AMEREN CORP (Form: 10-K, Received: 03/02/2009 16:42:16)

Fair Value

Less than 5 years

5 years to 10 years

Due after 10 years

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, 2008

		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
	(888) 789-2477

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:

The following securities are registered pursuant to Section 12(b) of the Securities Exchange Act of 1934 and are listed on the New York Stock Exchange:


Registrant		Title of each class

Ameren Corporation		Common Stock, $0.01 par value per share

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


Registrant	Title of each class

Union Electric Company	Preferred Stock, cumulative, no par value, stated value $100 per share –
	$4.56 Series	$4.50 Series
	$4.00 Series	$3.50 Series
Central Illinois Public Service Company	Preferred Stock, cumulative, $100 par value per share –
	6.625% Series	4.90% Series
	5.16% Series	4.25% Series
	4.92% Series	4.00% Series
	Depository Shares, each representing one-fourth of a share of 6.625% Preferred Stock, cumulative, $100 par value per share
Central Illinois Light Company	Preferred Stock, cumulative, $100 par value per share –
	4.50% Series

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

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


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

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


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

Indicate by check mark whether the registrants: (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.


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

CILCORP has voluntarily filed all reports that it would have been required to file if it had been subject to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months.

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

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


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

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


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

As of June 30, 2008, Ameren Corporation had 210,050,075 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 $8,870,414,667. The shares of common stock of the other registrants were held by affiliates as of June 30, 2008.

The number of shares outstanding of each registrant’s classes of common stock as of January 30, 2009, was as follows:


Ameren Corporation		Common stock, $0.01 par value per share: 212,519,772

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 Resources Company, LLC (parent company of the registrant and 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 2009 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		1

Forward-looking Statements		3

PART I
Item 1.	Business	4
	General	4
	Business Segments	5
	Rates and Regulation	5
	Supply for Electric Power	7
	Natural Gas Supply for Distribution	11
	Industry Issues	11
	Operating Statistics	12
	Available Information	14
Item 1A.	Risk Factors	14
Item 1B.	Unresolved Staff Comments	20
Item 2.	Properties	21
Item 3.	Legal Proceedings	23
Item 4.	Submission of Matters to a Vote of Security Holders	23

Executive Officers of the Registrants (Item 401(b) of Regulation S-K)		24

PART II
Item 5.	Market for Registrants’ Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities	26
Item 6.	Selected Financial Data.	27
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
	Overview	29
	Results of Operations	31
	Liquidity and Capital Resources	49
	Outlook	65
	Regulatory Matters	71
	Accounting Matters	71
	Effects of Inflation and Changing Prices	73
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	74
Item 8.	Financial Statements and Supplementary Data	80
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	177
Item 9A and Item 9A(T).	Controls and Procedures	177
Item 9B.	Other Information	178

PART III
Item 10.	Directors, Executive Officers, and Corporate Governance	178
Item 11.	Executive Compensation	178
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	179
Item 13.	Certain Relationships and Related Transactions and Director Independence	179
Item 14.	Principal Accountant Fees and Services	179

PART IV
Item 15.	Exhibits and Financial Statement Schedules	180
SIGNATURES		184
EXHIBIT INDEX		191

This Form 10-K contains “forward-looking” statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements should be read with the cautionary statements and important factors included on page 3 of this Form 10-K under the heading “Forward-looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.

GLOSSARY OF TERMS AND ABBREVIATIONS

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

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

AFS – Ameren Energy Fuels and Services Company, a Resources Company subsidiary that procures fuel and natural gas and manages the related risks for the Ameren Companies.

AITC – Ameren Illinois Transmission Company, a wholly owned subsidiary of Ameren Corporation that is engaged in the construction and operation of transmission assets in Illinois and is regulated by the ICC.

Ameren – Ameren Corporation and its subsidiaries on a consolidated basis. In references to financing activities, acquisition activities, or liquidity arrangements, Ameren is defined as Ameren Corporation, the parent.

Ameren Companies – The individual registrants within the Ameren consolidated group.

Ameren Illinois Utilities – CIPS, IP and the rate-regulated electric and gas utility operations of CILCO.

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

AMIL – The balancing authority area operated by Ameren, which includes the load of the Ameren Illinois Utilities and the generating assets of AERG and Genco.

AMMO – The balancing authority area operated by Ameren, which includes the load and generating assets of UE.

AMT – Alternative minimum tax.

ARB – Accounting Research Bulletin.

ARO – Asset retirement obligations.

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

Btu – British thermal unit, a standard unit for measuring the quantity of heat energy required to raise the temperature of one pound of water by one degree Fahrenheit.

Capacity factor – A percentage measure that indicates how much of an electric power generating unit’s capacity was used during a specific period.

CILCO – Central Illinois Light Company, a CILCORP subsidiary that operates a rate-regulated electric transmission and distribution business, a non-rate-regulated electric generation business through AERG, and a rate-regulated natural gas transmission and distribution business, all in Illinois, as AmerenCILCO. CILCO owns all of the common stock of AERG.

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

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.

CO ₂ – Carbon dioxide.

COLA – Combined construction and operating license application.

Cooling degree-days – The summation of positive differences between the mean daily temperature and a 65-degree Fahrenheit base. This statistic is useful for estimating electricity demand by residential and commercial customers for summer cooling.

CT – Combustion turbine electric generation equipment used primarily for peaking capacity.

Development Company – Ameren Energy Development Company, which was an Ameren Energy Resources Company subsidiary and parent of Genco, Marketing Company, AFS, and Medina Valley. It was eliminated in an internal reorganization in February 2008.

DOE – Department of Energy, a U.S. government agency.

DRPlus – Ameren Corporation’s dividend reinvestment and direct stock purchase plan.

Dth (dekatherm) – one million Btus of natural gas.

EEI – Electric Energy, Inc., an 80%-owned Ameren Corporation subsidiary that operates non-rate-regulated electric generation facilities and FERC-regulated transmission facilities in Illinois. Prior to February 29, 2008, EEI was 40% owned by UE and 40% owned by Development Company. On February 29, 2008, UE’s 40% ownership interest and Development Company’s 40% ownership interest were transferred to Resources Company. The remaining 20% is owned by Kentucky Utilities Company.

EITF – Emerging Issues Task Force, an organization designed to assist the FASB in improving financial reporting through the identification, discussion and resolution of financial issues in keeping with existing authoritative literature.

ELPC – Environmental Law and Policy Center.

EPA – Environmental Protection Agency, a U.S. government agency.

Equivalent availability factor – A measure that indicates the percentage of time an electric power generating unit was available for service during a period.

ERISA – Employee Retirement Income Security Act of 1974, as amended.

Exchange Act – Securities Exchange Act of 1934, as amended.

FAC – A fuel and purchased power cost recovery mechanism that allows UE to recover through customer rates 95% of changes in fuel (coal, coal transportation, natural gas for generation and nuclear) and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates.

FASB – Financial Accounting Standards Board, a rulemaking organization that establishes financial accounting and reporting standards in the United States.

FERC – The Federal Energy Regulatory Commission, a U.S. government agency.

FIN – FASB Interpretation. A FIN statement is an explanation intended to clarify accounting pronouncements previously issued by the FASB.

Fitch – Fitch Ratings, a credit rating agency.

FSP – FASB Staff Position, a publication that provides application guidance on FASB literature.

FTRs – Financial transmission rights, financial instruments that entitle the holder to pay or receive compensation for certain congestion-related transmission charges between two designated points.

Fuelco – Fuelco LLC, a limited-liability company that provides nuclear fuel management and services to its members. The members are UE, Luminant, and Pacific Gas and Electric Company.

GAAP – Generally accepted accounting principles in the United States of America.

Genco – Ameren Energy Generating Company, a Resources Company subsidiary that operates a non-rate-regulated electric generation business in Illinois and Missouri.

Gigawatthour – One thousand megawatthours.

Heating degree-days – The summation of negative differences between the mean daily temperature and a 65- degree Fahrenheit base. This statistic is useful as an indicator of demand for electricity and natural gas for winter space heating for residential and commercial customers.

IBEW – International Brotherhood of Electrical Workers, a labor union.

ICC – Illinois Commerce Commission, a state agency that regulates Illinois utility businesses, including the rate-regulated operations of CIPS, CILCO and IP.

Illinois Customer Choice Law – Illinois Electric Service Customer Choice and Rate Relief Law of 1997, which provided for electric utility restructuring and was designed to introduce competition into the retail supply of electric energy in Illinois.

Illinois electric settlement agreement – A comprehensive settlement of issues in Illinois arising out of the end of ten years of frozen electric rates, effective January 2, 2007. The Illinois electric settlement agreement, which became effective on August 28, 2007, was designed to avoid new rate rollback and freeze legislation and legislation that would impose a tax on electric generation in Illinois. The settlement addresses the issue of power procurement, and it includes a comprehensive rate relief and customer assistance program.

Illinois EPA – Illinois Environmental Protection Agency, a state government agency.

Illinois Regulated – A financial reporting segment consisting of the regulated electric and natural gas transmission and distribution businesses of CIPS, CILCO, IP and AITC.

