted market prices obtained from dealers or investment managers.

Nuclear Decommissioning Trust Fund

The fair value estimate is based on quoted market prices for securities.

 

Preferred Stock of UE, CIPS, CILCO and IP

The fair value estimate is based on the quoted market prices for the same or similar issues.

Long-term Debt

The fair value estimate is based on the quoted market prices for same or similar issues or on the current rates offered to the Ameren Companies for debt of comparable maturities.

Derivative Financial Instruments

Market prices used to determine fair value are primarily based on published indices and closing exchange prices. In addition, valuations must rely on management’s estimates, which take into account time value of money and volatility factors.

 

The following table presents the carrying amounts and estimated fair values of our financial instruments at December 31, 2005 and 2004:

 

      2005    2004
      Carrying Amount    Fair Value    Carrying Amount    Fair Value

Ameren:(a)

            

Long-term debt and capital lease obligations (including current portion)

    $ 5,450    $ 5,532    $ 5,444    $ 5,747

Preferred stock

      214      168      215      176

UE:

            

Long-term debt and capital lease obligations (including current portion)

    $ 2,702    $ 2,667    $ 2,062    $ 2,107

Preferred stock

      113      92      113      95

CIPS:

            

Long-term debt (including current portion)

    $ 430    $ 441    $ 450    $ 483

Preferred stock

      50      32      50      34

Genco:

            

Long-term debt (including current portion)

    $ 474    $ 566    $ 698    $ 836

CILCORP:(b)

            

Long-term debt (including current portion)

    $ 534    $ 557    $ 639    $ 708

Preferred stock

      38      34      39      36

CILCO:

            

Long-term debt (including current portion)

    $ 122    $ 124    $ 138    $ 143

Preferred stock

      38      34      39      36

IP:

            

Long-term debt (including current portion)

    $ 960    $ 954    $ 1,135    $ 1,138

Preferred stock

      46      36      46      37
(a) Includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.
(b) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

 

UE has investments in debt and equity securities that are held in a trust fund for the purpose of funding the nuclear decommissioning of its Callaway nuclear plant. See Note 16 – Callaway Nuclear Plant for further information. We have classified these investments in debt and equity securities as available for sale and have recorded all such investments at their fair market value at December 31, 2005 and 2004. Investments by the nuclear decommissioning trust fund are allocated 60% to 70% to equity securities, with the balance invested in fixed-income securities.

 

The following table presents proceeds from the sale of investments in UE’s nuclear decommissioning trust fund and the gross realized gains and losses on those sales for the years ended December 31, 2005, 2004 and 2003:

 

      2005    2004    2003

Proceeds from sales

    $ 99    $ 131    $ 123

Gross realized gains

      1      2      2

Gross realized losses

      2      1      1

 

95

Net realized and unrealized gains and losses are reflected in regulatory assets or regulatory liabilities on Ameren’s and UE’s Consolidated Balance Sheets. This reporting is consistent with the method we use to account for the decommissioning costs recovered in rates. Gains or losses on assets in the trust fund could result in lower or higher funding requirements for decommissioning costs, which we believe would be reflected in electric rates paid by UE’s customers.

The following table presents the costs and fair values of investments in debt and equity securities in UE’s nuclear decommissioning trust fund at December 31, 2005 and 2004:

 

Security Type    Cost    Gross Unrealized Gain    Gross Unrealized Loss    Fair Value

2005:

            

Debt securities

    $ 84    $ 1    $ 1    $ 84

Equity securities

      102      71      8      165

Cash equivalents

      1      -      -      1

Total

    $ 187    $ 72    $ 9    $ 250

2004:

            

Debt securities

    $ 65    $ 2    $ -    $ 67

Equity securities

      99      65      7      157

Cash equivalents

      11      -      -      11

Total

    $ 175    $ 67    $ 7    $ 235

The following table presents the costs and fair values of investments in debt securities in UE’s nuclear decommissioning trust fund according to their contractual maturities at December 31, 2005:

 

      Cost    Fair Value

Less than 5 years

    $ 40    $ 40

5 years to 10 years

      23      23

Due after 10 years

      21      21

Total

    $ 84    $ 84

The following table presents the fair value and the gross unrealized losses of the available-for-sale securities held in UE’s nuclear decommissioning trust fund that were not deemed to be other-than-temporarily impaired, aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2005:

 

      Less than 12 Months    12 Months or Greater     Total
      Fair Value   

Gross

Unrealized

Losses

    Fair Value   

Gross
Unrealized

Losses

     Fair Value   

Gross
Unrealized

Losses

Debt securities

    $ 37    $ 1    $ 17    $ (a )   $ 54    $ 1

Equity securities

      7      1      9      7       16      8

Total

    $ 44    $ 2    $ 26    $ 7     $ 70    $ 9
(a) Less than $1 million.

 

NOTE 18 – SEGMENT INFORMATION

Ameren’s reportable segment Utility Operations comprises its electric generation and electric and gas transmission and distribution operations. It includes the operations of UE, CIPS, Genco, CILCORP and CILCO. Ameren’s reportable segment Other consists of the parent holding company, Ameren Corporation. The operations of IP are included in Ameren’s Utility Operations segment from September 30, 2004.

 

The accounting policies for segment data are the same as those described in Note 1 – Summary of Significant Accounting Policies. Segment data includes intersegment revenues, as well as a charge for allocating costs of administrative support services to each of the operating companies, which in each case is eliminated upon consolidation. Ameren Services allocates administrative support services based on various factors, such as head count, number of customers, and total assets.

 

96

The following table presents information about the reported revenues, net income, and total assets of Ameren for the years ended December 31, 2005, 2004 and 2003:

 

        Utility Operations      Other        Reconciling Items(a)        Total

2005:

                    

Operating revenues

      $ 8,280      $ -        $ (1,500 )      $ 6,780

Net income

        608        (2 )        -          606

Total assets

        17,149        1,013          -          18,162

2004:(b)

                    

Operating revenues

      $ 6,317      $ -        $ (1,182 )      $ 5,135

Net income

        526        4          -          530

Total assets

        16,833        617          -          17,450

2003:(c)

                    

Operating revenues

      $ 5,673      $ -        $ (1,099 )      $ 4,574

Net income

        546        (22 )        -          524

Total assets

        13,475        761          -          14,236

 

(a) Elimination of intercompany revenues.
(b) Excludes amounts for IP before the acquisition date of September 30, 2004.
(c) Excludes amounts for CILCORP before the acquisition date of January 31, 2003.

The following table presents specified items included in Ameren’s segment profit (loss) for the years ended December 31, 2005, 2004 and 2003:

 

      Utility Operations    Other     Reconciling Items(a)     Total  

2005:

          

Interest expense

    $ 355    $ 19     $ (73 )   $ 301  

Depreciation and amortization

      632      -       -       632  

Income tax

      371      (15 )     -       356 (b)

2004:(c)

          

Interest expense

    $ 359    $ 24     $ (105 )   $ 278  

Depreciation and amortization

      557      -       -       557  

Income tax

      287      (5 )     -       282  

2003:(d)

          

Interest expense

    $ 344    $ 29     $ (96 )   $ 277  

Depreciation and amortization

      519      -       -       519  

Income tax

      305      (4 )     -       301 (b)

 

(a) Elimination of intercompany interest charges.
(b) Does not include income tax expense related to the cumulative effect gain recognized upon adoption of FIN 47 in 2005 or SFAS No. 143 in 2003.
(c) Excludes amounts for IP before the acquisition date of September 30, 2004.
(d) Excludes amounts for CILCORP before the acquisition date of January 31, 2003.

