Ameren Illinois Co - Annual Report: 2005 (Form 10-K)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

OR

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

Each of the following classes or series of securities is registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 and is listed on the New York Stock Exchange:

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

Ameren Energy Generating Company, CILCORP Inc., and Illinois Power Company do not have securities registered under either Section 12(b) or 12(g) of the Securities Exchange Act of 1934.

Indicate by check mark if each registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act of 1933.

Indicate by check mark if each registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.

Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes  (X)          No  (  )

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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of each registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Securities Exchange Act of 1934.

Indicate by check mark whether each registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).

As of June 30, 2005, Ameren Corporation had 203,710,912 shares of its $0.01 par value common stock outstanding. The aggregate market value of these shares of common stock (based upon the closing price of these shares on the New York Stock Exchange on that date) held by nonaffiliates was $11,265,213,437. The shares of common stock of the other registrants were held by affiliates as of June 30, 2005.

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

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DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement of Ameren Corporation and portions of the definitive information statements of Union Electric Company, Central Illinois Public Service Company, and Central Illinois Light Company for the 2006 annual meetings of shareholders are incorporated by reference into Part III of this Form 10-K.

OMISSION OF CERTAIN INFORMATION

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

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

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This Form 10-K contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included on page 8 of this Form 10-K under the heading “Forward-looking Statements”. Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.

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GLOSSARY OF TERMS AND ABBREVIATIONS

We use the words “our,” “we” or “us” with respect to certain information that relates to all Ameren Companies, as defined below. When appropriate, subsidiaries of Ameren are named specifically as we discuss their various business activities.

AERG – AmerenEnergy Resources Generating Company, a CILCO subsidiary that operates a non-rate-regulated electric generation business in Illinois.

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.

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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.

NO_x – Nitrogen oxide.

Noranda – Noranda Aluminum, Inc.

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

NYMEX – New York Mercantile Exchange.

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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.

FORWARD-LOOKING STATEMENTS

Statements in this report not based on historical facts are considered “forward-looking” and, accordingly, involve risks and uncertainties that could cause actual results to differ materially from those discussed. Although such forward-looking statements have been made in good faith and are based on reasonable assumptions, there is no assurance that the expected results will be achieved. These statements include (without limitation) statements as to future expectations, beliefs, plans, strategies, objectives, events, conditions, and financial performance. In connection with the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, we are providing this cautionary statement to identify important factors that could cause actual results to differ materially from those anticipated. The following factors, in addition to those discussed elsewhere in this report and in our other filings with the SEC, could cause actual results to differ materially from management expectations suggested in such forward-looking statements:

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Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements to reflect new information or future events.

PART I

ITEM 1. BUSINESS.

GENERAL

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with FERC under PUHCA 2005. Ameren was registered with the SEC as a public utility holding company under PUHCA 1935 until February 8, 2006, when PUHCA 1935 was repealed. Ameren was formed in 1997 by the merger of UE and CIPSCO, the former parent company of CIPS. Ameren acquired CILCORP in 2003 and IP in 2004. Ameren’s primary asset is the common stock of its subsidiaries, including UE, CIPS, Genco, CILCORP and IP. 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 upon distributions made to it by its subsidiaries.

The following table presents our total employees at December 31, 2005:

The IBEW, the IUOE, the NCF&O and the Laborers and Gas Fitters labor unions collectively represent about 63% of Ameren’s total employees, and 72%, 72%, 68%, 63%, 63% and 86% of the employees of UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. An IBEW contract representing about 350 UE workers expires on September 30, 2006. The remaining collective bargaining agreements covering UE, CIPS, Genco, CILCO and IP employees expire throughout 2007.

For additional information about the development of our businesses, our business operations and factors affecting our operations and financial position, see Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report and Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report. For additional information on reporting segments, see Note 18 – Segment Information to our financial statements under Part II, Item 8, of this report.

RATES AND REGULATION

Rates

Rates that UE, CIPS, CILCO and IP are allowed to charge for their services are the single most important influence upon their and Ameren’s consolidated results of

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operations, financial position, and liquidity. The rates charged to UE, CIPS, CILCO and IP customers are determined by governmental entities. Decisions by these entities are influenced by many factors, including the cost of providing service, the quality of service, regulatory staff knowledge and experience, economic conditions, public policy, and social and political views. Decisions made by these organizations regarding rates could have a material impact on the results of operations, financial position, or liquidity of UE, CIPS, CILCORP, CILCO, IP and Ameren on a consolidated basis.

As to rates and other matters, CIPS, CILCO and IP are subject to regulation by the ICC. UE is subject to regulation by the MoPSC. Genco and CILCORP, excluding CILCO operations, are not subject to regulation by the ICC or the MoPSC.

UE, CIPS, Genco, CILCO and IP are also subject to regulation by FERC as to their ability to charge market-based rates in connection with the wholesale sale of energy and transmission in interstate commerce and various other matters discussed below under General Regulatory Matters. Less than 5% of our electric operating revenues relate to transmission revenues regulated by FERC.

