Union Electric (UEPEM) 10-K 2005 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(X) Annual report pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

for the fiscal year ended December 31, 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.
1-14756	Ameren Corporation	43-1723446
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222
1-2967	Union Electric Company	43-0559760
	(Missouri Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222
1-3672	Central Illinois Public Service Company	37-0211380
	(Illinois Corporation)
	607 East Adams Street
	Springfield, Illinois 62739
	(217) 523-3600
333-56594	Ameren Energy Generating Company	37-1395586
	(Illinois Corporation)
	1901 Chouteau Avenue
	St. Louis, Missouri 63103
	(314) 621-3222
2-95569	CILCORP Inc.	37-1169387
	(Illinois Corporation)
	300 Liberty Street
	Peoria, Illinois 61602
	(309) 677-5271
1-2732	Central Illinois Light Company	37-0211050
	(Illinois Corporation)
	300 Liberty Street
	Peoria, Illinois 61602
	(309) 677-5271
1-3004	Illinois Power Company	37-0344645
	(Illinois Corporation)
	370 South Main Street
	Decatur, Illinois 62523
	(217) 424-6600

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

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

Registrant	Title of each class
Ameren Corporation	Common Stock, $0.01 par value per share and
	Preferred Share Purchase Rights
Union Electric Company	Preferred Stock, cumulative, no par value,
	Stated value $100 per share –
	$4.56 Series          $4.50 Series
	$4.00 Series          $3.50 Series
Central Illinois Light Company	Preferred Stock, cumulative, $100 par value per share –
	4 1/2% Series

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

Registrant	Title of each class
Central Illinois Public Service Company	Preferred Stock, cumulative, $100 par value per share –
	6.625% Series      4.90% Series
	5.16% Series        4.25% Series
	4.92% Series        4.00% Series
	Depository Shares, each representing one-fourth of a
	share of 6.625% Preferred Stock, cumulative,
	$100 par value per share

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

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

Ameren Corporation	Yes	(X)	No	(  )
Union Electric Company	Yes	(X)	No	(  )
Central Illinois Public Service Company	Yes	(  )	No	(X)
Ameren Energy Generating Company	Yes	(  )	No	(X)
CILCORP Inc.	Yes	(  )	No	(X)
Central Illinois Light Company	Yes	(  )	No	(X)
Illinois Power Company	Yes	(  )	No	(X)

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

Ameren Corporation	Yes	(  )	No	(X)
Union Electric Company	Yes	(  )	No	(X)
Central Illinois Public Service Company	Yes	(  )	No	(X)
Ameren Energy Generating Company	Yes	(X)	No	(  )
CILCORP Inc.	Yes	(X)	No	(  )
Central Illinois Light Company	Yes	(  )	No	(X)
Illinois Power Company	Yes	(X)	No	(  )

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

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

Ameren Corporation	(X)
Union Electric Company	(X)
Central Illinois Public Service Company	(X)
Ameren Energy Generating Company	(X)
CILCORP Inc.	(X)
Central Illinois Light Company	(X)
Illinois Power Company	(X)

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

	Large Accelerated Filer		Accelerated Filer		Non-Accelerated Filer
Ameren Corporation	(X	)	(	)	(	)
Union Electric Company	(	)	(	)	(X	)
Central Illinois Public Service Company	(	)	(	)	(X	)
Ameren Energy Generating Company	(	)	(	)	(X	)
CILCORP Inc.	(	)	(	)	(X	)
Central Illinois Light Company	(	)	(	)	(X	)
Illinois Power Company	(	)	(	)	(X	)

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

Ameren Corporation	Yes	(  )	No	(X)
Union Electric Company	Yes	(  )	No	(X)
Central Illinois Public Service Company	Yes	(  )	No	(X)
Ameren Energy Generating Company	Yes	(  )	No	(X)
CILCORP Inc.	Yes	(  )	No	(X)
Central Illinois Light Company	Yes	(  )	No	(X)
Illinois Power Company	Yes	(  )	No	(X)

As of June 30, 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:

Ameren Corporation	Common stock, $0.01 par value per share: 204,746,388
Union Electric Company	Common stock, $5 par value per share, held by Ameren Corporation (parent company of the registrant): 102,123,834
Central Illinois Public Service Company	Common stock, no par value, held by Ameren Corporation (parent company of the registrant): 25,452,373
Ameren Energy Generating Company	Common stock, no par value, held by Ameren Energy Development Company (parent company of the registrant and indirect subsidiary of Ameren Corporation): 2,000

CILCORP Inc.	Common stock, no par value, held by Ameren Corporation (parent company of the registrant): 1,000
Central Illinois Light Company	Common stock, no par value, held by CILCORP Inc. (parent company of the registrant and subsidiary of Ameren Corporation): 13,563,871
Illinois Power Company	Common stock, no par value, held by Ameren Corporation (parent company of the registrant): 23,000,000

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.

TABLE OF CONTENTS

		Page
GLOSSARY OF TERMS AND ABBREVIATIONS		6
Forward-looking Statements		8
PART I
Item 1.	Business
	General	9
	Rates and Regulation	9
	Supply for Electric Power	11
	Natural Gas Supply for Distribution	14
	Industry Issues	15
	Operating Statistics	15
	Available Information	16
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	24
Item 2.	Properties	24
Item 3.	Legal Proceedings	27
Item 4.	Submission of Matters to a Vote of Security Holders	27
Executive Officers of the Registrants (Item 401(b) of Regulation S-K)		28
PART II
Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	30
Item 6.	Selected Financial Data.	31
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Overview	33
	Results of Operations	36
	Liquidity and Capital Resources	47
	Outlook	60
	Regulatory Matters	63
	Accounting Matters	63
	Effects of Inflation and Changing Prices	64
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	65
Item 8.	Financial Statements and Supplementary Data	69
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	163
Item 9A.	Controls and Procedures	163
Item 9B.	Other Information	163
PART III
Item 10.	Directors and Executive Officers of the Registrants.	164
Item 11.	Executive Compensation.	165
Item 12.	Security Ownership of Certain Beneficial Owners and Management, and Related Stockholder Matters	169
Item 13.	Certain Relationships and Related Transactions.	170
Item 14.	Principal Accountant Fees and Services	170
PART IV
Item 15.	Exhibits and Financial Statement Schedules	171
SIGNATURES		173
EXHIBIT INDEX		180

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 todiffer 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:

• regulatory actions, including changes in regulatory policies and ratemaking determinations;

• the impact of changes to the joint dispatch agreement among UE, CIPS, and Genco ordered by or resulting from actions of regulators;

• changes in laws and other governmental actions, including monetary and fiscal policies;

• the effects of increased competition in the future due to, among other things, deregulation of certain aspects of our business at both the state and federal levels, and the implementation of deregulation, such as when the current electric rate freeze and current power supply contracts expire in Illinois in 2006;

• the effects of participation in the MISO;

• the availability of fuel such as coal, natural gas and enriched uranium used to produce electricity; the availability of purchased power and natural gas for distribution; and the level and volatility of future market prices for such commodities, including the ability to recover the costs for such commodities;

• the effectiveness of our risk management strategies and the use of financial and derivative instruments;

• prices for power in the Midwest;

• business and economic conditions, including their impact on interest rates;

• disruptions of the capital markets or other events that make the Ameren Companies’ access to necessary capital more difficult or costly;

• the impact of the adoption of new accounting standards and the application of appropriate technical accounting rules and guidance;

• actions of credit ratings agencies and the effects of such actions;

• weather conditions and other natural phenomena;

• generation plant construction, installation and performance, including costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident and its future operation;

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• operation of UE’s nuclear power facility, including planned and unplanned outages, and decommissioning costs;

• the effects of strategic initiatives, including acquisitions and divestitures;

• the impact of current environmental regulations on utilities and power generating companies and the expectation that more stringent requirements will be introduced over time, which could have a negative financial effect;

• labor disputes, future wage and employee benefits costs, including changes in returns on benefit plan assets;

• changes in the energy markets, environmental laws or regulations, interest rates, or other factors that could adversely affect assumptions in connection with the IP acquisition;

• the impact of conditions imposed by regulators in connection with their approval of Ameren’s acquisition of IP;

• the inability of our counterparties to meet their obligations with respect to contracts and financial instruments;

• the cost and availability of transmission capacity for the energy generated by the Ameren Companies’ facilities or required to satisfy energy sales made by the Ameren Companies;

• legal and administrative proceedings; and

• acts of sabotage, war, terrorism or intentionally disruptive acts.

Given these uncertainties, undue reliance should not be placed on these forward-looking statements. Except to the extent required by the federal securities laws, we undertake no obligation to 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 thecommon 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:

Ameren	UE	CIPS	Genco	CILCORP/CILCO	IP
9,136(a)	3,791	801	587	721	1,277

(a) Total for Ameren includes Ameren registrant and nonregistrant subsidiaries.

The IBEW, the IUOE, the NCF&O and the Laborers and Gas Fitters labor unions collectively represent about 63% of Ameren’s total employees, 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 Resultsof 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:

	MoPSC				ICC
	Electric(a)		Gas		Electric(a)		Gas
Ameren(b)	40	%	13	%	45	%	87	%
UE(c)	80		95		1		5
CIPS	-		-		95		100
CILCORP	-		-		93		100
CILCO	-		-		93		100
IP	-		-		100		100

(a) Interchange revenues are not subject to MoPSC or ICC regulation.

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

(c) UE transferred its Illinois electric service territory to CIPS on May 2, 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 inJanuary 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 willsatisfy 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:

	Coal		Nuclear		Natural Gas		Hydroelectric		Oil
Ameren:(a)
2005	86	%	10	%	1	%	2	%	1	%
2004	86		10		1		2		1
2003	85		13		(b	)	1		1
UE:
2005	80	%	16	%	1	%	3	%	(b	)
2004	80		17		(b	)	3		(b	)
2003	77		21		(b	)	2		(b	)
Genco:
2005	96	%	-		2	%	-		1	%
2004	98		-		2		-		(b	)
2003	98		-		2		-		(b	)
CILCORP and CILCO:
2005	99	%	-		1	%	-		(b	)
2004	99		-		1		-		(b	)
2003	100		-		(b	)	-		(b	)

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

(b) Less than 1% of total fuel supply.

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

Cost of Fuels(Dollars per million Btus)	2005		2004		2003
Ameren:(a)
Coal	$	1.160	$	1.049	$	1.049
Nuclear		.421		.432		.410
Natural gas(b)		9.044		8.471		8.665
Weighted average-all fuels(c)	$	1.194	$	1.021	$	.999
UE:
Coal	$	.994	$	.893	$	.913
Nuclear		.421		.432		.410
Natural gas(b)		8.825		6.960		9.328
Weighted average-all fuels(c)	$	.993	$	.823	$	.822
Genco
Coal	$	1.589	$	1.328	$	1.220
Natural gas(b)		9.395		8.868		8.759
Weighted average-all fuels(c)	$	1.808	$	1.474	$	1.368
CILCORP:
Coal(d)	$	1.257	$	1.288	$	1.516
Natural gas(b)		8.849		8.074		6.171
Weighted average-all fuels(c)	$	1.336	$	1.324	$	1.543
CILCO:
Coal	$	1.317	$	1.426	$	1.664
Natural gas(b)		8.849		8.074		6.171
Weighted average-all fuels(c)	$	1.396	$	1.462	$	1.690

(a) Excludes amounts for CILCORP and CILCO before the acquisition date of January 31, 2003.

(b) The fuel cost for natural gas represents the actual cost of natural gas and variable costs for transportation, storage, balancing, and fuel losses for delivery to the plant. In addition, the fixed costs for firm transportation and firm storage capacity are included to calculate fuel cost for the generating facilities.

(c) Represents all costs for fuels utilized in our electric generating facilities, to the extent applicable, including coal, nuclear, natural gas, oil, propane, tire chips, and handling.

(d) Includes impact of purchase accounting adjustment not pushed down to CILCO.

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 notbe 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:

• the potential for more intense competition in generation and supply;

• the potential for changes in laws and regulation;

• changes in the structure of the industry as a result of changes in federal and state laws, including the formation of non-rate-regulated generating entities and RTOs;

• fluctuations in power prices due to the balance of supply and demand and fuel prices;

• availability of fuel and increases in prices;

• continually developing and complex environmental laws, regulations and issues, including new air-quality standards and proposed mercury regulations;

• public concern about the siting of new facilities;

• construction of new power generating facilities;

• proposals for programs to encourage energy efficiency and renewable sources of power;

• public concerns about nuclear plant operation and decommissioning and the disposal of nuclear waste;

• consolidation of electric and gas companies; and

• global climate issues.

We are monitoring these issues. We are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see 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.

Electric Operating Statistics –Year Ended December 31,	2005		2004		2003
Electric operating revenues (millions)
Residential	$	1,805	$	1,323	$	1,247
Commercial		1,565		1,239		1,152
Industrial		1,019		815		778
Wholesale		339		335		295
Other		52		33		26
Native		4,780		3,745		3,498
Interchange		499		420		351
Miscellaneous		152		98		69
Total electric operating revenues	$	5,431	$	4,263	$	3,918
Kilowatthour sales (millions)
Residential		25,570		19,121		17,673
Commercial		24,969		20,863		19,248
Industrial		23,880		19,971		19,688
Wholesale		9,684		9,388		8,770
Other		732		421		308
Native		84,835		69,764		65,687
Interchange		11,224		13,801		12,094
Total kilowatthour sales		96,059		83,565		77,781
Residential revenue per kilowatthour (average)		7.06¢		6.92¢		7.06¢

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Electric Operating Statistics –Year Ended December 31,	2005			2004			2003
Capability at time of peak, including net purchases and sales (megawatts)
UE		9,892	(a)		9,243	(a)		9,022	(a)
Genco		4,815	(a)		4,603	(a)		4,429	(a)
CILCO		1,380			1,380			1,355
IP		4,000	(a)		(b)			-
EEI (Ameren’s ownership interest)		801			801			601
Generating capability at time of peak (megawatts)(c)
UE		9,318			8,351			8,298
Genco		3,685			4,239			4,452
CILCO		1,230			1,230			1,230
EEI (Ameren’s ownership interest)		801			801			601
Price per ton of delivered coal (average)	$	21.31		$	19.65		$	19.36
Source of energy supply
Coal		66.0	%		74.9	%		75.5	%
Gas		1.1			0.7			0.3
Oil		0.8			0.9			0.8
Nuclear		8.1			9.3			12.4
Hydroelectric		1.3			1.7			0.9
Purchased and interchanged, net		22.7			12.5			10.1
		100.0	%		100.0	%		100.0	%

(a) Includes purchases from EEI.

(b) Peak occurred before the acquisition date of September 30, 2004.

(c) Represents gross generating capability.

Gas Operating Statistics –Year Ended December 31,	2005		2004			2003
Natural gas operating revenues (millions)
Residential	$	804	$	506		$	343
Commercial		320		198			142
Industrial		158		121			123
Off-system sales		1		3			6
Other		62		38			34
Total natural gas operating revenues	$	1,345	$	866		$	648
MMBtu sales (millions of MMBtus)
Residential		67		49			35
Commercial		28		21			16
Industrial		19		18			20
Off-system sales		-		-			1
Total MMBtu sales (millions of MMBtus)		114		88			72
Peak day throughput (thousands of MMBtus)
UE		161		182			188
CIPS		143		272			282
CILCO		370		412			301	(a)
IP		569		541	(b)		-
Total peak day throughput		1,243		1,407			771

(a) Represents peak day throughput since the acquisition date of January 31, 2003. CILCO’s peak day throughput in January 2003 was 404 MMBtus.

(b) Represents peak day throughput since the acquisition date of September 30, 2004. IP’s peak day throughput for the first three quarters of 2004 was 654 MMBtus.

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, aprovision 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 hasbeen 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 alsoincur 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:

• increased prices for fuel and fuel transportation;

• facility shutdowns due to a failure of equipment or processes or operator error;

• longer-than-anticipated maintenance outages;

• disruptions in the delivery of fuel and lack of adequate inventories;

• labor disputes;

• inability to comply with regulatory or permit requirements;

• disruptions in the delivery of electricity;

• increased capital expenditure requirements, including those due to environmental regulation;

• unusual or adverse weather conditions; and

• catastrophic events such as fires, explosions, floods or other similar occurrences affecting electric generating facilities.

The breach of the upper reservoir of UE’s Taum Sauk pumped-storage hydroelectric facility could 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, thefacility 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:

• the current and future market prices for natural gas, fuel oil, and coal;

• current and forward prices for the sale of electricity;

• the extent of additional supplies of electric energy from current competitors or new market entrants;

• the pace of deregulation in our market area and the expansion of deregulated markets;

• the regulatory and pricing structures developed for evolving Midwest energy markets and the pace at which regional markets for energy and capacity develop outside of bilateral contracts;

• future pricing for, and availability of, services on transmission systems, and the effect of RTOs and export energy transmission constraints, which could limit our ability to sell energy in markets adjacent to Illinois;

• the growth rate in electricity usage as a result of population changes, regional economic conditions, and the implementation of conservation programs; and

• climate conditions in the Midwest market.

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 policiesmay 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 toreflect 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:

• potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials;

• limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with UE’s nuclear operations or those of others in the United States;

• uncertainties with respect to contingencies and assessment amounts if insurance coverage is inadequate;

• increased public and governmental concerns over the adequacy of security at nuclear power plants;

• uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives (UE’s facility operating license for the Callaway nuclear plant expires in 2024);

• limitations on the number of fuel suppliers; and

• costly and extended outages for scheduled or unscheduled maintenance.

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

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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:

Primary Fuel Source	Plant	Location	Net Kilowatt Capability(a)
UE:
Coal	Labadie	Franklin County, Mo.	2,389,000
	Rush Island	Jefferson County, Mo.	1,163,000
	Sioux	St. Charles County, Mo.	993,000
	Meramec	St. Louis County, Mo.	855,000
Total coal			5,400,000
Nuclear	Callaway	Callaway County, Mo.	1,190,000
Hydroelectric	Osage	Lakeside, Mo.	226,000
	Keokuk	Keokuk, Iowa	134,000
Total hydroelectric			360,000
Pumped-storage	Taum Sauk(b)	Reynolds County, Mo.	-
Oil (CTs)	Fairgrounds	Jefferson City, Mo.	55,000
	Meramec	St. Louis County, Mo.	55,000
	Mexico	Mexico, Mo.	55,000
	Moberly	Moberly, Mo.	55,000
	Moreau	Jefferson City, Mo.	55,000
	Howard Bend	St. Louis County, Mo.	43,000
	Venice	Venice, Ill.	25,000
Total oil			343,000
Natural gas (CTs)	Peno Creek(c)(d)	Bowling Green, Mo.	188,000
	Meramec(d)	St. Louis County, Mo.	53,000
	Venice(d)	Venice, Ill.	501,000
	Viaduct	Cape Girardeau, Mo.	26,000
	Kirksville	Kirksville, Mo.	13,000
	Audrain(c)(e)	Audrain County, Mo.	600,000
	Goose Creek(f)	Piatt County, Ill.	450,000
	Raccoon Creek(f)	Clay County, Ill.	300,000
	Pinckneyville(g)	Pinckneyville, Ill.	320,000
	Kinmundy(d)(g)	Kinmundy, Ill.	232,000
Total natural gas			2,683,000
Total UE			9,976,000
EEI:
Coal	Joppa Generating Station	Joppa, Ill.	800,000
Natural gas (CTs)	Joppa	Joppa, Ill.	44,000
Total EEI			844,000	(h)
Genco:
Coal	Newton	Newton, Ill.	1,151,000
	Coffeen	Coffeen, Ill.	900,000
	Meredosia	Meredosia, Ill.	327,000
	Hutsonville	Hutsonville, Ill.	153,000
Total coal			2,531,000
Oil	Meredosia	Meredosia, Ill.	186,000
	Hutsonville (Diesel)	Hutsonville, Ill.	3,000
Total oil			189,000
Natural gas (CTs)	Grand Tower	Grand Tower, Ill.	516,000
	Elgin(i)	Elgin, Ill.	452,000
	Gibson City	Gibson City, Ill.	232,000
	Joppa 7B(j)	Joppa, Ill.	162,000
	Columbia(k)	Columbia, Mo.	140,000
Total natural gas			1,502,000
Total Genco			4,222,000

25

Primary Fuel Source	Plant	Location	Net Kilowatt Capability(a)
CILCO:
Coal	E.D. Edwards(l)	Bartonville, Ill.	749,000
	Duck Creek(l)	Canton, Ill.	349,000
Total coal			1,098,000
Oil	Hallock (Diesel)	Peoria, Ill.	13,000
Total oil			13,000
Natural gas	Sterling Avenue(l)	Peoria, Ill.	30,000
	Indian Trails	Pekin, Ill.	10,000
Total natural gas			40,000
Total CILCO			1,151,000
Medina Valley:
Natural gas	Medina Valley	Mossville, Ill.	44,000
Total Ameren			16,237,000

(a) “Net Kilowatt Capability” is the generating capacity available for dispatch from the facility into the electric transmission grid.

(b) This facility is out of service. It will not be operational during the 2006 peak summer period because of a breach of its upper reservoir in December 2005. Its 2005 peak summer electrical demand net kilowatt capability was 440,000. See a discussion of this incident and related matters below.

(c) There is an economic development lease arrangement applicable to these CTs.

(d) Certain of these CTs have the capability to operate on either oil or natural gas (dual fuel).

(e) UE has entered into an asset purchase and sale agreement with affiliates of NRG Energy, Inc., for the purchase of this CT, subject to the authorization of various regulatory agencies and satisfaction of other customary closing conditions. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.

(f) UE entered into asset purchase and sale agreements with affiliates of Aquila, Inc., for the purchase of these CTs subject to the authorization of various regulatory agencies and satisfaction of other customary closing conditions. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.

(g) These CTs were transferred from Genco to UE in May 2005. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.

(h) This amount represents Ameren’s 80% interest in EEI. See Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.

(i) There is a tolling agreement in place for one of Elgin’s units (approximately 100 megawatts).

(j) These CTs are owned by Genco and leased to its parent, Development Company. The operating lease is for a minimum term of 15 years expiring September 30, 2015. Genco receives rental payments under the lease in fixed monthly amounts that vary over the term of the lease and range from $0.8 million to $1.0 million.

(k) Genco has granted the city of Columbia, Missouri, options to purchase an undivided ownership interest in these facilities, which would result in a sale of up to 72 megawatts (about 50%) of the facilities. Columbia can exercise one option for 36 megawatts at the end of 2010 for a purchase price of $15.5 million, at the end of 2014 for a purchase price of $9.5 million, or at the end of 2020 for a purchase price of $4 million. The other option can be exercised for another 36 megawatts at the end of 2013 for a purchase price of $15.5 million, at the end of 2017 for a purchase price of $9.5 million, or at the end of 2023 for a purchase price of $4 million. A power purchase agreement pursuant to which Columbia is now purchasing up to 72 megawatts of capacity and energy generated by these facilities from Marketing Company will terminate if Columbia exercises the purchase options.

(l) These facilities were contributed by CILCO to AERG in October 2003.

In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility. This resulted in significant local flooding, 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 by state authorities. UE expects the results of these reviews later in 2006. 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 whether, and if so, how to rebuild the facility. See Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for further information.

The following table presents electric and natural gas utility-related properties for UE, CIPS, CILCO and IP as of December 31, 2005:

	UE	CIPS	CILCO	IP
Circuit miles of electric transmission lines	3,240	1,900	330	1,850
Miles of natural gas transmission and distribution mains	3,010	5,270	3,810	8,560
Number of propane-air plants	1	1	-	-
Number of underground gas storage fields	-	3	2	7
Billion cubic feet of total working capacity of underground gas storage fields	-	3	8	15

26

Our other properties include distribution lines, underground cables, office buildings, warehouses, garages, and repair shops.

With only a few exceptions, we have fee title to all principal plants and other units of property material to the operation of our businesses, and to the real property on which such facilities are located (subject to mortgage liens securing our outstanding first mortgage bond indebtedness and to certain permitted liens and judgment liens). The exceptions are as follows:

• A portion of UE’s Osage plant reservoir, certain facilities at UE’s Sioux plant, most of UE’s Peno Creek CT facility, Genco’s Columbia CT facility, CILCO’s Indian Trails generating facility, Medina Valley’s generating facility, certain of Ameren’s substations, and most of our transmission and distribution lines and gas mains are situated on lands we occupy under leases, easements, franchises, licenses or permits.

• The United States or the state of Missouri may own or may have paramount rights to certain lands lying in the bed of the Osage River or located between the inner and outer harbor lines of the Mississippi River, on which certain of UE’s generating and other properties are located.

• The United States, the state of Illinois, the state of Iowa, or the city of Keokuk, Iowa, may own or may have paramount rights with respect to certain lands lying in the bed of the Mississippi River on which a portion of UE’s Keokuk plant is located.

Substantially all of the properties and plant of UE, CIPS, CILCO and IP are subject to the direct first liens of the indentures securing their mortgage bonds. In October 2003, CILCO transferred substantially all of its generating property and plant to its non-rate-regulated electric generating subsidiary, AERG. As part of the transfer, CILCO’s transferred generating property and plant was released from the lien of the indenture securing its first mortgage bonds. In May 2005, UE transferred substantially all of its Illinois electric and gas transmission and distribution properties to CIPS. As a part of the transfer, UE’s transferred utility properties were released from the lien of the indenture securing its first mortgage bonds and immediately became subject to the lien of the indenture securing CIPS’ first mortgage bonds.

In December 2002, UE conveyed most of its Peno Creek CT facility to the city of Bowling Green, Missouri, andleased the facility back from the city for a 20-year term. As a part of the transaction, most of UE’s Peno Creek CT property and plant was released from the lien of the indenture securing UE’s first mortgage bonds. Under the terms of this capital lease, UE retains all operation and maintenance responsibilities for the facility, and ownership of the facility will return to UE at the expiration of the lease. When ownership of the Peno Creek CT facility is returned to UE by Bowling Green, the property and plant may again become subject to the lien of any outstanding UE first mortgage bond indenture.

UE’s Audrain CT facility, upon the closing of the purchase and sale from the affiliates of NRG Energy, Inc., will be situated on land we will occupy under lease with Audrain County, Missouri, similar to the Peno Creek CT lease arrangement with Bowling Green. For additional information on this lease arrangement, see Note 3 – Rate and Regulatory Matters under Part II, Item 8, of this report.

ITEM 3. LEGAL PROCEEDINGS.

We are involved in legal and administrative proceedings before various courts and agencies with respect to matters that arise in the ordinary course of business, some of which involve substantial amounts of money. We believe that the final disposition of these proceedings, except as otherwise disclosed in this report, will not have a material adverse effect on our results of operations, financial position, or liquidity. Risk of loss is mitigated, in some cases, by insurance or contractual or statutory indemnification. We believe that we have established appropriate reserves for potential losses.