All construction expenditures for the years ended December 31, 2005, 2004 and 2003, were in the Utility Operations segment.

SELECTED QUARTERLY INFORMATION (Unaudited) (In millions, except per share amounts)

 

Ameren(a)

Quarter Ended

   

Operating

Revenues

   

Operating

Income

    Income Before
Cumulative Effect
of Change in
Accounting
Principle		    Net
Income		    Income Before
Cumulative Effect of
Change in
Accounting Principle
per Common Share		   

Earnings per
Common

Share – Basic
and Diluted

March 31, 2005

    $ 1,626    $ 263    $ 121    $ 121    $ 0.62    $ 0.62

March 31, 2004

      1,204      216      97      97      0.55      0.55

June 30, 2005

      1,585      368      185      185      0.93      0.93

June 30, 2004

      1,145      246      118      118      0.65      0.65

September 30, 2005

      1,868      510      280      280      1.37      1.37

September 30, 2004

      1,297      413      232      232      1.20      1.20

December 31, 2005

      1,701      143      42      20      0.21      0.10

December 31, 2004

      1,489      203      83      83      0.42      0.42

 

(a) Includes amounts for IP since the acquisition date of September 30, 2004.

 

97

Quarter Ended   

Operating

Revenues

   

Operating

Income

      Income (Loss) Before
Cumulative Effect of
Change in Accounting
Principle		     

Net

Income (Loss)

     

Net Income (Loss)

Available to
Common

Stockholder

  

UE

                                           

March 31, 2005

    $ 608    $ 107      $ -      $ 57      $ 56  

March 31, 2004

      607      113        -        58        57  

June 30, 2005

      751      229        -        132        130  

June 30, 2004

      680      193        -        109        107  

September 30, 2005

      895      282        -        164        163  

September 30, 2004

      775      306        -        182        181  

December 31, 2005

      635      22        -        (1 )      (3 )

December 31, 2004

      578      61        -        30        28  

CIPS

                                           

March 31, 2005

    $ 212    $ 13      $ -      $ 8      $ 7  

March 31, 2004

      212      17        -        10        9  

June 30, 2005

      198      19        -        7        7  

June 30, 2004

      167      19        -        8        8  

September 30, 2005

      267      50        -        31        30  

September 30, 2004

      187      36        -        23        22  

December 31, 2005

      257      3        -        (2 )      (3 )

December 31, 2004

      169      (14 )      -        (9 )      (10 )

Genco

                                           

March 31, 2005

    $ 225    $ 71      $ 31      $ 31      $ -  

March 31, 2004

      216      70        29        29        -  

June 30, 2005

      266      67        31        31        -  

June 30, 2004

      208      49        17        17        -  

September 30, 2005

      289      73        32        32        -  

September 30, 2004

      233      70        29        29        -  

December 31, 2005

      258      46        19        3        -  

December 31, 2004

      216      76        32        32        -  

CILCORP

                                           

March 31, 2005

    $ 222    $ 28      $ 9      $ 9      $ -  

March 31, 2004

      240      20        4        4        -  

June 30, 2005

      147      18        2        2        -  

June 30, 2004

      140      7        (4 )      (4 )      -  

September 30, 2005

      159      15        5        5        -  

September 30, 2004

      146      8        2        2        -  

December 31, 2005

      219      -        (11 )      (13 )      -  

December 31, 2004

      196      26        8        8        -  

CILCO

                                           

March 31, 2005

    $ 218    $ 29      $ 16      $ 16      $ 15  

March 31, 2004

      225      15        6        6        6  

June 30, 2005

      145      20        10        10        10  

June 30, 2004

      134      8        3        3        2  

September 30, 2005

      158      18        11        11        10  

September 30, 2004

      142      13        9        9        9  

December 31, 2005

      221      (4 )      (9 )      (11 )      (11 )

December 31, 2004

      187      22        14        14        13  

IP(a)

                                           

March 31, 2005

    $ 432    $ 44      $ 22      $ 22      $ 21  

March 31, 2004

      457      53        37        37        36  

June 30, 2005

      341      35        15        15        15  

June 30, 2004

      324      33        24        24        24  

September 30, 2005

      420      99        54        54        53  

September 30, 2004

      379      68        51        51        50  

December 31, 2005

      460      24        6        6        6  

December 31, 2004

      379      62        28        28        27  

 

(a) Includes predecessor information for periods before September 30, 2004.

 

98

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

 

(a)(1)  Financial Statements    Page No.

Ameren

   

Report of Independent Registered Public Accounting Firm

    5

Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003

    10

Consolidated Balance Sheet – December 31, 2005 and 2004

    11

Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003

    12

Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2005, 2004 and 2003

    13

UE

   

Report of Independent Registered Public Accounting Firm

    7

Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003

    14

Consolidated Balance Sheet – December 31, 2005 and 2004

    15

Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003

    16

Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2005, 2004 and 2003

    17

CIPS

   

Report of Independent Registered Public Accounting Firm

    7

Statement of Income – Years Ended December 31, 2005, 2004 and 2003

    18

Balance Sheet – December 31, 2005 and 2004

    19

Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003

    20

Statement of Common Stockholders’ Equity - Years Ended December 31, 2005, 2004 and 2003

    21

Genco

   

Report of Independent Registered Public Accounting Firm

    8

Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003

    22

Consolidated Balance Sheet – December 31, 2005 and 2004

    23

Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003

    24

Consolidated Statement of Common Stockholder’s Equity - Years Ended December 31, 2005, 2004 and 2003

    25

CILCORP

   

Report of Independent Registered Public Accounting Firm

    8

Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003

    26

Consolidated Balance Sheet – December 31, 2005 and 2004

    27

Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003

    28

Consolidated Statement of Common Stockholder’s Equity - Years Ended December 31, 2005, 2004 and 2003

    29

CILCO

   

Report of Independent Registered Public Accounting Firm

    9

Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003

    30

Consolidated Balance Sheet – December 31, 2005 and 2004

    31

Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003

    32

Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2005, 2004 and 2003

    33

IP

   

Report of Independent Registered Public Accounting Firm

    9

Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003

    34

Consolidated Balance Sheet – December 31, 2005 and 2004

    35

Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003

    36

Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2005, 2004 and 2003

    37

(a)(2) Financial Statement Schedule

   

Schedule II – Valuation and Qualifying Accounts for the years ended December 31, 2005, 2004 and 2003

   100

Schedule II should be read in conjunction with the aforementioned financial statements. Certain schedules have been omitted because they are not applicable or because the required data is shown in the aforementioned financial statements.

 

(a)(3) Exhibits.
  Reference is made to the Exhibit Index commencing on page 102.

 

(b) Exhibits are listed in the Exhibit Index commencing on page 102.