The following table presents the approximate percentage of electric and gas operating revenues subject to regulation by the MoPSC and the ICC for each of the Ameren Companies for the year ended December 31, 2005:

If certain criteria are met, UE’s, CIPS’, CILCO’s and IP’s gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas purchase costs to be passed directly to the consumer in Missouri and Illinois. There is currently no similar provision that would allow regulated electric operations to pass their fuel or purchased power costs directly to the consumer. However, a new law enacted in July 2005 enables the MoPSC to put in place fuel, purchased power, and environmental cost recovery mechanisms for Missouri’s utilities. Detailed rules are expected to be issued by the MoPSC in 2006. In addition, the ICC issued an order in January 2006 that will allow CIPS, CILCO and IP to recover prudently incurred power costs directly from the consumer effective January 2, 2007. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for actions taken by certain Illinois legislators, the Illinois governor, the Illinois attorney general, and others regarding this matter.

Environmental adjustment rate riders authorized by the ICC permit the recovery of prudently incurred MGP remediation and litigation costs from CIPS’, CILCO’s and IP’s Illinois electric and natural gas utility customers. As a part of the order approving Ameren’s acquisition of IP, the ICC authorized IP to implement a tariff rider to recover 90% of the costs of asbestos-related litigation claims in excess of $20 million from its electric utility customers, subject to certain terms, beginning in 2007. MoPSC natural gas pipeline replacement cost clauses allow the recovery of infrastructure replacement costs from gas utility customers. However, in conjunction with its 2004 Missouri gas rate case settlement, UE agreed to not seek recovery under a gas pipeline replacement cost clause before January 1, 2006.

For further information on rate matters, including the Missouri law enabling a fuel, purchased power and environmental cost recovery mechanism, the ICC order allowing for the recovery of prudently incurred power costs effective January 2, 2007, UE’s 2002 Missouri electric rate case settlement, UE’s 2004 Missouri gas rate case settlement, IP’s 2004 gas rate case settlement, CIPS’, CILCO’s and IP’s 2005 pending electric delivery services rate cases, proposed amendments to the joint dispatch agreement among UE, CIPS and Genco, and the ending of rate moratoriums in Missouri and Illinois in 2006, see Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 3 – Rate and Regulatory Matters, and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

General Regulatory Matters

Before February 8, 2006, Ameren was a registered holding company under PUHCA 1935. PUHCA 1935 regulated the issuance of securities, sales and acquisitions of securities and utility assets, affiliate transactions, financial reporting requirements, services performed by Ameren Services and AFS, and activities of certain other subsidiaries. Among other things, the issuance of common stock and short-term and long-term debt and other securities by Ameren and CILCORP and the issuance of debt with a maturity of 12 months or less by UE, CIPS, CILCO and IP were subject to approval by the SEC under PUHCA 1935.

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PUHCA 2005, enacted as part of the Energy Policy Act of 2005, repealed PUHCA 1935 effective February 8, 2006. As a consequence, authorization from the SEC under PUHCA 1935 is no longer required for any of the Ameren Companies to take any action, including the issuance of securities. With the repeal of PUHCA 1935, UE, CIPS, CILCO and IP now require the approval of FERC instead of the SEC to issue short-term debt securities. In addition, these Ameren utilities will continue to need authorization from the applicable state public utility regulatory agency to issue stock and long-term debt securities with maturities of more than 12 months and to conduct mergers, affiliate transactions, and various other activities. Genco and EEI will continue to be subject to FERC’s jurisdiction when they issue securities, long-term or short-term.

Although PUHCA 2005 does not impose any new substantive approval requirements on Ameren or its subsidiaries, it gives FERC and any state public utility regulatory agencies access to books and records of Ameren and its subsidiaries that are determined to be relevant to costs incurred by Ameren’s rate-regulated subsidiaries with respect to jurisdictional rates. PUHCA 2005 also permits Ameren, the ICC, or the MoPSC to request that FERC review cost allocations by Ameren Services to other Ameren companies.

In conjunction with the repeal of PUHCA 1935, Congress also amended the Federal Power Act, effective February 8, 2006, to give FERC jurisdiction over certain acquisitions, mergers and consolidations involving electric utility holding companies. In general, acquisitions of securities or assets of electric utilities or electric utility holding companies, and mergers or consolidations of such companies in transactions having a value in excess of $10 million, may require approval by FERC. FERC has recently adopted rules that, among other things, grant blanket authorizations for specified types of transactions subject to these requirements.

Operation of UE’s Callaway nuclear plant is subject to regulation by the NRC. Its facility operating license expires on October 18, 2024. UE’s Osage hydroelectric plant and UE’s Taum Sauk pumped-storage hydroelectric plant, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other things, the general operation and maintenance of the projects. The license for the Osage plant expired on February 28, 2006, but the plant is allowed to operate under this license pending FERC’s decision on UE’s license renewal application. In May 2005, the U.S. Department of the Interior and various state agencies reached a settlement agreement that is expected to lead to FERC’s relicensing of UE’s Osage plant for another 40 years. The settlement must be approved by FERC. The license for UE’s Taum Sauk plant expires on June 30, 2010. The Taum Sauk plant is currently out of service due to a major breach of the upper reservoir in December 2005. The incident is being investigated by state and federal authorities. UE’s Keokuk plant and its dam, in the Mississippi River between Hamilton, Illinois, and Keokuk, Iowa, are operated under authority, unlimited in time, granted by an Act of Congress in 1905.