For additional information on legal and administrative proceedings, see Rates and Regulation under Item 1, Business, above. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 3 – Rate and Regulatory Matters, and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

There were no matters submitted to a vote of security holders during the fourth quarter of 2005 with respect to any of the Ameren Companies.

27

EXECUTIVE OFFICERS OF THE REGISTRANTS (ITEM 401(b) OF REGULATION S-K):

The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 2005, all positions and offices held with the Ameren Companies, tenure as officer, and business background for at least the last five years. Some executive officers hold multiple positions within the Ameren Companies; their titles are given in the description of their business experience.

AMEREN CORPORATION:

Name	Age at 12/31/05	Positions and Offices Held
Gary L. Rainwater	59	Chairman, Chief Executive Officer, President, and Director
Rainwater joined UE in 1979 as an engineer. He was elected vice president, corporate planning, in 1993. Rainwater was elected executive vice president of CIPS in January 1997 and president and chief executive officer of CIPS in December 1997. He was elected president of Resources Company in 1999 and Genco in 2000. He was elected president and chief operating officer of Ameren, UE, and Ameren Services in August 2001, at which time he relinquished his position as president of Resources Company and Genco. In January 2003, Rainwater was elected president and chief executive officer of CILCORP and CILCO upon Ameren’s acquisition of those companies. Effective January 1, 2004, Rainwater became chairman and chief executive officer of Ameren, UE, and Ameren Services, in addition to being president. At that time, he was also elected chairman of CILCORP and CILCO. Rainwater was elected chairman, chief executive officer and president of IP in September 2004 upon Ameren’s acquisition of that company. He currently holds the position of chairman and chief executive officer of CIPS, CILCO and IP, after relinquishing his position as president in October 2004.
Warner L. Baxter	44	Executive Vice President and Chief Financial Officer
Baxter joined UE in 1995 as assistant controller. He was promoted to controller of UE in 1996, elected controller of Ameren Services in 1997 and elected vice president and controller of Ameren, UE and Ameren Services in 1998. Baxter was elected vice president, controller, of CIPS in 1999 and of Genco in 2000. He was elected senior vice president, finance, of Ameren, UE, CIPS, Ameren Services, and Genco in 2001. In January 2003, Baxter was elected senior vice president of CILCORP and CILCO upon Ameren’s acquisition of those companies. Baxter was elected to his present position at Ameren, UE, CIPS, Genco, AERG, AFS, Medina Valley, CILCORP, CILCO and Ameren Services in October 2003 and at IP in September 2004, upon Ameren’s acquisition of that company.
Thomas R. Voss	58	Executive Vice President and Chief Operating Officer
Voss joined UE in 1969 as an engineer. From 1973 to 1998, he held various positions at UE, including district manager and distribution operating manager. Voss was elected vice president of CIPS in 1998 and senior vice president of UE, CIPS and Ameren Services in 1999. He was elected senior vice president of CILCORP and CILCO in 2003 and of IP in September 2004, upon Ameren’s acquisitions of those companies. In October 2003, Voss was elected president of Genco, Resources Company, Marketing Company, AFS, Ameren Energy, Medina Valley, and AERG. Voss relinquished his presidency of these companies, with the exception of Ameren Energy, Medina Valley, and Resources Company in October 2004. He was elected to his present position at Ameren in January 2005. In June 2005, Voss relinquished his position as president of Ameren Energy.
Steven R. Sullivan	45	Senior Vice President, General Counsel, and Secretary
Sullivan joined Ameren, UE, CIPS and Ameren Services in 1998 as vice president, general counsel and secretary, and he added those positions at Genco in 2000. In January 2003, Sullivan was elected vice president, general counsel, and secretary of CILCORP and CILCO upon Ameren’s acquisition of those companies. He was elected to his present position at Ameren, UE, CIPS, Genco, Marketing, Resources Company, AERG, AFS, Medina Valley, CILCORP, CILCO and Ameren Services in October 2003 and at IP in September 2004, upon Ameren’s acquisition of that company.
Jerre E. Birdsong	51	Vice President and Treasurer
Birdsong joined UE in 1977 as an economist. He was promoted to assistant treasurer in 1984 and manager of finance in 1989. He was elected as treasurer of UE in 1993. He was elected treasurer of Ameren, CIPS and Ameren Services in 1997, Resources Company in 1999, Genco, AFS and Marketing in 2000, and AERG and Medina Valley in 2003. In addition to being treasurer, in 2001 he was elected vice president at Ameren and the subsidiaries listed above, with the exception of AERG and Medina Valley. Birdsong was elected vice president at AERG and Medina Valley in 2003. Additionally, he was elected vice president and treasurer of CILCORP and CILCO in January 2003 and of IP in September 2004, upon Ameren’s acquisition of that company.

28

Name	Age at 12/31/05	Positions and Offices Held
Martin J. Lyons	39	Vice President and Controller
Lyons joined Ameren, UE, CIPS, Genco and Ameren Services in October 2001 as controller. He was elected controller of CILCORP and CILCO in January 2003, upon Ameren’s acquisition of those companies. In addition to being controller, he was elected vice president of Ameren, UE, CIPS, Genco, AERG, AFS, Medina Valley, CILCORP, CILCO and Ameren Services in 2003 and vice president and controller of IP in September 2004, upon Ameren’s acquisition of that company. He was previously employed by PricewaterhouseCoopers LLP for 13 years, most recently as a partner.
SUBSIDIARIES:
Scott A. Cisel	52	President and Chief Operating Officer (CILCO, CIPS and IP)
Cisel assumed the position of vice president and chief operating officer for CILCO in 2003, upon Ameren’s acquisition of that company. Prior to that acquisition, he served as senior vice president of CILCO. Cisel has held various management positions at CILCO in sales, customer services, and district operations, including manager of commercial office operations in 1981, manager of consumer and energy services in 1984, manager of rates, sales, and customer service in 1988, and director of corporate sales in 1993. From 1995 to 2001, he was vice president, at first managing sales and marketing, then legislative and public affairs, and later sales, marketing and trading. In April 2001, he was elected senior vice president of CILCO. In September 2004, Cisel was elected vice president of UE and Ameren Services. In October 2004, he was elected president and chief operating officer of CIPS, CILCO and IP.
Daniel F. Cole	52	Senior Vice President (CILCO, CIPS, CILCORP, Genco, IP and UE)
Cole joined UE in 1976 as an engineer. He was named UE’s manager of resource planning in 1996 and general manager of corporate planning in 1997. In 1998, Cole was elected vice president of corporate planning of Ameren Services. He was elected senior vice president at UE and Ameren Services in 1999 and at CIPS in 2001. He was elected president of Genco in 2001 and relinquished that position in 2003. He was elected senior vice president at CILCORP and CILCO in 2003 and at IP in September 2004, upon Ameren’s acquisitions of those companies.
R. Alan Kelley	53	President (Genco) and Senior Vice President (CILCO and UE)
Kelley joined UE in 1974 as an engineer. He was named UE’s manager of corporate planning in 1985, vice president of energy supply in 1988. He was elected vice president of Ameren Services in 1997 and vice president of Resources Company in 2000. Kelley was elected senior vice president of Ameren Services in 1999 and of Genco in 2000. He was elected senior vice president at CILCO in January 2003, upon Ameren’s acquisition of that company. In October 2004, Kelley was elected president of Genco, AERG, and Medina Valley, and senior vice president of UE.
Richard J. Mark	50	Senior Vice President (UE)
Mark joined Ameren Services in January 2002 as vice president of customer service. In 2003, he was elected vice president of governmental policy and consumer affairs at Ameren Services, with responsibility for government affairs, economic development, and community relations for Ameren’s operating utility companies. He was elected senior vice president at UE in January 2005, with responsibility for Missouri energy delivery. Before joining Ameren, Mark was employed for 11 years by Ancilla Systems Inc. During that time, he served as vice president for governmental affairs, chief operating officer, and for the final six years, as chief executive officer of St. Mary’s Hospital in East St. Louis, Illinois.
Donna K. Martin	58	Senior Vice President and Chief Human Resources Officer (Ameren Services)
Martin joined Ameren Services in May 2002 as vice president, human resources. In 2004, she assumed the additional responsibility of the corporate communications function. In February 2005, Martin was elected senior vice president and chief human resources officer. Before joining Ameren, she was employed from 2000 to 2002 by Faulding Pharmaceuticals of Paramus, New Jersey where she was senior vice president, human resources. Martin also served as head of human resources in North America for Pharmacia from 1999 to 2000, after working as vice president of human resources for both Monsanto Company and Baxter Healthcare Corporation.
Michael G. Mueller	42	President (AFS)
Mueller joined UE in 1986 as an engineer in corporate planning. In 1988, he became a fuel buyer in the Fossil Fuel Department, and in 1994 he was named senior fuel buyer for UE. In 1998, Mueller became director of coal trade for Ameren Energy. In 1999, he was promoted to manager of the Fossil Fuel Department of Ameren Services. Mueller was elected vice president of AFS in 2000 and president in 2004.

29

Name	Age at 12/31/05	Positions and Offices Held
Charles D. Naslund	53	Senior Vice President and Chief Nuclear Officer (UE)
Naslund joined UE in 1974 as an assistant engineer in Engineering and Construction. He became manager, nuclear operations support, in 1986. In 1991, he was named manager, nuclear engineering. He was elected vice president of power operations at UE in 1999, vice president of Ameren Services in 2000 and vice president of nuclear operations at UE in September 2004. Naslund was elected senior vice president and chief nuclear officer at UE in January 2005.
Andrew M. Serri	44	President (Ameren Energy and Marketing Company)
Serri joined Marketing Company as vice president of sales and marketing in 2000. Serri was elected vice president of marketing and trading and of Ameren Services in 2004, before being elected president of Marketing Company and vice president of Ameren Energy that same year. In June 2005, Serri was elected president of Ameren Energy.
David A. Whiteley	49	Senior Vice President (CILCO, CIPS, CILCORP, Genco, IP and UE)
Whiteley joined UE in 1978 as an engineer. In 1993, he was named manager of transmission planning and later manager of electrical engineering and transmission planning. In 2000, Whiteley was elected vice president of Ameren Services, responsible for engineering and construction and later energy delivery technical services. He was elected senior vice president of UE, CIPS and Genco in 2001, of AERG, CILCORP and CILCO in 2003, and of IP in September 2004, upon Ameren’s acquisition of that company.

Officers are generally elected or appointed annually by the respective board of directors of each company, following the election of board members at the annual meetings of shareholders. No special arrangement or understanding exists between any of the above-named executive officers and the Ameren Companies, nor to our knowledge, with any other person or persons pursuant to which any executive officer was selected as an officer. There are no family relationships among the officers. Except for Martin J. Lyons, Richard J. Mark and Donna K. Martin, all of the above-named executive officers have been employed by an Ameren company for more than five years in executive or management positions.

The Ameren Companies previously designated all officers at the level of vice president and higher as executive officers. We have changed our designations of executive officers to more closely align our designations with SEC rules. The persons identified above are the officers of the Ameren Companies for purposes of Section 16 of the Exchange Act as of the date of this report.

PART II

ITEM 5. MARKET FOR REGISTRANTS’ COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren began trading on January 2, 1998, following the merger of UE and CIPSCO on December 31, 1997. Ameren has submitted to the NYSE a certificate of the chief executive officer of Ameren certifying that he is not aware of any violation by Ameren of NYSE corporate governance listing standards.

Ameren common shareholders of record totaled 83,438 on January 31, 2006. The following table presents the price ranges and dividends paid per Ameren common share for each quarter during 2005 and 2004.

	High		Low		Close		Dividends Paid
AEE 2005 Quarter Ended:
March 31	$	52.00	$	47.51	$	49.01	63 1/2	¢
June 30		58.84		48.70		55.30	63 1/2
September 30		56.77		52.05		53.49	63 1/2
December 31		54.46		49.61		51.24	63 1/2
AEE 2004 Quarter Ended:
March 31	$	48.34	$	44.91	$	46.09	63 1/2	¢
June 30		46.28		40.55		42.96	63 1/2
September 30		46.99		42.00		46.15	63 1/2
December 31		50.36		45.95		50.14	63 1/2

30

There is no trading market for the common stock of UE, CIPS, Genco, CILCORP, CILCO or IP. Ameren holds all outstanding common stock of UE, CIPS, CILCORP and IP; Development Company holds all outstanding common stock of Genco; and CILCORP holds all outstanding common stock of CILCO.

The following table sets forth the quarterly common stock dividend payments made by Ameren and its subsidiaries during 2005 and 2004:

	2005								2004
	Quarter Ended								Quarter Ended
Registrant	December 31		September 30		June 30		March 31		December 31		September 30		June 30		March 31
UE	$	71	$	74	$	75	$	60	$	85	$	85	$	66	$	79
CIPS		14		12		9		-		29		17		10		19
Genco		29		25		20		14		9		22		17		18
CILCORP(a)		-		-		-		30		-		-		18		-
IP(b)		16		20		20		20		-		-		-		-
Nonregistrants		-		-		2		-		-		-		5		-
Ameren	$	130	$	131	$	126	$	124	$	123	$	124	$	116	$	116

(a) CILCO paid dividends to CILCORP of $20 million in the quarterly period ended March 31, 2005, and $10 million in the quarterly period ended June 30, 2004.

(b) Prior to October 2004, the ICC prohibited IP from paying dividends. If they had been permitted, IP’s dividends would have been paid directly to Illinova and indirectly to Dynegy.

On February 10, 2006, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 63.5 cents per share. The common share dividend is payable March 31, 2006, to stockholders of record on March 8, 2006.

For a discussion of restrictions on the Ameren Companies’ payment of dividends, see Liquidity and Capital Resources in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report.

The following table presents Ameren’s purchases of equity securities reportable under Item 703 of Regulation S-K:

Period	(a) Total Number of Shares (or Units) Purchased		(b) Average Price Paid per Share (or Unit)		(c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs
October 1 – 31, 2005	-			-	-	-
November 1 – 30, 2005	-			-	-	-
December 1 – 31, 2005	2,660		$	51.98	-	-
Total	2,660	(a)	$	51.98	-	-

(a) These shares of Ameren common stock were purchased by Ameren in open-market transactions in satisfaction of Ameren’s obligations upon the exercise by employees of options issued under Ameren’s Long-term Incentive Plan of 1998. Ameren does not have any publicly announced equity securities repurchase plans or programs.

None of the other Ameren Companies purchased equity securities reportable under Item 703 of Regulation S-K during the period October 1 to December 31, 2005.

ITEM 6. SELECTED FINANCIAL DATA.

For the years ended December 31, (In millions, except per share amounts)	2005		2004		2003		2002(a)		2001(a)(b)
Ameren:
Operating revenues(c)	$	6,780	$	5,135	$	4,574	$	3,841	$	3,858
Operating income(c)		1,284		1,078		1,090		873		965
Net income(c)(d)		606		530		524		382		469
Common stock dividends		511		479		410		376		350
Earnings per share        – basic(c)(d)		3.02		2.84		3.25		2.61		3.41
– diluted(c)(d)		3.02		2.84		3.25		2.60		3.40
Common stock dividends per share		2.54		2.54		2.54		2.54		2.54

31

For the years ended December 31, (In millions, except per share amounts)	2005		2004		2003		2002(a)		2001(a)(b)
As of December 31,
Total assets(e)	$	18,162	$	17,450	$	14,236	$	12,151	$	10,401
Long-term debt, excluding current maturities		5,354		5,021		4,070		3,433		2,835
Preferred stock subject to mandatory redemption		19		20		21		-		-
Preferred stock not subject to mandatory redemption		195		195		182		193		235
Common stockholders’ equity		6,364		5,800		4,354		3,842		3,349
UE:
Operating revenues	$	2,889	$	2,640	$	2,616	$	2,650	$	2,786
Operating income		640		673		787		644		681
Net income after preferred stock dividends(d)		346		373		441		336		365
Distribution to parent		280		315		288		299		283
As of December 31,
Total assets(e)	$	9,277	$	8,750	$	8,517	$	8,103	$	7,288
Long-term debt, excluding current maturities		2,698		2,059		1,758		1,687		1,599
Preferred stock not subject to mandatory redemption		113		113		113		113		155
Common stockholder’s equity		2,903		2,883		2,810		2,632		2,654
CIPS:
Operating revenues	$	934	$	735	$	742	$	824	$	840
Operating income		85		58		45		52		69
Net income after preferred stock dividends		41		29		26		23		42
Distribution to parent		35		75		62		62		33
As of December 31,
Total assets(e)	$	1,784	$	1,615	$	1,742	$	1,821	$	1,783
Long-term debt, excluding current maturities		410		430		485		534		579
Preferred stock not subject to mandatory redemption		50		50		50		80		80
Common stockholder’s equity		519		440		482		512		564
Genco:
Operating revenues	$	1,038	$	873	$	785	$	743	$	730
Operating income		257		265		197		138		195
Net income(d)		97		107		75		32		76
Distribution to parent		88		66		36		21		-
As of December 31,
Total assets	$	1,811	$	1,955	$	1,977	$	2,010	$	1,756
Long-term debt, excluding current maturities		474		473		698		698		424
Subordinated intercompany notes		197		283		411		462		508
Common stockholder’s equity		444		435		321		280		274
CILCORP:(f)
Operating revenues	$	747	$	722	$	926	$	790	$	786
Operating income		61		61		85		98		116
Net income(d)		3		10		23		25		24
Distribution to parent		30		18		27		-		15
As of December 31,
Total assets(e)	$	2,234	$	2,156	$	2,136	$	1,928	$	1,814
Long-term debt, excluding current maturities		534		623		669		791		718
Preferred stock of subsidiary subject to mandatory redemption		19		20		21		22		22
Preferred stock of subsidiary not subject to mandatory redemption		19		19		19		19		19
Common stockholder’s equity		663		548		478		495		517
CILCO:
Operating revenues	$	742	$	688	$	839	$	731	$	740
Operating income		63		58		53		97		47
Net income after preferred stock dividends(d)		24		30		43		48		12
Distribution to parent		20		10		62		40		45
As of December 31,
Total assets(e)	$	1,557	$	1,381	$	1,324	$	1,250	$	1,043
Long-term debt, excluding current maturities		122		122		138		316		243
Preferred stock subject to mandatory redemption		19		20		21		22		22
Preferred stock not subject to mandatory redemption		19		19		19		19		19
Common stockholder’s equity		543		418		323		323		341

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For the years ended December 31, (In millions, except per share amounts)	2005		2004		2003		2002(a)		2001(a)(b)
IP:(g)
Operating revenues	$	1,653	$	1,539	$	1,568	$	1,518	$	1,614
Operating income		202		216		178		203		207
Net income after preferred stock dividends(d)		95		137		115		159		158
Distribution to parent		76		-		-		-		100
As of December 31,
Total assets(e)	$	3,056	$	3,117	$	5,059	$	5,050	$	4,929
Long-term debt, excluding current maturities		704		713		1,435		1,719		1,606
Long-term debt to IP SPT, excluding current maturities(h)		184		278		345		-		-
Preferred stock not subject to mandatory redemption		46		46		46		46		46
Common stockholder’s equity		1,241		1,234		1,484		1,366		1,222

(a) At Ameren, UE and Genco, revenues were netted with costs upon adoption of EITF No. 02-3 and the rescission of EITF No. 98-10 in 2003. The amounts netted were as follows at Ameren: 2002 - $738 million; 2001 - $648 million; at UE: 2002 - $458 million; 2001 - $392 million; and at Genco: 2002 - $253 million; 2001 - $256 million.

(b) Amounts for IP have not been reclassified to conform to Ameren classifications for 2001.

(c) Includes amounts for IP since the acquisition date of September 30, 2004; includes amounts for CILCORP since the acquisition date of January 31, 2003; and includes amounts for Ameren registrant and nonregistrant subsidiaries and intercompany eliminations.

(d) For the years ended December 31, 2005 and 2003, Ameren, Genco, CILCORP, CILCO and IP net income included income (loss) from cumulative effect of change in accounting principle of $(22) million and $18 million ($(0.11) and $0.11 per share), $(16) million and $18 million, $(2) million and $4 million, $(2) million and $24 million and $- and $(2) million, respectively. Ameren, UE and Genco net income included loss from cumulative effect of change in accounting principle of $7 million ($0.05 per share), $5 million and $2 million, respectively, for the year ended December 31, 2001. CILCORP had a $2 million loss from discontinued operations in 2001 that is included in net income.

(e) Estimated future removal costs embedded in accumulated depreciation within our regulated operations at December 31, 2002, of $652 million at Ameren, $528 million at UE, $124 million at CIPS, $27 million at CILCORP, $141 million at CILCO, and $69 million at IP were reclassified to a regulatory liability to conform to current-period presentation. Prior periods were not reclassified for any of the Ameren Companies, except IP, which includes a reclassification of $68 million for 2001. See Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report for further information.

(f) CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

(g) Includes 2004 combined financial data under ownership by Ameren and IP’s former ultimate parent, Dynegy. See Note 2 – Acquisitions to our financial statements under Part II, Item 8, of this report for further information.

(h) Effective December 31, 2003, IP SPT was deconsolidated from IP’s financial statements in conjunction with the adoption of FIN 46R. See Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report for further information.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

OVERVIEW

Ameren Executive Summary

Operations

A highlight of 2005 was the successful completion of the refueling and maintenance outage at UE’s Callaway nuclear plant. It was the most extensive in the Callaway plant’s history and also one of the most efficient and effective outages. During the outage, the plant was refueled and the steam generators and turbine rotors were replaced. The outage, originally scheduled to last 70 to 75 days, was completed in about 63 days. The replacement of the steam generators and turbine rotors is expected to improve reliability and has increased plant capacity by approximately 60 megawatts, positioning the plant very well for the future.

Ameren’s coal-fired power plants also achieved availability levels that were slightly higher than the record levels achieved in 2004. A major challenge in 2005 came from disruptions in deliveries of coal by rail from the Powder River Basin, which provides over 85% of Ameren’s coalrequirements. Deliveries in 2005 were well below expected levels due to rail maintenance, which resulted in lower-than-normal inventory levels. The impact of the coal delivery issues on inventory levels was exacerbated by warm summer weather and high power prices, which caused the plants to run more and burn more coal. In order to maintain acceptable coal inventory levels, higher-cost Illinois coal was purchased and interchange sales were reduced; both of which had a negative impact on 2005 earnings.

In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric facility that resulted in significant flooding in the local area, which damaged a state park. At this point, it is too early to say when, or if, the plant will return to service. Any decision on the future of the plant will wait until after reviews by state and federal authorities are concluded, further analyses are completed and input is received from key stakeholders. 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.

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Earnings

Ameren reported earnings of $3.02 per share for 2005 which compared to earnings of $2.84 per share last year. Excluding an 11 cent per share fourth quarter 2005 charge for the adoption of a new accounting principle related to AROs, Ameren’s earnings for 2005 were $3.13 per share. Improved operating earnings in 2005 resulted from the successful integration of IP, and greater availability of Ameren’s low-cost coal-fired power plants. This availability allowed Ameren to enhance operating margins as it supplied increased native load demand resulting from warmer summer weather and took advantage of higher power prices on short-term energy sales. In addition, operating earnings benefited from organic growth in Ameren’s service territory and from the sale of certain assets from its leveraged lease portfolio. These benefits more than offset increased fuel and purchased power expenses, including higher costs of operating in the MISO Day Two Energy Market.

Liquidity

Cash flows from operations of $1.2 billion in 2005 at Ameren, along with other funds, were used to pay dividends to common shareholders of $511 million and fund capital expenditures of $947 million. Capital expenditures included investments made at UE’s Callaway nuclear plant and in CTs, in addition to more routine expenditures. In 2005, UE announced the acquisition of 1,490 megawatts of CTs for $290 million, subject to regulatory approvals. These acquisitions are expected to be completed in 2006. Financing activities in 2005 primarily consisted of refinancing debt and funding capital investment.

Outlook

Ameren expects continued economic growth in its service territory to benefit energy demand in 2006 and beyond, but higher energy prices could result in reduced demand from consumers. Ameren’s coal and related transportation costs rose in 2005 and are expected to rise 10% to 15% in 2006 and another 15% to 20% in 2007.

By the end of 2006, bundled electric rates for Ameren’s three Illinois electric distribution subsidiaries – CIPS, CILCO and IP – will have been fixed or declining for periods ranging from 15 years to 25 years. In addition, power supplied by certain of Ameren’s non-rate-regulated generation subsidiaries has been partially subject to long-term fixed price contracts to supply Ameren’s Illinois electric distribution subsidiaries. On December 31, 2006, the Illinois electric rate freeze and the long-term fixed price affiliate power supply contracts expire. Prices reflected in the current long-term fixed price power supply contracts are below market prices for similar contracts in early 2006. In 2006, the ICC will rule on CIPS’, CILCO’s and IP’s request for a combined $200 million electric rate increase for electric deliveryservices. In addition, there is expected to be an auction in September 2006 for their power supply for 2007 and beyond in which Genco and AERG will likely participate through Marketing Company subject to limitations. In Missouri, UE has a rate moratorium set to expire June 30, 2006. Rates will not change until such time as a rate adjustment is requested and the MoPSC hears and rules on a rate adjustment request. UE has not made a final determination as to when it will file a rate case. The appropriate test year, economic and energy market conditions, expected plant additions and the rulemaking process surrounding fuel, purchased power and environmental cost recovery mechanisms, among other things, will drive the decision on when to file a rate case. The MoPSC staff and others will review an electric cost-of-service study submitted by UE in December 2005 and, based upon their analysis, may make their own recommendations for rate adjustments.

The EPA is requiring more stringent emission limits on all coal-fired power plants. Between 2006 and 2016, Ameren expects its subsidiaries will be required to spend between $2.1 billion and $2.9 billion to retrofit its power plants with pollution control equipment. Between 55% and 60% of this investment will be at UE and therefore is expected to be recoverable over time from ratepayers. The recoverability of amounts invested in non-rate-regulated operations will depend on whether market prices for power adjust to reflect this increased investment by the industry.

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company registered with FERC under PUHCA 2005. Ameren was registered with the SEC as a public utility holding company under PUHCA 1935, until its repeal 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, as discussed below. Dividends on Ameren’s common stock are dependent on distributions made to it by its subsidiaries. See Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report for a detailed description of our principal subsidiaries.

• UE operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri. Before May 2, 2005, UE also operated those businesses in Illinois.

• CIPS operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

• Genco operates a non-rate-regulated electric generation business.

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• CILCO, a subsidiary of CILCORP (a holding company), operates a rate-regulated electric transmission and distribution business, a primarily non-rate-regulated electric generation business (through its subsidiary, AERG) and a rate-regulated natural gas transmission and distribution business in Illinois.

• IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois.

The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. As the acquisition of IP occurred on September 30, 2004, Ameren’s Consolidated Statements of Income and Cash Flows for the periods before September 30, 2004, do not reflect IP’s results of operations or financial position. Financial information for CILCORP and CILCO in Ameren’s consolidated financial statements begins with January 31, 2003, when these companies were acquired. See Note 2 – Acquisitions to our financial statements under Part II, Item 8, of this report for further information on the accounting for the IP and CILCORP acquisitions. All significant intercompany transactions have been eliminated. All tabular dollar amounts are expressed in millions, unless otherwise indicated.

In addition to presenting results of operations and earnings amounts in total, we present certain information in cents per share. These amounts reflect factors that directly affect Ameren’s earnings. We believe this per share information helps readers to understand the impact of these factors on Ameren’s earnings per share. All references in this report to earnings per share are based on average diluted common shares outstanding during the applicable year.

IP Acquisition

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 electric and gas 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 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. The contract was marked to fair value at closing of the IP acquisition. 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 in 2006 will be supplied by other companies through contracts and open market purchases. In the event that suppliers are unable to supply 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. These proceeds were used to finance the cash portion of the purchase price, to reduce IP debt assumed as part of this transaction, and to pay related premiums.

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.

Acquisition Accounting

The amortization of noncash purchase accounting fair value adjustments at IP increased Ameren’s and IP’s net income for the years ended December 31, 2005 and 2004, as indicated in the table below. The amortization of the fair value adjustments at IP that increased net income were related to pension and postretirement liabilities, long-term debt, a power supply contract with EEI, and a power supply contract with Dynegy, which expired in 2004. Partially offsetting these items was the amortization of the fair value adjustment related to another power supply contract for 700 megawatts that also expired in 2004. Concurrent with its acquisition of IP, Ameren negotiated a contract with Dynegy to supply IP 2,800 megawatts for 2005 and 2006. The fair value adjustment associated with this contract is being amortized over the terms of the contract. It has a favorable impact on IP’s net income. The fair value adjustment associated with the EEI contract was fully amortized as of December 31, 2005, when that contract expired.

The following table presents the favorable (unfavorable) impact on Ameren’s and IP’s net income of the amortization of purchase accounting fair value adjustments associated with the IP acquisition for the year ended December 31, 2005, and for the three months ended December 31, 2004:

	Ameren						IP
	2005			2004			2005			2004
Statement of Income line item:
Other operations and maintenance(a)	$	27		$	7		$	27		$	7
Interest(b)		17			10			17			10
Fuel and purchased power(c)		44			26			21			26
Income taxes(d)		(35	)		(17	)		(26	)		(17	)
Impact on net income	$	53		$	26		$	39		$	26

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(a) Related to the adjustment to fair value of the pension and postretirement plans.

(b) Related to the adjustment to fair value of all the IP debt assumed at acquisition on September 30, 2004. The net write-up to fair value of all the IP debt assumed, excluding early redemption premiums, is being amortized over the anticipated remaining life of the debt. See Note 6 – Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for additional information.

(c) Related to the amortization of fair value adjustments to power supply contracts.

(d) Tax effect of the above amortization adjustments.

The amortization of noncash purchase accounting fair value adjustments at CILCORP increased Ameren’s and CILCORP’s net income in 2005, 2004 and 2003 as indicated in the table below. The amortization of the fair value adjustments that increased net income were related to pension and postretirement liabilities, coal contract liabilities, and long-term debt. The amortization of fair value adjustments that decreased net income were related to electric plant in service, purchased power, and emission credits. The following table presents the favorable (unfavorable) impact on Ameren’s and CILCORP’s net income of the amortization of purchase accounting fair value adjustments during 2005, 2004, and the 11 months ended December 31, 2003:

	2005			2004			2003
Statement of Income line item:
Other operations and maintenance(a)	$	8		$	13		$	39
Interest(b)		7			8			7
Fuel and purchased power(c)		(8	)		(6	)		1
Depreciation and amortization(d)		(5	)		(5	)		(7	)
Income taxes(e)		(1	)		(4	)		(16	)
Impact on net income	$	1		$	6		$	24

(a) Related to the adjustment to fair value of the pension and postretirement plans, retail customer contracts and investment assets.

(b) Related to CILCORP’s 9.375% senior notes due 2029 and 8.70% senior notes due 2009 being written up to fair value and amortized over the average remaining life of the debt. See Note 6 – Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for additional information.

(c) Related to emission credits and coal contracts.

(d) Related to plant assets at Duck Creek, E.D. Edwards, and Sterling Avenue being amortized over the remaining useful lives of the plants.

(e) Tax effect of the above amortization adjustments.

RESULTS OF OPERATIONS

Earnings Summary

Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. About 85% of Ameren’s revenues are directly subject to state and federal regulation. This regulation can have a material impact on the price we charge for our services. Our non-rate-regulated sales are subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil in our operations. The prices for thesecommodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We do not currently have fuel or purchased power cost recovery mechanisms in Missouri or Illinois for our electric utility businesses, but we do have gas cost recovery mechanisms in each state for our gas delivery businesses. The electric and gas rates for UE in Missouri are set through June 2006 and for CIPS, CILCO and IP in Illinois through January 1, 2007; therefore, cost decreases or increases will not be immediately reflected in rates. Fluctuations in interest rates affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risks and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.

Ameren’s net income for 2005, 2004, and 2003 was $606 million ($3.02 per share), $530 million ($2.84 per share), and $524 million ($3.25 per share), respectively. In 2005, Ameren’s net income included a net cumulative effect aftertax loss of $22 million (11 cents per share) associated with recording liabilities for conditional AROs as a result of our adoption of FIN 47, “Accounting for Conditional Asset Retirement Obligations.” In 2003, Ameren’s net income included an aftertax gain of $31 million (19 cents per share) related to the settlement of a dispute over mine reclamation issues with a coal supplier and a net cumulative effect aftertax gain of $18 million (11 cents per share) associated with the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations.” The coal contract settlement gain recaptured coal costs, plus accrued interest, paid to a coal supplier for future reclamation of a coal mine that principally supplied a UE power plant. The SFAS No. 143 net gain resulted principally from the elimination from accumulated depreciation of accrued costs of removal for non-rate-regulated assets; these accrued costs of removal were not legal obligations.

The following table presents net cumulative effect aftertax gains (losses) recorded upon adoption of FIN 47 in 2005 and SFAS No. 143 in 2003:

Net Cumulative Effect Aftertax Gain (Loss)	2005 FIN 47			2003 SFAS No. 143
Ameren(a)(b)	$	(22	)	$	18
Genco		(16	)		18
CILCORP(c)		(2	)		4
CILCO		(2	)		24
IP(c)		-			(2	)

(a) Includes amounts for EEI.

(b) 2003 excludes amounts for IP and CILCORP as SFAS No. 143 was adopted prior to the acquisitions by Ameren.

(c) Represents predecessor information for 2003.

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The following table presents a reconciliation of Ameren’s net income to net income, excluding the coal contract settlement discussed above. It also shows the effect of FIN 47 and SFAS No. 143 adoption, all net of taxes, for the years ended December 31, 2005, and 2003. Ameren believes that this reconciliation presents results from continuing operations on a more comparable basis. However, our presentation of net income or earnings per share excluding restructuring charges and other items is not a presentation defined under GAAP, and it may not be comparable to other companies’ presentations or more useful than the GAAP presentation included in Ameren’s financial statements.

	2005		2004		2003
Net income	$	606	$	530	$	524
Earnings per share – diluted	$	3.02	$	2.84	$	3.25
FIN 47 adoption – loss, net of taxes		22		-		-
Coal contract settlement, net of taxes		-		-		(31	)
SFAS No. 143 adoption – gain, net of taxes		-		-		(18	)
Total of coal contract settlement, and the effect of FIN 47 and SFAS No. 143 adoption, net of taxes	$	22	$	-	$	(49	)
– per share	$	0.11	$	-	$	(0.30	)
Net income, excluding coal contract settlement, and the effect of FIN 47 and SFAS No. 143 adoption	$	628	$	530	$	475
Earnings per share, excluding coal contract settlement, and the effect of FIN 47 and SFAS No. 143 adoption – diluted	$	3.13	$	2.84	$	2.95

Excluding the loss on the adoption of FIN 47 in 2005, Ameren’s net income increased $98 million, and earnings per share increased 29 cents in 2005 compared with 2004. The increase in net income was primarily due to warmer weather in the summer of 2005 compared with extremely mild conditions in the summer of 2004 (estimated at 24 to 28 cents per share), inclusion of IP results for an additional nine months in 2005 (23 cents per share), increased margins on interchange sales (11 cents per share), the lower cost of the refueling and maintenance outage at UE’s Callaway nuclear plant in 2005 versus the 2004 refueling and maintenance outage (3 cents per share), increased emission credit earnings (2 cents per share), net gains on sales of leveraged leases in 2005 (7 cents per share), employee benefit costs (5 cents per share) and organic growth in revenues. Partially offsetting these increases to net income were incremental costs of operating in the MISO Day Two Energy Market (29 cents per share), increased labor costs (8 cents per share), and increased fuel and purchased power costs. In addition, net income in 2004 benefited from a FERC-ordered refund of $18 million in exit fees, which had been previously paid by UE and CIPS to the MISO, upon their re-entry into the MISO (6 cents per share). Cents per share information in this paragraph is based on average shares outstanding in 2004. An increase in the number of common shares outstanding also reduced Ameren’s earnings per share in 2005 compared with 2004.

Excluding the gains on the adoption of SFAS No. 143 and the settlement of the coal mine reclamation dispute in the prior year, Ameren’s net income increased $55 million and earnings per share decreased 11 cents in 2004 from 2003. The change in net income was primarily due to organic growth in revenues, increased margins on interchange sales, primarily due to greater availability of low-cost generation (16 cents per share), gas delivery rate increases (10 cents per share), lower labor costs (8 cents per share), the MISO refund of previously paid exit fees upon UE’s and CIPS’ reentry into the MISO in the second quarter of 2004 (6 centsper share), and the results of CILCORP’s inclusion for an additional month and IP’s inclusion for three months in 2004. Partially offsetting these increases to income were increased fuel and purchased power costs and other operations and maintenance costs as a result of UE’s Callaway nuclear plant refueling and maintenance outage in the second quarter of 2004 (22 cents per share), extremely mild 2004 weather conditions (estimated at 12 to 16 cents per share), electric rate reductions (13 cents per share), and higher employee benefit costs (11 cents per share). Cents per share information in this paragraph is based on average shares outstanding in 2003. An increase in the number of common shares outstanding also reduced Ameren’s earnings per share in 2004 compared with 2003.

Because it is a holding company, Ameren’s net income and cash flows are primarily generated by its principal subsidiaries: UE, CIPS, Genco, CILCORP and IP. The following table presents the contribution by Ameren’s principal subsidiaries to Ameren’s consolidated net income for the years ended December 31, 2005, 2004 and 2003:

	2005		2004			2003
Net income:
UE(a)	$	346	$	373		$	441
CIPS		41		29			26
Genco(a)		97		107			75
CILCORP(a)(b)		3		10			14
IP(c)		95		27			-
Other(d)		24		(16	)		(32	)
Ameren net income	$	606	$	530		$	524

(a) Includes earnings from market-based interchange power sales that provided the following contributions to net income:

UE: 2005 - $75 million; 2004 - $75 million; 2003 - $58 million.

Genco: 2005 - $47 million; 2004 - $39 million; 2003 - $30 million.

CILCORP: 2005 - $13 million.

(b) Excludes net income prior to the acquisition on January 31, 2003.

(c) Excludes net income prior to the acquisition on September 30, 2004.

(d) Includes gains on leveraged lease sales in 2005, corporate general and administrative expenses, transition costs associated with the CILCORP and IP acquisitions and other non-rate-regulated operations.

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Electric Operations

The following tables present the favorable (unfavorable) variations in electric margins, defined as electric revenues less fuel and purchased power costs, from the previous year for the years ended December 31, 2005 and 2004. We consider electric and interchange margins useful measures to analyze the change in profitability of our electric operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, electric and interchange margins may not be a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

The variation in electric margin for Ameren shows the contribution from IP for the first nine months of 2005, from IP for the last three months of 2004, and from CILCORP for January 2004 as separate line items, which allows an easier comparison with other margin components. The variation in IP electric margin in 2005 is compared with the full year of 2004, despite Ameren’s acquisition of IP occurring on September 30, 2004. The variation in IP electric margin for the full year in 2004 is compared with the full year of 2003, when Ameren did not own IP and it did not contribute to Ameren’s electric margins. The variations in CILCORP and CILCO electric margins in 2004 are compared with the full year of 2003. Before January 31, 2003, Ameren did not own CILCORP and CILCO, so they did not contribute to Ameren’s electric margins.

2005 versus 2004	Ameren(a)			UE			CIPS			Genco			CILCORP			CILCO			IP(c)
Electric revenue change:
IP – January through September 2005	$	861		$	-		$	-		$	-		$	-		$	-		$	-
Effect of weather (estimate)		115			72			24			-			16			16			51
Growth and other (estimate)		120			21			149			97			-			-			-
Rate reductions		(7	)		(7	)		-			-			-			-			-
Interchange revenues		79			143			(1	)		67			(20	)		(20	)		-
Total	$	1,168		$	229		$	172		$	164		$	(4	)	$	(4	)	$	51
Fuel and purchased power change:
IP – January through September 2005	$	(509	)	$	-		$	-		$	-		$	-		$	-		$	-
Fuel:
Generation and other		(92	)		(83	)		-			8			(17	)		(15	)		-
Price		(45	)		(41	)		-			(29	)		25			25			-
Purchased power		(156	)		(127	)		(131	)		(160	)		(20	)		(20	)		(62	)
Total	$	(802	)	$	(251	)	$	(131	)	$	(181	)	$	(12	)	$	(10	)	$	(62	)
Net change in electric margins	$	366		$	(22	)	$	41		$	(17	)	$	(16	)	$	(14	)	$	(11	)
2004 versus 2003	Ameren(a)			UE			CIPS			Genco			CILCORP(b)			CILCO			IP(c)
Electric revenue change:
CILCORP – January 2004	$	49		$	-		$	-		$	-		$	-		$	-		$	-
IP – October through December 2004		229			-			-			-			-			-			-
Effect of weather (estimate)		(38	)		(24	)		(12	)		-			(1	)		(1	)		(16	)
Growth and other (estimate)		70			44			(5	)		65			(196	)		(196	)		(25	)
Rate reductions		(34	)		(34	)		-			-			-			-			-
Interchange revenues		69			20			-			23			27			27			-
Total	$	345		$	6		$	(17	)	$	88		$	(170	)	$	(170	)	$	(41	)
Fuel and purchased power change:
CILCORP – January 2004	$	(26	)	$	-		$	-		$	-		$	-		$	-		$	-
IP – October through December 2004		(128	)		-			-			-			-			-			-
Fuel:
Generation and other		(37	)		5			-			(23	)		(17	)		(7	)		-
Price		(9	)		(2	)		-			(6	)		11			11			-
Purchased power		(17	)		(24	)		16			2			162			159			57
Total	$	(217	)	$	(21	)	$	16		$	(27	)	$	156		$	163		$	57
Net change in electric margins	$	128		$	(15	)	$	(1	)	$	61		$	(14	)	$	(7	)	$	16

(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) Includes predecessor information for periods before January 31, 2003.

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

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Ameren

2005 versus 2004

Ameren’s electric margin increased $366 million in 2005 from 2004. 2005 includes an additional nine months of IP results, which added $352 million of electric margin. Electric margin also increased because of higher margins on interchange sales, favorable weather conditions in 2005, sales to a significant new customer, and organic growth. Partially offsetting these increases to electric margin were incremental costs of operating in the MISO Day Two Energy Market and increased fuel and purchased power costs. Electric rate reductions resulting from the 2002 UE electric rate case settlement in Missouri negatively affected electric revenues by $7 million during 2005. These were the final rate reductions under the rate case settlement. Ameren’s base load electric generating plants’ average capacity factors were about 76% in both 2005 and 2004. Equivalent availability factors were about 86% in both 2005 and 2004. Record coal-fired electric generation plant production was offset by an extended refueling and maintenance outage at UE’s Callaway nuclear plant.

Margins on interchange sales for Ameren increased $66 million in 2005, as compared with 2004, principally because of higher power prices and access to the MISO Day Two Energy Market. Average realized prices on Ameren’s interchange sales increased to about $44 per megawatthour in 2005 from about $30 per megawatthour in 2004. High natural gas, emission allowance and coal prices in 2005 contributed to the higher power prices. The MISO Day Two Energy Market also contributed to an increase in margins on interchange sales by an estimated $34 million in 2005 as compared to 2004.

Warmer summer weather in 2005, compared with extremely mild conditions in the summer of 2004, resulted in a 37% increase in cooling degree-days in 2005 in Ameren’s service territory. Cooling degree-days increased 19% from normal conditions in 2005. Excluding the additional nine months of IP sales in 2005, Ameren’s weather-sensitive residential and commercial sales were up 10% and 3%, respectively, in 2005 compared with 2004.

Ameren’s industrial sales, excluding the additional nine months of IP sales in 2005, were comparable in 2005 and 2004. Sales to Noranda, a significant new UE industrial customer in 2005, offset the expiration and nonrenewal of low-margin non-rate-regulated power sales contracts to customers outside our core service territory and decreased low-margin resale of power to the DOE by EEI under its power supply contract.

Ameren’s fuel and purchased power costs, excluding the additional nine months of IP results in 2005, increased$293 million in 2005 from 2004, primarily because of MISO Day Two Energy Market costs, increased fuel and purchased power prices, coal conservation efforts, unscheduled coal-fired plant outages during the peak summer period, increased CT generation as a result of the warmer weather in 2005, and increased emission allowance utilization at Genco and AERG. Incremental MISO costs included in purchased power were $107 million in 2005. MISO costs were greater than expected because of higher-than-anticipated line losses, transmission congestion charges, and charges associated with volatile weather conditions and deviations of actual from forecasted plant availability and customer loads. We attribute some of these higher costs to the relative infancy of the MISO Day Two Energy Market, suboptimal dispatching of plants and price volatility. Increased emission allowance utilization of $47 million in 2005 resulted in higher fuel costs. Fuel and purchased power costs were reduced in 2005 by a $21 million gain at Genco resulting from the nonmonetary swap of certain earlier vintage-year SO₂ emission allowances for later vintage-year allowances. Fuel and purchased power costs for UE’s 2005 Callaway nuclear plant refueling and maintenance outage were comparable with the 2004 refueling and maintenance outage.

2004 versus 2003

Ameren’s electric margin increased $128 million in 2004 from 2003. Excluding the additional month of CILCORP results and three months of IP results in 2004, electric margin increased $4 million. Strong organic growth due to improved economic conditions and increased margins on interchange sales more than offset the effect of unfavorable weather conditions, increased fuel and purchased power costs due to the second quarter 2004 Callaway nuclear plant refueling and maintenance outage, and rate reductions in 2004. In addition, earnings from emission credit sales decreased $7 million in 2004 compared with 2003.

According to the National Weather Service, summer weather in 2004 in Ameren’s service territory was the seventh mildest in the past 110 years. Cooling degree-days during that period in Ameren’s service territory were down about 20% from both normal conditions and from the prior year. Warmer winter weather in 2004 also resulted in heating degree-days that were down about 7% in 2004 in Ameren’s service territory from 2003, and down about 10% from normal conditions. Excluding the additional month of CILCORP sales and three months of IP sales in 2004, residential sales were flat compared to 2003, because organic growth offset the impact of the unfavorable weather conditions. Commercial and industrial sales increased 2% in 2004 because economic conditions improved.

Rate reductions resulting from the 2002 UE electric rate case settlement in Missouri negatively affected electric revenues during 2004 compared to 2003. Annual reductions

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of $50 million, $30 million, and $30 million were effective April 1, 2002, 2003, and 2004, respectively.

Margins on interchange sales increased $37 million in 2004 from 2003. This was because of increased availability of low-cost generation resulting from record power generation and reduced demand from native load customers due to the mild summer weather. In addition to increased availability of low-cost power, sales in 2004 also benefited because higher natural gas and coal prices both contributed to increased power prices. In 2004, Ameren’s baseload coal-fired electric generating plants’ average capacity factor was about 76%, despite the extremely mild weather, compared with 73% in 2003. The equivalent availability factor was about 86%, compared with 85% in the prior-year period.

Ameren’s fuel and purchased power costs increased $63 million, excluding the additional month of CILCORP and the additional three months of IP in 2004, compared with 2003, because of increased power purchases necessitated by the Callaway refueling and maintenance outage in 2004 as well as increased coal-fired generation and fuel prices.

UE

2005 versus 2004

UE’s electric margin decreased $22 million in 2005, from 2004, primarily because of the transfer of UE’s Illinois service territory to CIPS, reduced rates in the first quarter of 2005 as compared to the first quarter of 2004, increased fuel and purchased power costs, and decreased emission credit sales. Emission credit sales decreased $12 million in 2005, as UE continued to evaluate options for complying with the Clean Air Interstate Rule, which includes using emission credits for compliance purposes. Partially offsetting these decreases to margin were sales to Noranda, a significant new industrial customer in 2005, increased interchange sales, and favorable weather conditions.

On May 2, 2005, following the receipt of all required regulatory approvals, UE completed the transfer of its Illinois service territory, including its Illinois-based electric and gas utility, to CIPS. The transfer resulted in an estimated decrease in electric margin of $74 million in 2005.

Effective June 1, 2005, UE began to supply about 470 megawatts (peak load) of electric service (or about 5% of UE’s generating capability, including currently committed purchases) to Noranda’s primary aluminum smelter in southeast Missouri under a 15-year agreement. The additional sales to Noranda increased electric margin by $33 million in 2005. This increase in industrial sales was partially offset by the effect of the transfer of UE’s industrial customers in its Illinois service territory to CIPS.

Increased interchange margins and favorable weather conditions in the summer of 2005 added to margins in the current year. Margins on interchange sales with nonaffiliates increased $26 million in 2005, compared with 2004, primarily because of higher power prices and access to the MISO Day Two Energy Market. The MISO Day Two Energy Market resulted in an increase in margins on interchange sales by an estimated $23 million in 2005 compared to 2004. Residential and commercial sales increased 10% and 4%, respectively, in 2005, compared with 2004, primarily as a result of favorable weather conditions.

Fuel and purchased power increased in 2005, from 2004, primarily because of MISO Day Two Energy Market costs, increased fuel and purchased power prices, coal conservation efforts, and increased CT generation to serve increased summer demand. MISO costs included in purchased power were $59 million in 2005. Fuel and purchased power costs for the 2005 Callaway refueling and maintenance outage were comparable with the 2004 refueling and maintenance outage.

2004 versus 2003

UE’s electric margin decreased $15 million in 2004, compared with 2003. Residential sales in 2004 were comparable with prior-year sales as the effect of mild summer weather was offset by organic growth. Rate reductions from the 2002 rate case settlement negatively affected electric revenues during 2004 compared to 2003. Partially offsetting these decreases to electric margin were increased interchange margins. Margins on interchange sales increased $23 million in 2004 from 2003, because of increased availability of low-cost generation and higher power prices. Earnings from emission credit sales decreased $3 million in 2004 compared with 2003. Fuel and purchased power increased $20 million in 2004, primarily because of increased purchased power of $24 million resulting from the Callaway refueling and maintenance outage during the second quarter of 2004, partially offset by decreased demand due to mild summer weather conditions in 2004.

CIPS

CIPS’ electric margin increased $41 million in 2005, compared with 2004. The increase was primarily due to favorable weather conditions, increased industrial sales as a result of the transfer to CIPS of UE’s Illinois service territory, and customers’ switching to CIPS from Marketing Company because tariff rates were below market rates. The transfer of the Illinois service territory resulted in an estimated increase in electric margin of $27 million in 2005. Partially offsetting these margin increases were increased MISO costs. MISO costs included in purchased power were $23 million in 2005.

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CIPS’ 2004 electric margin was comparable with the margin in 2003. Electric margin in 2004 was favorably affected by an industrial customer who switched from CIPS to Marketing Company and by the elimination of the negative margin associated with this customer. Unfavorable weather conditions offset the increases to margin.

Genco

Genco’s electric margin decreased $17 million in 2005 compared with 2004. Wholesale margins decreased because Genco purchased higher-cost power to serve greater load. The increase in load was due to increased volume from the transfer of UE’s Illinois service territory to CIPS and to warmer than normal weather. Increased purchased power, principally from UE under the joint dispatch agreement, was made necessary by a major power plant maintenance outage that occurred primarily during the first quarter of 2005. Emission allowance utilization increased fuel and purchased power costs by $26 million in 2005. Fuel and purchased power costs were reduced in 2005 by a net gain of $15 million associated with a $21 million nonmonetary swap of certain earlier vintage-year SO₂ emission allowances for later vintage-year allowances, partially offset by losses of $6 million on emissions allowance options. Interchange margins increased $23 million in 2005 over 2004, primarily because of higher power prices and access to the MISO Day Two Energy Market. The MISO Day Two Energy Market resulted in an increase in margins on interchange sales by an estimated $10 million in 2005 as compared to 2004.

Genco’s electric margin increased $61 million in 2004 compared with 2003. The increase in electric margin was primarily attributable to an increase in wholesale and retail margins due to sales to new customers and increased availability of lower-cost generation. Interchange margins increased $14 million in 2004 from 2003, because power prices were higher and more low-cost power was available for sale because of the mild weather.

CILCORP and CILCO

Electric margin decreased $16 million and $14 million at CILCORP and CILCO, respectively, in 2005 compared with 2004, primarily because of decreased interchange margins and higher fuel and purchased power costs due to unscheduled plant outages during the peak summer period. MISO costs included in purchased power were $8 million in 2005. Increased costs of emission allowance utilization decreased margins by $20 million in 2005 compared with 2004. Decreases in electric margin were partially offset by the use of lower-cost coal at one of AERG’s power plants, along with favorable weather in the summer of 2005.

Electric margin decreased $14 million at CILCORP and $7 million at CILCO in 2004 from 2003. Decreases in electric margin were primarily attributable to reduced revenues. Two large CILCO industrial customers who switched to Marketing Company in July and October 2003 and transfers of other non-rate-regulated customers to Marketing Company accounted for a $168 million decrease in electric revenues. Fuel and purchased power also decreased because customers switched to Marketing Company.

IP

IP’s electric margin decreased $11 million in 2005, compared with 2004, primarily because of higher purchased power and MISO costs in 2005. Although power costs decreased in 2005 under IP’s new power supply agreement with DYPM, costs on other power purchase contracts were higher than in 2004. MISO costs included in purchased power were $9 million in 2005 versus none in 2004. Partially offsetting these decreases to electric margin were favorable weather conditions in 2005.