 

99

SCHEDULE II – VALUATION AND QUALIFYING ACCOUNTS

FOR THE YEARS ENDED DECEMBER 31, 2005, 2004 AND 2003

(in millions)

Column A

    Column B    Column C    Column D    Column E
Description   

Balance at

Beginning of

Period

   

(1)

Charged to Costs

and Expenses

    

(2)

Charged to Other

Accounts

    Deductions(a)   

Balance at End

of Period

Ameren:(b)

              

Deducted from assets – allowance for doubtful accounts:

              

2005

    $ 14    $ 38     $      $ 30    $ 22

2004

      13      29 (c)     -      28      14

2003

      7      30 (d)     -      24      13

UE:

              

Deducted from assets – allowance for doubtful accounts:

              

2005

    $ 3    $ 19     $      $ 16    $ 6

2004

      6      14       -      17      3

2003

      6      16       -      16      6

CIPS:

              

Deducted from assets – allowance for doubtful accounts:

              

2005

    $ 1    $ 9     $      $ 6    $ 4

2004

      1      6       -      6      1

2003

      1      5       -      5      1

CILCORP:(b)

              

Deducted from assets – allowance for doubtful accounts:

              

2005

    $ 3    $ 8     $      $ 6    $ 5

2004

      6      2       -      5      3

2003

      2      7       -      3      6

CILCO:

              

Deducted from assets – allowance for doubtful accounts:

              

2005

    $ 3    $ 8     $      $ 6    $ 5

2004

      6      2       -      5      3

2003

      2      7       -      3      6

IP:(b)

              

Deducted from assets – allowance for doubtful accounts:

              

2005

    $ 6    $ 3     $      $ 1    $ 8

2004

      6      8       -      8      6

2003

      6      5       -      5      6
(a) Uncollectible accounts charged off, less recoveries.
(b) Ameren 2004 and 2003 amounts include financial activity of IP and CILCORP, subsequent to their respective acquisition dates. Amounts for IP and CILCORP include predecessor and successor financial information in the year of their respective acquisitions.
(c) Amount includes $6 million related to IP balance at the date of acquisition on September 30, 2004.
(d) Amount includes $2 million related to CILCO balance at the date of acquisition on January 31, 2003.

 

100

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signatures for the undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiaries.

 

    

CENTRAL ILLINOIS LIGHT COMPANY

(registrant)

Date:        April 21, 2006

      By  

/s/ Gary L. Rainwater

      

Gary L. Rainwater

      

Chairman and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated.

 

    /s/ Gary L. Rainwater

Gary L. Rainwater

   

Chairman, Chief Executive Officer,

and Director

(Principal Executive Officer)

  

April 21, 2006

    /s/ Warner L. Baxter

Warner L. Baxter

   

Executive Vice President, Chief

Financial Officer, and Director

(Principal Financial Officer)

  

April 21, 2006

    /s/ Martin J. Lyons

Martin J. Lyons

   

Vice President and Controller

(Principal Accounting Officer)

  

April 21, 2006

*

Scott A. Cisel

   

Director

  

April 21, 2006

*

Daniel F. Cole

   

Director

  

April 21, 2006

*

Steven R. Sullivan

   

Director

  

April 21, 2006

*

Thomas R. Voss

   

Director

  

April 21, 2006

*

David A. Whiteley

   

Director

  

April 21, 2006

*By

  

/s/ Warner L. Baxter

     

April 21, 2006

 

Warner L. Baxter

Attorney-in-Fact

     

 

101

EXHIBIT INDEX

The documents listed below are being filed or have previously been filed on behalf of the Ameren Companies and are incorporated herein by reference from the documents indicated and made a part hereof. Exhibits not identified as previously filed are filed herewith:

 

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1   

Ameren

CILCORP

CILCO

    Stock Purchase Agreement, dated as of April 28, 2002, by and between AES and Ameren    March 31, 2002 Form 10-Q, Exhibit 2.1, File No. 1-14756
2.2   

Ameren

CILCORP

CILCO

    Membership Interest Purchase Agreement, dated as of April 28, 2002, by and between AES and Ameren    March 31, 2002 Form 10-Q, Exhibit 2.2, File No. 1-14756
2.3   

Ameren Companies

    Stock Purchase Agreement, dated as of February 2, 2004, by and between Dynegy and certain of its subsidiaries and Ameren    February 3, 2004 Form 8-K, Exhibit 2.1, File No. 1-14756
2.4   

Ameren Companies

    Amendment No. 1, dated as of March 23, 2004, to Stock Purchase Agreement, dated as of February 2, 2004, by and between Dynegy and certain of its subsidiaries and Ameren    March 24, 2004 Form 8-K, Exhibit 2.1, File No. 1-14756
2.5   

Ameren Companies

    Amendment No. 2, dated as of April 30, 2004, to Stock Purchase Agreement, dated as of February 2, 2004 by and between Dynegy and certain of its subsidiaries and Ameren    June 30, 2004 Form 10-Q, Exhibit 2.1, File No. 1-14756
2.6   

Ameren Companies

    Amendment No. 3, dated as of May 31, 2004, to Stock Purchase Agreement, dated as of February 2, 2004, by and between Dynegy and certain of its subsidiaries and Ameren    June 30, 2004 Form 10-Q, Exhibit 2.2, File No. 1-14756
2.7   

Ameren Companies

    Amendment No. 4, dated as of September 24, 2004, to Stock Purchase Agreement, dated as of February 2, 2004 between Dynegy and certain of its subsidiaries and Ameren    September 30, 2004 Form 10-Q, Exhibit 2.1, File No. 1-14756
Articles of Incorporation/ By-Laws
3.1(i)   

Ameren

    Restated Articles of Incorporation of Ameren    File No. 33-64165, Annex F
3.2(i)   

Ameren

    Certificate of Amendment to Ameren’s Restated Articles of Incorporation filed December 14, 1997    1998 Form 10-K, Exhibit 3(i), File No. 1-14756
3.3(i)   

UE

    Restated Articles of Incorporation of UE    1993 Form 10-K, Exhibit 3(i), File No. 1-2967
3.4(i)   

CIPS

    Restated Articles of Incorporation of CIPS    March 31, 1994 Form 10-Q, Exhibit 3(b), File No. 1-3672
3.5(i)   

Genco

    Articles of Incorporation of Genco    Exhibit 3.1, Form S-4, File No. 333-56594
3.6(i)   

Genco

    Amendment to Articles of Incorporation of Genco filed April 19, 2000    Exhibit 3.2, Form S-4, File No. 333-56594

 

102

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
3.7(i)   

CILCORP

    Articles of Incorporation of CILCORP, as amended to May 2, 1991   

Exhibit 3.1, File No. 333-90373

3.8(i)   

CILCORP

    Articles of Amendment to CILCORP’s Articles of Incorporation filed November 15, 1999    1999 Form 10-K, Exhibit 3, File No. 1-8946
3.9(i)   

CILCO

    Articles of Incorporation of CILCO as amended May 29, 1998    1998 Form 10-K, Exhibit 3, File No. 1-8946
3.10(i)   

IP

    Amended and Restated Articles of Incorporation of IP, dated September 7, 1994    September 7, 1994 Form 8-K, Exhibit 3(a), File No. 1-3004
3.11(ii)   

Ameren

    By-Laws of Ameren as amended effective August 28, 2005    August 29, 2005 Form 8-K, Exhibit 3.2(ii), File No. 1-14756
3.12(ii)   

UE

    By-Laws of UE as amended to August 25, 2005    August 29, 2005 Form 8-K/A, Exhibit 3.1(ii), File No. 1-2967
3.13(ii)    CIPS    By-Laws of CIPS as amended October 8, 2004    October 14, 2004 Form 8-K, Exhibit 3.1, File No. 1-3672
3.14(ii)    Genco    By-Laws of Genco as amended to October 8, 2004    September 30, 2004 Form 10-Q, Exhibit 3.1, File No. 333-56594
3.15(ii)    CILCORP    By-Laws of CILCORP as amended as of October 8, 2004    September 30, 2004 Form 10-Q, Exhibit 3.2, File No. 1-8946
3.16(ii)    CILCO    By-Laws of CILCO as amended effective October 8, 2004    October 14, 2004 Form 8-K, Exhibit 3.2, File No. 1-2732
3.17(ii)    IP    By-Laws of IP as amended October 8, 2004    October 14, 2004 Form 8-K, Exhibit 3.3, File No. 1-3004
Instruments Defining Rights of Security Holders
4.1         