For additional information on regulatory matters, see Note 3 – Rate and Regulatory Matters, and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, which include a discussion relating to the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric plant.

Environmental Matters

Certain of our operations are subject to federal, state, and local environmental statutes or regulations relating to the safety and health of personnel, the public, and the environment. These matters include identification, generation, storage, handling, transportation, disposal, record keeping, labeling, reporting, and emergency response in connection with hazardous and toxic materials, safety and health standards, and environmental protection requirements, including standards and limitations relating to the discharge of air and water pollutants. Failure to comply with those statutes or regulations could have material adverse effects on us. We could be subjected to criminal or civil penalties by regulatory agencies. We could be ordered to make payment to private parties by the courts. Except as indicated in this report, we believe that we are in material compliance with existing statutes and regulations.

For additional discussion of environmental matters, including potential NO_x, SO₂, and mercury emission reduction requirements and the December 2005 breach of the upper reservoir at UE’s Taum Sauk hydroelectric plant, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

SUPPLY FOR ELECTRIC POWER

During 2005, the Ameren Companies’ peak demand from retail and wholesale customers was 17,563 megawatts. The peak capability to deliver power from owned generation and power supply agreements was 20,567 megawatts. Forecasted peak demand from retail and wholesale customers for 2006 is 17,483 megawatts. Ameren-owned generation and purchased power meet the energy needs of UE, CIPS, Genco, CILCO and IP customers with a greater

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than 15% reserve margin. Factors that could cause us to purchase power include, among other things, absence of sufficient owned generation, plant outages, extreme weather conditions, and the availability of power at a cost lower than our cost of generating it. Contracts to supply CIPS and CILCO from Genco and AERG, respectively, expire at the end of 2006. See Note 3 – Rate and Regulatory Matters and Note 14 – Related Party Transactions to our financial statements under Part II, Item 8, of this report.

In December 2005, UE entered into asset purchase and sale agreements to acquire three CT facilities, totaling 1,490 megawatts of capacity at a price of $290 million. These purchases are designed to meet UE’s increased generating capacity needs as well as provide UE with additional flexibility in determining future baseload generating capacity additions. UE expects the addition of these CT facilities will satisfy demand growth until 2015. In the meantime, UE will be evaluating baseload electric generating plant options for 2015 and beyond, including coal-fired, nuclear, pumped-storage and integrated gasification combined cycle coal technology. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.

The acquisition of IP on September 30, 2004, included IP’s rate-regulated electric and gas transmission and distribution business. IP owns no significant generation assets. It obtains almost all of the electricity that it supplies to retail customers through short-term and long-term power purchase agreements. IP’s primary power supply contract with Dynegy expires at the end of 2006. For additional information on IP’s power purchase agreements, see Note 2 – Acquisitions to our financial statements under Part II, Item 8, of this report.

The following table presents the source of electric generation, excluding purchased power, for the years ended December 31, 2005, 2004 and 2003:

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The following table presents the cost of fuels for electric generation for the years ended December 31, 2005, 2004 and 2003. Oil, propane, and tire chips are excluded from this table because their use is minimal:

Coal

UE, Genco and CILCO have agreements in place to purchase coal and to transport it to electric generating facilities through 2011. Coal supply agreements typically have an initial term of five years, with about 20% of the contracts expiring annually. In 2005, UE, Genco and CILCO received 90% to 95% of expected Powder River Basin coal deliveries due to disruptions in rail deliveries. In 2006, UE’s, Genco’s and CILCO’s objective is to replace the coal inventories lost due to the rail delivery problems in 2005, and to begin building coal inventory levels in case of future disruptions of coal supply. As of December 31, 2005, 100% of UE’s, Genco’s and CILCO’s expected 2006 coal usage was under contract, and about 64% of the expected coal usage for 2007 to 2010 was under contract. Ameren burned 40 million (UE - 23 million, Genco - 8 million, CILCO - 4 million, EEI - 5 million) tons of coal in 2005.

UE, Genco and CILCO have a policy to maintain coal inventory consistent with their historical usage. Inventory may be adjusted because of uncertainties of supply due to potential work stoppages, delays in coal deliveries, equipment breakdowns, and other factors. As of December 31, 2005, coal inventories for UE, Genco and CILCO were adequate, but below historical levels due to the rail disruptions from the Powder River Basin. Additional disruptions in deliveries of coal in 2006 could cause UE, Genco and CILCO to incur higher fuel and purchased power costs and reduce their interchange sales.

Nuclear

UE has agreements or inventories to fulfill its Callaway nuclear plant’s need for uranium and conversion, enrichment and fabrication services through 2007. UE also has agreements or inventories to meet 69% of the 2008 to 2010 requirements. UE expects to enter into additional contracts to purchase nuclear fuel from time to time. Prices are expected to increase over the next few years. UE is a member of Fuelco, which allows UE to combine fuel needs and expertise with the other members, and thereby to increase its purchasing power and opportunities for volume discounts. The Callaway nuclear plant normally requires refueling at 18-month intervals. The last refueling was completed in November 2005. The next refueling is scheduled for spring 2007.