IP’s electric margin increased $16 million in 2004, compared with 2003. The increase in electric margin was principally due to lower purchased power costs that included the benefit of purchase accounting adjustments of $26 million recorded by IP in 2004. Revenues were reduced because of unfavorable summer weather. Electric margin was also unfavorably affected by industrial customers who chose alternative suppliers.

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Gas Operations

The following table presents the favorable (unfavorable) variations in gas margins, defined as gas revenues less gas purchased for resale, compared with the prior periods for the years ended December 31, 2005 and 2004. We consider gas margin to be a useful measure of the change in profitability of our gas utility operations between periods. The table below complements the financial information we provide in accordance with GAAP. However, gas margin may not be a presentation defined under GAAP. Our presentation may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.

	2005		2004
Ameren(a)	$	120	$	77
UE		10		9
CIPS		-		6
CILCORP		2		8
CILCO		2		6
IP(b)		2		(4	)

(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) Includes predecessor information prior to September 30, 2004.

Ameren’s gas margin increased $120 million in 2005 over 2004, primarily because of the inclusion of an additional nine months of IP results in the current year. Excluding these IP results, gas margin increased $16 million, primarily as a result of more favorable weather conditions in the fourth quarter of 2005 than in the same period in 2004, when we experienced mild weather in our service territory. UE’s gas margin increased in 2005, compared with 2004, because of the effect of rate increases in the first quarter of 2005 and favorable weather, partially offset by the transfer of UE’s Illinois service territory to CIPS. CIPS’ gas margin was comparable in 2005 to 2004. The transfer to CIPS of UE’s service territory and favorable weather conditions offset gas inventory adjustments. The service territory transfer resulted in an increase of $4 million in CIPS’ gas margin in 2005, and an equivalent decrease in UE’s gas margin. CILCORP’s and CILCO’s gas margins increased in 2005 over 2004 primarily as a result of favorable weather in the fourth quarter of 2005. IP’s gas margin increased because of a rate increase effective in May 2005 that added $6 million, partially offset by unfavorable winter weather during the first quarter of 2005.

Gas margins at Ameren, UE, CIPS, CILCORP and CILCO increased in 2004, compared to 2003, primarily because of delivery rate increases, partially offset by milder winter weather conditions. Ameren’s gas margin also increased $13 million because of the additional month of CILCORP results and $40 million because of the three months of IP results in 2004. Excluding the additional monthof CILCORP and the three months of IP in 2004, Ameren’s sales were down 5% as a result of the mild winter weather. IP’s gas margin decreased $4 million in 2004 from 2003, primarily because of milder winter weather in 2004.

Operating Expenses and Other Statement of Income Items

Other Operations and Maintenance

Ameren

Ameren’s other operations and maintenance expenses increased $150 million in 2005 compared with 2004. IP expenses in the first nine months of 2005 added other operations and maintenance expenses of $166 million to Ameren. Excluding these IP expenses, other operations and maintenance expenses decreased $16 million at Ameren. Plant maintenance expenditures decreased because the expenses related to the 2005 UE Callaway nuclear plant refueling and maintenance outage were lower in 2005 than in 2004. Refueling and maintenance outages occur approximately every 18 months and typically include fuel replacement, maintenance, and inspections. Maintenance and labor costs for refueling and maintenance outages were $31 million in 2005 compared with $39 million in 2004. The 2005 and 2004 refueling and maintenance outages lasted about 64 days; however, in 2005, the outage included more capital activities and less maintenance activities than 2004. In 2005, Ameren replaced steam generators and turbine rotors in addition to normal maintenance procedures. Lower employee benefit costs also resulted in reduced other operations and maintenance expenses in 2005. Ameren and several subsidiaries consummated the sale of leveraged lease assets in the fourth quarter of 2005. The net pretax gain on the sale of these assets was $26 million. Partially offsetting these favorable items was an impairment of $10 million recorded in the third quarter of 2005 related to Ameren’s investment in a leveraged lease of an aircraft to Delta Air Lines, Inc., which filed Chapter 11 bankruptcy in September 2005. Additionally, labor costs, other than those incurred for the Callaway refueling and maintenance outage, were higher in 2005 compared with 2004. Ameren, UE and CIPS received a refund of previously paid exit fees totaling $18 million upon their reentry into the MISO during the second quarter of 2004. This refund did not recur in 2005 and, therefore, other operations and maintenance expenses for this item increased in 2005 relative to 2004.

Ameren’s other operations and maintenance expenses increased $113 million in 2004 from 2003. The additional month of CILCORP results and three months of IP results in 2004 accounted for $15 million and $43 million, respectively, of other operations and maintenance expense in 2004 compared with 2003. Additionally, expenses at Ameren

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increased $55 million in 2004, primarily because of increased maintenance expenses of $39 million stemming from the refueling and maintenance outage at UE’s Callaway nuclear plant during the second quarter of 2004. The previous refueling and maintenance outage occurred in the fall of 2002. In addition to the Callaway nuclear plant outage expenses, employee benefit costs were $43 million higher, primarily because of increased pension and postretirement medical costs. The adoption in the second quarter of 2004, retroactive to January 1, 2004, of FSP SFAS No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” resulted in the recognition of nontaxable federal subsidies expected to be provided under the Medicare Prescription Drug, Improvement and Modernization Act (the Medicare Prescription Drug Subsidy), which partially offset the employee benefit cost increases noted above ($11 million). See Note 1 – Summary of Significant Accounting Policies, and Note 11 – Retirement Benefits to our financial statements under Part II, Item 8, of this report for further information. Expenses at Ameren, UE and CIPS were reduced in 2004 by $18 million, $13 million, and $5 million, respectively, from the refund to UE and CIPS of previously paid exit fees upon their reentry into the MISO. Lower labor costs of $21 million in 2004 also partially offset the above increases to other operations and maintenance expenses.

UE

Other operations and maintenance expenses at UE decreased $14 million in 2005 from 2004, primarily because of reduced plant maintenance costs in 2005. Other operations and maintenance expenses associated with the refueling and maintenance outage at UE’s Callaway nuclear plant were $8 million lower in 2005 than in 2004. Additionally, in the first quarter of 2004, there was an unscheduled outage at the Callaway nuclear plant and planned outages at two coal-fired plants. The transfer of UE’s Illinois service territory to CIPS decreased other operations and maintenance expenses by $16 million in 2005. Partially offsetting these favorable variances were increased labor costs and storm damage expenses in 2005. Additionally, UE received a $13 million MISO exit fee refund during the second quarter of 2004.

Other operations and maintenance expenses at UE increased $38 million in 2004 over 2003, primarily because of increased power plant maintenance expenses of $39 million for the refueling and maintenance outage at UE’s Callaway nuclear plant, as discussed above. In addition to the Callaway outage expenses, employee benefit costs increased by $8 million. These were primarily increased pension costs, partially offset by reduced postretirement costs due to the adoption of FSP SFAS No. 106-2, noted above. In addition, the refund of exit fees of $13 million upon UE’s reentry into the MISO also partially offset the increased costs.

CIPS

Other operations and maintenance expenses at CIPS decreased $4 million in 2005 from 2004 primarily as a result of lower information technology, employee benefit, and administrative and general costs. These positive items were partially offset by the transfer of UE’s Illinois service territory to CIPS, which resulted in an increase in other operations and maintenance expenses of $16 million in 2005. Additionally, CIPS received a $5 million MISO exit fee refund during the second quarter of 2004 that did not recur in 2005.

CIPS’ other operations and maintenance expenses decreased $8 million in 2004 from 2003, primarily because of CIPS’ portion of the MISO exit fee refund and lower labor costs, partially offset by increased employee benefit costs of $2 million.

Genco

Other operations and maintenance expenses at Genco increased $4 million in 2005 over 2004 primarily because of a major power plant maintenance outage in 2005, which was partially offset by reduced employee benefit costs.

Other operations and maintenance expenses at Genco decreased $6 million in 2004 from 2003, primarily because of a reduction in power plant maintenance of $10 million, a result of fewer outages and lower labor costs, partially offset by increased employee benefit costs of $5 million.

CILCORP and CILCO

Other operations and maintenance expenses at CILCORP and CILCO decreased $16 million and $14 million, respectively, in 2005 from 2004. Other operations and maintenance expenses decreased primarily because of lower employee benefit costs in 2005 and the absence of an $8 million charge similar to 2004 for the cost of settling a litigation claim by Enron Power Marketing, Inc. in conjunction with Ameren’s acquisition of CILCORP in 2003. Partially offsetting these favorable variances was the recognition of a pretax loss of $5 million at CILCO on the sale of a leveraged lease in the fourth quarter of 2005 and increased plant maintenance expenditures due to plant outages.

CILCORP’s and CILCO’s other operations and maintenance expenses increased $41 million and $33 million, respectively, in 2004 compared with 2003, primarily because of higher employee benefit costs of $12 million, the settlement of the litigation claim discussed above, and additional injury and damage costs of $4 million. CILCO’s other operations and maintenance expenses also increased because of higher maintenance costs of $3 million, higher information technology expenses of $3 million, and higher overhead allocations. Partially offsetting these

43

increases to other operations and maintenance expenses at CILCORP and CILCO were reduced labor costs in 2004.

IP

IP’s other operations and maintenance expenses increased $39 million in 2005 over 2004, due in part to the receipt of a refund of previously paid exit fees of $9 million from MISO during the third quarter of 2004. Other operations and maintenance expenses also increased because of higher tree-trimming expenses and increased overhead and labor costs associated with the integration of systems and operations with Ameren in 2005.

IP’s other operations and maintenance expenses decreased $19 million in 2004 from 2003. The decrease primarily resulted from the $9 million reimbursement of the MISO exit fee discussed above, as well as reduced labor costs and other operating efficiencies of $12 million. Partially offsetting these favorable variances were higher employee benefit costs of $8 million and costs associated with injuries and damages.

Coal Contract Settlement

See Note 7 – Restructuring Charges and Other Special Items to our financial statements under Part II, Item 8, of this report.

Depreciation and Amortization

2005 versus 2004

Ameren’s depreciation and amortization expenses increased $75 million in 2005 from 2004, principally because of an additional nine months of IP results in 2005, which added $59 million. Capital additions also resulted in increased depreciation expenses in 2005.

Depreciation and amortization expenses at UE increased $30 million in 2005 over 2004. The increases were primarily due to capital additions and depreciation on CTs transferred from Genco to UE in May 2005, partially offset by reduced depreciation on property transferred by UE to CIPS in the Illinois service territory transfer in May 2005.

CIPS’ depreciation and amortization expenses increased $11 million in 2005 over 2004, primarily because of depreciation on property transferred from UE in the Illinois service territory transfer and capital additions.

Depreciation and amortization expenses at Genco decreased $4 million in 2005 from 2004, principally because of the transfer of CTs from Genco to UE in May 2005.

Depreciation and amortization expenses at both CILCORP and CILCO increased $3 million in 2005 over 2004, because of capital additions.

IP’s depreciation and amortization expenses, excluding the amortization of regulatory assets, were comparable in 2005 and 2004. Amortization of regulatory assets at IP decreased $33 million in 2005 from 2004. The transition cost regulatory asset was eliminated in conjunction with Ameren’s acquisition of IP in September 2004.

2004 versus 2003

Ameren’s, UE’s and IP’s depreciation and amortization expenses increased $38 million, $10 million, and $2 million, respectively, in 2004, compared with 2003, because of capital additions. Depreciation and amortization expenses at Ameren also increased in 2004 because 2004 included an additional month of CILCORP expenses of $6 million and three months of IP expenses of $21 million. Amortization of regulatory assets at IP decreased $9 million in 2004 from 2003 as the transition cost regulatory asset was written off in purchase accounting in conjunction with Ameren’s acquisition of IP.

Depreciation and amortization expenses at CIPS and Genco were comparable in 2004 and 2003.

Depreciation and amortization expenses at CILCORP and CILCO decreased $9 million and $6 million, respectively, in 2004 compared with 2003, primarily because reduced expenses as a result of property retirements at the end of 2003 exceeded the increased expenses from new capital additions in 2004. CILCORP depreciation was also favorably affected by reduced purchase accounting amortization adjustments.

Taxes Other Than Income Taxes

2005 versus 2004

Ameren’s taxes other than income taxes increased $53 million in 2005 over 2004 because of an additional nine months of IP results in 2005, which added $54 million.

UE’s taxes other than income taxes increased $7 million in 2005 over 2004, primarily because of increased property taxes due to higher assessments. These property tax increases were mitigated in 2005 by the transfer of UE’s Illinois service territory to CIPS.

Taxes other than income taxes at CIPS were $7 million higher in 2005 than in 2004, primarily because of increased property taxes resulting from the transfer to CIPS of UE’s Illinois service territory.

Genco’s taxes other than income taxes were $8 million lower in 2005 than they were in 2004, primarily because of a favorable court decision in 2005 regarding property taxes.

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CILCORP’s and CILCO’s taxes other than income taxes decreased $5 million and $4 million, respectively, in 2005 compared with 2004, primarily because of reduced gross receipts taxes related to transfers of customers to Marketing Company and to decreased property taxes.

Taxes other than income taxes at IP were comparable in 2005 and 2004.

2004 versus 2003

Taxes other than income taxes increased $13 million at Ameren in 2004 over 2003. Excluding the additional month of CILCORP ($6 million) and the three months of IP ($15 million) included in 2004, taxes other than income taxes decreased $8 million. The decrease was primarily due to decreased gross receipts taxes, partially offset by increased property taxes.

UE’s taxes other than income taxes increased $9 million in 2004 compared with 2003, primarily because of higher property taxes in 2004.

Taxes other than income taxes at CIPS, Genco and IP were comparable in 2004 and 2003.

Taxes other than income taxes decreased at CILCORP and CILCO by $13 million and $14 million, respectively, in 2004 compared with 2003, primarily because gross receipts taxes were down as a result of customers switching to Marketing Company.

Other Income and Expenses

2005 versus 2004

Other income and expenses at Ameren decreased $9 million in 2005 compared with 2004. Excluding the additional nine months of IP results in 2005, other income and expenses at Ameren decreased $14 million from 2004. The decrease was primarily due to reduced interest income from the investment of equity issuance proceeds in the prior year.

CIPS’ other income and expenses were $9 million lower in 2005 than in 2004, primarily because of reduced interest income on the intercompany note receivable from Genco.

Other income and expenses at IP decreased $140 million in 2005 from 2004, primarily because of reduced interest income after the elimination of IP’s note receivable from a former affiliate in conjunction with Ameren’s acquisition of IP on September 30, 2004.

Other income and expenses at UE, Genco, CILCORP and CILCO were comparable in 2005 and 2004.

2004 versus 2003

Ameren’s other income and expenses increased $18 million in 2004 from 2003, primarily because of increased interest income of $8 million from the temporary investment of proceeds from Ameren’s February and July 2004 equity offerings and increased allowance for funds used during construction of $6 million. The additional month of CILCORP results and three months of IP results in 2004 had a minimal impact on other income and expenses.

Total other income at IP decreased $35 million in 2004 from 2003, primarily because interest income was reduced after the elimination of IP’s note receivable from former affiliate in conjunction with Ameren’s acquisition of IP. See Note 2 – Acquisitions to our financial statements under Part II, Item 8, of this report for a discussion of the note elimination. Other income and expenses includes interest income of $128 million for 2004 compared with $170 million in 2003 under IP’s note receivable from a former affiliate.

Other income and expenses at UE, CIPS, Genco, CILCORP and CILCO were comparable in 2004 and 2003. See Note 8 – Other Income and Expenses to our financial statements under Part II, Item 8, of this report for further information.

Interest

2005 versus 2004

Interest expense increased $23 million at Ameren in 2005 from 2004, principally because of the acquisition of IP, which added $32 million of interest for the first nine months of 2005. Excluding the additional IP expense in 2005, interest expense decreased $9 million primarily because of the items discussed below.

UE’s interest expense increased $12 million in 2005 over 2004, primarily because of the issuances of $300 million of senior secured notes in July 2005, $85 million senior secured notes in January 2005 and $300 million senior secured notes in September 2004, partially offset by maturities of $188 million of first mortgage bonds in August 2004 and $85 million of first mortgage bonds in December 2004 and the redemption of $100 million first mortgage bonds in June 2004.

Genco’s interest expense decreased $21 million in 2005 from 2004, primarily because of the maturity of $225 million of senior notes in November 2005, lower average money pool borrowings, and a reduction in principal amounts outstanding on intercompany promissory notes to CIPS and Ameren. The outstanding balance on the intercompany note payable to CIPS was $197 million at December 31, 2005, compared to $283 million at December 31, 2004. The intercompany note payable to Ameren was repaid in 2005.

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Interest expense at IP decreased $87 million in 2005 from 2004, primarily because of redemptions and repurchases of indebtedness of $700 million in the fourth quarter of 2004 and $70 million in early 2005 and reductions in notes payable to IP SPT.

Interest expense at CIPS, CILCORP and CILCO was comparable in 2005 and 2004.

2004 versus 2003

Interest expense for Ameren was comparable in 2004 and 2003. However, excluding the additional month of CILCORP results and three months of IP results in 2004, interest expense at Ameren decreased by $20 million. The decrease was primarily due to the maturity of $150 million of Ameren floating rate notes at the end of 2003 and reduced short-term borrowings, as well as redemptions of long-term debt during 2004 and 2003 at its subsidiaries, as noted below.

Genco’s interest expense was reduced $7 million in 2004 from 2003, primarily due to a reduction in principal amounts outstanding on intercompany promissory notes to CIPS and Ameren. There were also decreased borrowings from Ameren’s non-state-regulated subsidiary money pool. The balance of intercompany notes payable to CIPS and Ameren was $283 million at December 31, 2004, $411 million at December 31, 2003, and $462 million at December 31, 2002.

Interest expense decreased $32 million at IP in 2004 from 2003, primarily due to redemptions and repurchases of indebtedness of $700 million in 2004 and $190 million in 2003, reductions in the notes payable to IP SPT, and purchase accounting amortization. See Note 5 – Short-term Borrowings and Liquidity, and Note 6 – Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for further information.

Interest expense at UE, CIPS, CILCORP, and CILCO was comparable in 2004 and 2003.

Income Taxes

2005 versus 2004

Income tax expense at Ameren increased $74 million in 2005 from 2004, primarily because an additional nine months of IP results included in 2005 added $60 million of incometax expense, and because other pretax income was higher. Partially offsetting these increases at Ameren was the recognition in 2005 of a deduction allowed under the Jobs Creation Act of $5 million.

UE’s income tax expense decreased in 2005 because of lower pretax income and by the recognition of the Jobs Creation Act deduction. Income tax expense increased at CIPS in 2005 because of higher pretax income, partially offset by tax credits and other permanent tax benefits. Income tax expense was higher at CILCORP and CILCO in 2005 than in 2004, because of the tax benefit in the prior year related to CILCO’s settlement of its litigation claim with Enron Power Marketing, Inc., and, in CILCO’s case, higher pretax income. Partially offsetting these increases in tax expenses at CILCORP and CILCO were the permanent items related to the leveraged lease sales. Income tax expense at Genco increased in 2005 over 2004 due to higher pretax income. IP’s income tax expense was lower in 2005 than in 2004, as pretax income decreased from the prior year.

2004 versus 2003

Income tax expense was lower at Ameren in 2004 than in 2003, because of a lower effective tax rate. The effective tax rate was lower primarily because of the recording in 2004 of the expected nontaxable federal Medicare Prescription Drug Subsidy and the tax benefit related to CILCO’s settlement of the Enron Power Marketing, Inc. litigation claim.

Income tax expense decreased at UE, primarily because of lower pretax income in 2004. Income tax expense increased at CIPS in 2004 from 2003, primarily because of higher pretax income in 2004 and an Illinois tax settlement in 2003, which resulted in reduced income taxes in the prior-year period. Income tax expense increased at Genco and IP in 2004 primarily because of higher pretax income in 2004. The recording of the nontaxable federal Medicare Prescription Drug Subsidy lowered taxable income at all the Ameren companies. Income tax expense decreased at CILCORP and CILCO primarily because of the tax benefit from CILCO’s Enron Power Marketing, Inc. litigation claim settlement and lower pretax income in 2004. See also Note 13 – Income Taxes to our financial statements under Part II, Item 8, of this report for information regarding effective tax rates.

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LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO and IP) continue to be the principal source of cash from operating activities for Ameren and its subsidiaries. A diversified retail-customer mix of primarily rate-regulated residential, commercial and industrial classes and a commodity mix of gas and electric service provide a reasonably predictable source of cash flows. For cash flow, Genco principally relies on sales to an affiliate under a contract expiring at the end of 2006 and sales to other wholesale and industrial customers under long-term contracts. In addition, we plan to use short-term borrowings to support normal operations and other temporary capital requirements.

The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2005, 2004 and 2003:

	Net Cash Provided By Operating Activities						Net Cash Provided By (Used In) Investing Activities									Net Cash Provided By (Used In) Financing Activities
	2005		2004		2003		2005			2004			2003			2005			2004			2003
Ameren(a)	$	1,171	$	1,129	$	1,022	$	(881	)	$	(1,266	)	$	(1,181	)	$	(263	)	$	95		$	(358	)
UE		698		749		633		(792	)		(580	)		(503	)		66			(136	)		(124	)
CIPS		133		73		57		(12	)		78			12			(123	)		(165	)		(70	)
Genco		143		180		211		165			(50	)		(58	)		(309	)		(131	)		(154	)
CILCORP(b)		13		136		70		(89	)		(120	)		(95	)		72			(20	)		4
CILCO		47		137		103		(94	)		(125	)		(86	)		47			(18	)		(31	)
IP(c)		148		247		128		9			(272	)		(126	)		(162	)		13			(102	)

(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) Includes predecessor information for periods prior to January 31, 2003. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

(c) 2004 amounts include predecessor financial information prior to the acquisition date of September 30, 2004.

Cash Flows from Operating Activities

2005 versus 2004

Ameren’s increase in cash from operations in 2005, as compared with 2004, was primarily attributable to $207 million of incremental IP operating cash flow in the nine months ended September 30, 2005, since Ameren did not own IP during this same period in 2004. Excluding the impact of IP, Ameren’s increase in electric and gas margins of $14 million and $16 million, respectively, also contributed to the increase in cash from operations. In addition, decreased pension and other postretirement benefit contributions of $206 million and decreased interest payments of $30 million contributed to the favorable variance in cash from operations. Partially offsetting the positive variance in 2005 were increased tax payments of $159 million, additional SO₂ emission allowance purchases in 2005 of $86 million, the absence in 2005 of $36 million of cash from the UE coal contract settlement received in 2004, and $92 million of incremental net investment in inventories and trade receivables and payables due to higher gas prices and colder weather in December 2005 as compared to December 2004. The absence in 2005 of $34 million of refunds in 2004 for previously paid fees to MISO and RTO start-up costs also partially offset the positive variance in cash from operations. Ameren’s working capital investment in coal inventories as of December 31, 2005, did not change significantly, as compared with 2004, as a one million ton decrease involumes due to rail derailments was offset by higher prices. As volumes return to normal levels in 2006, our working capital investment will increase, assuming prices remain at current or higher levels.

At UE, cash from operating activities in 2005 was generally consistent with changes in its results of operations and its operating cash flows in 2004. A $127 million decrease in pension and postretirement contributions benefited 2005 operating cash flow as compared to 2004. Significant items negatively impacting cash in 2005 as compared to 2004 include: increased tax payments of $37 million, less cash from electric margins and emissions sales of $36 million, the impact of the coal contract settlement discussed above, the absence of $20 million received in 2004 for MISO exit fees and RTO start-up costs discussed above, and incremental working capital investment of $32 million, primarily because of timing differences, prices, and weather as discussed above.

CIPS’ increase in cash from operating activities in 2005 was principally due to increased electric margins of $41 million, a reduction of $23 million in pension and postretirement benefit contributions, and reduced interest and tax payments. This was partially offset by increases in cash outflows caused by differences in the timing and amount of working capital items, as compared with 2004.

Cash from operating activities decreased for Genco in 2005 as compared with 2004, primarily due to a $65 million

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increase in SO₂ emissions allowance purchases, and increased tax payments of $41 million. Reduced pension and postretirement contributions of $20 million and lower interest payments of $39 million partially offset the incremental uses of cash.

Cash from operating activities decreased for CILCORP and CILCO in 2005 compared with 2004 primarily because of increased tax payments of $60 million for CILCORP and $54 million for CILCO, lower electric margins of $16 million for CILCORP and $14 million for CILCO, and incremental working capital investment of $94 million and $76 million at CILCORP and CILCO, primarily due to higher prices and colder weather, which increased inventories and receivables by approximately $20 million and $28 million (CILCO - $31 million), respectively. CILCORP’s cash from operating activities was also negatively impacted by additional interest payments of $14 million in 2005 compared to 2004. These decreases were partially offset by a decrease in pension and other postretirement contributions of $33 million.

IP’s cash from operations in 2005 compared with 2004 was impacted by Ameren’s ownership of IP for all of 2005 compared to only the fourth quarter of last year. IP’s operating cash flows in 2005 are not directly comparable with 2004 due to the integration of IP into Ameren’s operations, significant changes in capital structure, termination of certain of IP’s former affiliate agreements and new purchased power arrangements, among other factors. IP’s cash from operations in 2005 benefited from lower taxes paid of $141 million, which resulted mostly from changes in taxable income and deferred tax benefits from accelerated depreciation resulting from the acquisition, and lower interest paid of $93 million. Negative impacts to IP’s operating cash in 2005 included: the absence of $128 million of interest received from IP’s former affiliate, increased cash required for other operations and maintenance expenses of $59 million, and an incremental investment in working capital of $93 million. One of the significant drivers of the increase in working capital investment was colder weather and higher gas prices in December which increased receivables and gas inventories. IP’s gas sales were up 45% over December of 2004.

2004 versus 2003

Cash from operating activities increased for Ameren in 2004 from 2003, primarily because of incremental earnings from the acquisition of IP in the fourth quarter of 2004 and lower taxes paid as a result of the pension contribution, IP debt redemption premiums, and accelerated tax depreciation. Ameren and UE also received $36 million in 2004, compared with $15 million in 2003, as a result of UE’s 2003 settlement of a dispute over mine reclamation issues with a coal supplier.

Cash from operating activities for all the Ameren Companies, except IP, were negatively affected in 2004 by a $295 million pension contribution made by Ameren (UE -$186 million; CIPS - $33 million; Genco - $29 million; CILCORP and CILCO - $41 million).