Ameren

    Agreement, dated as of October 9, 1998, between Ameren and Computershare (formerly EquiServe Trust Company, N.A., as successor to First Chicago Trust Company of New York), as Rights Agent, which includes the form of Certificate of Designation of the Preferred Shares as Exhibit A, the form of Rights Certificate as Exhibit B, and the Summary of Rights as Exhibit C    October 14, 1998 Form 8-K, Exhibit 4, File No. 1-14756
4.2          Ameren    Indenture of Ameren with The Bank of New York, as Trustee, relating to senior debt securities dated as of December 1, 2001 (Ameren’s Senior Indenture)    Exhibit 4.5, File No. 333-81774
4.3          Ameren    Ameren Company Order relating to $100 million 5.70% Notes due February 1, 2007, issued under Ameren’s Senior Indenture (including forms of notes)    Exhibit 4.7, File No. 333-81774
4.4         

Ameren

    Ameren Company Order relating to $345 million Notes due May 15, 2007, issued under Ameren’s Senior Indenture (including forms of notes)   

Exhibit 4.8, File No. 333-81774

 

103

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
4.5   

Ameren

UE

    Indenture of Mortgage and Deed of Trust dated June 15, 1937 (UE Mortgage), as amended May 1, 1941, and Second Supplemental Indenture dated May 1, 1941   

Exhibit B-1, File No. 2-4940

4.6   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of April 1, 1971    April 1971 Form 8-K, Exhibit 6, File No. 1-2967
4.7   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of February 1, 1974    February 1974 Form 8-K, Exhibit 3, File No. 1-2967
4.8   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of July 7, 1980    Exhibit 4.6, File No. 2-69821
4.9   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of May 1, 1990    1990 Form 10-K, Exhibit 4.6, File No. 1-2967
4.10   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of December 1, 1991    Exhibit 4.4, File No. 33-45008
4.11   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of December 4, 1991    Exhibit 4.5, File No. 33-45008
4.12   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of January 1, 1992    1991 Form 10-K, Exhibit 4.6, File No. 1-2967
4.13   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of October 1, 1992    1992 Form 10-K, Exhibit 4.6, File No. 1-2967
4.14   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of December 1, 1992    1992 Form 10-K, Exhibit 4.7, File No. 1-2967
4.15   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of February 1, 1993    1992 Form 10-K, Exhibit 4.8, File No. 1-2967
4.16   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of May 1, 1993    1993 Form 10-K, Exhibit 4.6, File No. 1-2967
4.17   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of August 1, 1993    1993 Form 10-K, Exhibit 4.7, File No. 1-2967
4.18   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of October 1, 1993    1993 Form 10-K, Exhibit 4.8, File No. 1-2967
4.19   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of January 1, 1994    1993 Form 10-K, Exhibit 4.9, File No. 1-2967
4.20   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated as of February 1, 2000    2000 Form 10-K, Exhibit 4.1, File No. 1-2967
4.21   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated August 15, 2002    August 23, 2002 Form 8-K, Exhibit 4.3, File No. 1-2967
4.22   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated March 5, 2003    March 11, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967
4.23   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated April 1, 2003    April 10, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967
4.24   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated July 15, 2003    August 4, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967
4.25   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated October 1, 2003    October 8, 2003 Form 8-K, Exhibit 4.4, File No. 1-2967
4.26   

Ameren

UE

    Supplemental Indenture to the UE Mortgage dated February 1, 2004    March 31, 2004 Form 10-Q, Exhibit 4.1, File No. 1-2967

 

104

Exhibit Designation    Registrant(s)   Nature of Exhibit    Previously Filed as Exhibit to:
4.27   

Ameren

UE

   Supplemental Indenture dated February 1, 2004, to the UE Mortgage relative to Series 2004B (1998B) Bonds    March 31, 2004 Form 10-Q, Exhibit 4.2, File No. 1-2967
4.28   

Ameren

UE

   Supplemental Indenture dated February 1, 2004, to the UE Mortgage relative to Series 2004C (1998C) Bonds    March 31, 2004 Form 10-Q, Exhibit 4.3, File No. 1-2967
4.29   

Ameren

UE

   Supplemental Indenture dated February 1, 2004, to the UE Mortgage relative to Series 2004D (2000B) Bonds    March 31, 2004 Form 10-Q, Exhibit 4.4, File No. 1-2967
4.30   

Ameren

UE

   Supplemental Indenture dated February 1, 2004, to the UE Mortgage relative to Series 2004E (2000A) Bonds    March 31, 2004 Form 10-Q, Exhibit 4.5, File No. 1-2967
4.31   

Ameren

UE

   Supplemental Indenture dated February 1, 2004, to the UE Mortgage relative to Series 2004F (2000C) Bonds    March 31, 2004 Form 10-Q, Exhibit 4.6, File No. 1-2967
4.32   

Ameren

UE

   Supplemental Indenture dated February 1, 2004, to the UE Mortgage relative to Series 2004G (1991) Bonds    March 31, 2004 Form 10-Q, Exhibit 4.7, File No. 1-2967
4.33   

Ameren

UE

   Supplemental Indenture dated February 1, 2004, to the UE Mortgage relative to Series 2004H (1992) Bonds    March 31, 2004 Form 10-Q, Exhibit 4.8, File No. 1-2967
4.34   

Ameren

UE

   Supplemental Indenture to the UE Mortgage dated May 1, 2004    May 18, 2004 Form 8-K, Exhibit 4.4, File No. 1-2967
4.35   

Ameren

UE

   Supplemental Indenture to the UE Mortgage dated September 1, 2004    September 23, 2004 Form 8-K, Exhibit 4.4, File No. 1-2967
4.36   

Ameren

UE

   Supplemental Indenture to the UE Mortgage dated January 1, 2005    January 27, 2005 Form 8-K, Exhibit 4.4, File No. 1-2967
4.37   

Ameren

UE

   Supplemental Indenture to the UE Mortgage dated July 1, 2005    July 21, 2005 Form 8-K, Exhibit 4.4, File No. 1-2967
4.38   

Ameren

UE

   Supplemental Indenture to the UE Mortgage dated December 1, 2005    December 9, 2005 Form 8-K, Exhibit 4.4, File No. 1-2967
4.39   

Ameren

UE

   Loan Agreement dated as of December 1, 1991, between the Missouri Environmental Authority and UE, together with Indenture of Trust dated as of December 1, 1991, between the Missouri Environmental Authority and UMB Bank N.A. as successor trustee to Mercantile Bank of St. Louis, N. A.    1992 Form 10-K, Exhibit 4.37, File No. 1-2967
4.40   

Ameren

UE

   First Amendment dated as of February 1, 2004, to Loan Agreement dated as of December 1, 1991, between the Missouri Environmental Authority and UE    March 31, 2004 Form 10-Q, Exhibit 4.9, File No. 1-2967
4.41   