IP – Illinois Power Company, an Ameren Corporation subsidiary. IP operates a rate-regulated electric and natural gas transmission and distribution business in Illinois as AmerenIP.

IP LLC – Illinois Power Securitization Limited Liability Company, which was a special-purpose Delaware limited-liability company. It was dissolved in February 2009 because the remaining TFNs, with respect to which this entity was created, were redeemed by IP in September 2008.

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. It was dissolved in February 2009 because the remaining TFNs were redeemed by IP in September 2008.

IPA – Illinois Power Agency, a state government agency that has broad authority to assist in the procurement of electric power for residential and nonresidential customers beginning in June 2009.

ISRS – Infrastructure system replacement surcharge. A cost recovery mechanism in Missouri that allows UE to recover gas infrastructure replacement costs from utility customers without a traditional rate case.

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

JDA – The joint dispatch agreement among UE, CIPS, and Genco under which UE and Genco jointly dispatched electric generation prior to its termination on December 31, 2006.

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

Lehman – Lehman Brothers Holdings, Inc.

MACT – Maximum Achievable Control Technology.

Marketing Company – Ameren Energy Marketing Company, a Resources Company subsidiary that markets power for Genco, AERG and EEI.

Medina Valley – AmerenEnergy Medina Valley Cogen L.L.C., a Resources Company subsidiary, which owns a 40-megawatt gas-fired electric generation plant.

Megawatthour – One thousand kilowatthours.

MGP – Manufactured gas plant.

MISO – Midwest Independent Transmission System Operator, Inc.

MISO Day Two Energy Market – A market that uses market-based pricing, incorporating transmission congestion and line losses, to compensate market participants for power.

Missouri Environmental Authority – Environmental Improvement and Energy Resources Authority of the state of Missouri, a governmental body authorized to finance environmental projects by issuing tax-exempt bonds and notes.

Missouri Regulated – A financial reporting segment consisting of UE’s rate-regulated businesses.

Money pool – Borrowing agreements among Ameren and its subsidiaries to coordinate and provide for certain short-term cash and working capital requirements. Separate money pools maintained for rate-regulated and non-rate-regulated business 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 Missouri utility businesses, including the rate-regulated operations of UE.

MPS – Multi-Pollutant Standard, an agreement reached in 2006 among Genco, CILCO (AERG), EEI and the Illinois EPA, which was codified in Illinois environmental regulations.

MW – Megawatt.

Native load – Wholesale customers and end-use retail customers, whom we are obligated to serve by statute, franchise, contract, or other regulatory requirement.

NCF&O – National Congress of Firemen and Oilers, a labor union.

Non-rate-regulated Generation – A financial reporting segment consisting of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, Medina Valley, and Marketing Company.

NO _x – Nitrogen oxide.

Noranda – Noranda Aluminum, Inc.

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

NYMEX – New York Mercantile Exchange.

NYSE – New York Stock Exchange, Inc.

OATT – Open Access Transmission Tariff.

OCI – Other comprehensive income (loss) as defined by GAAP.

Off-system revenues – Revenues from other than native load sales.

OTC – Over-the-counter.

PGA – Purchased Gas Adjustment tariffs, which allow the passing through of the actual cost of natural gas to utility customers.

PJM – PJM Interconnection LLC.

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

Regulatory lag – Adjustments to retail electric and natural gas rates are based on historic cost levels. Rate increase requests can take up to 11 months to be acted upon by the MoPSC and the ICC. As a result, revenue increases authorized by regulators will lag behind changing costs.

Resources Company – Ameren Energy Resources Company, LLC, an Ameren Corporation subsidiary that consists of non-rate-regulated operations, including Genco, Marketing Company, EEI, AFS, and Medina Valley. It is the successor to Ameren Energy Resources Company, which was eliminated in an internal reorganization in February 2008.

RFP – Request for proposal.

RTO – Regional Transmission Organization.

S&P – Standard & Poor’s Ratings Services, a credit rating agency that is a division of The McGraw-Hill Companies, Inc.

SEC – Securities and Exchange Commission, a U.S. government agency.

SERC – SERC Reliability Corporation, one of the regional electric reliability councils organized for coordinating the planning and operation of the nation’s bulk power supply.

SFAS – Statement of Financial Accounting Standards, the accounting and financial reporting rules issued by the FASB.

SO ₂ – Sulfur dioxide.

TFN – Transitional Funding Trust Notes issued by IP SPT as allowed under the Illinois Customer Choice Law. IP designated a portion of cash received from customer billings to pay the TFNs. The designated funds received by

IP were remitted to IP SPT. The designated funds were 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 did not consolidate IP SPT. Therefore, the obligation to IP SPT appears on IP’s balance sheet as of December 31, 2007. In September 2008, IP redeemed the remaining TFNs.

TVA – Tennessee Valley Authority, a public power authority.

UE – Union Electric Company, an Ameren Corporation subsidiary that operates a rate-regulated electric generation, transmission and distribution business, and a rate-regulated natural gas transmission and distribution business in Missouri as AmerenUE.

FORWARD-LOOKING STATEMENTS

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

regulatory or legislative actions, including changes in regulatory policies and ratemaking determinations and future rate proceedings or future legislative actions that seek to limit or reverse rate increases;

uncertainty as to the continued effectiveness of the Illinois power procurement process;

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

changes in laws or regulations that adversely affect the ability of electric distribution companies and other purchasers of wholesale electricity to pay their suppliers, including UE and Marketing Company;

enactment of legislation taxing electric generators, in Illinois or elsewhere;

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

increasing capital expenditure and operating expense requirements and our ability to recover these costs in a timely fashion in light of regulatory lag;

the effects of participation in the MISO;

the cost and availability of fuel such as coal, natural gas, and enriched uranium used to produce electricity; the cost and 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, including forward prices;

business and economic conditions, including their impact on interest rates, bad debt expense, and demand for our products;

disruptions of the capital markets or other events that make the Ameren Companies’ access to necessary capital, including short-term credit, impossible, more difficult or costly;

our assessment of our liquidity;

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

actions of credit rating agencies and the effects of such actions;

weather conditions and other natural phenomena, including impacts to our customers;

the impact of system outages caused by severe weather conditions or other events;

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

recoverability through insurance of costs associated with UE’s Taum Sauk pumped-storage hydroelectric plant incident;

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

the effects of strategic initiatives, including acquisitions and divestitures;

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

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

the inability of our counterparties and affiliates to meet their obligations with respect to contracts, credit facilities and financial instruments;

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

legal and administrative proceedings; and

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

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

PART I

ITEM 1.

BUSINESS.

GENERAL

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005 administered by FERC. Ameren was formed in 1997 by the merger of UE and CIPSCO. Ameren acquired CILCORP in 2003 and IP in 2004. Ameren’s primary assets are the common stock of its subsidiaries, including UE, CIPS, Genco, CILCORP and IP.

Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock are dependent on distributions made to it by its subsidiaries.

The following table presents our total employees at December 31, 2008:


Ameren ^(a)		9,524
UE		4,146
CIPS		679
Genco		577
CILCORP/CILCO		626
IP		1,173

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

As of January 1, 2009, the IBEW, the IUOE, the NCF&O and the Laborers and Gas Fitters labor unions collectively represent about 58% of Ameren’s total employees. They represent 63% of the employees at UE, 82% at CIPS, 70% at Genco, 38% at CILCORP, 38% at CILCO, and 90% at IP. All collective bargaining agreements that expired in 2008 have been renegotiated and ratified. Most of the collective

bargaining agreements have four- or five-year terms, and expire in 2011 and 2012. The collective bargaining agreement between UE and IUOE Local 148, covering approximately 1,100 employees, expires on June 30, 2009.

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

BUSINESS SEGMENTS

Ameren has three reportable segments: Missouri Regulated, Illinois Regulated, and Non-rate-regulated Generation. CILCORP and CILCO have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. See Note 17 – Segment Information to our financial statements under Part II, Item 8, of this report for additional information on reporting segments.

RATES AND REGULATION

Rates

Rates that UE, CIPS, CILCO and IP are allowed to charge for their utility services are an important influence upon their and Ameren’s consolidated results of operations, financial position, and liquidity. The utility rates charged to UE, CIPS, CILCO and IP customers are determined by governmental entities. Decisions by these entities are influenced by many factors, including the cost of providing service, the quality of service, regulatory staff knowledge and experience, economic conditions, public policy, and social and political views. Decisions made by these governmental entities regarding rates, as well as the regulatory lag involved in filing and getting new rates approved, could have a material impact on the results of operations, financial position, or liquidity of UE, CIPS, CILCORP, CILCO, IP and Ameren.

The ICC regulates rates and other matters for CIPS, CILCO and IP. The MoPSC regulates rates and other matters for UE. The FERC regulates UE, CIPS, Genco, CILCO, and IP as to their ability to charge market-based rates for the sale and transmission of energy in interstate commerce and various other matters discussed below under General Regulatory Matters.

About 35% of Ameren’s electric and 14% of its gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2008. About 41% of Ameren’s electric and 86% of its gas operating revenues were subject to regulation by the ICC in the year ended December 31, 2008. Wholesale revenues for UE, Genco and AERG are subject to FERC regulation, but not subject to direct MoPSC or ICC regulation.