Cash provided by operating activities increased for CIPS, CILCORP, CILCO and IP in 2004 from 2003, primarily because of the increased earnings discussed under Results of Operations and less income taxes paid. CILCORP and CILCO benefited from net income tax refunds of $40 million and $20 million, respectively. IP’s cash from operations benefited from the 2004 recovery of prepayments related to IP natural gas purchase contracts made in 2003. These benefits in 2004 were partially offset at UE, CIPS, Genco, CILCORP, and CILCO by the pension contribution. IP’s cash from operations was negatively affected by the timing of IP’s income tax reimbursements to Dynegy and the effect of the acquisition on tax payments to Dynegy. Taxes paid at IP in 2004 benefited from debt redemption premiums and accelerated tax depreciation resulting from the acquisition.

Genco’s cash provided by operating activities decreased in 2004 from 2003, primarily because of the differences in the timing and amount of income tax payments and the increased pension contributions. These decreases were partially offset by increased electric margins.

Pension Funding

Ameren’s 2004 and 2005 contributions to the defined benefit retirement plan qualified trusts, among other things, provided cost savings, because they mitigate future benefit cost increases. In addition, the contribution in 2004 allowed us to avoid paying a portion of the insurance premium to the Pension Benefit Guaranty Trust Corporation. Federal interest rate relief expired December 31, 2005. 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 approximately 64%, 10%, 10%, 9% and 7%, respectively. These amounts are estimates and may change with actual stock market performance, changes in interest rates, any pertinent changes in government regulations, and any prior voluntary contributions. See Note 11 – Retirement Benefits to our financial statements under Part II, Item 8, of this report for additional information.

Cash Flows from Investing Activities

2005 versus 2004

Ameren’s decrease in cash used in investing activities was primarily because of $443 million used to acquire IP in

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2004. That decrease was partially offset by a $97 million increase in capital expenditures reflecting a full year of IP capital expenditures in 2005 compared to three months of IP expenditures in 2004, and increased capital expenditures at UE discussed below.

UE’s cash used in investing activities increased in 2005 primarily because UE spent $237 million to purchase 550 megawatts of CTs from Genco and $25 million for a 117 megawatt CT from Development Company. Excluding the CT acquisitions, UE’s capital expenditures in 2005 were consistent with 2004. UE maintained consistent plant expenditures by allocating fewer resources to projects at its coal-fired plants due to $221 million of expenditures at the Callaway nuclear plant for planned upgrades during a refueling and maintenance outage.

CIPS’ increase in cash used in investing activities in 2005 over 2004 was due to an $18 million increase in capital expenditures and a $72 million reduction in cash received from principal payments on a note receivable from Genco. The increased capital expenditures were used to improve the reliability of the transmission and distribution systems.

Genco’s cash provided by investing activities increased in 2005 over 2004, because of the sale of 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois, to UE for $241 million. These proceeds were partially offset by increased capital expenditures for upgrades at one of its power plants in 2005.

CILCORP’s and CILCO’s cash used in investing activities decreased in 2005 from 2004, primarily because CILCORP and CILCO reduced capital expenditures and received proceeds of $13 million from the sale of leveraged leases. In 2004, AERG made capital expenditures for significant power plant upgrades to increase fuel supply flexibility for power generation.

IP’s cash provided by investing activities in 2005 increased primarily because of proceeds of $140 million for repayments of advances of $140 million that were made to the money pool by IP in 2004.

Intercompany Transfer of Illinois Service Territory

On May 2, 2005, UE completed the transfer of its Illinois-based electric and natural gas service territory to CIPS, at a net book value of $133 million. 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.

Leveraged Lease Sales

In December 2005, Ameren, CILCORP, and CILCO generated proceeds of $54 million, $13 million, and$13 million, respectively, from the sale of certain leveraged leases. Prior to the sale, CILCORP transferred certain of its direct and indirect subsidiaries that hold leveraged leases to Resources Company and AERG in exchange for a note receivable. Additionally, an indirect subsidiary of CILCORP that owned leveraged leases was transferred to AERG in exchange for a note receivable.

See Note 3 – Rate and Regulatory Matters to our financial statements, under Part II, Item 8 of this report for a discussion of the Illinois service territory asset transfer and the leveraged lease sales.

2004 versus 2003

Cash used in investing activities increased for Ameren, UE, CILCORP and CILCO and decreased for Genco in 2004. Included in Ameren’s cash used in investing activities was $443 million of net cash paid for the acquisition of IP and Dynegy’s 20% interest in EEI in 2004 and $479 million of net cash paid for the acquisition of CILCORP and Medina Valley in 2003. Excluding the cash paid for acquisitions in 2004 and 2003, Ameren’s cash used in investing activities increased in 2004, primarily because of increased capital expenditures, discussed below, at UE, CILCORP, and CILCO, and the addition of IP’s capital expenditures after the acquisition date.

CIPS’ cash provided by investing activities increased in 2004 from 2003, principally because of increased cash receipts related to the intercompany note receivable from Genco. CIPS’ cash flows provided by investing activities also increased because capital expenditures were lower in 2004 than in 2003.

Genco’s cash used in investing activities decreased, principally because capital expenditures were lower in 2004 than in 2003.

IP’s cash used in investing activities increased principally because of advances made to the utility money pool in 2004.

Capital Expenditures

The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2005, 2004, and 2003:

Capital Expenditures	2005		2004		2003
Ameren(a)	$	947	$	806	$	682
UE		787		524		480
CIPS		64		46		50
Genco		76		50		58
CILCORP(b)		107		125		87
CILCO		107		125		87
IP(c)		132		135		126

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(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) The 2003 amount includes January 2003 predecessor information of $16 million. CILCORP consolidates CILCO and therefore includes CILCO amounts in its balances.

(c) The 2003 amount represents predecessor information. The 2004 amounts include $100 million incurred prior to the acquisition date of September 30, 2004.

Ameren’s and UE’s capital expenditures for 2005 principally consisted of $221 million for steam generators, low pressure rotor replacements, and other upgrades during the 2005 refueling and maintenance outage at UE’s Callaway nuclear plant. Ameren and UE also incurred expenditures of $65 million for three CTs at its Venice plant, $60 million for numerous projects at its generating plants, and $45 million for various upgrades to its transmission and distribution system. In addition, UE incurred expenditures of $237 million for CTs purchased from Genco as discussed above. CILCORP and CILCO capital expenditures included $29 million for ongoing generation plant projects to improve flexibility in future fuel supply for power generation. In addition, CILCO, CIPS, and IP incurred expenditures to maintain, upgrade and expand the reliability of their transmission and distribution systems.

Ameren’s capital expenditures for 2004 were made principally for various upgrades at UE’s power plants, including the replacement of condenser bundles, and other upgrades during the 2004 refueling and maintenance outage at UE’s Callaway nuclear plant. The replacement and upgrade work at UE’s Callaway plant resulted in capital expenditures of $40 million in 2004. In addition, UE incurred costs for steam generators and low pressure rotors that were replaced during the 2005 refueling and maintenance outage at the Callaway nuclear plant. UE also incurred capital expenditures related to the installation of new CTs at its Venice plant and replacement of turbines at two of its power plants in 2004. In addition, UE’s capital expenditures included environmental and other upgrades at its power plants and expenditures incurred for new transmission and distribution lines. CILCORP’s and CILCO’s capital expenditures in 2004 were primarily related to power plant projects to improve flexibility in future fuel supply for power generation. Genco’s 2004 capital expenditures were primarily attributed to the replacement of a turbine generator at one of its power plants. Capital expenditures at IP and CIPS consisted of numerous projects to upgrade and maintain the reliability of their respective electric and gas transmission and distribution systems and to add new customers to the systems.

Ameren’s capital expenditures for 2003 principally related to various upgrades at UE’s and Genco’s coal-fired power plants, NO_x reduction equipment expenditures atCILCO’s generating plants, replacements and improvements to the existing electric transmission and distribution system and natural gas distribution system, and construction costs for CTs at UE.

The following table estimates the capital expenditures that will be incurred by the Ameren Companies from 2006 through 2010, including construction expenditures, capitalized interest and allowance for funds used during construction (except for Genco, which has no allowance for funds used during construction) and estimated expenditures for compliance with environmental standards:

	2006		2007    -		2010		Total
Ameren(a)(b)	$	1,225	$	3,805    -	$	5,250	$	5,030    -	$	6,475
UE(b)		790		1,660    -		2,290		2,450    -		3,080
CIPS		75		275    -		380		350    -		455
Genco		95		675    -		935		770    -		1,030
CILCO		110		435    -		605		545    -		715
IP		150		600    -		825		750    -		975

(a) Includes amounts for nonregistrant Ameren subsidiaries.

(b) Includes $290 million for the purchase of 1,490 megawatts of CTs.

UE’s estimated capital expenditures include transmission, distribution and generation-related activities, as well as expenditures for compliance with new environmental regulations discussed below. UE’s 2006 capital expenditures will satisfy its commitment, as part of UE’s 2002 Missouri electric rate case settlement, to make between $2.25 billion to $2.75 billion of infrastructure investments during the period January 1, 2002 to June 30, 2006, including the addition of 700 megawatts of generation capacity. The new capacity requirement was satisfied by the addition of 240 megawatts of CTs in 2002 and the transfer from Genco to UE of 550 megawatts of CTs at Pinckneyville and Kinmundy, Illinois, discussed above. In addition, commitments totaling at least $15 million for gas infrastructure improvements between July 1, 2003, and June 30, 2006, were agreed upon as part of UE’s 2003 Missouri gas rate case settlement.

In December 2005, UE entered into separate agreements to purchase CTs with 1,490 total megawatts of capacity for a total of $290 million. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further discussion of UE and IP regulatory proceedings related to capital expenditures and UE’s agreements to purchase CTs.

CIPS’ and CILCO’s estimated capital expenditures are primarily for transmission and distribution-related activities. Genco’s estimated capital expenditures are primarily for upgrades to existing coal and gas-fired generating facilities and compliance with new environmental regulations. CILCO’s estimate also includes capital expenditures for generation-related activities, as well as for compliance with new environmental regulations at AERG’s generating facilities.

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IP’s estimated capital expenditures in 2006 include energy infrastructure improvements that will satisfy Ameren’s commitment to the ICC to spend $275 million to $325 million through 2006, and other upgrades to the transmission and distribution system.

We continually review our generation portfolio and expected power needs. As a result, we could modify our plan for generation capacity, which could include changing the times when certain assets will be added to or removed from our portfolio, the type of generation asset technology that will be employed, and whether capacity may be purchased, among other things. Any changes that we may plan to make for future generating needs could result in significant capital expenditures or losses being incurred, which could be material.

Environmental Capital Expenditures

In May 2005, the EPA issued final regulations with respect to SO₂ and NO_x 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. The Clean Air Act and NO_x Budget Trading Program created marketable commodities called allowances. Each allowance gives the owner the right to emit one ton of SO₂ or NO_x. 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, the use of low-sulfur fuels, and through the application of pollution control technology. The NO_x Budget Trading Program limits emissions of NO_x during the ozone season (May through September). The NO_x Budget Trading Program applies to all electric generating units in Illinois beginning in 2004; it applies to all electric generating units in 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 NO_xlimits through the use and purchase of allowances or through the application of pollution control technology, including low-NO_x 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 ofDecember 31, 2005, UE, Genco, CILCO and EEI Illinois facilities held 272 tons, 11,977 tons, 2,178 tons and 2,859 tons, respectively, of NO_x emission allowances with vintages from 2005 to 2008. As of December 31, 2005, the SO₂and NO_xemission 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 NO_x emission allowance allocations for 2007 and 2008. UE, Genco, CILCO and EEI expect to use a substantial portion of the SO₂ and NO_x allowances for ongoing operations. Allocations of NO_x allowances for UE’s 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 as discussed below, 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 ratio of 2.86 allowances for every ton of emission.

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, NO_x, 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 these rules will be drafted and determined is still in its early stages, but should such rules be adopted, it would change our overall environmental compliance strategy for our 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 for the Ameren system to comply with the federal Clean Air Interstate Rule and Clean Air Mercury Rule. Estimates for 2006 to 2010 are included in the estimated

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capital expenditures above. 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

See Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a further discussion of environmental matters.

Cash Flows from Financing Activities

2005 versus 2004

Cash used in financing activities increased for Ameren in 2005 from 2004, primarily because of a $1 billion decrease in proceeds from common stock issuances in 2005 compared to 2004. The common stock proceeds in 2004 were principally used to fund the acquisition of IP and Dynegy’s 20% interest in EEI on September 30, 2004, and to repurchase and redeem certain IP indebtedness subsequent to the acquisition. In 2005, total common stock proceeds of $454 million included $345 million from the issuance of 7.4 million shares of common stock related to the settlement of a stock purchase obligation in Ameren’s adjustable conversion-rate equity security units. The 2005 increase in cash used in financing activities was also attributable to $224 million of net redemptions of short-term debt compared to net proceeds of $256 million in 2004. Decreased long-term debt redemptions of $847 million, increased long-term debt issuances of $185 million, and the absence in 2005 of a $67 million UE nuclear fuel lease payment in 2004 partially offset the decrease in cash from financing activities in 2005.

UE’s cash provided by financing activities increased in 2005 from 2004, primarily because of a $374 million decrease in long-term debt redemptions, a $239 million increase in issuances of long-term debt, a $35 million decrease in the payment of dividends to Ameren, and the absence of a $67 million nuclear fuel lease payment that was made in 2004. These 2005 benefits in cash from financing activities were partially offset by $295 million used for short-term debt repayments; in 2004, UE had net proceeds from short-term debt.

CIPS’ cash used in financing activities decreased in 2005 from 2004, primarily because of a $40 million cash benefit from reduced dividends paid to Ameren, and decreased long-term debt redemptions of $50 million. These cash benefits were partially offset by decreased issuances oflong-term debt of $35 million, and net repayments of utility money pool borrowings of $13 million.

Genco’s cash used in financing activities increased in 2005 from 2004, primarily because of a $225 million long-term debt redemption in 2005 and increased payments of $30 million on its note payable to Ameren. The funds for these repayments came from the $241 million in proceeds from the 2005 sale of 550 megawatts of CTs to UE. Net cash used in financing activities also increased because of a capital contribution decrease of $72 million. A reduction of $72 million in payments on a note payable to CIPS and a net increase in non-state-regulated subsidiary money pool borrowings of $95 million partially offset the additional uses of cash.

Effective May 1, 2005, Genco and CIPS amended certain terms of Genco’s subordinated affiliate note payable to CIPS by issuing to CIPS an amended and restated subordinated promissory note for $249 million with an interest rate of 7.125% per year, a 5-year amortization schedule, and a maturity of May 1, 2010.

CILCORP’s cash from financing activities benefited from an $88 million increase in proceeds from an intercompany note payable to Ameren and from decreased long-term debt redemptions of $41 million. Partially offsetting these increases were an increase in net repayments of money pool borrowings of $33 million and lower long-term debt issuances of $19 million. CILCO’s increase in cash from financing activities was mainly due to decreased long-term debt redemptions of $103 million and increased capital contributions from Ameren of $27 million. Partially offsetting these increases were increased net repayments of utility money pool borrowings of $36 million and increased dividend payments of $10 million.

IP’s cash used in financing activities increased in 2005 from 2004 primarily because 2004 included an $871 million capital contribution from Ameren. IP’s $76 million increase in dividends to Ameren also contributed to IP’s increase in cash used in financing activities. These negative items were partially offset by lower redemptions and repurchases of long-term debt of $732 million and by $75 million of cash received from utility money pool borrowings.

2004 versus 2003

Cash from financing activities increased for Ameren in 2004 from 2003, principally because of more proceeds from the issuance of common stock, an increase in net short-term debt, and lower preferred stock redemptions. Proceeds aggregating $1.3 billion from the issuance of common stock in February 2004 and July 2004 were used to fund the cash portion of the purchase price for the acquisition of IP and

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Dynegy’s 20% interest in EEI and to reduce IP debt assumed as part of the transaction and to pay related premiums. Proceeds received from the issuance of common stock in 2003 and 2002 were principally used by Ameren to acquire CILCORP in January 2003. Proceeds received from the issuance of common stock in 2004 were also temporarily used to repay a $100 million term loan at CILCO and to repay short-term debt totaling $181 million, pending their use for the acquisition and recapitalization of IP. A portion of the short-term debt was also used temporarily to fund UE’s maturity of long-term debt totaling $85 million in December 2004.

Ameren’s increase in cash flows from financing activities was partially offset by increased redemptions, repurchases and maturities of long-term debt, and an increase in nuclear fuel lease payments. The issuance of additional common shares and long-term debt resulted in an incremental $26 million in capital issuance costs in 2004 compared with 2003. Ameren also paid an additional $69 million in common dividends because more common shares were outstanding in 2004 than in 2003.

UE’s cash used in financing activities decreased in 2004 from 2003, primarily because of cash provided by increased net borrowings from the utility money pool and by increased net short-term debt. Partially offsetting these sources of cash were decreased long-term debt issuances, higher dividends paid to Ameren, and increased nuclear fuel lease payments.

CIPS’ cash used in financing activities increased in 2004 from 2003, principally because CIPS repaid $53 million to the utility money pool arrangement in 2004. CIPS borrowed $121 million from the money pool in 2003. Increased dividend payments of $13 million to Ameren in 2004, compared with 2003, contributed to CIPS’ increase in cash used in financing activities. Proceeds from the issuance of long-term debt in 2004, along with decreasedredemptions, repurchases, and maturities of long-term debt and preferred stock partially offset CIPS’ increase in cash used in financing activities in 2004.

Genco’s cash used in financing activities decreased in 2004 from 2003, primarily because of a capital contribution of $75 million received indirectly from Ameren in 2004. That capital contribution was used to make Genco’s prepayment of $75 million of the principal amount outstanding under its intercompany note payable to CIPS. Increased cash from operations allowed Genco to reduce non-state-regulated subsidiary money pool borrowings in 2004. Genco’s dividend payments were higher in 2004 than in 2003.

CILCORP’s cash from financing activities decreased in 2004 from 2003, primarily because of a $128 million decrease in utility money pool borrowings and a $20 million decrease in intercompany borrowings from Ameren in 2004. A capital contribution from Ameren of $75 million, decreased dividend payments, and increased long-term debt issuances helped to offset the decreases in cash from financing activities.

CILCO’s cash used in financing activities decreased in 2004 from 2003, primarily because of reduced dividend contributions made to CILCORP in 2004 and a $75 million capital contribution received indirectly from Ameren. CILCO’s reduction of cash flows used in financing activities was partially offset by reduced borrowings from the utility money pool arrangement in 2004.

Cash from financing activities increased for IP in 2004 from 2003, primarily because Ameren’s fourth-quarter capital contributions of $871 million were used to redeem and repurchase long-term debt of $700 million and to pay related premiums of $102 million. In 2003, $376 million was used for redemptions of short-term debt and long-term debt. In 2003, proceeds from the issuance of long-term debt and prepaid interest received from an affiliate, which totaled $278 million, partially offset cash used in financing activities.

Short-term Borrowings and Liquidity

Short-term borrowings typically consist of commercial paper issuances and drawings under committed bank credit facilities with maturities of 1 to 45 days. See Note 5 – Short-term Borrowings and Liquidity to our financial statements under Part II, Item 8, of this report.

The following table presents the various committed bank credit facilities of Ameren and EEI as of December 31, 2005:

Credit Facility	Expiration	Amount Committed		Amount Available
Ameren:(a)
Multiyear revolving(b)	July 2010	$	1,150	$	960
Multiyear revolving	July 2010		350		350
EEI:
One bank credit facility	April 2006		20		20
Total		$	1,520	$	1,330

(a) Ameren Companies may access these credit facilities through intercompany borrowing arrangements.

(b) UE, CIPS, CILCO, Genco and IP are also direct borrowers under this agreement.

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At December 31, 2005, Ameren had two committed bank credit facilities totaling $1.5 billion. The committed bank credit facilities are used to support our commercial paper programs. At December 31, 2005, Ameren and UE had $190 million and $80 million, respectively, ($413 million and $375 million for Ameren and UE, respectively, in 2004) of commercial paper borrowings outstanding, which reduced the available amounts under these facilities. Accordingly, $1.31 billion was available for use, subject to applicable regulatory short-term borrowing authorizations, by UE, CIPS, CILCO, IP and Ameren Services through a utility money pool agreement. One of these facilities, totaling $1.15 billion, in addition to being fully available to Ameren, may also be directly borrowed under by UE up to $500 million on a 364-day basis, and by CIPS, Genco, CILCO and IP up to $150 million each also on a 364-day basis. These facilities were also 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. Ameren has money pool agreements with and among its subsidiaries to coordinate and to provide for certain short-term cash and working capital requirements. Separate money pools are maintained for utility and non-state regulated entities. In addition, a unilateral borrowing agreement among Ameren, IP, and Ameren Services 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 pool agreement, together with any outstanding external short-term borrowings by IP, may not exceed $500 million pursuant to authorization from the ICC (such authorization also exists under PUHCA 1935). Ameren Services is responsible for operation and administration of the agreements. See Note 14 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for a detailed explanation of the money pool arrangements and the unilateral borrowing agreement.Ameren’s short-term debt balance includes $3 million and $4 million of borrowings at a nonregistrant subsidiary at December 31, 2005 and 2004, respectively. Access to our credit facilities for all Ameren Companies is subject to reduction based on use by affiliates.

In addition to committed credit facilities, a further source of liquidity for Ameren from time to time is available cash and cash equivalents. At December 31, 2005, Ameren had $96 million of cash and cash equivalents.

UE is authorized under PUHCA 1935 to have an aggregate of up to $1 billion of short-term unsecured debt instruments outstanding at any time. In addition, CIPS and CILCO have PUHCA 1935 authority to have an aggregate of up to $250 million each of short-term unsecured debt instruments outstanding at any time.

With the repeal of PUHCA 1935 in February 2006, the issuance of short-term debt securities by Ameren’s public-utility subsidiaries is now subject to approval by FERC under the Federal Power Act. Accordingly, UE, CIPS and CILCO are seeking short-term debt authority from FERC under the Federal Power Act. Pending receipt of an order approving their financing request, the legislation repealing PUHCA 1935 permits UE, CIPS and CILCO to continue to rely upon their current SEC authorization under PUHCA 1935 until not later than December 31, 2007.

Genco is authorized by FERC to have up to $300 million of short-term debt outstanding at any time. Genco is seeking a renewal of that authorization. IP and EEI have “blanket” short-term debt authorization from FERC.

With the repeal of PUHCA 1935 in February 2006, the issuance of short-term unsecured debt securities by Ameren and CILCORP, which was previously subject to SEC approval under PUHCA 1935, is no longer subject to approval by any regulatory body.

The Ameren Companies continually evaluate adequacy and appropriateness of their credit arrangements given changing business conditions. When business conditions warrant, changes may be made to existing credit agreements or other short-term borrowing arrangements.

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Long-term Debt and Equity

The following table presents the issuances of common stock and the issuances, redemptions, repurchases and maturities of long-term debt and preferred stock (net of any issuance discounts and including any redemption premiums) for the years 2005, 2004 and 2003 for the Ameren Companies, Medina Valley, and EEI. For additional information related to the terms and uses of these issuances and the sources of funds and terms for the redemptions, see Note 6 – Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report.

	Month Issued, Redeemed, Repurchased or Matured	2005		2004		2003
Issuances
Long-term debt
UE:
5.40% Senior secured notes due 2016	December	$	259	$	-	$	-
5.30% Senior secured notes due 2037	July		299		-		-
5.00% Senior secured notes due 2020	January		85		-		-
5.10% Senior secured notes due 2019	September		-		300		-
5.50% Senior secured notes due 2014	May		-		104		-
4.65% Senior secured notes due 2013	October		-		-		200
5.10% Senior secured notes due 2018	July		-		-		200
4.75% Senior secured notes due 2015	April		-		-		114
5.50% Senior secured notes due 2034	March		-		-		184
CIPS:
2004 Series environmental improvement revenue bonds due 2025	November		-		35		-
CILCO:
Series 2004 environmental improvement revenue bonds due 2039	November		-		19		-
IP:
11.50% series due 2010	January/December		-		-		150
Less: CILCO and IP activity prior to acquisitions			-		-		(150	)
Total Ameren long-term debt issuances		$	643	$	458	$	698
Common stock
Ameren:
7,402,320 Shares at $46.61(a)	May	$	345	$	-	$	-
10,925,000 Shares at $42.00	July		-		459		-
19,063,181 Shares at $45.90	February		-		875		-
6,325,000 Shares at $40.50	January		-		-		256
DRPlus and 401(k)	Various		109		107		105
Total common stock issuances		$	454	$	1,441	$	361
Total Ameren long-term debt and common stock issuances		$	1,097	$	1,899	$	1,059
Redemptions, Repurchases and Maturities
Long-term debt/capital lease
Ameren:
Senior notes due 2007(b)	February	$	95	$	-	$	-
Floating Rate Notes due 2003	December		-		-		150
UE:
7.375% First mortgage bonds due 2004	December		-		85		-
6.875% First mortgage bonds due 2004	August		-		188		-
7.00% First mortgage bonds due 2024	June		-		100		-
7.15% First mortgage bonds due 2023	August		-		-		75
7.65% First mortgage bonds due 2003	July		-		-		100
8.00% First mortgage bonds due 2022	May		-		-		85
8.25% First mortgage bonds due 2022	April		-		-		104
City of Bowling Green capital lease (Peno Creek CT)	December		3		4		3
CIPS:
6.49% First mortgage bonds due 2005	June		20		-		-
1993 Series A 6.375% due 2028	December		-		35		-
1993 Series B-2 5.90% due 2028	December		-		18		-
1993 Series C-2 5.70% due 2026	December		-		17		-
6.375% Series Z first mortgage bonds due 2003	April		-		-		40
7.50% Series X first mortgage bonds due 2007	April		-		-		50
6.99% Series 97-1 first mortgage bonds due 2003	March		-		-		5

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	Month Issued, Redeemed, Repurchased or Matured	2005		2004			2003
Genco:
7.75% Senior notes due 2005	November	$	225	$	-		$	-
CILCORP:(c)
9.375% Senior bonds due 2029	May/July		-		23			31
8.70% Senior bonds due 2009	Various		85		-			17
CILCO:(c)
6.13% First mortgage bonds due 2005	December		16		-			-
1992 Series C 6.50% due 2010	December		-		5			-
1992 Series A 6.50% due 2018	December		-		14			-
8.20% First mortgage bonds due 2022	April		-		-			65
7.80% Two series of first mortgage bonds due 2023	April		-		-			10
6.82% First mortgage bonds due 2003	February		-		-			25
Secured bank term loan	February		-		100			-
Hallock substation power modules bank loan due through 2004	August		-		-			3
Kickapoo substation power modules bank loan due through 2004	August		-		-			2
IP:(c)
6.75% First mortgage bonds due 2005	March		70		-			-
11.50% First mortgage bonds due 2010	November/December		-		649			-
7.50% First mortgage bonds due 2025	December		-		68			-
7.40% Series 1994 pollution control bonds B due 2024	December		-		86			-
6.00% First mortgage bonds due 2003	September		-		-			90
6.50% First mortgage bonds due 2003	August		-		-			100
Note payable to IP SPT
5.34% Series due 2003	Various		-		-			29
5.38% Series due 2005	Various		31		32			57
5.54% Series due 2007	Various		58		54			-
Medina Valley:
Secured term loan due 2019	June		-		-			36
EEI:
2000 bank term loan due 2004	June		-		40			-
1991 8.60% Senior medium term notes	December		7		6			7
1994 6.61% Senior medium term notes	December		8		8			7
Preferred Stock
CILCO: 5.85% Series	July		1		1			1
CIPS: 1993 auction preferred	December		-		-			30
Less: CILCORP, CILCO and IP activity prior to acquisition date			-		(67	)		(276	)
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities		$	619	$	1,466		$	846

(a) Shares issued upon settlement of the purchase contracts, which were a component of the adjustable conversion-rate equity security units.