Ameren

UE

   Loan Agreement dated as of December 1, 1992, between the Missouri Environmental Authority and UE, together with Indenture of Trust dated as of December 1, 1992 between the Missouri Environmental Authority and UMB Bank, N.A. as successor trustee to Mercantile Bank of St. Louis, N.A.    1992 Form 10-K, Exhibit 4.38, File No. 1-2967

 

105

Exhibit Designation    Registrant(s)   Nature of Exhibit    Previously Filed as Exhibit to:
4.42   

Ameren

UE

   First Amendment dated as of February 1, 2004, to Loan Agreement dated as of December 1, 1992, between the Missouri Environmental Authority and UE    March 31, 2004 Form 10-Q, Exhibit 4.10, File No. 1-2967
4.43   

Ameren

UE

   Series 1998A Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE    September 30, 1998 Form 10-Q, Exhibit 4.28, File No. 1-2967
4.44   

Ameren

UE

   First Amendment dated as of February 1, 2004, to Series 1998A Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE    March 31, 2004 Form 10-Q, Exhibit 4.11, File No. 1-2967
4.45   

Ameren

UE

   Series 1998B Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE    September 30, 1998 Form 10-Q, Exhibit 4.29, File No. 1-2967
4.46   

Ameren

UE

   First Amendment dated as of February 1, 2004, to Series 1998B Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE    March 31, 2004 Form 10-Q, Exhibit 4.12, File No. 1-2967
4.47   

Ameren

UE

   Series 1998C Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE    September 30, 1998 Form 10-Q, Exhibit 4.30, File No. 1-2967
4.48   

Ameren

UE

   First Amendment dated as of February 1, 2004, to Series 1998C Loan Agreement dated as of September 1, 1998, between the Missouri Environmental Authority and UE    March 31, 2004 Form 10-Q Exhibit 4.13, File No. 1-2967
4.49   

Ameren

UE

   Indenture dated as of August 15, 2002, from UE to The Bank of New York, as Trustee, relating to senior secured debt securities)    August 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-2967
4.50   

Ameren

UE

   UE Company Order dated August 22, 2002, establishing the 5.25% Senior Secured Notes due 2012 (including the global note)    August 23, 2002 Form 8-K, Exhibit 4.2, File No. 1-2967
4.51   

Ameren

UE

   UE Company Order dated March 10, 2003, establishing the 5.50% Senior Secured Notes due 2034 (including the global note)    March 11, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.52   

Ameren

UE

   UE Company Order dated April 9, 2003, establishing the 4.75% Senior Secured Notes due 2015 (including the global note)    April 10, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.53   

Ameren

UE

   UE Company Order dated July 28, 2003, establishing the 5.10% Senior Secured Notes due 2018 (including the global note)    August 4, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.54   

Ameren

UE

   UE Company Order dated October 7, 2003, establishing the 4.65% Senior Secured Notes due 2013 (including the global note)    October 8, 2003 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967

 

106

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
4.55   

Ameren

UE

    UE Company Order dated May 13, 2004, establishing the 5.50% Senior Secured Notes due 2014 (including the global note)    May 18, 2004 Form 8-K, Exhibits 4.2 and 4.3, No. 1-2967
4.56   

Ameren

UE

    UE Company Order dated September 1, 2004, establishing the 5.10% Senior Secured Notes due 2019 (including the global note)    September 23, 2004 Form 8-K, Exhibits 4.2 and 4.3, No. 1-2967
4.57   

Ameren

UE

    UE Company Order dated January 27, 2005, establishing the 5.00% Senior Secured Notes due 2020 (including the global note)    January 27, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.58   

Ameren

UE

    UE Company Order dated July 21, 2005, establishing the 5.30% Senior Secured Notes due 2037 (including the global note)    July 21, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.59   

Ameren

UE

    UE Company Order dated December 8, 2005, establishing the 5.40% Senior Secured Notes due 2016 (including the global note)    December 9, 2005 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.60   

Ameren

CIPS

    Indenture of Mortgage or Deed of Trust dated October 1, 1941, from CIPS to Continental Illinois National Bank and Trust Company of Chicago and Edmond B. Stofft, as Trustees (U.S. Bank National Association and Patrick J. Crowley are successor Trustees) (CIPS Mortgage)    Exhibit 2.01, File No. 2-60232
4.61   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated September 1, 1947    Amended Exhibit 7(b), File No. 2-7341
4.62   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated January 1, 1949    Second Amended Exhibit 7.03, File No. 2-7795
4.63   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated February 1, 1952    Second Amended Exhibit 4.07, File No. 2-9353
4.64   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated September 1, 1952    Amended Exhibit 4.05, File No. 2-9802
4.65   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated June 1, 1954    Amended Exhibit 4.02, File No. 2-10944
4.66   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated February 1, 1958    Amended Exhibit 2.02, File No. 2-13866
4.67   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated January 1, 1959    Amended Exhibit 2.02, File No. 2-14656
4.68   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated May 1, 1963    Amended Exhibit 2.02, File No. 2-21345
4.69   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated May 1, 1964    Amended Exhibit 2.02, File No. 2-22326
4.70   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated June 1, 1965    Amended Exhibit 2.02, File No. 2-23569
4.71   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated May 1, 1967    Amended Exhibit 2.02, File No. 2-26284
4.72   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated April 1, 1970    Amended Exhibit 2.02, File No. 2-36388

 

107

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
4.73   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated April 1, 1971    Amended Exhibit 2.02, File No. 2-39587
4.74   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated September 1, 1971    Amended Exhibit 2.02, File No. 2-41468
4.75   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated May 1, 1972    Amended Exhibit 2.02, File No. 2-43912
4.76   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated December 1, 1973    Exhibit 2.03, File No. 2-60232
4.77   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated March 1, 1974    Amended Exhibit 2.02, File No. 2-50146
4.78   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated April 1, 1975    Amended Exhibit 2.02, File No. 2-52886
4.79   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated October 1, 1976    Second Amended Exhibit 2.04, File No. 2-57141
4.80   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated November 1,1976    Amended Exhibit 2.04, File No. 2-57557
4.81   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated October 1, 1978    Amended Exhibit 2.06, File No. 2-62564
4.82   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated August 1, 1979    Exhibit 2.02(a), File No. 2-65914
4.83   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated February 1, 1980    Exhibit 2.02(a), File No. 2-66380
4.84   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated February 1, 1986    Amended Exhibit 4.02, File No. 33-3188
4.85   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated May 15, 1992    May 15, 1992 Form 8-K, Exhibit 4.02, File No. 1-3672
4.86   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated July 1, 1992    July 1, 1992 Form 8-K, Exhibit 4.02, File No. 1-3672
4.87   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated September 15, 1992    September 15, 1992 Form 8-K, Exhibit 4.02, File No. 1-3672
4.88   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated April 1, 1993    March 30, 1993 Form 8-K, Exhibit 4.02, File No. 1-3672
4.89   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated June 1, 1995    June 8, 1995 Form 8-K, Exhibit 4.03, File No. 1-3672
4.90   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated March 15, 1997    March 26, 1997 Form 8-K, Exhibit 4.03, File No. 1-3672
4.91   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated June 1, 1997    June 6, 1997 Form 8-K, Exhibit 4.03, File No. 1-3672
4.92   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated December 1, 1998    Exhibit 4.2, File No. 333-59438
4.93   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated June 1, 2001    June 30, 2001 Form 10-Q, Exhibit 4.1, File No. 1-3672
4.94   