Missouri Regulated

Electric

About 81% of UE’s electric operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2008.

Following the expiration of a multiyear electric rate change moratorium, UE filed a request with the MoPSC in July 2006 for approval of an increase in its annual revenues for electric service. In May 2007, the MoPSC issued an order, that, as clarified, granted UE a $43 million increase in base rates for electric service, effective June 4, 2007.

On January 27, 2009, the MoPSC issued an order responding to UE’s April 2008 rate increase request, approving an increase for UE in annual revenues for electric service of approximately $162 million. The MoPSC also approved UE’s implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism. Rate changes consistent with the MoPSC order, as well as the FAC and the vegetation management and infrastructure inspection cost tracking mechanism, were effective as of March 1, 2009. These cost recovery and tracking mechanisms help to mitigate the negative effect of regulatory lag.

The MoPSC initiated a proceeding in December 2008 to develop revised rules for an environmental cost recovery mechanism, which has been authorized under Missouri law. Rules for the environmental cost recovery mechanism are expected to be approved by the MoPSC during the second quarter of 2009 and will be effective once published in the Missouri Register. UE will not be able to implement an environmental cost recovery mechanism until authorized by the MoPSC as part of a rate case proceeding. UE has not requested approval of an environmental cost recovery mechanism.

Gas

All of UE’s gas operating revenues were subject to regulation by the MoPSC in the year ended December 31, 2008.

If certain criteria are met, UE’s gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer. The ISRS also permits prudently incurred gas infrastructure replacement costs to be passed directly to the consumer.

As part of a 2007 stipulation and agreement approved by the MoPSC authorizing an increase in annual natural gas delivery revenues of $6 million effective April 1, 2007, UE agreed not to file a natural gas delivery rate case before March 15, 2010. This agreement did not prevent UE from filing to recover gas infrastructure replacement costs through an ISRS during this three-year rate moratorium. During 2008, the MoPSC approved two UE requests to establish an ISRS to recover annual revenues of $2 million in the aggregate, effective in March and November 2008.

For further information on Missouri rate matters, see Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 2 – Rate and Regulatory Matters, and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

Illinois Regulated

The following table presents the approximate percentage of electric and gas operating revenues subject to regulation by the ICC for each of the Illinois Regulated companies for the year ended December 31, 2008:


	Electric		Gas
CIPS	100	%	100	%
CILCORP/CILCO ^(a)	56		100
IP	100		100

(a)	AERG’s revenues are not subject to ICC regulation.

If certain criteria are met, CIPS’, CILCO’s and IP’s gas rates may be adjusted without a traditional rate proceeding. PGA clauses permit prudently incurred natural gas costs to be passed directly to the consumer.

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. In addition, IP has 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 is recoverable by IP from a trust fund established by IP. At December 31, 2008, the trust fund balance was $23 million, including accumulated interest. If cash expenditures are less than the amount in base rates, IP will contribute 90% of the difference to the fund. Once the trust fund is depleted, 90% of allowed cash expenditures in excess of base rates will be recoverable through charges assessed to customers under the tariff rider.

A multiyear electric rate moratorium expired and new electric rates for CIPS, CILCO and IP went into effect on January 2, 2007. The new rates reflected delivery service tariffs approved by the ICC in November 2006 and a cost recovery mechanism for power purchased on behalf of the Ameren Illinois Utilities’ customers. In 2007, an agreement was reached among key stakeholders in Illinois to address the increase in electric rates and the future power procurement process. The Illinois electric settlement agreement provides $1 billion of funding from 2007 to 2010 for rate relief for certain electric customers in Illinois, including $488 million to customers of the Ameren Illinois Utilities. Ameren’s contributions over the four-year period under the Illinois electric settlement agreement aggregate $150 million.

In September 2008, responding to CIPS’, CILCO’s and IP’s November 2007 electric and natural gas rate adjustment requests, the ICC issued a consolidated order approving a net increase in annual revenues for electric service of $123 million in the aggregate (CIPS – $22 million increase, CILCO – $3 million decrease, and IP – $104 million increase) and a net increase in annual revenues for natural gas delivery service of $38 million in the aggregate (CIPS – $7 million increase, CILCO – $9 million decrease, and IP – $40 million increase). Rate changes implementing these adjustments were effective on October 1, 2008. The ICC also approved an increase in the percentage of costs to be recovered through fixed monthly charges for natural gas customers, as well as an increase in the Supply Cost Adjustment factors for the customers who take their power supply from the Ameren Illinois Utilities. These two rate structure changes help to mitigate the negative effect of regulatory lag.

For further information on Illinois rate matters, including the pending court appeal of the September 2008 consolidated electric and gas rate order, see Results of Operations and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, and Note 2 – Rate and Regulatory Matters, and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

Non-rate-regulated Generation

Non-rate-regulated Generation revenues are determined by market conditions. We expect the Non-rate-regulated Generation fleet of assets to have 6,480 megawatts of capacity available for the 2009 peak demand. As discussed below, Genco, AERG, and EEI sell all of their power and capacity to Marketing Company via power supply agreements. Marketing Company attempts to optimize the value of those generation assets and mitigate risks utilizing a variety of hedging techniques including wholesale sales of capacity and energy, retail sales in the non-rate-regulated Illinois market, spot market sales primarily in MISO and PJM, and financial transactions. Marketing Company enters into long-term and short-term contracts. Marketing Company’s counterparties include cooperatives, municipalities, commercial and industrial customers, power marketers, MISO, and investor-owned utilities like the Ameren Illinois Utilities. See Note 14 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information, including Marketing Company sales to the Ameren Illinois Utilities.

General Regulatory Matters

UE, CIPS, CILCO and IP must receive FERC approval to issue short-term debt securities and to conduct certain acquisitions, mergers and consolidations involving electric utility holding companies having a value in excess of $10 million. In addition, these Ameren utilities must receive

authorization from the applicable state public utility regulatory agency to issue stock and long-term debt securities (with maturities of more than 12 months) and to conduct mergers, affiliate transactions, and various other activities. Genco, AERG and EEI are subject to FERC’s jurisdiction when they issue any securities.

Under PUHCA 2005, FERC and any state public utility regulatory agencies may access books and records of Ameren and its subsidiaries that are determined to be relevant to costs incurred by Ameren’s rate-regulated subsidiaries with respect to jurisdictional rates. PUHCA 2005 also permits Ameren, the ICC, or the MoPSC to request that FERC review cost allocations by Ameren Services to other Ameren companies.

Operation of UE’s Callaway nuclear plant is subject to regulation by the NRC. Its facility operating license expires on June 11, 2024. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. UE’s Osage hydroelectric plant and UE’s Taum Sauk pumped-storage hydroelectric plant, as licensed projects under the Federal Power Act, are subject to FERC regulations affecting, among other things, the general operation and maintenance of the projects. The license for UE’s Osage hydroelectric plant expires on March 30, 2047, and the license for UE’s Taum Sauk plant expires on June 30, 2010. In June 2008, UE filed an application with FERC to relicense its Taum Sauk plant for another 40 years. The Taum Sauk plant is currently out of service. It is being rebuilt due to a major breach of the upper reservoir in December 2005. UE’s Keokuk plant and its dam, in the Mississippi River between Hamilton, Illinois, and Keokuk, Iowa, are operated under authority granted by an Act of Congress in 1905.

For additional information on regulatory matters, see Note 2 – 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 about the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage hydroelectric plant.

Environmental Matters

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

are in material compliance with existing statutes and regulations.

For additional discussion of environmental matters, including NO _x , SO ₂ , and mercury emission reduction requirements and the December 2005 breach of the upper reservoir at UE’s Taum Sauk pumped-storage 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

Ameren operates an integrated transmission system that comprises the transmission assets of UE, CIPS, CILCO, IP and AITC. AITC placed its first transmission assets, jointly owned with IP, in service during the fourth quarter of 2008. Any transmission assets of AITC would be eligible for rate recovery upon making the necessary filings with and acceptance by FERC. Ameren also operates two balancing authority areas, AMMO (which includes UE) and AMIL (which includes CIPS, CILCO, IP, AITC, Genco and AERG). During 2008, the peak demand in AMMO was 8,644 MW and in AMIL was 8,794 MW. The Ameren transmission system directly connects with 17 other balancing authority areas for the exchange of electric energy.

UE, CIPS, CILCO and IP are transmission-owning members of MISO, and they have transferred functional control of their systems to MISO. Transmission service on the UE, CIPS, CILCO and IP transmission systems is provided pursuant to the terms of the MISO OATT on file with FERC. EEI operates its own balancing authority area and its own transmission facilities in southern Illinois. The EEI transmission system is directly connected to MISO and TVA. EEI’s generating units are dispatched separately from those of UE, Genco and AERG.

The Ameren Companies and EEI are members of SERC. SERC is responsible for the bulk electric power supply system in much of the southeastern United States, including all or portions of Missouri, Illinois, Arkansas, Kentucky, Tennessee, North Carolina, South Carolina, Georgia, Mississippi, Alabama, Louisiana, Virginia, Florida, Oklahoma, Iowa, and Texas. The Ameren membership covers UE, CIPS, CILCO and IP.