(b) Component of the adjustable conversion-rate equity security units.

(c) Amounts for CILCORP and CILCO before January 31, 2003, and IP before September 30, 2004, have not been included in the total long-term debt and preferred stock redemption and repurchases at Ameren.

The following table presents the authorized amounts under Form S-3 shelf registration statements filed and declared effective for certain Ameren Companies 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

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 soldunder 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.

Ameren is also currently selling newly issued shares of its common stock under certain of its 401(k) plans pursuant to effective SEC 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.

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Ameren, UE and CIPS may sell all or a portion of the remaining securities registered under their effective registration statements if market conditions and capital requirements warrant such a sale. Any offer and sale will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

Indebtedness Provisions and Other Covenants

See Note 5 – Short-term Borrowings and Liquidity to our financial statements under Part II, Item 8, of this report for a discussion of the covenants and provisions contained in Ameren’s and EEI’s bank credit facilities. Also see Note 6 – Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for a discussion of covenants and provisions contained in certain of the Ameren Companies’ indenture agreements and articles of incorporation.

Our credit agreements contain indebtedness cross-default provisions that could trigger a default under the facilities. In the event that 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 default under the Ameren credit facilities would occur. A CILCO bankruptcy would also cause a default under CILCORP’s debt agreements. In addition, a default of $50 million or greater or a bankruptcy would cause a default under the International Swap and Derivatives Association (ISDA) master agreements supporting $100 million of Ameren LIBOR swaps.

At December 31, 2005, the Ameren Companies were in compliance with their credit agreement, indenture, and articles of incorporation provisions and covenants.

We consider access to short-term and long-term capital markets a significant source of funding for capital requirements not satisfied by our operating cash flows. Our inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and expand our businesses. After assessing our current operating performance, liquidity, and credit ratings (see Credit Ratings below), we believe that we will continue to have access to the capital markets. However, events beyond our control may create uncertainty in the capital markets. Such events might increase our cost of capital or adversely affect our ability to access the capital markets.

Dividends

Common Dividends

Ameren paid to its shareholders common stock dividends totaling $511 million, or $2.54 per share, in 2005,$479 million, or $2.54 per share, in 2004, and $410 million, or $2.54 per share, in 2003. This resulted in a payout rate based on net income of 84%, 90% and 78% in 2005, 2004 and 2003, respectively. Dividends paid to common shareholders in relation to net cash provided by operating activities for the same periods were 44%, 42% and 40%, respectively.

The amount and timing of dividends payable on Ameren’s common stock are within the sole discretion of Ameren’s board of directors. The board of directors has not set specific targets or payout parameters when declaring common stock dividends. However, the board considers various issues, including Ameren’s historic earnings and cash flow, projected earnings, projected cash flow and potential cash flow requirements, dividend payout rates at other utilities, return on investments with similar risk characteristics, and overall business considerations. On February 10, 2006, Ameren’s board of directors declared a quarterly common stock dividend of 63.5 cents per share payable on March 31, 2006, to shareholders of record on March 8, 2006.

Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends. UE would experience restrictions on dividend payments if it were to extend or defer interest payments on its subordinated debentures. CIPS’ articles of incorporation require its dividend payments to be based on ratios of common stock to total capitalization and other provisions related to certain operating expenses and accumulations of earned surplus. Genco’s indenture includes restrictions that prohibit it from making any dividend payments if debt service coverage ratios are below a defined threshold. CILCORP has dividend payment restrictions if leverage ratio and interest coverage ratio thresholds are not met or if CILCORP’s senior long-term debt does not have the ratings described in its indenture. CILCO has restrictions in its Articles of Incorporation on dividend payments relative to the ratio of its balance of retained earnings to the annual dividend requirement on its preferred stock and amounts to be set aside for any sinking fund retirement of its 5.85% Series preferred stock. At December 31, 2005, none of the conditions described above that would restrict the payment of dividends existed. In its approval of the acquisition of IP by Ameren, the ICC issued an order that permits IP to pay dividends on its common stock subject to certain conditions related to credit ratings of IP and Ameren and the elimination of IP’s 11.50% mortgage bonds. Given the current credit ratings of IP and the amount of IP’s 11.50% mortgage bonds that remain outstanding, IP’s payment of dividends on its common stock was restricted to $80 million in 2005 and is restricted to $160 million cumulatively through 2006. In addition, in accordance with the order issued by the ICC, IP will establish a dividend policy comparable to that of

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Ameren’s other Illinois utilities and consistent with achieving and maintaining a common equity–to-total-capitalization ratio between 50% and 60%.

The following table presents dividends paid by Ameren Corporation and by Ameren’s subsidiaries to their respective parents.

	2005		2004		2003
UE	$	280	$	315	$	288
CIPS		35		75		62
Genco		88		66		36
CILCORP(a)		30		18		27
IP(b)		76		-		(b	)
Ameren (parent)		-		-		(3	)
Nonregistrants		2		5		-
Dividends paid by Ameren	$	511	$	479	$	410

(a) Before February 2003, CILCORP’s dividends would have been paid to AES. These amounts are excluded from the total dividends paid to Ameren.

(b) Before October 2004, the ICC prohibited IP from paying dividends. If permitted, IP’s dividends would have been paid directly to Illinova and indirectly to Dynegy.

Preferred Dividends

Certain of the Ameren Companies have issued preferred stock on which they are obligated to make preferred dividend payments. Each company’s board of directors declares the preferred stock dividends to shareholders of record on a certain date, stating the date on which it is payable and the amount that will be paid. See Note 10 – Stockholder Rights Plan and Preferred Stock to our financial statements under Part II, Item 8, of this report for further detail concerning the preferred stock issuances.

Contractual Obligations

The following table presents our contractual obligations as of December 31, 2005. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for information regarding Ameren’s, UE’s and IP’s capital expenditure commitments related to UE’s 2002 Missouri electric rate case settlement, UE’s 2004 Missouri gas rate case settlement, and Ameren’s acquisition of IP. See Note 11 – Retirement Benefits to our financial statements under Part II, Item 8, of this report for information regarding expected minimum funding levels for our pension plan. These capital commitments and expected pension funding amounts are not included in the table below. In addition, routine short-term purchase order commitments are not included.

	Total			Less than 1 Year		1 – 3 Years		3 – 5 Years		After 5 Years
Ameren:(a)
Long-term debt and capital lease obligations(b)(c)(d)	$	5,350		$	96	$	744	$	581	$	3,929
Short-term debt		193			193		-		-		-
Interest payments(b)		3,864			285		512		438		2,629
Operating leases(e)		265			29		45		39		152
Other obligations(f)		3,919			1,384		1,660		766		109
Preferred stock of subsidiary subject to mandatory redemption		19			1		18		-		-
Total cash contractual obligations	$	13,610		$	1,988	$	2,979	$	1,824	$	6,819
UE:
Long-term debt and capital lease obligations	$	2,708	(c)	$	4	$	156	$	7	$	2,541
Short-term debt		80			80		-		-		-
Interest payments(b)		1,979			124		241		228		1,386
Operating leases(e)		122			10		19		18		75
Other obligations(f)		1,653			468		703		398		84
Total cash contractual obligations	$	6,542		$	686	$	1,119	$	651	$	4,086
CIPS:
Long-term debt	$	431	(c)	$	20	$	15	$	-	$	396
Borrowings from money pool		2			2		-		-		-
Interest payments		286			25		48		48		165
Operating leases(e)		2			-		1		1		-
Other obligations(f)		384			217		122		44		1
Total cash contractual obligations	$	1,105		$	264	$	186	$	93	$	562

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	Total			Less than 1 Year		1 – 3 Years		3 – 5 Years		After 5 Years
Genco:
Long-term debt	$	475	(c)	$	-	$	-	$	200	$	275
Borrowings from money pool		203			203		-		-		-
Interest payments		660			39		78		75		468
Operating leases(e)		86			5		9		9		63
Other obligations(f)		611			141		281		177		12
Total cash contractual obligations	$	2,035		$	388	$	368	$	461	$	818
CILCORP:
Long-term debt(b)(g)	$	344		$	-	$	-	$	124	$	220
Borrowings from money pool		154			154		-		-		-
Interest payments(g)		530			31		62		50		387
Operating leases(e)		21			1		3		2		15
Preferred stock of subsidiary subject to mandatory redemption		19			1		18		-		-
Other obligations(f)		697			342		262		93		-
Total cash contractual obligations	$	1,765		$	529	$	345	$	269	$	622
CILCO:
Long-term debt	$	122		$	-	$	50	$	-	$	72
Borrowings from money pool		161			161		-		-		-
Interest payments		83			8		8		8		59
Operating leases(e)		21			1		3		2		15
Preferred stock subject to mandatory redemption		19			1		18		-		-
Other obligations(f)		697			342		262		93		-
Total cash contractual obligations	$	1,103		$	513	$	341	$	103	$	146
IP:
Long-term debt(d)	$	920	(c)	$	72	$	173	$	250	$	425
Borrowings from money pool		75			75		-		-		-
Interest payments(b)		306			42		71		29		164
Operating leases(e)		18			5		7		6		-
Other obligations(f)		516			338		151		16		11
Total cash contractual obligations	$	1,835		$	532	$	402	$	301	$	600

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

(b) The weighted average variable rate debt has been calculated using the interest rate as of December 31, 2005.

(c) Excludes unamortized discount of $6 million, $1 million, $1 million and $5 million at UE, CIPS, Genco and IP, respectively.

(d) Excludes fair market value adjustments of long-term debt for CILCORP and IP, totaling $68 million and $45 million, respectively.

(e) Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. The $1 million annual obligation for these items is 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 that period is indefinite.

(f) Represents purchase contracts for coal, gas, nuclear fuel, and electric capacity. Also represents a decommissioning liability at IP.

(g) Represents parent company only.

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.

Credit Ratings

The following table presents the principal credit ratings of the Ameren Companies by Moody’s, S&P and Fitch effective on the date of this report:

	Moody’s	S&P	Fitch
Ameren:
Issuer/corporate credit rating	Baa1	BBB+	N/A
Unsecured debt	Baa1	BBB	A-
Commercial paper	P-2	A-2	F2
UE:
Secured debt	A1	BBB+	A+
Commercial paper	P-1	A-2	F1
CIPS:
Secured debt	A3	A-	A
Genco:
Unsecured debt	Baa2	BBB+	BBB+
CILCORP:
Unsecured debt	Baa3	BBB	BBB+
CILCO:
Secured debt	A3	A-	A
IP:
Secured debt	Baa2	BBB+	BBB

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On September 30, 2005, Moody’s placed the long-term credit ratings of Ameren, CIPS, CILCORP, CILCO and IP under review for possible downgrade. On December 15, 2005, Moody’s downgraded Ameren’s senior unsecured debt and issuer credit ratings from A3 to Baa1, CIPS’ senior secured debt rating from A1 to A3, CILCORP’s senior unsecured debt rating from Baa2 to Baa3, CILCO’s senior secured debt rating from A2 to A3, and IP’s senior secured debt rating from Baa1 to Baa2, among other ratings downgrades. These ratings remain under review for possible downgrade. In addition, Moody’s also placed under review for possible downgrade Ameren’s P-2 commercial paper rating and UE’s long-term debt, preferred stock, and commercial paper ratings. All of these ratings actions were undertaken principally because of recent unfavorable actions by the Illinois governor with respect to CIPS, CILCO and IP electric rates in 2007. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report, for a more detailed discussion of actions by the Illinois governor and others.

On October 3, 2005, S&P downgraded the Ameren Companies’ long-term corporate credit ratings from A- to BBB+ and Ameren’s senior unsecured debt from BBB+ to BBB, the secured debt ratings at UE and IP, both from A- to BBB+, Genco’s senior unsecured debt from A- to BBB+ and CILCORP’s senior unsecured debt from BBB+ to BBB, among other ratings downgrades. S&P also placed all of the Ameren Companies’ ratings under negative credit watch. These downgrades were also principally a result of recent unfavorable actions by the Illinois governor with respect to CIPS, CILCO and IP electric rates in 2007.

As of March 1, 2006, Fitch had not made any changes to ratings or outlooks for the Ameren Companies.

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital. It may also increase the cost of borrowing and power supply, among other things, resulting in a negative impact on earnings. For example, if at December 31, 2005, the Ameren Companies had a sub-investment-grade rating (less than BBB- or Baa3), Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP could have been required to post collateral for certain trade obligations amounting to $123 million, $31 million, $3 million, less than $1 million, $13 million, $13 million, or $25 million, respectively. In addition, the cost of borrowing under our credit facilities can increase or decrease with credit ratings. A credit rating is not a recommendation to buy, sell or hold securities. It should be evaluated independently of any other rating. Ratings are subject to revision or withdrawal at any time by the rating organization.

OUTLOOK

Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2006 and beyond:

Revenues

• By the end of 2006, electric rates for Ameren’s operating subsidiaries will have been fixed or declining for periods ranging from 15 years to 25 years. In 2006, electric rate adjustment moratoriums and power supply contracts expire in Ameren’s regulatory jurisdictions.

• Approximately 11 million megawatthours supplied annually by Genco and 6 million megawatthours supplied annually by AERG have been subject to contracts to provide CIPS and CILCO, respectively, with power. The prices in these power supply contracts of $34.00 per megawatthour for AERG and $38.50 per megawatthour for Genco were below estimated market prices for similar contracts in early 2006. Most of Genco’s other wholesale and retail electric power supply agreements also expire during 2006 and substantially all of these are below market prices for similar contracts in early 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. This approval is subject to rehearing and appeal.

• Certain Illinois legislators, the Illinois attorney general, the Illinois governor, and other parties have sought and continue to seek various methods, including legislation, to block the power procurement auction and/or the recovery of related costs for power supply resulting from the auction through rates to customers. 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 are willing to work to ease the burden of higher energy prices on residential customers through a rate increase phase-in plan, as long as such plan allows for the full and timely recovery of costs and does not adversely impact credit ratings.

• The Ameren Illinois utilities filed proposed new tariffs with the ICC in December 2005 that would increase revenues from electric delivery services, effective January 2, 2007, 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) per year commencing in 2008. These proposed tariffs are subject to the approval of the ICC, which is expected to rule by November 2006. See Note 3 – Rate and

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Regulatory Matters to our financial statements under Part II, Item 8, of this report.

• In accordance with an August 2002 MoPSC order, UE submitted a confidential cost-of-electric service study to the MoPSC staff and others in December 2005. The study was based on a test year ending June 30, 2005. This cost-of-electric service study 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 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 the status of the rulemaking proceeding at the MoPSC for 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.

• We expect continued economic growth in our service territory to benefit energy demand in 2006 and beyond, but higher energy prices could result in reduced demand from consumers.

• UE, Genco and CILCO are seeking to raise the equivalent availability and capacity factors of their power plants through a process improvement program.

• In 2006, we expect natural gas and coal prices to support power prices below 2005 levels. However, very volatile power prices in the Midwest affect the amount of revenues UE, Genco and CILCO (through AERG) can generate by marketing power into the wholesale and interchange markets and influence the cost of power we purchase in the interchange markets.

• 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.

Fuel and Purchased Power

• In 2005, 86% of Ameren’s electric generation (UE - 80%, Genco - 93%, CILCO - 99%) was supplied by its coal-fired power plants. About 85% of the coal used by these plants (UE - 97%, Genco - - 66%, CILCO - 26%) was delivered by railroads from the Powder River Basin in Wyoming. In May 2005, the joint Burlington Northern-Union Pacific rail line in the Powder River Basin suffered two derailments due to unstable track conditions. As a result, the Federal Rail Administration placed slow orders, or speed restrictions, on sections of the line until the track could be made safe. In addition, large sections of track on a Union Pacific rail line were damaged by heavy rains near Topeka, Kansas, inOctober 2005. These actions reduced deliveries of coal from Powder River Basin mines. Because of the railroad delivery problems, UE, Genco and CILCO received only about 90% to 95% of scheduled deliveries of Powder River Basin coal in 2005. The impact of the coal delivery issues on inventory levels was exacerbated by warm summer weather and high power prices, which caused UE, Genco and CILCO plants to run more and to burn record amounts of coal. Maintenance on the rail lines into the Powder River Basin is expected to continue in 2006, but to have less of an impact on deliveries. Further disruptions in coal deliveries could cause UE, Genco and CILCO to pursue a strategy that could include reducing sales of power during low-margin periods, utilizing higher-cost fuels to generate required electricity and purchasing power.

• Due to higher energy and transportation costs, Ameren’s coal and related transportation costs are expected to increase 10% to 15% in 2006 and an additional 15% to 20% in 2007. In addition, power generation from higher-cost gas-fired plants is expected to increase in the next few years. See Item 7A – Quantitative and Qualitative Disclosures about Market Risk for information about the percentage of fuel and transportation requirements that are price-hedged for 2006 through 2010.

• The MISO Day Two Energy Market resulted in significantly higher MISO-related costs 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.

• In July 2005, a new law was enacted that will enable the MoPSC to put in place fuel, purchased power, and environmental cost recovery mechanisms for Missouri utilities. The legislation 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.

Other Costs

• In December 2005, there was a breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydro-electric 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

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incident. Additionally, the incident is being investigated by FERC and by state authorities. UE expects the results of these reviews later in 2006. The facility will remain closed 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. 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. 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 to meet load requirements, reduced interchange sales, and increased expenses.

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

• Over the next few years, we expect rising employee benefit costs as well as higher insurance and security costs associated with additional measures we have taken, or may need to take, at UE’s Callaway nuclear plant and our other facilities. Insurance premiums may also increase as a result of the Taum Sauk incident.

• We are currently undertaking cost reduction or control initiatives associated with the strategic sourcing of purchases and streamlining of all aspects of our business.

Capital Expenditures

• The EPA has issued more stringent emission limits on all coal-fired power plants. Between 2006 and 2016, Ameren expects that certain Ameren Companies will be required to invest between $2.1 billion and $2.9 billion to retrofit their power plants with pollution control equipment. More stringent state regulations could increase these costs. These investments will also result in higher ongoing operating expenses. Approximately 55% to 60% of this investment will be in Ameren’s regulated UE operations, and therefore it is expected to be recoverable over time from ratepayers. The recoverability of amounts expended in non-rate-regulated operations will depend on whether market prices for power adjust as a result of this increased investment.

• In December 2005, UE reached agreements to purchase three gas-fired CT facilities with a capacity of nearly 1,500 megawatts in transactions valued at $290 million. These transactions are subject to various regulatory agency approvals by state and federal regulators. The purchase of these facilities is designedto meet UE’s increased generating capacity needs and to provide additional flexibility in determining future base-load generating capacity additions. UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity, but at this time does not expect to require new baseload generation capacity until at least 2015.

Affiliate Transactions

• Due to a MoPSC order issued in conjunction with the transfer of UE’s Illinois service territory to CIPS, UE and Genco amended an agreement to jointly dispatch electric generation in January 2006. In 2005, such an amendment probably would have resulted in a transfer of electric margins from Genco to UE of $35 million to $45 million based on certain assumptions and historical results. Ameren’s consolidated earnings could be affected when electric rates for UE are adjusted by the MoPSC to reflect the change in revenue. The Missouri OPC intervened in the FERC proceeding considering approval of the proposed amendment 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. The ultimate impact of the amendment will be determined by whether the joint dispatch agreement continues to exist, future native load demand, the availability of electric generation from UE and Genco and market prices, among other things, but such impact could be material. See Risk Factors under Part I, Item 1A and 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 modification to the joint dispatch agreement ordered by the MoPSC and the further amendments sought by the Missouri OPC in this FERC proceeding.

• On December 31, 2005, a power supply agreement for UE, CIPS and IP with EEI expired. Power supplied under the agreement by EEI to UE, CIPS and IP was priced at EEI’s cost. The expiration of this agreement may require UE, Genco (as a result of its power supply agreement with CIPS) and IP to incur higher fuel or purchased power costs. Power previously supplied under this agreement to UE, CIPS and IP will be sold by Marketing Company at market prices. Market prices in early 2006 were above EEI’s cost to produce power. See Note 14 – Related Party Transactions to our financial statements under Part II, Item 8 of this report for a further discussion of the EEI power supply agreement.

Recent Acquisitions

• Ameren, CILCORP, CILCO and IP expect to focus on realizing integration synergies associated with these

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acquisitions, including utilizing more economical fuels at CILCORP and CILCO and reducing administrative and operating expenses at IP.

Other

• In August 2005, President George W. Bush signed into law the Energy Policy Act of 2005. This legislation includes several provisions that affect the Ameren Companies, including the repeal of PUHCA 1935 (under which Ameren was registered) effective in February 2006, and tax incentives for investments in pollution control equipment, electric transmission property, clean coal facilities, and natural gas distribution lines. The Energy Policy Act of 2005 alsoextends the Price-Anderson nuclear plant liability provisions under the Atomic Energy Act of 1954.

The above items could have a material impact on our results of operations, financial position, or liquidity. Additionally, in the ordinary course of business, we evaluate strategies to enhance our results of operations, financial position, and liquidity. These strategies may include acquisitions, divestitures, opportunities to reduce costs or increase revenues, and other strategic initiatives to increase Ameren’s shareholder value. We are unable to predict which, if any, of these initiatives will be executed. The execution of these initiatives may have a material impact on our future results of operations, financial position, or liquidity.

REGULATORY MATTERS

See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.

ACCOUNTING MATTERS

Critical Accounting Policies

Preparation of the financial statements and related disclosures in compliance with GAAP requires the application of appropriate technical accounting rules and guidance, as well as the use of estimates. Our application of these policies involves judgments regarding many factors which in and of themselves could materially affect the financial statements and disclosures. We have outlined below the critical accounting policies that we believe are most difficult, subjective or complex. Any change in the assumptions or judgments applied in determining the following matters, among others, could have a material impact on future financial results.

Accounting Policy	Uncertainties Affecting Application
Regulatory Mechanisms and Cost Recovery All of the Ameren Companies, except Genco, defer costs as regulatory assets in accordance with SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” and make investments that they assume will be collected in future rates.	•        Regulatory environment and external regulatory decisions and requirements •        Anticipated future regulatory decisions and their impact •        Impact of deregulation, rate freezes, and competition on ratemaking process and ability to recover costs
Basis for Judgment We determine which costs are recoverable by consulting previous rulings by state regulatory authorities in jurisdictions where we operate or other factors that lead us to believe that cost recovery is probable. If facts and circumstances lead us to conclude that a recorded regulatory asset is no longer probable of being recovered, we will record a charge to earnings, which could be material.
Environmental Costs We accrue for all known environmental contamination where remediation can be reasonably estimated, but some of our operations have existed for over 100 years and previous contamination may be unknown to us.	•        Extent of contamination •        Responsible party determination •        Approved methods for cleanup •        Present and future legislation and governmental regulations and standards •        Results of ongoing research and development regarding environmental impacts
Basis for Judgment We determine the proper amounts to accrue for known environmental contamination by using internal and third-party estimates of cleanup costs in the context of current remediation standards and available technology.

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Accounting Policy	Uncertainties Affecting Application
Unbilled Revenue At the end of each period, we project expected usage, and we estimate the amount of revenue to record for services that have been provided to customers but not yet billed.	•        Projecting customer energy usage •        Estimating impacts of weather and other usage-affecting factors for the unbilled period •        Estimating loss of energy during transmission and delivery
Basis for Judgment We base our estimate of unbilled revenue each period on the volume of energy delivered, as valued by a model of billing cycles and historical usage rates and growth by customer class for our service area. This figure is then adjusted for the modeled impact of seasonal and weather variations based on historical results.
Valuation of Goodwill, Long-Lived Assets, and Asset Retirement Obligations
We assess the carrying value of our goodwill and long-lived assets to determine whether they are impaired. We also review for the existence of asset retirement obligations. If an asset retirement obligation is identified, we determine its fair value and subsequently reassess and adjust the obligation, as necessary.	•        Management’s identification of impairment indicators •        Changes in business, industry, laws, technology, or economic and market conditions •        Valuation assumptions and conclusions •        Estimated useful lives of our significant long-lived assets •        Actions or assessments by our regulators •        Identification of an asset retirement obligation
Basis for Judgment Annually, or whenever events indicate a valuation may have changed, we use internal models and third parties to determine fair values. We use various methods to determine valuations, including earnings before interest, taxes, depreciation and amortization multiples, and discounted, undiscounted, and probabilistic discounted cash flow models with multiple scenarios. The identification of asset retirement obligations is conducted through the review of legal documents and interviews.
Benefit Plan Accounting Based on actuarial calculations, we accrue costs of providing future employee benefits in accordance with SFAS Nos. 87, 106 and 112, which provide guidance on benefit plan accounting. See Note 11 – Retirement Benefits to our financial statements under Part II, Item 8, of this report.	•        Future rate of return on pension and other plan assets •        Interest rates used in valuing benefit obligations •        Health care cost trend rates •        Timing of employee retirements and mortality assumptions
Basis for Judgment We use a third-party consultant to assist us in evaluating and recording the proper amount for future employee benefits. Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension assets is based on our review of available historical, current, and projected rates, as applicable.

Impact of Future Accounting Pronouncements

The FASB has stated it plans to issue an exposure draft on pension and postretirement benefit obligations, in the first quarter of 2006, with the goal of making the provisions of a final standard effective for fiscal years ending after December 15, 2006. The proposed standard is expected to require recognition of the overfunded or underfunded status of defined benefit pension and postretirement plans as an asset or a liability in the balance sheet, which would include recognition of all previously unrecognized items (such as unrecognized actuarial gains and losses). If approved, this standard could have a material impact on the Ameren Companies’ financial position.

See Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report.