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Natural Gas Supply for Power Generation

Our natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to our generating units. We do this in two ways. We optimize transportation and storage options, and we minimize cost and price risk through various supply and price hedging agreements that allow us to maintain access to multiple gas pools, supply basins, and storage. For 2006, 66% of Ameren’s estimated required natural gas supply for generation is under contract. As of December 31, 2005, 21% of Ameren’s 2006 required gas supply for generation for 2006 was hedged for price risk. For 2007 to 2010, 4% of Ameren’s estimated required natural gas supply for generation is hedged for price risk.

Purchased Power

We believe that we can obtain enough purchased power to meet future needs. However, during periods of high demand, the price and availability of purchased power may be significantly affected. The Ameren transmission system has a minimum of 18 direct connections to other control areas, which give us access to numerous sources of supply. UE, CIPS, CILCO and IP are members of the MISO. Effective April 1, 2005, the MISO Day Two Energy Market began operation; it is designed to improve transparency of power pricing and to make generation dispatch more efficient.

CIPS, CILCO and IP have contracts in place to supply almost all of their power needs through 2006. For a description of IP’s primary power supply contract with Dynegy and a description of CIPS’ and CILCO’s power supply contracts with affiliates, see Note 2 – Acquisitions, and Note 14 – Related Party Transactions to our financial statements under Part II, Item 8, of this report.

On December 31, 2006, the current Illinois electric rate freeze expires, as do the supply contracts for the power requirements of CIPS, CILCO and IP. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for their customers in 2007 through an auction. This approval is subject to rehearing and appeal.

Copies of the Illinois governor’s letter to the ICC in opposition to the power procurement auction and related cost recovery mechanism and CIPS’, CILCO’s and IP’s response letter appear as Exhibits 99.1 and 99.2, respectively, to the Current Report on Form 8-K dated September 15, 2005.

Certain Illinois legislators, the Illinois governor and the Illinois attorney general assert that the energy component of CIPS’, CILCO’s and IP’s retail rates for electricity should not be based on their costs to procure energy and capacity in the wholesale market. We are unable to predict whether certain Illinois legislators, the Illinois governor, the Illinois attorney general, or other parties will ultimately succeed in preventing the implementation of the power procurement auction and the related cost recovery mechanism approved by the ICC and the impact of a different process to procure power or recover costs (if any is implemented) would have on our results of operations, financial position, or liquidity. 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. As noted in the Ameren Illinois utilities’ 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 credit rating changes recently issued in response to actions in Illinois, and Risk Factors under Part I, Item 1A, and Note 3 – Rate and Regulatory Matters, under Part II, Item 8, of this report for a discussion of the ICC and court proceedings related to the power procurement auction and the related cost recovery mechanism and Illinois legislative activity.

NATURAL GAS SUPPLY FOR DISTRIBUTION

UE, CIPS, CILCO and IP are responsible for the purchase and delivery of natural gas to their gas utility customers. UE, CIPS, CILCO and IP develop and manage a portfolio of gas supply resources, including firm gas supply under term agreements with producers, interstate and intrastate firm transportation capacity, firm storage capacity leased from interstate pipelines, and on-system storage facilities to maintain gas deliveries to our customers throughout the year and especially during peak demand. UE, CIPS, CILCO and IP primarily use the Panhandle Eastern Pipe Line Company, the Trunkline Gas Company, the Natural Gas Pipeline Company of America, the Mississippi River Transmission Corporation, and the Texas Eastern Transmission Corporation interstate pipeline systems to transport natural gas to our systems. In addition to physical transactions, financial instruments including those entered into in the NYMEX futures market and in the OTC financial markets are used to hedge the price paid for natural gas. Prudently incurred natural gas purchase costs are passed on to UE, CIPS, CILCO and IP gas customers in Illinois and Missouri dollar-for-dollar under PGA clauses, subject to review by the ICC and the MoPSC.

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For additional information on our fuel and purchased power supply, see Results of Operations, Liquidity and Capital Resources and Effects of Inflation and Changing Prices in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report; Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, of this report; and Note 1 – Summary of Significant Accounting Policies, Note 9 – Derivative Financial Instruments, Note 14 – Related Party Transactions, Note 15 – Commitments and Contingencies, and Note 16 – Callaway Nuclear Plant to our financial statements under Part II, Item 8, of this report.

INDUSTRY ISSUES

We are facing issues common to the electric and gas utility industry. These issues include:

We are monitoring these issues. We are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Outlook and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Note 3 – Rate and Regulatory Matters, and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

OPERATING STATISTICS

The following tables present key electric and natural gas operating statistics for Ameren for the past three years. CILCORP and CILCO are included only for the periods after January 31, 2003. Unless otherwise indicated, IP is included only for the periods after September 30, 2004.

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AVAILABLE INFORMATION

The Ameren Companies make available free of charge through Ameren’s Internet Web site (www.ameren.com) their annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably possible after such reports are electronically filed with, or furnished to, the SEC.