Ameren

CIPS

    Supplemental Indenture to the CIPS Mortgage, dated October 1, 2004    2004 Form 10-K, Exhibit 4.91, File No. 1-3672

 

108

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
4.95   

Ameren

CIPS

    Indenture dated as of December 1, 1998, from CIPS to The Bank of New York, as trustee, relating to CIPS’ Senior Notes, 5.375% due 2008 and 6.125% due 2028    Exhibit 4.4, File No. 333-59438
4.96   

Ameren

Genco

    Indenture dated as of November 1, 2000, from Genco to The Bank of New York, as trustee, relating to the issuance of senior notes (Genco Indenture)    Exhibit 4.1, File No. 333-56594
4.97   

Ameren

Genco

    First Supplemental Indenture dated as of November 1, 2000, to Genco Indenture, relating to Genco’s 7.75% Senior Notes, Series A due 2005 and 8.35% Senior Notes, Series B due 2010    Exhibit 4.2, File No. 333-56594
4.98   

Ameren

Genco

    Form of Second Supplemental Indenture dated as of June 12, 2001, to Genco Indenture, relating to Genco’s 7.75% Senior Notes, Series C due 2005 and 8.35% Senior Note, Series D due 2010    Exhibit 4.3, File No. 333-56594
4.99   

Ameren

Genco

    Third Supplemental Indenture dated as of June 1, 2002, to Genco Indenture, relating to Genco’s 7.95% Senior Notes, Series E due 2032    June 30, 2002 Form 10-Q, Exhibit 4.1, File No. 333-56594
4.100   

Ameren

Genco

    Fourth Supplemental Indenture dated as of January 15, 2003, to Genco Indenture, relating to Genco 7.95% Senior Notes, Series F due 2032    2002 Form 10-K, Exhibit 4.5, File No. 333-56594
4.101   

Ameren

CILCORP

    Indenture, dated as of October 18, 1999, between Midwest Energy, Inc., and The Bank of New York, as Trustee, and First Supplemental Indenture, dated as of October 18, 1999, between CILCORP and The Bank of New York    Exhibits 4.1 and 4.2, File No. 333-90373
4.102   

Ameren

CILCO

    Indenture of Mortgage and Deed of Trust between Illinois Power Company and Deutsche Bank Trust Company Americas (formerly known as Bankers Trust Company), as trustee, dated as of April 1, 1933 (CILCO Mortgage), Supplemental Indenture between the same parties dated as of June 30, 1933, Supplemental Indenture between CILCO and the trustee, dated as of July 1, 1933 and Supplemental Indenture between the same parties dated as of January 1, 1935, securing First Mortgage Bonds.    Exhibit B-1, Registration No. 2-1937; Exhibit B-1(a), Registration No. 2-2093; and Exhibit A, April 1940 Form 8-K, File No. 1-2732
4.103   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated December 1, 1949    December 1949 Form 8-K, Exhibit A, File No. 1-2732
4.104   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated December 1, 1951    December 1951 Form 8-K, Exhibit A, File No. 1-2732
4.105   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated July 1, 1957    July 1957 Form 8-K, Exhibit A, File No. 1-2732

 

109

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
4.106   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated July 1, 1958    July 1958 Form 8-K, Exhibit A, File No. 1-2732
4.107   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated March 1, 1960    March 1960 Form 8-K, Exhibit A, File No. 1-2732
4.108   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated September 20, 1961    September 1961 Form 8-K, Exhibit A, File No. 1-2732
4.109   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated March 1, 1963    March 1963 Form 8-K, Exhibit B, File No. 1-2732
4.110   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated February 1, 1966    February 1966 Form 8-K, Exhibit A, File No. 1-2732
4.111   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated March 1, 1967    March 1967 Form 8-K, Exhibit A, File No. 1-2732
4.112   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated August 1, 1970    August 1970 Form 8-K, Exhibit A, File No. 1-2732
4.113   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated September 1, 1971    September 1971 Form 8-K, Exhibit A, File No. 1-2732
4.114   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated September 20, 1972    September 1972 Form 8-K, Exhibit A, File No. 1-2732
4.115   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated April 1, 1974    April 1974 Form 8-K, Exhibit A, File No. 1-2732
4.116   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated June 1, 1974    June 1974 Form 8-K, Exhibit 2(b), File No. 1-2732
4.117   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated March 1, 1975    March 1975 Form 8-K, Exhibit A, File No. 1-2732
4.118   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated May 1, 1976    May 1976 Form 8-K, Exhibit A, File No. 1-2732
4.119   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated May 16, 1978    June 30, 1978 Form 10-Q, Exhibit A, File No. 1-2732
4.120   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated September 1, 1982    1982 Form 10-K, Exhibit 2, File No.
1-2732
4.121   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated January 15, 1992    January 30, 1982 Form 8-K, Exhibit 4(b), File No. 1-2732
4.122   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated January 1, 1993    January 29, 1993 Form 8-K, Exhibit 4, File No. 1-2732
4.123   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated November 1, 1994    December 2, 1994 Form 8-K, Exhibit 4, File No. 1-2732
4.124   

Ameren

CILCO

    Supplemental Indenture to the CILCO Mortgage, dated October 1, 2004    2004 Form 10-K, Exhibit 4.121, File No. 1-2732
4.125   

Ameren

IP

    General Mortgage Indenture and Deed of Trust dated as of November 1, 1992 between IP and BNY Midwest Trust Company (successor to Harris Trust and Savings Bank) (IP Mortgage)    1992 Form 10-K, Exhibit 4(cc), File No. 1-3004
4.126   

Ameren

IP

    Supplemental Indenture No. 2 dated March 15, 1993, to IP Mortgage for the 6  3/4% bonds due 2005    1992 Form 10-K Exhibit 4(ii), File No. 1-3004

 

110

Exhibit Designation    Registrant(s)   Nature of Exhibit    Previously Filed as Exhibit to:
4.127   

Ameren

IP

   Supplemental Indenture dated July 15, 1993, to IP Mortgage for the 7 1/2% bonds due 2025    June 30, 1993 Form 10-Q, Exhibit 4(kk), File No. 1-3004
4.128   

Ameren

IP

   Supplemental Indenture dated August 1, 1993, to IP Mortgage for the 6 1/2% bonds due 2003    June 30, 1993 Form 10-Q, Exhibit 4(mm), File No. 1-3004
4.129   

Ameren

IP

   Supplemental Indenture dated as of April 1, 1997, to IP Mortgage for the series P, Q and R bonds    March 31, 1997 Form 10-Q, Exhibit 4(b), File No. 1-3004
4.130   

Ameren

IP

   Supplemental Indenture dated as of March 1, 1998, to IP Mortgage for the series S bonds   

Exhibit 4.41, File No. 333-71061

4.131   

Ameren

IP

   Supplemental Indenture dated as of March 1, 1998, to IP Mortgage for the series T bonds   

Exhibit 4.42, File No. 333-71061

4.132   

Ameren

IP

   Supplemental Indenture dated as of September 15, 1998, to IP Mortgage for the 6% bonds due 2003   

Exhibit 4.46, File No. 333-71061

4.133   

Ameren

IP

   Supplemental Indenture dated as of June 15, 1999, to IP Mortgage for the 7.50% bonds due 2009    June 30, 1999 Form 10-Q, Exhibit 4.2, File No. 1-3004
4.134   