EFFECTS OF INFLATION AND CHANGING PRICES

Our rates for retail electric and gas utility service are regulated by the MoPSC and the ICC. Nonretail electric rates are regulated by FERC. Our Missouri electric and gas rates were set through June 30, 2006, as part of the settlement ofour Missouri electric and gas rate cases. Our Illinois electric rates are legislatively fixed through January 1, 2007. Even without these rate moratoriums, adjustments to rates are based on a regulatory process that reviews a historical

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period. As a result, revenue increases will lag behind changing prices. Inflation affects our operations, earnings, stockholders’ equity, and financial performance.

The current replacement cost of our utility plant substantially exceeds our recorded historical cost. Under existing regulatory practice, only the historical cost of plant is recoverable from customers. As a result, cash flows designed to provide recovery of historical costs through depreciation might not be adequate to replace the plant in future years. The generation portion of our business in Illinois is principally non- rate-regulated and therefore does not have regulated recovery mechanisms.

In our retail electric utility jurisdictions, we currently have no tariffs for adjusting rates to accommodate changes in the cost of fuel for electric generation or the cost of purchased power. However, in Missouri, the MoPSC iscurrently developing rules covering the establishment by utilities of fuel and purchased power, and environmental cost recovery mechanisms. In Illinois, the ICC issued an order in January 2006 that would allow the recovery by Illinois electric utilities of purchased power costs directly from customers through a cost recovery mechanism starting in 2007. The ICC order is subject to rehearing and appeal. UE, Genco, CILCORP and CILCO are affected by changes in market prices for natural gas to the extent that they must purchase natural gas to run CTs. These companies have structured various supply agreements to maintain access to multiple gas pools and supply basins, to minimize the impact to the financial statements. In our retail gas utility jurisdictions, changes in gas costs are generally reflected in billings to gas customers through PGA clauses. See Quantitative and Qualitative Disclosures about Market Risk – Commodity Price Risk under Part II, Item 7A, of this report for further information.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk is the risk of changes in value of a physical asset or a financial instrument, derivative or non-derivative, caused by fluctuations in market variables such as interest rates. The following discussion of our risk management activities includes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those projected in the forward-looking statements. We handle market risks in accordance with established policies, which may include entering into various derivative transactions. In the normal course of business, we also face risks that are either nonfinancial or nonquantifiable. Such risks, principally business, legal and operational risks, are not part of the following discussion.

Our risk management objective is to optimize our physical generating assets within prudent risk parameters. Our risk management policies are set by a Risk Management Steering Committee, which is comprised of senior-level Ameren officers.

Interest Rate Risk

We are exposed to market risk through changes in interest rates associated with:

• long-term and short-term variable-rate debt;

• fixed-rate debt;

• commercial paper; and

• auction-rate long-term debt.

We manage our interest rate exposure by controlling the amount of these instruments we hold within our total capitalization portfolio and by monitoring the effects of market changes in interest rates.

The following table presents the estimated increase in our annual interest expense and decrease in net income if interest rates were to increase by 1% on variable rate debt outstanding at December 31, 2005:

	Interest Expense			Net Income(a)
Ameren	$	11		$	(7	)
UE		5			(3	)
CIPS		(b	)		(b	)
Genco		2			(1	)
CILCORP		4			(2	)
CILCO		2			(1	)
IP		4			(3	)

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

(b) Less than $1 million.

The model does not consider potential reduced overall economic activity that would exist in such an environment. In the event of a significant change in interest rates, management would probably act to further mitigate our exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure.

Credit Risk

Credit risk represents the loss that would be recognized if counterparties fail to perform as contracted. NYMEX-traded futures contracts are supported by the financial and credit quality of the clearing members of the NYMEX and have nominal credit risk. On all other transactions, we are exposed to credit risk in the event of nonperformance by the counterparties to the transaction.

Our physical and financial instruments are subject to credit risk consisting of trade accounts receivables,

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executory contracts with market risk exposures, and leveraged lease investments. The risk associated with trade receivables is mitigated by the large number of customers in a broad range of industry groups who make up our customer base. At December 31, 2005, no nonaffiliated customer represented greater than 10%, in the aggregate, of our accounts receivable. Our revenues are primarily derived from sales of electricity and natural gas to customers in Missouri and Illinois. UE, Genco, IP and Marketing Company have credit exposure associated with interchange purchase and sale activity with nonaffiliated companies. At December 31, 2005, UE’s, Genco’s, IP’s and Marketing Company’s combined credit exposure to non-investment-grade counterparties related to interchange purchases and sales was $39 million, net of collateral (2004 - $2 million). We establish credit limits for these counterparties and monitor the appropriateness of these limits on an ongoing basis through a credit risk management program that involves daily exposure reporting to senior management, master trading and netting agreements, and credit support, such as letters of credit and parental guarantees. We also analyze each counterparty’s financial condition before we enter into sales, forwards, swaps, futures or option contracts, and we monitor counterparty exposure associated with our leveraged leases. We estimate our credit exposure to MISO associated with the implementation of the MISO Day Two Energy Market on April 1, 2005, to be $26 million at December 31, 2005.

Equity Price Risk

Our costs of providing defined benefit retirement and postretirement benefit plans are dependent upon a number of factors including the rate of return on plan assets.

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.

In future years, the costs of such plans reflected in net income or OCI and cash contributions to the plans could increase materially without pension asset portfolio investment returns equal to or in excess of our assumed return on plan assets of 8.5%.

UE also maintains a trust fund, as required by the NRC and Missouri law, to fund certain costs of nuclear plant decommissioning. As of December 31, 2005, this fund was invested primarily in domestic equity securities (66%) and debt securities (34%) and totaled $250 million (2004 - $235 million). By maintaining a portfolio that includes long-term equity investments, UE seeks to maximize the returns to be utilized to fund nuclear decommissioning costs within acceptable parameters of risk. However, the equity securities included in the portfolio are exposed to price fluctuations in equity markets and the fixed-rate, fixed-income securities are exposed to changes in interest rates. UE actively monitors the portfolio by benchmarking the performance of its investments against certain indices and by maintaining and periodically reviewing established target allocation percentages of the assets of the trust to various investment options. UE’s exposure to equity price market risk is in large part mitigated, because UE is currently allowed to recover decommissioning costs in its electric rates, which would include unfavorable investment results.

Commodity Price Risk

We are exposed to changes in market prices for electricity, fuel, and natural gas. UE’s, Genco’s, AERG’s and EEI’s risks of changes in prices for power sales are partially hedged through sales agreements to regulated and unregulated electric customers. We also attempt to mitigate financial risks through structured risk management programs and policies, through structured forward-hedging programs, and through derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset.

CIPS, CILCO and IP have electric rate freezes in Illinois through January 1, 2007, and power supply contracts in place through December 31, 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 a September 2006 auction. The approved framework also allows for full cost recovery of power through a rate mechanism. This approval is subject to rehearing and appeal. UE has an electric rate freeze in Missouri through June 30, 2006, and is also exposed to price risk on its interchange sales.

        During 2006, Genco’s and AERG’s electric power supply agreements with CIPS (through Marketing Company)

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and CILCO, respectively, expire, as do most of Genco’s wholesale and retail electric power supply agreements. EEI’s power supply agreements with UE and CIPS expired on December 31, 2005. The expiration of these agreements expose Genco, AERG and EEI to price risk for the power they generate and sell. Genco and AERG will likely participate through Marketing Company in the September 2006 Illinois auction. The auction will be structured to allow for one-third of CIPS’, CILCO’s and IP’s power needs to be procured each year after all power needs are initially procured in the September 2006 auction subject to an ICC-ordered limitation of 35% on the amount of power that can be provided of CIPS’, CILCO’s, and IP’s expected load by any one supplier or group of affiliated suppliers. See Note 3 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for more information on the Illinois power procurement process.

As noted above, IP has electric power supply agreements in place through the end of 2006. Should power acquired under these agreements be insufficient to meet IP’s load requirements, IP will be required to buy power at market prices. Some purchased power agreements oblige the suppliers to provide power up to the reservation amount, and at the same prices, even if individual units are unavailable at various times. Purchased power agreements with other suppliers do not oblige them to acquire replacement power for us in the event of a curtailment or shutdown of their plants. Any costs not covered by rates could not be passed on to ratepayers, which could have an unfavorable impact on IP’s results of operations.

With regard to our exposure to commodity price risk for purchased power and market-based electricity sales, Ameren has two subsidiaries, Ameren Energy and Marketing Company, whose primary responsibilities include managing market risks associated with changing market prices for electricity purchased and sold on behalf of UE, Genco, CILCO and EEI. Purchases are generally transacted when they are economically beneficial to serve load requirements.

Similar techniques are used to manage risks associated with fuel exposures for generation. Most UE, Genco and CILCO fuel supply contracts are physical forward contracts. UE, Genco and CILCO do not have a provision similar to the PGA clause for electric operations, so UE, Genco and CILCO have entered into long-term contracts with various suppliers to purchase coal and nuclear fuel in order to manage their exposure to fuel prices. The coal hedging strategy is intended to secure a reliable coal supply while reducing exposure to commodity price volatility. Price and volumetric risk mitigation is accomplished primarily through periodic bid procedures, whereby the amount of coal purchased is determined by the current market prices and the minimum and maximum coal purchase guidelines for the given year. We generally purchase coal up to five years in advance, but we may purchase coal beyond five years totake advantage of favorable deals or market conditions. The strategy also allows for the decision not to purchase coal to avoid unfavorable market conditions.

Transportation costs for coal and natural gas can be a significant portion of fuel costs. We typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. The natural gas transportation expenses for the distribution companies and the gas-fired generation units are controlled by FERC via published tariffs with rights to extend the contracts from year to year. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariffs for our requirements.

The following table shows how our total fuel expense might increase and how our net income might decrease if coal and coal transportation costs were to increase by 1% on any requirements not currently covered by fixed-price contracts for the five-year period 2006 through 2010:

	Coal					Transportation
	Fuel Expense		Net Income(a)			Fuel Expense		Net Income(a)
Ameren	$	11	$	(7	)	$	10	$	(6	)
UE		6		(4	)		3		(2	)
Genco		3		(2	)		4		(3	)
CILCORP		1		(1	)		2		(1	)
CILCO		1		(1	)		2		(1	)

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

In the event of a significant change in coal prices, UE, Genco and CILCO would probably take actions to further mitigate their exposure to this market risk. However, due to the uncertainty of the specific actions that would be taken and their possible effects, this sensitivity analysis assumes no change in our financial structure or fuel sources.

With regard to exposure for commodity price risk for nuclear fuel, UE has both fixed-priced and base-price–with- escalation agreements or inventories to fulfill its Callaway nuclear plant needs for uranium, conversion, enrichment, and fabrication services through 2007. UE also has agreements or inventories for 69% of the 2008 to 2010 requirements. UE expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected life of the plant, at prices which cannot now be accurately predicted. UE’s strategy is to hedge at least 75% of its three-year requirements. This strategy permits optimum timing of new forward contracts, given the relatively long price cycles in the nuclear fuel markets. It also provides security of supply to protect against unforeseen market disruptions. Unlike the electricity and natural gas markets, nuclear fuel markets have no sophisticated financial instruments, so most hedging is done via inventories and forward contracts.

With regard to the electric generating operations for UE, Genco and CILCO that are exposed to changes in

67

market prices for natural gas used to run the CTs, the natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas while minimizing costs. We optimize transportation and storage options and price risk by structuring supply agreements to maintain access to multiple gas pools and supply basins.

Through the market allocation process, UE, CIPS, Genco, CILCO and IP have been granted FTRs associated with the advent of the MISO Day Two Energy Market. Marketing Company has acquired FTRs for its participation in the PJM-Northern Illinois market. The FTRs are intended to mitigate expected electric transmission congestion charges related to our physical electricity business. Depending on the congestion and prices at various points on the electric transmission 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 a risk that we may incorrectlymodel the amount of FTRs we will need, and there is the potential that the FTRs could be ineffective in mitigating transmission congestion charges.

With regard to UE’s, CIPS’, CILCO’s and IP’s natural gas distribution businesses, exposure to changing market prices is in large part mitigated by the fact there are gas cost recovery mechanisms (PGA clauses) in place in both Missouri and Illinois. These gas cost recovery mechanisms allow UE, CIPS, CILCO and IP to pass on to retail customers prudently incurred costs of natural gas. Our strategy is designed to reduce the effect of market fluctuations on our regulated natural gas customers. We cannot eliminate the effects of gas price volatility. However, the gas procurement strategy involves risk management techniques and instruments similar to those outlined earlier, as well as the management of physical assets, including storage and operator and balancing agreements.

The following table presents the percentages of the projected required supply of coal and coal transportation for our coal-fired power plants, nuclear fuel for UE’s Callaway nuclear plant, natural gas for our CTs and retail distribution, as appropriate, and purchased power needs of CIPS, CILCO and IP, which own virtually no generation, that are price-hedged over the five-year period 2006 through 2010:

	2006		2007		2008 – 2010
Ameren:
Coal	100	%	92	%	55	%
Coal transportation	100		93		60
Nuclear fuel	100		100		69
Natural gas for generation	21		10		2
Natural gas for distribution(a)	87		15		5
UE:
Coal	100		93		51
Coal transportation	100		98		79
Nuclear fuel	100		100		69
Natural gas for generation	11		7		1
Natural gas for distribution(a)	100		15		6
CIPS:
Natural gas for distribution(a)	95		27		13
Purchased power(b)	100		-		-
Genco:
Coal	100		89		65
Coal transportation	100		89		38
Natural gas for generation	20		19		3
CILCORP:
Coal	100		94		53
Coal transportation	100		67		44
Natural gas for distribution(a)	89		24		7
Purchased power(b)	100		-		-
CILCO:
Coal	100		94		53
Coal transportation	100		67		44
Natural gas for distribution(a)	89		24		7
Purchased power(b)	100		-		-
IP:
Natural gas for distribution(a)	79		5		1
Purchased power(b)	90		-		-

68

(a) Represents the percentage of natural gas price hedged for the peak winter season of November through March. The year 2006 represents the period January 2006 through March 2006. The year 2007 represents November 2006 through March 2007. This continues each successive year through March 2010.

(b) Beginning in 2007, CIPS, CILCO and IP are expected to purchase all electric capacity and energy through a power procurement process approved by the ICC. See Note 3 – Rate and Regulatory Matters for a discussion of this matter.

See Supply for Electric Power under Part I, Item 1, of this report for the percentages of our historical needs satisfied by coal, nuclear, natural gas, hydroelectric and oil. Also see Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for further information.

Fair Value of Contracts

Most of our commodity contracts qualify for treatment as normal purchases and normal sales. 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 may cause any of these conditions:

• an unrealized appreciation or depreciation of our contracted commitments to purchase or sell when purchase or sales 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. See Note 9 – Derivative Financial Instruments to our financial statements under Part II, Item 8, of this report for further information.

The following table presents the favorable (unfavorable) changes in the fair value of all derivative contracts marked-to-market during the year ended December 31, 2005. The sources used to determine the fair value of these contracts were active quotes, other external sources, and other modeling and valuation methods. All of these contracts have maturities of less than three years.

	Ameren(a)			UE			CIPS			CILCORP			CILCO			IP
Fair value of contracts at beginning of period, net	$	21		$	(10	)	$	6		$	14		$	14		$	-
Contracts realized or otherwise settled during the period		(17	)		(1	)		(4	)		(3	)		(3	)		-
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		-			-			-			-			-			-
Other changes in fair value		65			6			10			39			39			(2	)
Fair value of contracts outstanding at end of period, net	$	69		$	(5	)	$	12		$	50		$	50		$	(2	)

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

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.

69

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

70

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

71

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

72

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 the years then ended 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

73

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.

74

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.

75

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.

76

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.

77

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.

78

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.

79

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.

80

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.

81

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.

82

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.

83

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.

84

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.

85

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 ofChange 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.

86

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.

87

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.

88

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.

89

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.

90

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.

91

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.

92

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.

93

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.

94

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.

95

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.

96

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.

97

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 CumulativeEffect 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.

98

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.

99

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.

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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.

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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 in1902. 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.

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• 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.

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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 notconstitute 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

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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 ofsuch 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

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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.

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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 taxcredits. 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

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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

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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 DevelopmentCompany’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

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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 throughcontracts 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

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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.

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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 energytransfers 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.

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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 theMoPSC 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

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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’sprogress 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.

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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.

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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 wasintroduced 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.

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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

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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

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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 forprotection 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

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	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.

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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 ofAmeren, 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

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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 Amerendirectly, 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

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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.

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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) 5.10% Senior secured notes due 2018(b)		260 200			- 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

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	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

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	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

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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 anoption 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.

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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 dueFebruary 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.

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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

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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 underwhich 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.

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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.

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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

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	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 withchanges 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		-

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	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.

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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 topurchase, 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

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		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.

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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.

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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

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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.

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(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.

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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.

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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.

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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.

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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.

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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 anenergy 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

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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 MarketingCompany, 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

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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 September2003, 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

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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.

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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.

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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.

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(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.

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(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.

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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 NO_x 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, NO_x, 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 NO_x emissions that result from burning fossil fuels. The Clean Air Act and NO_x Budget Trading Program created marketable commodities called allowances. Each allowance gives the owner the right to emit one ton of SO₂ or NO_x. 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 NO_x Budget Trading Program limits emissions of NO_x during the ozone season (May through September). The NO_x 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 NO_x limits through the use and purchase of allowances or through the application of pollution control technology,

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including low-NO_x 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 NO_X emission allowances, with vintages from 2005 to 2008. As of December 31, 2005, the SO₂and NO_xemission 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 NO_x emission allowance allocations for 2007 and 2008. UE, Genco, CILCO and EEI expect to use a substantial portion of the SO₂ and NO_x allowances for ongoing operations. Allocations of NO_x 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 aresignificant 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

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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 invarious 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

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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

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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 ofdefendants 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 baseelectric 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

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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.

158

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

159

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.

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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.

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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.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A. CONTROLS AND PROCEDURES.

Only Ameren, as a “large accelerated filer” with respect to the reporting requirements of the Exchange Act, was required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and related SEC regulations as to management’s assessment of internal control over financial reporting for the 2005 fiscal year. UE, CIPS, Genco, CILCORP, CILCO and IP are not accelerated filers. They were therefore not required to comply with Section 404 of the Sarbanes-Oxley Act of 2002 and related SEC regulations as to management’s assessment of internal control over financial reporting for the 2005 fiscal year.

(a) Evaluation of Disclosure Controls and Procedures

As of December 31, 2005, the principal executive officer and principal financial officer of each of the Ameren Companies have evaluated the effectiveness of the design and operation of such registrant’s disclosure controls and procedures (as defined in Rules 13a – 15(e) and 15d – 15(e) of the Exchange Act). Upon making that evaluation, the principal executive officer and principal financial officer of each of the Ameren Companies have concluded that such disclosure controls and procedures are effective in timely alerting them to any material information relating to such registrant that is required in such registrant’s reports filed or submitted to the SEC under the Exchange Act, and are effective in ensuring that information required to be disclosed in reports filed under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

(b) Management’s Report on Internal Control over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f). Under the supervision and with the participation of management, including the principal executive officer and principal financial officer, an evaluation was conducted of the effectiveness of Ameren’s internal control over financial reporting based on the framework inInternal Control – Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Upon making that evaluation under the framework inInternal Control – Integrated Frameworkissued by the COSO,management concluded that Ameren’s internal control over financial reporting was effective as of December 31, 2005. Management’s assessment of the effectiveness of Ameren’s internal control over financial reporting as of December 31, 2005, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report herein under Part II, Item 8.

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.

(c) Change in Internal Controls

There has been no change in the Ameren Companies’ internal control over financial reporting during their most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, their internal control over financial reporting, except that in the fourth quarter of 2005, the Ameren Companies completed the implementation of a new fixed-asset application system. Internal controls over financial reporting were modified to accommodate this new application system. The Ameren Companies expect this new system to enhance their internal controls over the fixed asset accounting process.

ITEM 9B. OTHER INFORMATION.

The Ameren Companies have no information reportable under this item that was required to be disclosed in a report on SEC Form 8-K during the fourth quarter of 2005 that has not previously been reported on an SEC Form 8-K.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS.

Information required by Items 401 and 405 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2006 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for UE, CIPS and CILCO will be included in each company’s definitive information statement for its 2006 annual meetings of shareholders filed pursuant to Regulation 14C; it is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I (2) of Form 10-K. Information required by SEC Regulation S-K Items 401 and 405 for IP is set forth at the conclusion of this Item 10.

Information concerning executive officers of the Ameren Companies required by Item 401 of SEC Regulation S-K is reported under a separate caption entitled “Executive Officers of the Registrants” in Part I of this report.

UE, CIPS, Genco, CILCORP, CILCO and IP do not have separately designated standing audit committees, but instead use Ameren’s audit committee to perform such committee functions for their boards of directors. This arrangement is permitted under exemptions provided in the NYSE listing standards for companies such as UE and CILCO, which list only preferred stock (nonconvertible and nonparticipating) on the NYSE. CIPS, Genco, CILCORP and IP have no securities listed on the NYSE and therefore are not subject to the NYSE listing standards. Douglas R. Oberhelman serves as chairman of Ameren’s audit committee and Susan S. Elliott, Richard A. Liddy, and Richard A. Lumpkin serve as members. The board of directors of Ameren has determined that Douglas R. Oberhelman qualifies as an audit committee financial expert and that he is “independent” as that term is used in SEC Regulation 14A.

Also, on the same basis as reported above, the boards of directors of UE, CIPS, Genco, CILCORP, CILCO and IP use the nominating and corporate governance committee of Ameren’s board to perform such committee functions. This committee is responsible for the nomination of directors and corporate governance practices. Ameren’s nominating and corporate governance committee will consider director nominations from shareholders in accordance with its Policy Regarding Nominations of Directors, which can be found on Ameren’s Web site (www.ameren.com).

To encourage ethical conduct in its financial management and reporting, Ameren has adopted a Code of Ethics that applies to the principal executive officer, theprincipal financial officer, the principal accounting officer and controller, and the treasurer of the Ameren Companies. Ameren has also adopted a Code of Business Conduct that applies to the directors, officers and employees of the Ameren Companies, referred to as the Corporate Compliance Policy. The Ameren Companies make available free of charge through Ameren’s Web site (www.ameren.com) the Code of Ethics and Corporate Compliance Policy. These documents are also available free in print upon written request to Ameren Corporation, Attention: Secretary, P.O. Box 66149, St. Louis, Missouri 63166-6149. Any amendment to, or waiver of, the Code of Ethics and Corporate Compliance Policy will be posted on Ameren’s Web site within four business days following the date of the amendment or waiver.

Information Concerning IP’s Directors as Required by Item 401 of SEC Regulation S-K

The current members of IP’s board of directors are Warner L. Baxter, Scott A. Cisel, Daniel F. Cole, Gary L. Rainwater, Steven R. Sullivan, Thomas R. Voss, and David A. Whiteley, each of whom is an executive officer of IP or an affiliate. For each director’s age as of December 31, 2005, and business background for at least the last five years, see “Executive Officers of the Registrants” in Part I of this report. All of the directors were elected by IP’s shareholders at a prior annual meeting. All of these directors were nominated by Ameren’s nominating and corporate governance committee and approved by IP’s board of directors for reelection to IP’s board at its annual meeting of shareholders to be held on May 2, 2006. If reelected they will serve until the next annual meeting of shareholders and until their respective successors have been duly elected and qualified. Each nominee has consented to being nominated for director and has agreed to serve if elected. No arrangement or understanding exists between any nominee and IP or, to IP’s knowledge, any other person or persons pursuant to which any nominee was or is to be selected as a director or nominee. There are no family relationships among any directors, executive officers, or people nominated or chosen by IP to become directors or executive officers. See Item 13 under Part III of this report for certain reportable family relationships with nonexecutive officers. IP has been informed that Ameren intends to cast the votes of all of the outstanding shares of common stock of IP for the election of the nominees for directors named above. Accordingly, all the nominees are expected to be reelected.

164

Section 16(a) Beneficial Ownership Reporting Compliance (for IP as Required by Item 405 of SEC Regulation S-K)

Section 16(a) of the Exchange Act, as amended, requires IP’s directors and executive officers and persons who own more than 10% of IP’s common stock to file with the SEC reports of their ownership in IP’s preferred stock, and, in some cases, of its ultimate parent’s common stock, and of changes in that ownership. SEC regulations also require IP to identify in this report any person subject to this requirement who failed to file any such report on a timely basis. After a review of the filed reports and written representations that no other reports are required, we determined that each of IP’s directors and executive officers complied with all such filing requirements during 2005.

ITEM 11. EXECUTIVE COMPENSATION.

Information required by Item 402 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2006 annual meeting of shareholders filed pursuant to SEC Regulation 14A. It is incorporated herein by reference. Information required by this SEC Regulation S-K item for UE, CIPS and CILCO will be included in each company’s definitive information statement for their 2006 annual meetings of shareholders filed pursuant to Regulation 14C and is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I (2) of Form 10-K. Information required by SEC Regulation S-K Item 402 for IP is as follows.

Compensation Tables for IP

The following tables set forth compensation information for the periods indicated for IP’s chairman and chief executive officer and the four other most highly compensated executive officers of IP who were serving at the end of 2005, named in the Summary Compensation Table below (the “IP Named Executive Officers”). The compensation information for the IP Named Executive Officers relates to services rendered by them in all capacities to IP and its affiliates. No options were granted in fiscal year 2005 to any IP Named Executive Officer.

Summary Compensation Table

		Annual Compensation			Long-term Compensation Awards
Name and Principal Position(a)	Year	Salary($)	Bonus($)(b)	Other Annual Compensation(c)	Restricted Stock Awards ($)(d)	Securities Underlying Options(#)	All Other Compensation ($)(e)
G.L. Rainwater Chairman and Chief Executive Officer, IP, CIPS and CILCO; Chairman, Chief Executive Officer and President, Ameren, UE and CILCORP	2005	800,000	986,000	-	680,018	-	70,085
	2004	650,000	507,000	-	552,512	-	52,885
	2003	500,000	397,500	-	374,987	-	44,861
W.L. Baxter Executive Vice President and Chief Financial Officer, IP, Ameren, UE, CIPS, Genco, CILCORP and CILCO	2005	470,000	408,900	-	352,478	-	19,389
	2004	420,000	273,000	-	315,019	-	19,310
	2003	340,834	287,340	-	191,984	-	18,525
T.R. Voss Senior Vice President, IP, UE, CIPS, CILCORP and CILCO; Executive Vice President and Chief Operating Officer, Ameren; President, Resources Company	2005	400,000	348,000	-	299,988	-	34,885
	2004	310,000	201,500	-	186,009	-	28,849
	2003	270,417	202,900	-	156,019	-	26,883
S.R. Sullivan Senior Vice President, General Counsel and Secretary, IP, Ameren, UE, CIPS, CILCO, CILCORP and Genco	2005	350,000	304,500	-	210,012	-	23,085
	2004	290,000	150,800	-	174,007	-	18,723
	2003	254,771	155,760	-	98,198	-	18,466
D.F. Cole Senior Vice President, IP, UE, CIPS, CILCORP, CILCO and Genco	2005	300,000	212,070	-	180,003	-	22,970
	2004	292,000	148,050	-	175,212	-	20,756
	2003	280,000	176,970	-	167,981	-	19,601

(a) Includes compensation received as an officer of IP and its affiliates.