The Ameren Companies also make available free of charge through Ameren’s Web site (www.ameren.com) the charters of Ameren’s board of directors’ audit committee, human resources committee, nominating and corporate governance committee, nuclear oversight committee and public policy committee; the corporate governance guidelines; shareholder communications policy; and director nomination policy that apply to the Ameren Companies.

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These documents are also available in print upon written request to Ameren Corporation, Attention: Secretary, P.O. Box 66149, St. Louis, Missouri 63166-6149.

ITEM 1A. RISK FACTORS

The electric and gas rates that certain Ameren Companies are allowed to charge in Missouri and Illinois are largely set through 2006. These “rate freezes,” along with other actions of lawmakers and regulators that can significantly adversely affect our prospective earnings, liquidity, or business activities, are largely outside our control.

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

As a part of the settlement of UE’s Missouri electric rate case in 2002, UE is subject to a rate moratorium that prohibits changes in its electric rates in Missouri before July 1, 2006, with limited statutory and other exceptions. Furthermore, as part of the settlement of UE’s Missouri gas rate case, which was approved by the MoPSC in January 2004, UE agreed to make no changes in its gas delivery rates prior to July 1, 2006, with certain exceptions. In accordance with the August 2002 MoPSC order, UE submitted a confidential cost of electric service study to the MoPSC Staff and others in December 2005, which was 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 affect the decision, including determining the appropriate test year to use in a potential rate filing to set future rates, economic and energy market conditions, expected generating plant additions, and fuel, purchased power, and environmental cost recovery mechanisms, 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.

The ICC order approving Ameren’s acquisition of IP prohibited IP from filing for any increase in gas delivery rates effective before January 1, 2007, beyond IP’s then-pending request for a gas delivery rate increase. In addition, a provision of the Illinois Customer Choice Law related to the restructuring of the Illinois electric industry put a rate freeze into effect through January 1, 2007, for CIPS, CILCO and IP. This Illinois legislation also requires that 50% of the earnings from each respective jurisdiction in excess of certain levels be refunded to CIPS’, CILCO’s and IP’s Illinois customers through 2006. In January 2006, the ICC approved a framework for CIPS, CILCO and IP to procure power for use by their customers in 2007 through an auction and related tariffs. This approval is subject to rehearing and appeal. In addition, 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, through rates to customers, of related costs for power supply resulting from the auction. 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, including 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, impaired customer service, job losses, and financial insolvency. See the Credit Ratings section in Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report for a discussion of the credit rating changes recently issued in response to actions in Illinois.

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 Illinois legislators, the Illinois attorney general, the Illinois governor and other stakeholders, or that the legal and

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regulatory actions, strategies and alternatives that Ameren and the Ameren Illinois utilities are considering will be successful.

In December 2005, the Ameren Illinois utilities filed with the ICC proposed new tariffs that would increase revenues from electric delivery services, effective January 2, 2007, based on a proposed residential rate phase-in plan, by $156 million (CIPS – $14 million, CILCO – $33 million, IP – $109 million) per year commencing in 2007 and an additional $46 million (CILCO – $10 million, IP – $36 million) per year commencing in 2008. These proposed tariffs are subject to approval of, and reduction by, the ICC, which is expected to rule by November 2006. We cannot predict the outcome of these proceedings.

As a part of the settlement of UE’s Missouri electric rate case in 2002, UE undertook to use commercially reasonable efforts to make critical energy infrastructure investments of $2.25 billion to $2.75 billion from January 1, 2002, through June 30, 2006. Ameren also committed IP to make between $275 million and $325 million in energy infrastructure investments over its first two years of ownership, in conjunction with the ICC’s approval of Ameren’s acquisition of IP. UE’s agreement to a rate moratorium in Missouri and CIPS’, CILCO’s and IP’s rate freezes mean that capital expenditures will not become recoverable in rates and will not earn a return before at least July 1, 2006, for UE and January 2, 2007, for CIPS, CILCO and IP. In the current climate of rate reductions and rate moratoriums, any new energy infrastructure and new programs could result in increased financing requirements for UE, CIPS, CILCO and IP. This could have a material impact on our results of operations, financial position, and liquidity.

As of December 31, 2005, the Ameren Companies did not have, in either Missouri or Illinois, a rate adjustment clause for their electric operations that would allow them to recover the costs for purchased power or increased fuel costs from customers. Therefore, in so far as we have not hedged our fuel and power costs, we are exposed to changes in fuel and power prices to the extent that fuel for our electric generating facilities and power must be purchased on the open market. See the Outlook section in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a discussion of Missouri legislation enabling a fuel and purchased power adjustment clause and an ICC order allowing for the recovery of power costs, effective January 2, 2007.

Steps taken and being considered at the federal and state levels continue to change the structure of the electric industry and utility regulation. At the federal level, FERC has been mandating changes in the regulatory framework for transmission-owning public utilities such as UE, CIPS, CILCO and IP.