See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further information.

Missouri Regulated

UE’s electric supply is obtained primarily from its own generation. Factors that could cause UE to purchase power include, among other things, absence of sufficient owned generation, plant outages, the failure of suppliers to meet their power supply obligations, extreme weather conditions, and the availability of power at a cost lower than the cost of generating it.

In March 2006, UE completed the purchase of three CT facilities, totaling 1,490 megawatts of capacity, at a price of $292 million. These purchases were designed to help meet UE’s increased generating capacity needs and to provide UE with additional flexibility in determining when to add future baseload generating capacity. UE expects these CT facilities to satisfy demand growth until 2018 or 2020. However, due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE is actively studying future plant alternatives, including those that would use coal or nuclear fuel. In 2008, UE filed an integrated resource plan with the MoPSC. The plan included proposals to pursue energy efficiency programs, expand the role of renewable energy sources in UE’s overall generation mix, increase operational efficiency at existing power plants, and possibly retire some generating units that are older and less efficient.

In July 2008, UE filed a COLA with the NRC for a potential new nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. In addition, in 2008, UE filed an application with the DOE for loan guarantees associated with the potential construction of a new nuclear unit. UE has also signed contracts for certain long lead-time nuclear plant related equipment. The filing of the COLA and the DOE loan guarantee application and entering into these contracts does not mean a decision has been made to build another nuclear unit. These are only the first steps in the regulatory licensing and procurement process and are necessary actions to preserve the option to develop a new nuclear unit.

See also Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 and Note 2 – Rate and Regulatory Matters and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

Illinois Regulated

As of January 1, 2007, CIPS, CILCO and IP were required to obtain all electric supply requirements for customers who did not purchase electric supply from third-party suppliers. The power procurement costs incurred by CIPS, CILCO and IP are passed directly to their customers through a cost recovery mechanism.

In September 2006, a reverse power procurement auction was held, as a result of which CIPS, CILCO and IP entered into power supply contracts with the winning bidders, including Marketing Company. Under these contracts, the electric suppliers are responsible for providing to CIPS, CILCO and IP energy, capacity, certain transmission, volumetric risk management, and other services necessary for the Ameren Illinois Utilities to serve the electric load needs of fixed price residential and small commercial customers (with less than one MW of demand) at an all-inclusive fixed price. These contracts commenced on January 1, 2007, with one-third of the supply contracts expiring in each of May 2008, 2009 and 2010.

As part of the Illinois electric settlement agreement reached in 2007, the reverse power procurement auction process in Illinois was discontinued. It was replaced with a new power procurement process led by the IPA beginning in 2009. Under the new plan, the IPA will procure separate wholesale products (capacity, energy swaps and renewable energy credits) on behalf of the Ameren Illinois Utilities for the period of June 1, 2009, through May 30, 2014. The products will be procured through a RFP process, which is expected to begin during the first half of 2009. In 2008, utilities contracted for necessary power and energy requirements not already supplied through the September 2006 auction contracts, primarily through a RFP process that was subject to ICC review and approval.

A portion of the electric power supply required for the Ameren Illinois Utilities to satisfy their distribution customers’ requirements is purchased from Marketing Company on behalf of Genco, AERG and EEI. Also as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of their round-the-clock power requirements during the period June 1, 2008, to December 31, 2012, at relevant market prices at that time. These financial contracts do not include capacity, are not load-following products, and do not involve the physical delivery of energy.

See Note 2 – Rate and Regulatory Matters and Note 14 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information on power procurement in Illinois.

Non-rate-regulated Generation

In December 2006, Genco and Marketing Company, and AERG and Marketing Company, entered into power supply agreements whereby Genco and AERG sell and Marketing Company purchases all the capacity available from Genco’s and AERG’s generation fleets and the associated energy commencing on January 1, 2007. These power supply agreements continue through December 31, 2022, and from year to year thereafter unless either party elects to terminate the agreement by providing the other party with no less than six months advance written notice. In December 2005, EEI and Marketing Company entered into a power supply agreement whereby EEI sells all of its capacity and energy to Marketing Company commencing January 1, 2006. This agreement expires on December 31, 2015. All of Genco’s, AERG’s and EEI’s generating capacity competes for the sale of energy and capacity in the competitive energy markets through Marketing Company. See Note 14 – Related Party Transactions to our financial statements under Part II, Item 8, of this report for additional information.

Factors that could cause Marketing Company to purchase power for the Non-rate-regulated Generation business segment include, among other things, absence of sufficient owned generation, plant outages, the failure of suppliers to meet their power supply obligations, and extreme weather conditions.

FUEL FOR POWER GENERATION

The following table presents the source of electric generation by fuel type, excluding purchased power, for the years ended December 31, 2008, 2007 and 2006:


	Coal		Nuclear		Natural Gas		Hydroelectric		Oil
Ameren: ^(a)
2008	85	%	12	%	1	%	2	%	(b	)%
2007	84		12		2		2		(b	)
2006	85		13		1		1		(b	)
Missouri Regulated:
UE:
2008	77	%	19	%	1	%	3	%	(b	)%
2007	76		19		2		3		(b	)
2006	77		20		1		2		(b	)
Non-rate-regulated Generation:
Genco:
2008	99	%	-	%	1	%	-	%	(b	)%
2007	96		-		4		-		(b	)
2006	97		-		2		-		1
CILCO (AERG):
2008	99	%	-	%	1	%	-	%	-	%
2007	99		-		1		-		(b	)
2006	99		-		1		-		(b	)
EEI:
2008	100	%	-	%	-	%	-	%	-	%
2007	100		-		-		-		-
2006	100		-		(b	)	-		-
Total Non-rate-regulated Generation:
2008	99	%	-	%	1	%	-	%	(b	)%
2007	98		-		2		-		(b	)
2006	99		-		1		-		(b	)

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

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

The following table presents the cost of fuels for electric generation for the years ended December 31, 2008, 2007 and 2006:


Cost of Fuels (Dollars per million Btus)	2008		2007		2006
Ameren:
Coal ^(a)(d)	$	1.572	$	1.399	$	1.271
Nuclear		0.493		0.490		0.434
Natural gas ^(b)		10.503		7.939		8.718
Weighted average – all fuels ^(c)(d)	$	1.573	$	1.462	$	1.281
Missouri Regulated:
UE:
Coal ^(a)	$	1.426	$	1.284	$	1.084
Nuclear		0.493		0.490		0.434
Natural gas ^(b)		10.264		7.580		8.625
Weighted average – all fuels ^(c)	$	1.340	$	1.271	$	1.035
Non-rate-regulated Generation:
Genco:
Coal ^(a)(d)	$	1.958	$	1.717	$	1.691
Natural gas ^(b)		15.857		8.440		9.391
Weighted average – all fuels ^(c)(d)	$	2.121	$	1.939	$	1.865
CILCO (AERG):
Coal ^(a)	$	1.598	$	1.309	$	1.419
Weighted average – all fuels ^(c)	$	1.721	$	1.450	$	1.466
EEI:
Coal ^(a)	$	1.438	$	1.329	$	1.266
Total Non-rate-regulated Generation:
Coal ^(a)(d)	$	1.746	$	1.545	$	1.513
Natural gas ^(b)		10.764		8.390		8.793
Weighted average – all fuels ^(c)	$	1.919	$	1.759	$	1.677

(a)	The fuel cost for coal represents the cost of coal, costs for transportation, which includes diesel fuel adders, and cost of emission allowances.

(b)

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

(c)

Represents all costs for fuels used in our electric generating facilities, to the extent applicable, including coal, nuclear, natural gas, oil, propane, tire chips, paint products, and handling. Oil, paint, propane, and tire chips are not individually listed in this table because their use is minimal.

(d)	Excludes impact of the Genco coal supply contract settlement under which Genco received a lump-sum payment of $60 million in July 2008 from a coal mine owner. See Note 1 – Summary of Significant Accounting Policies under Part II, Item 8, of this report.

Coal

UE, Genco, AERG and EEI have agreements in place to purchase a portion of their coal needs and to transport it to electric generating facilities through 2012. UE, Genco, AERG and EEI expect to enter into additional contracts to purchase coal. Coal supply agreements typically have an initial term of five years, with about 20% of the contracts expiring annually. Ameren burned 40.3 million (UE – 22.0 million, Genco – 9.6 million, AERG – 3.7 million, EEI – 5.0 million) tons of coal in 2008. See Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about coal supply contracts.

About 96% of Ameren’s coal (UE – 97%, Genco – 98%, AERG – 77%, EEI – 100%) is purchased from the Powder River Basin in Wyoming. The remaining coal is typically purchased from the Illinois Basin. UE, Genco, AERG and EEI have a policy to maintain coal inventory consistent with their projected usage. Inventory may be adjusted because of uncertainties of supply due to potential work stoppages, delays in coal deliveries,

equipment breakdowns, and other factors. In the past, deliveries from the Powder River Basin have been restricted because of rail maintenance, weather and derailments. As of December 31, 2008, coal inventories for UE, Genco, AERG and EEI were adequate and at targeted levels. Disruptions in coal deliveries could cause UE, Genco, AERG and EEI to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.