(b) Amounts for each fiscal year represent bonus compensation earned for that year payable in the subsequent year.

(c) The amounts for the value of perquisites and other personal benefits are not disclosed in accordance with SEC rules because they do not exceed the lesser of $50,000 or 10% of any IP Named Executive Officer’s total annual salary and bonus.

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(d) Restricted stock awards relate to Ameren common stock. This column is based on the closing market price of Ameren common stock on the date the restricted stock was awarded (for 2005, $51.21 per share on February 11, 2005; for 2004, $46.34 per share on February 13, 2004; and for 2003, $39.74 per share on February 14, 2003). The aggregate number of restricted shares of Ameren common stock held at December 31, 2005, and the value of such holdings, based on the number of restricted shares for which restrictions have not lapsed times the closing market price at December 30, 2005 ($51.24 per share), was 57,314 shares and $2,936,769 for Rainwater; 28,339 shares and $1,452,090 for Baxter; 16,646 shares and $852,941 for Voss; 17,247 shares and $883,736 for Sullivan; and 14,256 shares and $730,477 for Cole. Restricted shares have the potential to vest over a seven-year period from date of grant (approximately one-seventh on each anniversary date) if certain Ameren earnings per share performance levels are achieved. The vesting period is reduced from seven years to three years if Ameren’s ongoing earnings per share achieve a prescribed growth rate over the three-year period. In February 2006, Ameren’s board of directors approved the elimination of stock ownership requirements as a condition to vesting in restricted shares to facilitate the transition from the Long-term Incentive Plan of 1998, pursuant to which the restricted shares were awarded, to the new 2006 Omnibus Incentive Compensation Plan proposed for shareholder approval at Ameren’s annual meeting of shareholders on May 2, 2006. Upon the occurrence of a “change in control,” as defined in Ameren’s Long-term Incentive Plan of 1998, all restrictions and vesting requirements with respect to the restricted stock terminate. Dividends paid on restricted shares are reinvested in additional shares of Ameren common stock, which vest concurrently with the restricted shares. The IP Named Executive Officers are entitled to voting privileges associated with the restricted shares to the extent the restricted shares have not been forfeited.

(e) For the IP Named Executive Officers, amounts include the following matching contributions to Ameren’s 401(k) plan, the dollar value of insurance premiums paid by Ameren with respect to term life insurance, and above-market earnings on deferred compensation. See “Arrangements with IP Named Executive Officers – Deferred Compensation Plans” below.

Name	Year	Matching 401(k) Plan Contributions ($)	Executive Term Life Insurance Premiums ($)	Above Market Earnings On Deferred Compensation ($)
G.L. Rainwater	2005	9,600	14,842	45,643
	2004	9,851	11,122	31,912
	2003	9,047	7,792	28,022
W.L. Baxter	2005	8,422	2,109	8,858
	2004	10,480	1,688	7,142
	2003	9,619	1,285	7,621
T.R. Voss	2005	9,450	6,865	18,570
	2004	9,358	4,832	14,659
	2003	8,366	3,722	14,795
S.R. Sullivan	2005	7,379	1,796	13,910
	2004	6,808	1,355	10,560
	2003	7,406	1,031	10,029
D.F. Cole	2005	9,450	2,926	10,594
	2004	9,788	2,584	8,384
	2003	9,060	2,315	8,226

Aggregated Option Exercises in 2005 and Year-End Values for the IP Named Executive Officers^(a)

			Unexercised Options at Year End (#)		Value of In-the-Money Options at Year End ($)(b)
Name	Shares Acquired on Exercise (#)	Value Realized ($)	Exercisable	Unexercisable	Exercisable	Unexercisable
G.L. Rainwater	8,150	163,448	-	-	-	-
W.L. Baxter	3,525	72,897	-	-	-	-
T.R. Voss	16,300	337,084	-	-	-	-
S.R. Sullivan	3,525	70,606	-	-	-	-
D.F. Cole	30,350	541,235	16,300	-	329,912	-

(a) No options were granted by Ameren in 2005.

(b) These columns represent the excess of the closing price of Ameren’s common stock of $51.24 per share, as of December 30, 2005, above the exercise price of the options. The amounts under the Exercisable column report the value of options that are vested and therefore could be exercised. The Unexercisable column reports the value of options that are not vested and therefore could not be exercised as of December 31, 2005. There is no guarantee that, if and when these options are exercised, they will have this value. Upon the occurrence of a “change in control,” as defined in Ameren’s Long-term Incentive Plan of 1998, all options become vested and immediately exercisable. Except for Mr. Cole, none of the IP Named Executive Officers hold any options (exercisable or unexercisable) to purchase shares of Ameren’s common stock.

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Ameren Retirement Plan (as it applies to the IP Named Executive Officers)

Most salaried employees of Ameren and its subsidiaries, including the IP Named Executive Officers, earn benefits under the Ameren Retirement Plan immediately upon employment. Benefits generally become vested after five years of service. On an annual basis, a bookkeeping account in a participant’s name is credited with an amount equal to a percentage of the participant’s pensionable earnings for the year. Pensionable earnings include base pay, overtime, and annual bonuses, which are equivalent to amounts shown as “Annual Compensation” in the Summary Compensation Table above. The applicable percentage is based on the participant’s age as of December 31 of that year. If the participant was an employee prior to July 1, 1998, an additional transition credit percentage is credited to the participant’s account through 2007 (or an earlier date if the participant had less than 10 years of service on December 31, 1998).

Participant’s Age on December 31	Regular Credit for Pensionable Earnings(a)		Transition Credit Pensionable Earnings		Total Credits
Less than 30	3	%	1	%	4	%
30 to 34	4	%	1	%	5	%
35 to 39	4	%	2	%	6	%
40 to 44	5	%	3	%	8	%
45 to 49	6	%	4.5	%	10.5	%
50 to 54	7	%	4	%	11	%
55 and over	8	%	3	%	11	%

(a) An additional regular credit of 3% is received for pensionable earnings above the Social Security wage base.

These accounts also receive interest credits based on the average yield for one-year U.S. Treasury Bills for the previous October, plus 1%. The minimum interest credit is 5%. In addition, certain annuity benefits earned by participants under prior plans as of December 31, 1997, were converted to additional credit balances under the Ameren Retirement Plan as of January 1, 1998. Effective January 1, 2001, we added an Enhancement Account that provides a $500 additional credit at the end of each year. When a participant terminates employment, the amount credited to the participant’s account is converted to an annuity or paid to the participant in a lump sum. The participant can also choose to defer distribution, in which case the account balance is credited with interest at the applicable rate until the future date of distribution.

In certain cases, pension benefits under the Retirement Plan are reduced to comply with maximum limitations imposed by the Internal Revenue Code. A Supplemental Retirement Plan is maintained by Ameren to provide for a supplemental benefit equal to the difference between the benefit that would have been paid if such code limitations were not in effect and the reduced benefit payable as a result of such code limitations. The Supplemental Retirement Plan is unfunded; it is not a qualified plan under the Internal Revenue Code.

The following table shows the estimated annual retirement benefits, including supplemental benefits described in the preceding paragraph, which would be payable to each IP Named Executive Officer listed as a single life annuity if he were to retire at age 65. These estimates were derived on the basis of the following assumptions: base salary will increase by 6% per year and each IP Named Executive Officer will receive an annual bonus equal to his average bonus over the last five years. There is no offset under either the Retirement Plan or the Supplemental Retirement Plan for Social Security benefits or other offset amounts.

Name	Year of 65th Birthday	Estimated Annual Benefit
G.L. Rainwater	2011	$	236,000
W.L. Baxter	2026		342,000
T.R. Voss	2012		161,000
S.R. Sullivan	2025		261,000
D.F. Cole	2018		180,000

Compensation of IP Directors

IP directors who are employees or directors of Ameren or any of its subsidiaries receive no additional compensation for their services as IP directors. All directors of IP are executive officers of Ameren or its subsidiaries.

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Arrangements with IP Named Executive Officers

Change of Control Severance Plan

In February 2006, Ameren’s board of directors approved an Amended and Restated Change of Control Severance Plan (the “Change of Control Plan”), the entire text of which was filed as Exhibit 10.5 to the Current Report on Form 8-K dated February 16, 2006. Under the Change of Control Plan, designated officers of Ameren and its subsidiaries, including the IP Named Executive Officers, are entitled to receive severance benefits if their employment is terminated without Cause (as defined in the Change of Control Plan) or by the officer for Good Reason (as defined in the Change of Control Plan) within two years after a “change of control.” A change of control occurs, in general, if (1) any individual, entity or group acquires 20% or more of the outstanding common stock of Ameren or of the combined voting power of the outstanding voting securities of Ameren; (2) individuals who, as of the effective date of the Change of Control Plan, constitute the board of directors of Ameren, or who have been approved by a majority of the board who were in office prior to the change, cease for any reason to constitute a majority of the board; (3) Ameren enters into certain business combinations, unless certain requirements are met regarding continuing ownership of the outstanding common stock and voting securities of Ameren and the membership of its board of directors; or (4) approval by Ameren shareholders of a complete liquidation or dissolution of Ameren.

Severance benefits are based upon a severance period of two or three years, depending on the officer’s position. An officer entitled to severance will receive a cash lump sum equal to the following: (1) salary and unpaid vacation pay through the date of termination; (2) a pro rata bonus for the year of termination, and base salary and bonus for the severance period; (3) continued employee welfare benefits for the severance period; (4) a cash payment equal to the actuarial value of the additional benefits the officer would have received under Ameren’s qualified and supplemental retirement plans if employed for the severance period; (5) up to $30,000 for the cost of outplacement services; and (6) reimbursement for any excise tax imposed on such benefits as excess payments under the Internal Revenue Code.

In addition to the foregoing severance benefits, Ameren’s Long-term Incentive Plan of 1998, certain Ameren deferred compensation plans and awards granted pursuant to Ameren’s 2006 Omnibus Incentive Compensation Plan (subject to shareholder approval at Ameren’s 2006 annual meeting) include provisions providing certain protections to the officers of Ameren and its subsidiaries, including the IP Named Executive Officers, upon the occurrence of a change of control, as defined in the related plan or in the award issued pursuant to such plan. The protections include immediate vesting of certain awards and benefits and elimination of restrictions of restricted stock awards.

Ameren’s board may amend or terminate the Change of Control Plan at any time, including designating any other event as a “change of control”, provided that the Change of Control Plan may not be amended or terminated (i) following a “change of control”, (ii) at the request of a third party who has taken steps reasonably calculated to effect a “change of control” or (iii) otherwise in connection with or in anticipation of a “change of control” in any manner that could adversely affect the rights of any officer covered by the Change of Control Plan.

Deferred Compensation Plans

Under the Ameren Deferred Compensation Plan and its Executive Incentive Compensation Program Elective Deferral Provisions, executive officers and certain key employees, including the IP Named Executive Officers, may choose to defer up to

30% of their salary and 25%, 50%, 75%, or 100% of their bonus. All of the IP Named Executive Officers have deferred amounts under one or both of the plans. The minimum amount of salary that can be deferred in any calendar year is $3,500 and the minimum amount of bonus that can be annually deferred is $2,000. Deferred amounts under both plans earn interest at 150% of the average Mergent’s Seasoned AAA Corporate Bond Yield Index (“Mergent’s Index” was formerly called Moody’s Index) until the participant retires or attains 65 years of age. After the participant retires, attains 65 years of age, or dies, the deferred amounts under the plans earn the average Mergent’s Index rate. For 2005, the average Mergent’s Index rate was 5.63%, 150% of that was 8.46%. In 2005, the IP Named Executive Officers earned the following interest on their deferred amounts: G.L. Rainwater, $140,429; W.L. Baxter, $27,235; T.R. Voss, $57,104; S.R. Sullivan, $42,780; and D.F. Cole, $32,575. A participant may choose to receive the deferred amounts at retirement in a lump sum payment or in installments over a set period, up to

15 years with respect to deferred salary and 10 years with respect to deferred bonus. In the event a participant terminates employment with Ameren before attaining retirement age and after the occurrence of a change in control (as defined in such plans), the balance in such participant’s deferral account, including interest payable at 150% of the average Mergent’s Index, is distributable in a lump sum to the participant within 30 days of the date the participant terminates employment.

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Compensation Committee Interlocks and Insider Participation

The members of the human resources committee of the Ameren board of directors performed compensation-related committee functions for IP for 2005. Its current members, Richard A. Liddy, Gordon R. Lohman, Richard A. Lumpkin, Harvey Saligman, and Patrick T. Stokes, were not at any time during 2005 or at any other time officers or employees of Ameren or IP, and no member had any relationship with Ameren or IP requiring disclosure under applicable SEC rules. No executive officer of Ameren or IP has served on the board of directors or compensation committee of any other entity whose executive officers served on Ameren’s or IP’s board of directors or Ameren’s human resources committee during 2005.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

Equity Compensation Plan Information

Equity compensation plan information required by Item 201(d) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2006 annual meeting of shareholders filed pursuant to SEC Regulation 14A and is incorporated herein by reference.

UE, CIPS, Genco, CILCORP, CILCO and IP do not have separate equity compensation plans.

Security Ownership of Certain Beneficial Owners and Management

The information required by Item 403 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2006 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by this SEC Regulation S-K item for UE, CIPS and CILCO will be included in each company’s definitive information statement for its 2006 annual meetings of shareholders filed pursuant to Regulation 14C; it is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I (2) of Form 10-K. Information required by SEC Regulation S-K Item 403 for IP is as follows.

Securities of IP

All 23 million outstanding shares of IP’s common stock and 662,924 shares, or approximately 73%, of IP’s preferred stock were acquired by Ameren from Dynegy and its subsidiaries on September 30, 2004. They are owned by Ameren as of the date of this report. This acquisition resulted in a change in control of IP. IP is now a subsidiary of Ameren.

None of IP’s outstanding shares of preferred stock were owned by directors, nominees for director, or executive officers of IP as of February 1, 2006. To our knowledge, other than Ameren, which as noted above owns 73% of IP’s outstanding preferred stock, there are no beneficial owners of 5% or more of IP’s outstanding shares of preferred stock as of February 1, 2006, but no independent inquiry has been made to determine whether any shareholder is the beneficial owner of shares not registered in the name of such shareholder or whether any shareholder is a member of a shareholder group.

Securities of Ameren (As Applicable to IP)

The following table sets forth certain information known to IP with respect to beneficial ownership of Ameren common stock as of February 1, 2006, for (1) each director and nominee for director of IP, (2) the IP Named Executive Officers, and (3) all executive officers, directors, and nominees for director as a group.

Name	Number of Shares of Ameren Common Stock Beneficially Owned(a)	Percent Owned(b)
Warner L. Baxter	33,522	*
Scott A. Cisel	10,808	*
Daniel F. Cole	43,128	*
Gary L. Rainwater	79,535	*
Steven R. Sullivan	17,894	*
Thomas R. Voss	33,694	*
David A. Whiteley	17,713	*
All directors, nominees for director and executive officers as a group (9)	260,661	*

* Less than 1%.

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(a) This column lists voting securities, including Ameren restricted stock held by executive officers over whom the officers have voting power but no investment power. For Mr. Cole, this column also includes 16,300 shares issuable within 60 days upon the exercise of Ameren stock options. None of the other named individuals held shares issuable within 60 days upon the exercise of Ameren stock options. Reported shares include those for which a director, nominee for director, or executive officer has voting or investment power because of joint or fiduciary ownership of the shares or a relationship with the record owner, most commonly a spouse, even if such director, nominee for director, or executive officer does not claim beneficial ownership.

(b) For each individual and group included in the table, percentage ownership is calculated by dividing the number of shares beneficially owned by such person or group as described above by the sum of the 204,746,388 shares of Ameren common stock outstanding on February 1, 2006, and the number of shares of Ameren common stock that such person or group had the right to acquire on or within 60 days of February 1, 2006, including but not limited to, upon the exercise of options.

The address of all persons listed above is c/o Illinois Power Company, 370 South Main Street, Decatur, Illinois 62523.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

Information required by Item 404 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2006 annual meeting of shareholders filed pursuant to SEC Regulation 14A; it is incorporated herein by reference. Information required by this SEC Regulation S-K item for UE, CIPS and CILCO will be included in each company’s definitive information statement for its 2006 annual meetings of shareholders filed pursuant to Regulation 14C; it is incorporated herein by reference. With respect to Genco and CILCORP, this information is omitted in reliance on General Instruction I (2) of Form 10-K. Information required by SEC Regulation S-K Item 404 for IP is as follows.

During 2005, other than employment by IP or its affiliates, IP had no business relationships with directors and nominees for director required to be reported by SEC rules.

Certain of IP’s current directors and executive officers did have reportable family relationships in 2005. A sister of IP Chairman and Chief Executive Officer Gary L. Rainwater, Patricia A. Fuller, is employed by IP affiliate Ameren Services as a health and welfare consultant in its human resources function, for which she received an aggregate salary, bonus, and other compensation of $104,436 for 2005. Wendy C. Brumitt, a daughter of IP Senior Vice President Thomas R. Voss, is employed by IP affiliate UE as an engineer at its Callaway nuclear plant, for which she received aggregate salary, bonus, and other compensation of $85,469 for 2005. A brother of IP Vice President Dennis W. Weisenborn, Gary L. Weisenborn, is employed by UE as a superintendent, for which he received aggregate salary, bonus, and other compensation of $132,870 for 2005. Diana L. Weisenborn, the wife of Gary L. Weisenborn and sister-in-law of Dennis W. Weisenborn, is employed by Ameren Services as an executive secretary, for which she received aggregate salary, bonus, and other compensation of $68,095 for 2005. Susan M. Prebil, wife of IP Vice President William J. Prebil, was employed by CILCO as a settlement specialist during a portion of 2005, for which she received salary of $3,881. In 2005, Susan M. Prebil terminated her 28 year employment with CILCO pursuant to a voluntary separation program and in that connection received aggregate compensation of $103,644.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

Information required by Item 9(e) of SEC Schedule 14A for the Ameren Companies (including for IP only the period after its acquisition by Ameren) will be included in the definitive proxy statement of Ameren and the definitive information statements of UE, CIPS and CILCO for their 2006 annual meetings of shareholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference. This information as it relates to IP prior to its acquisition by Ameren is expected to be reported in Dynegy’s definitive proxy statement for its 2006 annual meeting of shareholders, which shall not be deemed to be incorporated by reference into this report and for which the Ameren Companies accept no responsibility.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.

(a)(1)  Financial Statements	Page No.
Ameren
Report of Independent Registered Public Accounting Firm	69
Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003	74
Consolidated Balance Sheet – December 31, 2005 and 2004	75
Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003	76
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2005, 2004 and 2003	77
UE
Report of Independent Registered Public Accounting Firm	71
Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003	78
Consolidated Balance Sheet – December 31, 2005 and 2004	79
Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003	80
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2005, 2004 and 2003	81
CIPS
Report of Independent Registered Public Accounting Firm	71
Statement of Income – Years Ended December 31, 2005, 2004 and 2003	82
Balance Sheet – December 31, 2005 and 2004	83
Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003	84
Statement of Common Stockholders��� Equity - Years Ended December 31, 2005, 2004 and 2003	85
Genco
Report of Independent Registered Public Accounting Firm	72
Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003	86
Consolidated Balance Sheet – December 31, 2005 and 2004	87
Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003	88
Consolidated Statement of Common Stockholder’s Equity - Years Ended December 31, 2005, 2004 and 2003	89
CILCORP
Report of Independent Registered Public Accounting Firm	72
Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003	90
Consolidated Balance Sheet – December 31, 2005 and 2004	91
Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003	92
Consolidated Statement of Common Stockholder’s Equity - Years Ended December 31, 2005, 2004 and 2003	93
CILCO
Report of Independent Registered Public Accounting Firm	73
Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003	94
Consolidated Balance Sheet – December 31, 2005 and 2004	95
Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003	96
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2005, 2004 and 2003	97
IP
Report of Independent Registered Public Accounting Firm	73
Consolidated Statement of Income – Years Ended December 31, 2005, 2004 and 2003	98
Consolidated Balance Sheet – December 31, 2005 and 2004	99
Consolidated Statement of Cash Flows – Years Ended December 31, 2005, 2004 and 2003	100
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2005, 2004 and 2003	101
(a)(2) Financial Statement Schedule
Schedule II – Valuation and Qualifying Accounts for the years ended December 31, 2005, 2004 and 2003	172

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 180.

(b) Exhibits are listed in the Exhibit Index commencing on page 180.

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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.

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SIGNATURES

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

	AMEREN CORPORATION (registrant)
Date:        March 7, 2006	By	/s/ Gary L. Rainwater
		Gary L. Rainwater Chairman, Chief Executive Officer, and President

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, President, and Director (Principal Executive Officer)	March 7, 2006
/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 7, 2006
/s/ Martin J. Lyons Martin J. Lyons	Vice President and Controller (Principal Accounting Officer)	March 7, 2006
* Susan S. Elliott	Director	March 7, 2006
* Gayle P.W. Jackson	Director	March 7, 2006
* James C. Johnson	Director	March 7, 2006
* Richard A. Liddy	Director	March 7, 2006
* Gordon R. Lohman	Director	March 7, 2006
* Richard A. Lumpkin	Director	March 7, 2006
* Charles W. Mueller	Director	March 7, 2006
* Douglas R. Oberhelman	Director	March 7, 2006
* Harvey Saligman	Director	March 7, 2006
* Patrick T. Stokes	Director	March 7, 2006

*By	/s/ Warner L. Baxter	March 7, 2006
	Warner L. Baxter Attorney-in-Fact

173

		UNION ELECTRIC COMPANY (registrant)
Date:        March 7, 2006	By	/s/ Gary L. Rainwater
		Gary L. Rainwater
		Chairman, Chief Executive Officer, and President

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, President, and Director (Principal Executive Officer)	March 7, 2006
/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer, and Director (Principal Financial Officer)	March 7, 2006
/s/ Martin J. Lyons Martin J. Lyons	Vice President and Controller (Principal Accounting Officer)	March 7, 2006
* Daniel F. Cole	Director	March 7, 2006
* Richard J. Mark	Director	March 7, 2006
* Steven R. Sullivan	Director	March 7, 2006
* Thomas R. Voss	Director	March 7, 2006
* David A. Whiteley	Director	March 7, 2006

*By	/s/ Warner L. Baxter	March 7, 2006
	Warner L. Baxter
	Attorney-in-Fact

174

	CENTRAL ILLINOIS PUBLIC SERVICE COMPANY (registrant)
Date:        March 7, 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)	March 7, 2006
/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer, and Director (Principal Financial Officer)	March 7, 2006
/s/ Martin J. Lyons Martin J. Lyons	Vice President and Controller (Principal Accounting Officer)	March 7, 2006
* Scott A. Cisel	Director	March 7, 2006
* Daniel F. Cole	Director	March 7, 2006
* Steven R. Sullivan	Director	March 7, 2006
* Thomas R. Voss	Director	March 7, 2006
* David A. Whiteley	Director	March 7, 2006

*By	/s/ Warner L. Baxter	March 7, 2006
	Warner L. Baxter Attorney-in-Fact

175

	AMEREN ENERGY GENERATING COMPANY (registrant)
Date:        March 7, 2006	By	/s/ R. Alan Kelley
		R. Alan Kelley
		President

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/ R. Alan Kelley R. Alan Kelley	President and Director (Principal Executive Officer)	March 7, 2006
/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer, and Director (Principal Financial Officer)	March 7, 2006
/s/ Martin J. Lyons Martin J. Lyons	Vice President and Controller (Principal Accounting Officer)	March 7, 2006
* Daniel F. Cole	Director	March 7, 2006
* Gary L. Rainwater	Director	March 7, 2006
* Steven R. Sullivan	Director	March 7, 2006
* Thomas R. Voss	Director	March 7, 2006
* David A. Whiteley	Director	March 7, 2006

*By	/s/ Warner L. Baxter	March 7, 2006
	Warner L. Baxter Attorney-in-Fact

176

	CILCORP INC.(registrant)
Date:        March 7, 2006	By	/s/ Gary L. Rainwater
		Gary L. Rainwater
		Chairman, Chief Executive Officer, and President

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, President, and Director (Principal Executive Officer)	March 7, 2006
/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer, and Director (Principal Financial Officer)	March 7, 2006
/s/ Martin J. Lyons Martin J. Lyons	Vice President and Controller (Principal Accounting Officer)	March 7, 2006
* Daniel F. Cole	Director	March 7, 2006
* Richard A. Liddy	Director	March 7, 2006
* Steven R. Sullivan	Director	March 7, 2006
* Thomas R. Voss	Director	March 7, 2006
* David A. Whiteley	Director	March 7, 2006

*By	/s/ Warner L. Baxter	March 7, 2006
	Warner L. Baxter Attorney-in-Fact

177

	CENTRAL ILLINOIS LIGHT COMPANY (registrant)
Date:        March 7, 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)	March 7, 2006
/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer, and Director (Principal Financial Officer)	March 7, 2006
/s/ Martin J. Lyons Martin J. Lyons	Vice President and Controller (Principal Accounting Officer)	March 7, 2006
* Scott A. Cisel	Director	March 7, 2006
* Daniel F. Cole	Director	March 7, 2006
* Steven R. Sullivan	Director	March 7, 2006
* Thomas R. Voss	Director	March 7, 2006
* David A. Whiteley	Director	March 7, 2006

*By	/s/ Warner L. Baxter	March 7, 2006
	Warner L. Baxter Attorney-in-Fact

178

	ILLINOIS POWER COMPANY (registrant)
Date:        March 7, 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)	March 7, 2006
/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer, and Director (Principal Financial Officer)	March 7, 2006
/s/ Martin J. Lyons Martin J. Lyons	Vice President and Controller (Principal Accounting Officer)	March 7, 2006
* Scott A. Cisel	Director	March 7, 2006
* Daniel F. Cole	Director	March 7, 2006
* Steven R. Sullivan	Director	March 7, 2006
* Thomas R. Voss	Director	March 7, 2006
* David A. Whiteley	Director	March 7, 2006

*By	/s/ Warner L. Baxter	March 7, 2006
	Warner L. Baxter Attorney-in-Fact

179

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

180

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

181

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

182

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

183

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

184

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

185

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

186

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

187

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, Exhibit4.121, 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

188

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

189

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

190

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

191

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

192

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

193

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
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
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.

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.

194