Principally because of rate reductions and rate moratoriums that affect certain Ameren Companies, increased costs and investments have caused decreased returns in Ameren’s distribution utility businesses. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report. In response to competitive, economic, political, legislative and regulatory pressures, we may be subject to further rate moratoriums, rate refunds, limits on rate increases or rate reductions, including phase-in plans. Any or all of these could have a significant adverse effect on our results of operations, financial position, or liquidity.

Increased federal and state environmental regulation will require UE, Genco, CILCO (primarily through AERG) and EEI to incur large capital expenditures and to increase operating costs.

About 61% of Ameren’s generating capacity is coal-fired. The rest is nuclear, gas-fired, hydroelectric, and oil-fired. In May 2005, the EPA issued final regulations with respect to SO₂, NO_x, and mercury emissions from coal-fired power plants. The new rules require significant additional reductions in these emissions from UE, Genco, AERG and EEI power plants in phases, beginning in 2009. Preliminary estimates of capital compliance costs for Ameren, UE, Genco and AERG range from $2.1 billion to $2.9 billion by 2016.

State regulators are required to submit state implementation plans for SO₂, NO_x and mercury emissions controls in 2006. In January 2006, the governor of Illinois recommended that the Illinois EPA adopt rules for limitations on mercury emissions which would be significantly stricter than the federal rules. The drafting of state rules 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, AERG’s and EEI’s coal-fired power plants and increase related costs from previous estimates.

Future initiatives regarding greenhouse gas emissions and global warming continue to be the subject of much debate. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities. Coal-fired power plants, however, are significant sources of carbon dioxide, a principal greenhouse gas. The related Kyoto Protocol was signed by the United States but has since been rejected by the president, who instead has asked for an 18% decrease in carbon intensity

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on a voluntary basis. 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 by the utility sector between 2002 and 2012. Currently, Ameren is considering various initiatives to comply with the MOU, including increased generation at our nuclear and hydroelectric power plants, increased efficiency measures at our coal-fired units, and investing in renewable energy and carbon sequestration projects.

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

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

We are unable to predict the ultimate effect of any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation on our results of operations, financial position, or liquidity. Any of these factors could result in a significant increase in capital expenditures, penalties and operating costs for UE, Genco, CILCO (primarily through AERG) and EEI. Therefore, such factors could also result in increased financing requirements for these Ameren companies. Although costs incurred by UE would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar mechanism for recovery of costs by Genco, AERG or EEI in Illinois.

UE’s, CIPS’, CILCO’s and IP’s participation in the MISO could continue to increase costs, reduce revenues, and reduce UE’s, CIPS’, CILCO’s and IP’s control over their transmission assets. Genco could also incur increased costs or reduced revenues by its participation in the MISO Day Two Energy Market.

On May 1, 2004, functional control of the UE and CIPS transmission systems was transferred to the MISO. On September 30, 2004, IP transferred functional control of its transmission system to the MISO. CILCO had transferred functional control of its transmission system to the MISO before its acquisition by Ameren. UE, CIPS, CILCO and IP may be required to incur expenses or expand their transmission systems according to decisions made by MISO rather than according to their internal planning process. See Note 3 – Rate and Regulatory Matters, to our financial statements under Part II, Item 8, of this report.

The MISO Day Two Energy Market, which began operation on April 1, 2005, is designed to improve transparency of power pricing and efficiency in generation dispatch. This is a new and complex market, which has incurred significant price volatility and suboptimal dispatching of power plants. In addition, the sale of power in this market-based environment has resulted in unanticipated transmission congestion and other settlement charges.

Until we achieve a greater degree of operational experience participating in the MISO, including the MISO Day Two Energy Market, there is considerable uncertainty as to the impact of our MISO participation. In addition, there is uncertainty regarding whether we will continue to participate in MISO, as well as the impact of ongoing RTO developments at FERC. We are unable to predict the impact these issues could have on our results of operations, financial position, or liquidity.

Increasing costs associated with our defined benefit retirement plans, health care plans, and other employee-related benefits may adversely affect our results of operations, financial position, or liquidity.

We offer defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates, and other actuarial assumptions have a significant impact on our earnings and funding requirements. At December 31, 2005, assuming continuation of the recently expired federal interest rate relief beyond 2006, we do not expect future contributions to be required to maintain minimum funding levels for Ameren’s pension plans 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 be needed in 2009 to 2010 based on other recent federal legislative proposals. In the meantime, we may continue our practice of making voluntary contributions to maintain more prudent funded levels than minimally required. These

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amounts are estimates; they may change with actual stock market performance, changes in interest rates, or any changes in government regulations.

In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased substantially in recent years. We believe that our employee benefit costs, including costs of health care plans for our employees and former employees, will continue to rise. The increasing costs and funding requirements associated with our defined benefit retirement plans, health care plans, and other employee benefits may adversely affect our results of operations, financial position, or liquidity.

UE’s, Genco’s, CILCO’s, AERG’s, Medina Valley’s and EEI’s electric generating facilities are subject to operational risks that could result in unscheduled plant outages, unanticipated operation and maintenance expenses, liability and increased purchased power costs.