Ameren

IP

   Supplemental Indenture dated as of July 15, 1999, to IP Mortgage for the series U bonds    June 30, 1999 Form 10-Q, Exhibit 4.4, File No. 1-3004
4.135   

Ameren

IP

   Supplemental Indenture dated as of July 15, 1999, to IP Mortgage for the series V bonds    June 30, 1999 Form 10-Q, Exhibit 4.6, File No. 1-3004
4.136   

Ameren

IP

   Supplemental Indenture dated as of May 1, 2001 to IP Mortgage for the series W bonds    2001 Form 10-K, Exhibit 4.19, File No. 1-3004
4.137   

Ameren

IP

   Supplemental Indenture dated as of May 1, 2001, to IP Mortgage for the series X bonds    2001 Form 10-K, Exhibit 4.20, File No. 1-3004
4.138   

Ameren

IP

   Supplemental Indenture dated as of December 15, 2002, to IP Mortgage for the 11.50% bonds due 2010    December 23, 2002 Form 8-K, Exhibit
4.1, File No. 1-3004
4.139   

Ameren

CIPS

Genco

   Amended and Restated Genco Subordinated Promissory Note dated as of May 1, 2005    May 2, 2005 Form 8-K, Exhibit 4.1, File No. 1-14756
4.140   

Ameren

UE

CIPS

   CIPS Subordinated Promissory Note, dated as of May 2, 2005    May 2, 2005 Form 8-K, Exhibit 4.2, File No. 1-14756
Material Contracts
10.1   

Ameren

CIPS

Genco

   Asset Transfer Agreement between Genco and CIPS, dated May 1, 2000    June 30, 2000 Form 10-Q, Exhibit 10, File No. 1-3672
10.2   

Ameren

CIPS

Genco

   Amended Electric Power Supply Agreement between Genco and Marketing Company, dated May 1, 2000 and amended August 14, 2000    Exhibit 10.2, Form S-4, File No.
333-56594

 

111

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
10.3   

Ameren

CIPS

Genco

    Second Amended Electric Power Supply Agreement between Genco and Marketing Company, dated March 30, 2001    March 31, 2001 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.4   

Ameren

CIPS

Genco

    Electric Power Supply Agreement between Marketing Company and CIPS, dated May 1, 2000    Exhibit 10.3, Form S-4, File No.
333-56594
10.5   

Ameren

CIPS

Genco

    Amended Electric Power Supply Agreement between Marketing Company and CIPS, dated March 30, 2001    March 31, 2001 Form 10-Q, Exhibit 10.2, File No. 1-14756
10.6   

Ameren

UE

Genco

    Power Sales Agreement between Marketing Company and UE, dated March 29, 2001    September 30, 2001 Form 10-Q, Exhibit 10.1, File No. 333-56594
10.7   

Ameren

UE

Genco

    Power Sales Agreement between Marketing Company and UE, dated March 20, 2002    March 31, 2002 Form 10-Q, Exhibit 10.1, File No. 333-56594
10.8   

Ameren

UE

CIPS

Genco

    Amended Joint Dispatch Agreement among Genco, CIPS and UE, dated May 1, 2000    Exhibit 10.4, Form S-4, File No.
333-56594
10.9   

Ameren

UE

CIPS

Genco

    Second Amendment to the Joint Dispatch Agreement among Genco, CIPS and UE, dated January 9, 2006    January 13, 2006 Form 8-K, Exhibit 10.1, File No. 1-14756
10.10   

Ameren

UE

    Lease Agreement dated as of December 1, 2002, between the City of Bowling Green, Missouri, as lessor and UE, as lessee    2002 Form 10-K, Exhibit 10.9, File No. 1-2967
10.11   

Ameren

UE

    Trust Indenture dated as of December 1, 2002, between the City of Bowling Green, Missouri, and Commerce Bank N.A. as trustee    2002 Form 10-K, Exhibit 10.10, File No. 1-2967
10.12   

Ameren

CILCORP

CILCO

    Contribution Agreement between CILCO and AERG dated as of October 3, 2003    September 30, 2003 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.13   

Ameren

CILCORP

CILCO

    Power Supply Agreement between AERG and CILCO, dated as of October 3, 2003    September 30, 2003 Form 10-Q, Exhibit 10.2, File No. 1-14756
10.14   

Ameren

Companies

    Third Amended Ameren Corporation System Utility Money Pool Agreement, as amended September 30, 2004    October 1, 2004 Form 8-K, Exhibit 10.2, File No. 1-14756
10.15   

Ameren

Genco

CILCORP

    Ameren Corporation System Non-State Regulated Subsidiary Money Pool Agreement, dated as of February 27, 2003    September 30, 2003 Form 10-Q, Exhibit 10.4, File No. 1-14756
10.16   

Ameren

CILCORP

CILCO

    Extension of Power Supply Agreement between AERG and CILCO dated July 12, 2004    June 30, 2004 Form 10-Q, Exhibit 10.3, File No. 1-14756
10.17   

Ameren

IP

    Power Purchase Agreement between IP and Dynegy Power Marketing, Inc. dated as of September 30, 2004    October 1, 2004 Form 8-K, Exhibit 10.1, File No. 1-3004

 

112

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
10.18   

Ameren

IP

    Unilateral Borrowing Agreement by and among Ameren, IP and Ameren Services, dated as of September 30, 2004    October 1, 2004 Form 8-K, Exhibit 10.3, File No. 3004
10.19   

Ameren

CIPS

Genco

    Electric Power Supply Agreement between CIPS and Marketing Company, as amended November 5, 2004    September 30, 2004 Form 10-Q, Exhibit 10.2, File No. 1-14756
10.20   

Ameren

UE

CIPS

Genco

    UE Illinois Asset Transfer Agreement among Ameren, UE and CIPS, dated as of May 2, 2005    May 2, 2005 Form 8-K, Exhibit 10.1, File No. 1-14756
10.21   

Ameren

UE

CIPS

Genco

    Asset Transfer Agreement related to Kinmundy Generation Station between Genco and UE, dated as of May 2, 2005    May 2, 2005 Form 8-K, Exhibit 10.2, File No. 1-14756
10.22   

Ameren

UE

CIPS

Genco

    Asset Transfer Agreement related to Pinckneyville Generation Station between Genco and UE, dated as of May 2, 2005    May 2, 2005 Form 8-K, Exhibit 10.3, File No. 1-14756
10.23    Ameren Companies    Five-Year Revolving Credit Agreement, dated as of July 14, 2005    July 15, 2005 Form 8-K, Exhibit 10.1, File No. 1-14756
10.24   

Ameren

    Amended and Restated Five-Year Revolving Credit Agreement, dated as of July 14, 2005    July 15, 2005 Form 8-K, Exhibit 10.2, File No. 1-14756
10.25    Ameren Companies    *Ameren’s Long-Term Incentive Plan of 1998    1998 Form 10-K, Exhibit 10.1, File No. 1-14756
10.26    Ameren Companies    *First Amendment to Ameren’s Long-Term Incentive Plan of 1998    February 16, 2006 Form 8 K, Exhibit 10.6, File No. 1 14756
10.27    Ameren Companies    *Form of Restricted Stock Award under Ameren’s Long-Term Incentive Plan of 1998    February 14, 2005 Form 8-K, Exhibit 10.1, File No. 1-14756
10.28    Ameren Companies    *Ameren’s Deferred Compensation Plan for Members of the Board of Directors    1998 Form 10-K, Exhibit 10.4, File No. 1-14756
10.29    Ameren Companies    *Ameren’s Deferred Compensation Plan for Members of the Ameren Leadership Team as amended and restated effective January 1, 2001    2000 Form 10-K, Exhibit 10.1, File No. 1-14756
10.30    Ameren Companies    *Ameren’s Executive Incentive Compensation Program Elective Deferral Provisions for Members of the Ameren Leadership Team as amended and restated effective January 1, 2001    2000 Form 10-K, Exhibit 10.2, File No. 1-14756
10.31   