Nuclear

Developing nuclear generating fuel generally involves the mining and milling of uranium ore to produce uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride gas, enrichment of that gas, and then the fabrication of the enriched uranium hexafluoride gas into usable fuel assemblies. UE has entered into uranium, uranium conversion, enrichment, and fabrication contracts to procure the fuel supply for its Callaway nuclear plant.

Fuel assemblies for the 2010 spring refueling at UE’s Callaway nuclear plant will begin manufacture during the fourth quarter of 2009. Enriched uranium for such assemblies is in inventory. UE also has agreements or inventories to price-hedge approximately 95% of Callaway’s 2010 and 55% of Callaway’s 2011 refueling requirements. UE has uranium (concentrate and hexafluoride) inventories and supply contracts sufficient to meet all of its uranium and conversion requirements through at least 2014. UE has enriched uranium inventories and enrichment supply contracts sufficient to satisfy enrichment requirements through 2012. Fuel fabrication services are under contract through 2010. UE expects to enter into additional contracts to purchase nuclear fuel. As a member of Fuelco, UE can join with other member companies to increase its purchasing power and opportunities for volume discounts. The Callaway nuclear plant normally requires refueling at 18-month intervals. The last refueling was completed in November 2008. There is no refueling scheduled in 2009 or 2012. The nuclear fuel markets are competitive, and prices can be volatile; however, we do not anticipate any significant problems in meeting our future supply requirements.

Natural Gas Supply

To maintain gas deliveries to gas-fired generating units throughout the year, especially during the summer peak demand, Ameren’s portfolio of natural gas supply resources includes firm transportation capacity and firm no-notice storage capacity leased from interstate pipelines. UE, Genco and EEI primarily use the interstate pipeline systems of Panhandle Eastern Pipe Line Company, Trunkline Gas Company, Natural Gas Pipeline Company of America, and Mississippi River Transmission Corporation to transport natural gas to generating units. In addition to physical transactions, Ameren uses financial instruments, including some in the NYMEX futures market and some in the OTC financial markets, to hedge the price paid for natural gas.

UE, Genco and EEI’s natural gas procurement strategy is designed to ensure reliable and immediate delivery of natural gas to their generating units. UE, Genco and EEI do this in two ways. They optimize transportation and storage options and minimize cost and price risk through various supply and price hedging agreements that allow them to maintain access to multiple gas pools, supply basins, and storage. As of December 31, 2008, UE had price-hedged about 22% and Genco had price-hedged about 30% of their required gas supply for generation in 2009. As of December 31, 2008, EEI did not have any of its required gas supply for generation hedged for price risk.

NATURAL GAS SUPPLY FOR DISTRIBUTION

UE, CIPS, CILCO and IP are responsible for the purchase and delivery of natural gas to their gas utility customers. UE, CIPS, CILCO and IP develop and manage a portfolio of gas supply resources. These include 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 customers throughout the year and especially during peak demand. UE, CIPS, CILCO and IP primarily use the Panhandle Eastern Pipe Line Company, the Trunkline Gas Company, the Natural Gas Pipeline Company of America, the Mississippi River Transmission Corporation, and the Texas Eastern Transmission Corporation interstate pipeline systems to transport natural gas to their systems. In addition to physical transactions, financial instruments, including those entered into in the NYMEX futures market and in the OTC financial markets, are used to hedge the price paid for natural gas. See Part II, Item 7A – Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about natural gas supply contracts. Prudently incurred natural gas purchase costs are passed on to customers of UE, CIPS, CILCO and IP in Illinois and Missouri under PGA clauses, subject to prudency review by the ICC and the MoPSC.

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

INDUSTRY ISSUES

We are facing issues common to the electric and gas utility industry and the non-rate-regulated electric generation industry. These issues include:

political and regulatory resistance to higher rates, especially in a recessionary economic environment;

the potential for changes in laws, regulation, and policies at the state and federal level, including those resulting from election cycles;

access to and uncertainty in the capital and credit markets;

the potential for more intense competition in generation and supply;

pressure on customer growth and usage in light of current economic conditions;

the potential for reregulation in some states, including Illinois, which could cause electric distribution companies to build or acquire generation facilities and to purchase less power from electric generating companies like Genco, AERG and EEI;

changes in the structure of the industry as a result of changes in federal and state laws, including the

formation of non-rate-regulated generating entities and RTOs;

increases or decreases in power prices due to the balance of supply and demand;

the availability of fuel and increases or decreases in fuel prices;

the availability of labor and material and rising costs;

regulatory lag;

negative free cash flows due to rising investments and the regulatory framework;

continually developing and complex environmental laws, regulations and issues, including air-quality standards, mercury regulations, and increasingly likely greenhouse gas limitations;

public concern about the siting of new facilities;

construction of power generation and transmission facilities;

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

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

consolidation of electric and gas companies.

We are monitoring these issues. Except as otherwise noted in this report, we are unable to predict what impact, if any, these issues will have on our results of operations, financial position, or liquidity. For additional information, see Risk Factors under Part I, Item 1A, and Outlook and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 2 – Rate and Regulatory Matters, and Note 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:


Electric Operating Statistics – Year Ended December 31,	2008			2007			2006
Electric Sales – kilowatthours (in millions):
Missouri Regulated:
Residential		13,904			14,258			13,081
Commercial		14,690			14,766			14,075
Industrial		9,256			9,675			9,582
Other		785			759			739
Native load subtotal		38,635			39,458			37,477
Nonaffiliate interchange sales		10,457			10,984			3,132
Affiliate interchange sales		-			-			10,072
Subtotal		49,092			50,442			50,681
Illinois Regulated:
Residential
Generation and delivery service		11,667			11,857			11,476
Commercial
Generation and delivery service		6,095			7,232			11,406
Delivery service only		6,147			5,178			269
Industrial
Generation and delivery service		1,442			1,606			10,950
Delivery service only		11,300			11,199			2,349
Other		555			576			598
Native load subtotal		37,206			37,648			37,048
Non-rate-regulated Generation:
Nonaffiliate energy sales		26,395			25,196			24,921
Affiliate native energy sales		6,055			7,296			18,425
Subtotal		32,450			32,492			43,346
Eliminate affiliate sales		(6,055	)		(7,296	)		(28,036	)
Eliminate Illinois Regulated/Non-rate-regulated Generation common customers		(4,939	)		(5,800	)		(2,024	)
Ameren Total		107,754			107,486			101,015
Electric Operating Revenues (in millions):
Missouri Regulated:
Residential	$	948		$	980		$	899
Commercial		838			839			796
Industrial		372			390			392
Other		108			93			104
Native load subtotal		2,266			2,302			2,191
Nonaffiliate interchange sales		490			484			263
Affiliate interchange sales		-			-			196
Subtotal	$	2,756		$	2,786		$	2,650


Electric Operating Statistics – Year Ended December 31,	2008			2007			2006
Illinois Regulated:
Residential
Generation and delivery service	$	1,112		$	1,055		$	852
Commercial
Generation and delivery service		616			666			784
Delivery service only		77			54			3
Industrial
Generation and delivery service		102			105			489
Delivery service only		30			24			2
Other		285			372			126
Native load subtotal	$	2,222		$	2,276		$	2,256
Non-rate-regulated Generation:
Nonaffiliate energy sales	$	1,389		$	1,310		$	1,032
Affiliate native energy sales		441			461			662
Other		106			41			19
Subtotal	$	1,936		$	1,812		$	1,713
Eliminate affiliate revenues		(547	)		(591	)		(1,019	)
Ameren Total	$	6,367		$	6,283		$	5,600
Electric Generation – megawatthour (in millions):
Missouri Regulated		49.3			50.3			50.8
Non-rate-regulated Generation:
Genco		16.6			17.4			15.4
AERG		6.7			5.3			6.7
EEI		8.0			8.1			8.3
Medina Valley		0.2			0.2			0.2
Subtotal		31.5			31.0			30.6
Ameren Total		80.8			81.3			81.4
Price per ton of delivered coal (average) ^(a)	$	26.90		$	25.20		$	22.74
Source of energy supply:
Coal		70.1	%		68.7	%		65.8	%
Gas		0.8			1.8			0.9
Oil		-			-			0.7
Nuclear		9.5			9.4			9.7
Hydroelectric		1.8			1.6			0.9
Purchased and interchanged, net		17.8			18.5			22.0
		100.0	%		100.0	%		100.0	%


Gas Operating Statistics – Year Ended December 31,	2008		2007	2006
Gas Sales (millions of Dth)
Missouri Regulated:
Residential	8		7	7
Commercial	4		4	3
Industrial	1		1	1
Subtotal	13		12	11
Illinois Regulated:
Residential	65		59	55
Commercial	28		25	23
Industrial	11		10	13
Subtotal	104		94	91
Other:
Residential	-		-	-
Commercial	-		-	-
Industrial	4		2	7
Subtotal	4		2	7
Eliminate affiliate sales	(1	)	-	-
Ameren Total	120		108	109


Gas Operating Statistics – Year Ended December 31,	2008			2007			2006
Natural Gas Operating Revenues (in millions)
Missouri Regulated:
Residential	$	121		$	108		$	101
Commercial		54			47			46
Industrial		12			12			13
Other		14			7			(2	)
Subtotal	$	201		$	174		$	158
Illinois Regulated:
Residential	$	819		$	687		$	690
Commercial		338			272			271
Industrial		119			103			82
Other		(21	)		39			53
Subtotal	$	1,255		$	1,101		$	1,096
Other:
Residential	$	-		$	-		$	-
Commercial		-			-			-
Industrial		26			16			60
Other		-			-			-
Subtotal	$	26		$	16		$	60
Eliminate affiliate revenues		(10	)		(12	)		(19	)
Ameren Total	$	1,472		$	1,279		$	1,295
Peak day throughput (thousands of Dth):
UE		158			155			124
CIPS		266			250			242
CILCO		399			401			356
IP		615			574			540
Total peak day throughput		1,438			1,380			1,262

(a)	Includes impact of the Genco coal settlement under which Genco received a lump-sum payment of $60 million in July 2008 from a coal mine owner. See Note 1 – Summary of Significant Account Policies to our financial statements under Part II, Item 8, of this report.