UE, Genco, CILCO, AERG, Medina Valley, and EEI own and operate coal, nuclear, gas-fired, hydroelectric, and oil-fired generating facilities. Operation of electric generating facilities involves certain risks that can adversely affect energy output and efficiency levels. Among these risks are:

The breach of the upper reservoir of UE’s Taum Sauk pumped-storage hydroelectric facility could have an adverse effect on Ameren’s and UE’s results of operations, liquidity, and financial condition.

In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant flooding in the local area, which damaged a state park. This incident is being investigated by FERC and state authorities. As a result, the facility will remain out of service until after these reviews are concluded, further analyses are completed and input is received from key stakeholders as to how and whether to rebuild the facility. In 2005, the Taum Sauk facility provided 587,000 megawatthours of electricity.

As a result of this breach, UE may be subject to litigation by private parties or by state or federal authorities. To the extent that UE needs to purchase power due to the unavailability of the Taum Sauk facility, there is the risk that UE will not be permitted to recover these additional costs from ratepayers. The Taum Sauk incident is expected to reduce Ameren’s and UE’s 2006 pretax earnings by $20 million to $35 million as a result of the need to use higher cost sources of power, reduced interchange sales and increased expenses. In addition, there is also the risk that UE will not be permitted to rebuild the Taum Sauk facility upper reservoir and be required to immediately expense its remaining investment in the plant of $56 million. 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.

A substantial portion of Genco’s and CILCO’s generating capacity is committed under affiliate contracts that expire at the end of 2006. Upon expiration of these contracts, Genco’s and CILCO’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risk. With the expiration of its power supply contract with affiliates on December 31, 2005, EEI’s electric generating facilities are competing for the sale of energy and capacity, which exposes EEI to price risk.

As of December 31, 2005, Genco and CILCO (through AERG) owned 4,200 megawatts and 1,100 megawatts, respectively, of non-rate-regulated electric generating facilities. Of these non-rate-regulated electric generating facilities, about 3,300 megawatts are under full-requirements contracts with our affiliates for 2006. During 2006, most of Genco’s and AERG’s other wholesale and retail electric power supply agreements will also expire. As a result, Genco and AERG will be required to compete for the sale of energy and capacity after the expiration of these agreements.

As of December 31, 2005, EEI owned 1,055 megawatts of non-rate-regulated electric generating facilities, of which Ameren’s share was 844 megawatts. On December 31,

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2005, EEI’s power supply contract with its affiliates, including UE, CIPS and IP, expired. All of EEI’s generating capacity is now competing for the sale of energy and capacity.

In January 2006, the ICC approved a process that will allow CIPS, CILCO and IP to procure power through an auction monitored by the ICC after the current Illinois rate freeze and power supply contracts end in 2006. Genco and AERG, through Marketing Company, would probably participate in this auction, but with an ICC-mandated maximum of 35% on the amount of power that could be supplied to Ameren’s Illinois utilities. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a discussion of the proceedings related to this power procurement auction process and the pending opposition to this process.

To the extent that electric capacity generated by these facilities is not under contract to be sold, the revenues and results of operations of these non-rate-regulated subsidiaries will generally depend on the prices that they can obtain for energy and capacity in Illinois and adjacent markets. Among the factors that could influence such prices (all of which are beyond our control to a significant degree) are:

UE, CIPS and Genco are parties to an agreement to jointly dispatch power. Modification or termination of this agreement could result in the transfer of electric margins from Genco to UE and the reduction of electric margins at Ameren.

Genco and UE have an agreement to dispatch their generating facilities jointly. Recently completed, ongoing or future federal and state regulatory proceedings and policies may evolve in ways that could affect Genco’s and UE’s ability to participate in this affiliate arrangement on current terms. For example, as a result of the MoPSC order approving the transfer of UE’s Illinois service territory to CIPS, the provision in the 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 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 of $35 million to $45 million.

The Missouri OPC intervened in the FERC proceeding and requested that the joint dispatch agreement be further amended to price all transfers 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

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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 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 3 – Rate and Regulatory Matters and Note 14 – Related Party Transactions to our financial statements under Part II, Item 8 of this report for a further discussion of the joint dispatch agreement.

UE’s ownership and operation of a nuclear generating facility creates business, financial, and waste disposal risks.

UE owns the Callaway nuclear plant, which represents about 12% of UE’s generation capacity. Therefore, UE is subject to the risks of nuclear generation, which include the following:

The NRC has broad authority under federal law to impose licensing and safety requirements for nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose fines, shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as

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UE’s. In addition, if a serious nuclear incident were to occur, it could have a material but indeterminable adverse effect on UE’s results of operations, financial position, or liquidity. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit.

UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in 2007. During an outage, which occurs approximately every 18 months, maintenance and purchased power costs increase, and the amount of excess power available for sale decreases, compared to non-outage years.