Ameren

UE

CIPS

Genco

CILCORP

CILCO

    *2003 Ameren Executive Incentive Plan    March 31, 2003 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.32    Ameren Companies    *2004 Ameren Executive Incentive Plan    2003 Form 10-K, Exhibit 10.7, File No. 1-14756

 

113

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
10.33    Ameren Companies    *2005 Ameren Executive Incentive Plan    February 14, 2005 Form 8-K, Exhibit 10.2, File No. 1-14756
10.34    Ameren Companies    *2006 Executive Incentive Compensation Plan    February 16, 2006 Form 8-K, Exhibit 10.2, File No. 1-14756
10.35    Ameren Companies    *2005 and 2006 Base Salary Table for Named Executive Officers and 2006 Executive Officer Bonus Targets    December 15, 2005 Form 8-K, Exhibit 10.1, File No. 1-14756
10.36    Ameren Companies    *Amended and Restated Ameren Corporation Change of Control Severance Plan    February 16, 2006 Form 8-K, Exhibit 10.5, File No. 1-14756
10.37    Ameren Companies    *Table of 2005 Cash Bonus Awards and 2006 Performance Share Unit Awards Issued to Named Executive Officers    February 16, 2006 Form 8-K, Exhibit 10.1, File No. 1-14756
10.38    Ameren Companies    *Ameren Corporation 2006 Omnibus Incentive Compensation Plan    February 16, 2006 Form 8-K, Exhibit 10.3, File No. 1-14756
10.39    Ameren Companies    *Form of Performance Share Unit Award Issued Pursuant to 2006 Omnibus Incentive Compensation Plan    February 16, 2006 Form 8-K, Exhibit 10.4, File No. 1-14756
10.40   

Ameren

CILCORP

CILCO

    *CILCO Executive Deferral Plan as amended effective August 15, 1999    1999 Form 10-K, Exhibit 10, File No. 1-2732
10.41   

Ameren

CILCORP

CILCO

    *CILCO Executive Deferral Plan II as amended effective April 1, 1999    1999 Form 10-K, Exhibit 10(a), File No. 1-2732
10.42   

Ameren

CILCORP

CILCO

    *CILCO Benefit Replacement Plan as amended effective August 15, 1999    1999 Form 10-K, Exhibit 10(b), File No. 1-2732
10.43   

Ameren

CILCORP

CILCO

    *CILCO Restructured Executive Deferral Plan (approved August 15, 1999)    1999 Form 10-K, Exhibit 10(e), File No. 1-2732
10.44    IP    *Letter Agreement dated March 6, 2003, between Dynegy Inc. and Shawn E. Schukar   

2003 Form 10-K, Exhibit 10.14,

File No. 1-3004

10.45   

Ameren

UE

CIPS

Genco

CILCORP

CILCO

    *Separation and Release Agreement of Garry L. Randolph, dated September 17, 2004    September 24, 2004 Form 8-K, Exhibit 10.1, File No. 1-14756
Statement re: Computation of Ratios
12.1    Ameren    Ameren’s Statement of Computation of Ratio of Earnings to Fixed Charges    **
12.2    UE    UE’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements    **
12.3    CIPS    CIPS’ Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements    **

 

114

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
12.4    Genco    Genco’s Statement of Computation of Ratio of Earnings to Fixed Charges    **
12.5    CILCORP    CILCORP’s Statement of Computation of Ratio of Earnings to Fixed Charges    **
12.6    CILCO    CILCO’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements    **
12.7    IP    IP’s Statement of Computation of Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Stock Dividend Requirements    **
Code of Ethics
14.1    Ameren Companies    Code of Ethics amended as of June 11, 2004    June 30, 2004 Form 10-Q, Exhibit 14.1, 1-14756
Subsidiaries of the Registrant
21.1    Ameren Companies    Subsidiaries of Ameren    **
Consent of Experts and Counsel
23.1    Ameren    Consent of Independent Registered Public Accounting Firm with respect to Ameren    **
23.2    UE    Consent of Independent Registered Public Accounting Firm with respect to UE    **
23.3    CIPS    Consent of Independent Registered Public Accounting Firm with respect to CIPS    **
Power of Attorney
24.1    Ameren    Power of Attorney with respect to Ameren    **
24.2    UE    Power of Attorney with respect to UE    **
24.3    CIPS    Power of Attorney with respect to CIPS    **
24.4    Genco    Power of Attorney with respect to Genco    **
24.5    CILCORP    Power of Attorney with respect to CILCORP    **
24.6    CILCO    Power of Attorney with respect to CILCO    **
24.7    IP    Power of Attorney with respect to IP    **
Rule 13a-14(a)/15d-14(a) Certifications
31.1    Ameren    Rule13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Ameren    **
31.2    Ameren    Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Ameren    **
31.3   

UE

CIPS

CILCORP

CILCO

IP

    Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE, CIPS, CILCORP, CILCO and IP    **

 

115

Exhibit Designation    Registrant(s)    Nature of Exhibit    Previously Filed as Exhibit to:
31.4   

UE

CIPS

Genco

CILCORP

CILCO

IP

    Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE, CIPS, Genco, CILCORP, CILCO and IP    **
31.5    Genco    Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco    **
31.6    CILCO    Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCO with respect to the Form 10-K/A     
31.7    CILCO    Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCO with respect to the Form 10-K/A     
Section 1350 Certifications
32.1   

Ameren

UE

CIPS

CILCORP

CILCO

IP

    Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren, UE, CIPS, CILCORP, CILCO and IP    **
32.2    Genco    Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco    **
32.3    CILCO    Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCO     
Additional Exhibits
99.1   

Ameren

UE

    Stipulation and Agreement dated July 15, 2002 in Missouri Public Service Commission Case No. EC-2002-1 (earnings complaint case against UE)    Exhibit 99.1, File Nos. 333-87506 and 333-87506-01
99.2    Ameren Companies    Illinois Governor’s Letter to the Commissioners of the ICC, dated September 2, 2005    September 15, 2005 Form 8-K, Exhibit 99.1, File No. 1-14756
99.3    Ameren Companies    Ameren Illinois Utilities’ Letter to the Illinois Governor, dated September 15, 2005    September 15, 2005 Form 8-K, Exhibit 99.2, File No. 1-14756

The file number references for the Ameren Companies’ filings with the SEC are: Ameren, 1-14756; UE, 1-2967; CIPS, 1-3672; Genco, 333-56594; CILCORP, 2-95569; CILCO, 1-2732; and IP, 1-3004.

*Management compensatory plan or arrangement.

**Previously filed with the Form 10-K for the year ended December 31, 2005, filed by the Ameren Companies with the SEC on March 7, 2006.

Each registrant hereby undertakes to furnish to the SEC upon request a copy of any long-term debt instrument not listed above that such registrant has not filed as an exhibit pursuant to the exemption provided by Item 601(b)(4)(iii)(A) of Regulation S-K.

 

116