AVAILABLE INFORMATION

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

The Ameren Companies also make available free of charge through Ameren’s Web site (www.ameren.com) the charters of Ameren’s board of directors’ audit and risk committee, human resources committee, nominating and corporate governance committee, finance committee, nuclear oversight committee, and public policy committee; the corporate governance guidelines; a policy regarding communications to the board of directors; a policy and procedures with respect to related-person transactions; a code of ethics for principal executive and senior financial officers; a code of business conduct applicable to all directors, officers and employees; and a director nomination policy that applies to the Ameren Companies.

These documents are also available in print upon written request to Ameren Corporation, Attention: Secretary, P.O. Box 66149, St. Louis, Missouri 63166- 6149. The public may read and copy any materials filed with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

ITEM 1A.

RISK FACTORS

Investors should review carefully the following risk factors and the other information contained in this report. The risks that the Ameren Companies face are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect the financial position, results of operations and liquidity of the Ameren Companies. See Forward-looking Statements and Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report.

The electric and gas rates that UE, CIPS, CILCO and IP are allowed to charge are determined through regulatory proceedings and are subject to legislative actions, which are largely outside of their control. Any such events that prevent UE, CIPS, CILCO or IP from recovering their respective costs or from earning appropriate returns on their investments could have a material adverse effect on future results of operations, financial position, or liquidity.

The rates that UE, CIPS, CILCO and IP are allowed to charge for their services are an important item influencing the results of operations, financial position, and liquidity of these companies and Ameren. The electric and gas utility industry is highly regulated. The regulation of the rates that utility customers are charged is determined, in large part, by governmental entities, including the MoPSC, the ICC, and FERC. 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 and are largely outside of our control. Decisions made by these entities could have a material adverse effect on results of operations, financial position, or liquidity.

UE, CIPS, CILCO and IP electric and gas utility rates are typically established in regulatory proceedings that take up to 11 months to complete. Rates established in those proceedings are primarily based on historical costs, and they include an allowed return on investments by the regulator.

Our company, and the industry as a whole, is going through a period of rising costs and investments. The fact that rates at UE, CIPS, CILCO and IP are primarily based on historical costs means that these companies may not be able to earn the allowed return established by their regulators (often referred to as regulatory lag). As a result, UE, CIPS, CILCO and IP expect to file more frequent rate cases. A period of increasing rates to our customers, especially during weak economic times, could result in additional regulatory and legislative actions, as well as competitive and political pressures, that could have a material adverse effect on our results of operations, financial position, or liquidity.

We are subject to various environmental laws and regulations that require significant capital expenditures, can increase our operating costs, and may adversely influence or limit our results of operations, financial position or liquidity or expose us to environmental fines and liabilities.

emissions, impacts to air and water, protected and cultural resources (such as wetlands, endangered species, and archeological and historical resources), and chemical and waste handling. Complex and lengthy processes are required to 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 release prevention plans and emergency response procedures.

Compliance with environmental laws and regulations can require significant capital expenditures and operating costs. Actions required to ensure that our facilities are in compliance with environmental laws and regulations could be prohibitively expensive. As a result, we could be required to close or alter the operation of our facilities, which could have an adverse effect on our results of operations, financial position, and liquidity.

Failure to comply with environmental laws and regulations may also result in the imposition of fines, penalties, and injunctive measures affecting operating assets. We are also subject to liability under environmental laws for remediating environmental contamination of property now or formerly owned by us or by our predecessors, as well as property contaminated by hazardous substances that we generated. Such sites include MGP sites and third-party sites, such as landfills. Additionally, private individuals may seek to enforce environmental laws and regulations against us and could allege injury from exposure to hazardous materials.

About 85% of Ameren’s (UE – 77%, Genco – 99%, CILCO (through AERG) – 99%, EEI – 100%) generating capacity is coal-fired. The remaining electric generation comes from nuclear, gas-fired, hydroelectric, and oil-fired power plants. Federal and state laws require significant reductions in SO ₂ , NO _x and mercury emissions from coal-fired plants.

Ameren’s estimated capital costs through 2018, based on current technology, to comply with the federal Clean Air Interstate Rule and related state implementation plans and the MPS as well as federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility Rule range from $4.5 billion to $5.5 billion (UE – $2.2 billion to $2.6 billion; Genco – $1.2 billion to $1.4 billion, CILCO (through AERG) – $480 million to $590 million, EEI – $665 million to $830 million). In addition, the Ameren Companies could incur additional capital costs with respect to a MACT standard for mercury emissions. The EPA is expected to move forward with a MACT standard for mercury emissions as the U.S. Supreme Court denied in February 2009 a petition to review a U.S. Court of Appeals decision that vacated the federal Clean Air Mercury Rule. Further, with respect to the EPA’s 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 the New Source Review requirements or New Source Performance Standards under the Clean Air Act, Ameren, UE, Genco, AERG and EEI could incur increased capital expenditures for

the installation of control technology, increased operations and maintenance expenses, as well as fines or penalties.

New environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation could result in a significant increase in capital expenditures and operating costs, decreased revenues, increased financing requirements, penalties, or closure of power plants for UE, Genco, AERG and EEI. Although costs incurred by UE would be eligible for recovery in rates over time, subject to MoPSC approval in a rate proceeding, there is no similar mechanism for recovery of costs for Genco, AERG or EEI. We are unable to predict the ultimate impact of these matters on our results of operations, financial position or liquidity.

Future limits on greenhouse gas emissions would likely require UE, Genco, CILCO (through AERG) and EEI to incur significant increases in capital expenditures and operating costs, which, if excessive, could result in the closures of coal-fired generating plants or otherwise materially adversely affect our results of operations, financial position or liquidity.

Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. In October 2008, the U.S. House of Representatives, Energy and Commerce Committee, Subcommittee on Energy and Air Quality issued a “discussion draft” of climate legislation, which proposed establishing an economy-wide cap-and-trade program. The overarching goal of such legislation is to reduce greenhouse gas emissions to 6% below 2005 levels by 2020 and to 80% below 2005 levels by 2050. In addition, new leadership in the Energy and Commerce Committee is considering aggressive climate legislation. Finally, President Obama supports an economy-wide cap-and-trade greenhouse gas reduction program that would reduce emissions to 1990 levels by 2020 and 80% below 1990 levels by 2050. President Obama has also indicated support for auctioning 100% of the emission allowances to be distributed under the legislation. Although we cannot predict the date of enactment or the requirements of any global warming legislation or regulations, we believe it is likely that some form of federal greenhouse gas legislation or regulations will become law during President Obama’s administration.

As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities, but coal-fired power plants are significant sources of CO ₂ , a principal greenhouse gas. Ameren’s current analysis shows that under some policy scenarios being considered in the U.S. Congress, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the Midwest economy because of our region’s reliance on electricity generated by coal-fired power plants. Natural gas emits about half the amount of CO ₂ that coal emits when burned to produce electricity. As a result, economy-wide shifts favoring natural gas as a fuel source for electric generation could affect the cost of heating for our utility customers and many industrial

processes. Ameren believes that under some policy scenarios being considered by Congress, wholesale natural gas costs could rise significantly as well. Higher costs for energy could contribute to reduced demand for both electricity and natural gas.

Future initiatives regarding greenhouse gas emissions and global warming may also be subject to the activities pursuant to the Midwest Greenhouse Gas Reduction Accord, an agreement signed by the governors of Illinois, Iowa, Kansas, Michigan, Wisconsin and Minnesota to develop a strategy to achieve energy security and reduce greenhouse gas emissions through a cap-and-trade mechanism. It is expected that the advisory group to the Midwest governors will provide recommendations on the design of a greenhouse gas reduction program by the third quarter of 2009. However, it is uncertain whether legislation to implement the recommendations will be implemented or passed by any of the states, including Illinois.