Operating performance at UE’s Callaway nuclear plant has resulted in unscheduled or extended outages, including the extension of Callaway’s scheduled refueling and maintenance outage in 2004. In addition, Ameren and UE incurred significant unanticipated replacement power and maintenance costs. The operating performance at UE’s Callaway nuclear plant has declined both in comparison with its past operating performance and with the operating performance of other nuclear plants in the United States. Ameren and UE are actively working to address the factors that led to the decline in Callaway’s operating performance. Management and supervision of operating personnel, equipment reliability, maintenance worker practices, engineering performance, and overall organizational effectiveness have been reviewed, with some actions taken and other actions currently under consideration. However, Ameren and UE cannot predict whether such efforts will result in an overall improvement of operations at Callaway. Any actions taken are expected to result in incremental operating costs at Callaway. Further, additional unscheduled or extended outages at Callaway could have a material adverse effect on the results of operations, financial position, or liquidity of Ameren and UE.

Our energy risk management strategies may not be effective in managing fuel and electricity pricing risks, which could result in unanticipated liabilities or increased volatility in our earnings.

We are exposed to changes in market prices for natural gas, fuel, electricity, emission credits and transmission congestion. Prices for natural gas, fuel, electricity, and emission credits may fluctuate substantially over relatively short periods of time and expose us to commodity price risk. We use long-term purchase and sales contracts in addition to derivatives such as forward contracts, futures contracts, options, and swaps to manage these risks. We attempt to manage our risk associated with these activities through enforcement of established risk limits and risk management procedures. We cannot ensure that these strategies will be successful in managing our pricing risk, or that they will not result in net liabilities because of future volatility in these markets.

Although we routinely enter into contracts to hedge our exposure to the risks of demand, market effects of weather, and changes in commodity prices, we do not hedge the entire exposure of our operations from commodity price volatility. Furthermore, our ability to hedge our exposure to commodity price volatility depends on liquid commodity markets. To the extent that commodity markets are illiquid, we may not be able to execute our risk management strategies, which could result in greater unhedged positions than we would prefer at a given time. To the extent that unhedged positions exist, fluctuating commodity prices can adversely affect our results of operations, financial position, or liquidity.

Our counterparties may not meet their obligations to us.

We are exposed to the risk that counterparties who owe us money, energy, coal or other commodities or services will not be able to perform their obligations. Should the counterparties to these arrangements (which include agreements with a subsidiary of Dynegy and others to supply electricity to IP during 2006) fail to perform, we might be forced to replace the underlying commitment at then-current market prices. In such event, we might incur losses in addition to the amounts, if any, already paid to the counterparties.

Our facilities are considered critical energy infrastructure and may therefore be targets of acts of terrorism.

Like other electric and gas utilities, our power generation plants, fuel storage facilities, and transmission and distribution facilities may be targets of terrorist activities that could result in disruption of our ability to produce or distribute some portion of our energy products. Any such disruption could result in a significant decrease in revenues or significant additional costs to repair, which could have a material adverse effect on our results of operations, financial position, or liquidity.

Our businesses are dependent on our ability to access the capital markets successfully. We may not have access to sufficient capital in the amounts and at the times needed.

We use short-term and long-term capital markets as a significant source of liquidity and funding for capital requirements, including those related to future environmental compliance, not satisfied by our operating cash flows. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. Our current credit ratings cause us to believe that we will continue to have access to the capital markets. However, events

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beyond our control may create uncertainty that could increase our cost of capital or impair our ability to access the capital markets. See the Credit Ratings section in Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for a discussion of recent credit rating changes in response to actions in Illinois with respect to the matter of power procurement commencing in 2007.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

The Ameren Companies have no information reportable under this item.

ITEM 2. PROPERTIES.

For information on our principal properties, including planned additions, replacements and transfers, see the generating facilities table below. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report. See also Note 3 – Rate and Regulatory Matters, Note 6 – Long-term Debt and Equity Financings, and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

Effective January 1, 2006, Ameren became a member of SERC, a regional electric reliability organization. SERC is responsible for promoting, coordinating and ensuring the reliability and adequacy of the bulk electric power supply system in much of the southeastern United States, including portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, and Texas. The Ameren membership covers UE, CIPS, CILCO and IP. Ameren was previously a member of MAIN, which ceased operations on January 1, 2006.

The bulk power system of UE, CIPS and Genco is operated as a single control area and transmission system under a joint dispatch agreement. This allows UE and Genco to achieve economies consistent with the provision of reliable electric service and to share the benefits and costs of that coordinated operation. See Note 3 – Rate and Regulatory Matters, and Note 14 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for a discussion of the joint dispatch agreement, including a MoPSC–required amendment and a Missouri OPC–proposed amendment, which are awaiting FERC action. In 2005, we had a minimum of 18 direct connections with other control areas for the exchange of electric energy, some directly and some through the facilities of others. CILCO continues to operate as a separate control area, so CILCO’s generating plants, including those of its subsidiary, AERG, have not been jointly dispatched with the generating plants owned by UE and Genco. EEI operates a separate control area in southern Illinois. EEI’s transmission system is directly connected to MISO and TVA. EEI’s generating units are dispatched separately. UE, CIPS, CILCO and IP are transmission-owning members of the MISO, and they have transferred functional control of their systems to the MISO. Transmission service on the UE, CIPS, CILCO and IP transmission systems are provided pursuant to the terms of the MISO OATT on file with FERC. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further information.

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The following table shows what our electric generating facilities and capability are anticipated to be at the time of our expected 2006 peak summer electrical demand:

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