With regard to greenhouse gas regulation under existing law, in April 2007, the U.S. Supreme Court issued a decision that the EPA has the authority to regulate CO ₂ and other greenhouse gases from automobiles as “air pollutants” under the Clean Air Act. This decision was a result of a Bush Administration ruling denying a waiver request by the state of California to implement such regulations. The Supreme Court sent the case back to the EPA, which must conduct a rulemaking process to determine whether greenhouse gas emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” In July 2008, the EPA issued an advance notice of public rulemaking (ANPR) in response to the U.S. Supreme Court’s directive. The ANPR solicited public comments on the benefits and ramifications of regulating greenhouse gases under the Clean Air Act, and that rulemaking has not been completed. On February 12, 2009, the EPA announced its intent to reconsider the decision under the Bush Administration denying the waiver to the state of California for regulating CO ₂ emissions from automobiles. On February 17, 2009, the EPA also granted a petition for reconsideration filed by the Sierra Club to reexamine a December 2008 Bush Administration ruling that CO ₂ should not be regulated under the Clean Air Act when issuing construction permits for power plants. These EPA actions will factor into the rulemaking process on the ANPR and could ultimately lead to regulation of CO ₂ from power plants.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force UE, Genco, CILCO (through AERG) and EEI and other similarly situated electric power generators to close some coal-fired facilities and could lead to possible impairment of assets. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, CILCO’s (through AERG) and EEI’s results of operations, financial position, or liquidity.

The construction of, and capital improvements to, UE’s, CIPS’, CILCO’s and IP’s electric and gas utility infrastructure as well as to Genco’s, CILCO’s (through AERG) and EEI’s non-rate-regulated generation facilities involve substantial risks. These risks include escalating costs, performance of the projects when completed and the ability to complete projects as scheduled, which could result in the closure of facilities and higher costs.

Over the next five years, the Ameren Companies will incur significant capital expenditures for compliance with environmental regulations and to make significant investments in their electric and gas utility infrastructure and their non-rate-regulated generation facilities. The Ameren Companies estimate that they will incur up to $10.4 billion (UE – up to $5.3 billion; CIPS – up to $565 million; Genco – up to $1.8 billion; CILCO (Illinois Regulated) – up to $415 million; CILCO (AERG) – up to $640 million; IP – up to $1.2 billion; EEI – up to $385 million; Other – up to $160 million) of capital expenditures during the period 2009 through 2013. These expenses include construction expenditures, capitalized interest or allowance for funds used during construction, and compliance with EPA and state regulations regarding SO ₂ and NO _x emissions and mercury emissions from coal-fired power plants. Costs for these types of projects have escalated in recent years and are expected to either stay at current levels or further escalate.

Investments in Ameren’s regulated operations are expected to be recoverable from ratepayers, but are subject to prudency reviews. The recoverability of amounts expended in non-rate-regulated generation operations will depend on whether market prices for power adjust to reflect increased costs for generators.

The ability of the Ameren Companies to complete facilities under construction successfully, and to complete future projects within established estimates, is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their contracts, changes in the scope and timing of projects, the inability to raise capital on favorable terms, or other events beyond our control may occur that may materially affect the schedule, cost and performance of these projects. With respect to capital spent for pollution control equipment, there is a risk that electric generating plants will not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines or does not perform as expected. Should any such construction efforts be unsuccessful, the Ameren Companies could be subject to additional costs and the loss of their investment in the project or facility. The Ameren Companies may also be required to purchase additional electricity or natural gas for their customers until the projects are completed. All of these risks may have a material adverse effect on the Ameren Companies’ results of operations, financial position, or liquidity.

Our counterparties may not meet their obligations to us.

We are exposed to the risk that counterparties to various arrangements who owe us money, energy, coal, or other commodities or services will not be able to perform their obligations or, with respect to our credit facilities, will fail to honor their commitments. Should the counterparties to commodity arrangements fail to perform, we might be forced to replace or to sell the underlying commitment at then-current market prices. Should the lenders under our current credit facilities fail to perform, the level of borrowing capacity under those arrangements would decrease unless we were able to find replacement lenders to assume the nonperforming lender’s commitment. In such an event, we might incur losses, or our results of operations, financial position, or liquidity could otherwise be adversely affected.

Certain of the Ameren Companies have obligations to other Ameren Companies or other Ameren subsidiaries because of transactions involving energy, coal, other commodities, services, and because of hedging transactions. If one Ameren entity failed to perform under any of these arrangements, other Ameren entities might incur losses. Their results of operations, financial position, or liquidity could be adversely affected, resulting in the nondefaulting Ameren entity being unable to meet its obligations to unrelated third-parties. Our hedging activities are generally undertaken with a view to the Ameren-wide exposures. Some Ameren Companies may therefore be more or less hedged than if they were to engage in such hedging alone.

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

We offer defined benefit and postretirement plans that cover substantially all of our employees. Assumptions related to future costs, returns on investments, interest rates, and other actuarial matters have a significant impact on our earnings and funding requirements. Ameren expects to fund its pension plans at a level equal at least to the pension expense. Based on Ameren’s assumptions at December 31, 2008, and reflecting this pension funding policy, Ameren expects to make annual contributions of $90 million to $200 million in each of the next five years. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 61%, 6%, 10%, 9%, and 14%, respectively. These amounts are estimates. They may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions.

In addition to the costs of our retirement plans, the costs of providing health care benefits to our employees and retirees have increased 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.

Our electric generating, transmission and distribution facilities are subject to operational risks that could adversely affect our results of operations, liquidity, and financial position.

The Ameren Companies’ financial performance depends on the successful operation of electric generating, transmission, and distribution facilities. Operation of electric generating, transmission, and distribution facilities involves many risks, including:

increased prices for fuel and fuel transportation;

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

longer-than-anticipated maintenance outages;

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

increased purchased power costs;

lack of water for cooling plant operations;

labor disputes;

inability to comply with regulatory or permit requirements, including environmental contamination;

disruptions in the delivery of electricity, including impacts on us or our customers;

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

handling and storage of fossil-fuel combustion waste products, such as coal ash;

unusual or adverse weather conditions, including severe storms, drought and floods;

a workplace accident that might result in injury or loss of life, extensive property damage or environmental damage;

information security risk, such as a breach of our systems on which sensitive utility customer data and account information are stored;

catastrophic events such as fires, explosions, or other similar occurrences; and

other unanticipated operations and maintenance expenses and liabilities.

Even though agreements have been reached with the state of Missouri and the FERC, the breach of the upper reservoir of UE’s Taum Sauk pumped-storage hydroelectric facility could continue to have an adverse effect on Ameren’s and UE’s results of operations, liquidity, and financial condition.

UE has settled with the FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. Other parties have also claimed damages as a result of the incident. UE has begun rebuilding the upper reservoir at its Taum Sauk plant. The estimated cost to rebuild the upper reservoir is in the range of $480 million. UE expects the Taum Sauk plant to be out of service through early 2010.

If UE must purchase power because of the unavailability of the Taum Sauk facility during the rebuild of the upper reservoir, UE has committed to not seek recovery of these additional costs from ratepayers. The Taum Sauk incident is expected to reduce Ameren’s and UE’s 2009 pretax earnings by $15 million to $20 million, excluding any unreimbursed costs related to the incident or the rebuild, which are currently not expected. UE expects to realize higher-cost sources of power, reduced interchange sales, and increased expenses, net of insurance reimbursement for replacement power costs.

At this time, UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. As a result of this breach, UE is engaged in litigation initiated by certain private parties and the Department of the Army, Corp of Engineers. Until all litigation has been resolved and the insurance review is completed, among other things, we are unable to determine the total impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.

Genco’s, AERG’s, and EEI’s electric generating facilities must compete for the sale of energy and capacity, which exposes them to price risks.

All of Genco’s, AERG’s, and EEI’s generating facilities compete for the sale of energy and capacity in the competitive energy markets.

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

current and future delivered market prices for natural gas, fuel oil, and coal and related transportation costs;

current and forward prices for the sale of electricity;

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

the regulatory and market structures developed for evolving Midwest energy markets;

changes enacted by the Illinois legislature, the ICC, the IPA or other government agencies with respect to power procurement procedures;

the potential for reregulation of generation in some states;

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

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

climate conditions in the Midwest market; and

environmental laws and regulations.

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

UE owns the Callaway nuclear plant, which represents about 12% of UE’s generation capacity and produced 19% of UE’s 2008 generation. Therefore, UE is subject to the risks of nuclear generation, which include the following:

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

the lack of a permanent waste storage site;

limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with UE or other U.S. nuclear operations;

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

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

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

limited availability of fuel supply; and

costly and extended outages for scheduled or unscheduled maintenance and refueling.

The NRC has broad authority under federal law to impose licensing and safety requirements for nuclear generation facilities. In the event of noncompliance, the NRC has the authority to impose fines, shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants such as UE’s. In addition, if a serious nuclear incident were to occur, it could have a material but indeterminable adverse effect on UE’s results of operations, financial position, or liquidity. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit.

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

We are exposed to changes in market prices for natural gas, fuel, electricity, emission allowances, and transmission congestion. Prices for natural gas, fuel, electricity, and emission allowances may fluctuate substantially over relatively short periods of time and expose us to commodity

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

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

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

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

The global capital and credit markets experienced extreme volatility and disruption in 2008, and we expect those conditions to continue throughout 2009. Several factors have driven this situation, including deteriorating global economic conditions and the weakened condition of major financial institutions. The extreme disruption in the financial markets has limited companies’, including the Ameren Companies’, ability to access the debt and equity capital markets as well as credit markets to support their operations and refinance debt, which has led to higher financing costs compared to recent years. At December 31, 2008, the Ameren Companies had in place revolving bank credit facilities aggregating $2.15 billion, the size of which would be reduced if any of the participating banks fail to honor their commitments. In total, 18 banks participated in these credit facilities.

We use short-term and long-term debt as a significant source of liquidity and funding for capital requirements not

satisfied by our operating cash flow, including requirements related to future environmental compliance. As a result of rising costs and increased capital and operations and maintenance expenditures, coupled with near-term regulatory lag, we expect to need more short-term and long-term debt financing. The inability to raise debt or equity capital on favorable terms, or at all, particularly during times of uncertainty in the capital markets, could negatively affect our ability to maintain and to expand our businesses. Our current credit ratings cause us to believe that we will continue to have access to the capital markets. However, events beyond our control, such as the extreme volatility and disruption in global debt or equity capital and credit markets in 2008 and 2009, may create uncertainty that could increase our cost of capital or impair, or eliminate, our ability to access the debt, equity or credit markets, including the ability to draw on our bank credit facilities. Certain of the Ameren Companies rely, in part, on Ameren for access to capital. Circumstances that limit Ameren’s access to capital, including those relating to its other subsidiaries, could impair its ability to provide those Ameren Companies with needed capital.

The Ameren Companies have certain debt that matures, and credit facilities that expire, in 2009 and 2010. Although we are actively developing plans and strategies to refinance or otherwise repay this debt and to renew or replace these credit facilities, we are unable to predict capital market conditions, our access to the capital markets or the degree of success we will have in renewing or replacing any of the credit facilities and whether the size and terms of any new credit facilities will be comparable to the existing credit facilities.

Ameren’s and some of the Ameren Companies’ holding company structures could limit their ability to pay common stock dividends, to service their respective debt obligations and to pay dividends on their outstanding preferred stock, as applicable.

Ameren is a holding company, and therefore, its primary assets are the common stock of its subsidiaries. As

a result, Ameren’s ability to pay dividends on its common stock depends on the earnings of its subsidiaries and the ability of its subsidiaries to pay dividends or otherwise transfer funds to Ameren. Similarly, Ameren’s and some of the Ameren Companies’ ability to service their respective debt obligations and to pay dividends on their respective preferred stock are also dependent upon the earnings of operating subsidiaries and the distribution of those earnings and other payments, including payments of principal and interest under intercompany indebtedness. The payment of dividends to Ameren by its subsidiaries in turn depends on their results of operations and cash flows and other items affecting retained earnings. Ameren’s subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any dividends or make any other distributions (except for payments required pursuant to the terms of intercompany borrowing arrangements) to Ameren. Certain of the Ameren Companies’ financing agreements and articles of incorporation, in addition to certain statutory and regulatory requirements, may impose certain restrictions on the ability of such Ameren Companies to transfer funds to Ameren in the form of cash dividends, loans or advances.

Failure to retain and attract key officers and other skilled professional and technical employees could have an adverse effect on our operations.

Our businesses depend upon our ability to employ and retain key officers and other skilled professional and technical employees. A significant portion of our workforce is nearing retirement, including many employees with specialized skills such as maintaining and servicing our electric and natural gas infrastructure and operating our generating units. Our inability to retain and recruit qualified employees could adversely affect our results of operations.

ITEM 1B.

UNRESOLVED STAFF COMMENTS.

None.

ITEM 2.

PROPERTIES.

For information on our principal properties, see the generating facilities table below. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, of this report for any planned additions, replacements or transfers. See also Note 5 – Long-term Debt and Equity Financings, and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report.

The following table shows what our electric generating facilities and capability are anticipated to be at the time of our expected 2009 peak summer electrical demand:


Primary Fuel Source	Plant	Location	Net Kilowatt Capability ^(a)
Missouri Regulated:
UE:
Coal	Labadie	Franklin County, Mo.	2,405,000
	Rush Island	Jefferson County, Mo.	1,181,000
	Sioux	St. Charles County, Mo.	986,000
	Meramec	St. Louis County, Mo.	841,000
Total coal			5,413,000
Nuclear	Callaway	Callaway County, Mo.	1,190,000
Hydroelectric	Osage	Lakeside, Mo.	234,000
	Keokuk	Keokuk, Iowa	137,000
Total hydroelectric			371,000
Pumped-storage	Taum Sauk	Reynolds County, Mo.	(b	)
Oil (CTs)	Fairgrounds	Jefferson City, Mo.	55,000
	Meramec	St. Louis County, Mo.	59,000
	Mexico	Mexico, Mo.	55,000
	Moberly	Moberly, Mo.	55,000
	Moreau	Jefferson City, Mo.	55,000
	Howard Bend	St. Louis County, Mo.	43,000
	Venice	Venice, Ill.	(c	)
Total oil			322,000
Natural gas (CTs)	Peno Creek ⁽ ^d ⁾ ^(e)	Bowling Green, Mo.	188,000
	Meramec ^(e)	St. Louis County, Mo.	53,000
	Venice ^(e ⁾	Venice, Ill.	500,000
	Viaduct	Cape Girardeau, Mo.	25,000
	Kirksville	Kirksville, Mo.	13,000
	Audrain ^(d)	Audrain County, Mo.	608,000
	Goose Creek	Piatt County, Ill.	438,000
	Raccoon Creek	Clay County, Ill.	304,000
	Pinckneyville	Pinckneyville, Ill.	316,000
	Kinmundy ^(e ⁾	Kinmundy, Ill.	232,000
Total natural gas			2,677,000
Total UE			9,973,000


Primary Fuel Source	Plant	Location	Net Kilowatt Capability ^(a)
Non-rate-regulated Generation:
EEI ^(f) :
Coal	Joppa Generating Station	Joppa, Ill.	1,002,000
Natural gas (CTs)	Joppa	Joppa, Ill.	74,000
Total EEI			1,076,000
Genco:
Coal	Newton	Newton, Ill.	1,198,000
	Coffeen	Coffeen, Ill.	900,000
	Meredosia	Meredosia, Ill.	308,000
	Hutsonville	Hutsonville, Ill.	151,000
Total coal			2,557,000
Oil	Meredosia	Meredosia, Ill.	156,000
	Hutsonville (Diesel)	Hutsonville, Ill.	3,000
Total oil			159,000
Natural gas (CTs)	Grand Tower	Grand Tower, Ill.	511,000
	Elgin ^(g)	Elgin, Ill.	460,000
	Gibson City	Gibson City, Ill.	228,000
	Joppa 7B	Joppa, Ill.	165,000
	Columbia ⁽ ^h ⁾	Columbia, Mo.	140,000
Total natural gas			1,504,000
Total Genco			4,220,000
CILCO (through AERG):
Coal	E.D. Edwards	Bartonville, Ill.	715,000
	Duck Creek	Canton, Ill.	410,000
Total coal			1,125,000
Natural gas	Sterling Avenue	Peoria, Ill.	(i	)
	Indian Trails	Pekin, Ill.	(j	)
Total natural gas			-
Oil	CAT/Mapleton	Mapleton, Ill	9,000
	CAT/Mossville	Mossville, Ill	6,000
Total Oil			15,000
Total CILCO			1,140,000
Medina Valley:
Natural gas	Medina Valley	Mossville, Ill.	44,000
Total Non-rate-regulated Generation			6,480,000
Total Ameren			16,453,000

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

(b)

This facility is not operational because of a breach of its upper reservoir in December 2005. It is expected to be out of service through early 2010. Its 2005 peak summer electrical demand net kilowatt capability was 440,000. For additional information on the Taum Sauk incident, see Note 15 – Commitments and Contingencies under Part II, Item 8 of this report.

(c)	This facility will be out of service in 2009.

(d)	There are economic development lease arrangements applicable to these CTs.

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

(f)	Ameren owns an 80% interest in EEI. See Part I, Item 1, Business and Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report. This table reflects the full capability of EEI’s facilities.

(g)	There is a tolling agreement in place for one of Elgin’s units (approximately 100 megawatts). The agreement expires on May 31, 2009.

(h)

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.

(i)	In December 2008, CILCO entered into talks with a third party to sell the Sterling Avenue facility. CILCO expects to sell this facility in 2009.

(j)	This facility exclusively serves one industrial customer, which announced in early 2009 a suspension of operations of its plant.

The following table presents electric and natural gas utility-related properties for UE, CIPS, CILCO and IP as of December 31, 2008:


	UE		CIPS		CILCO		IP
Circuit miles of electric transmission lines	2,942		2,306		331		1,853
Circuit miles of electric distribution lines	32,956		14,931		8,853		21,607
Circuit miles of electric distribution lines underground	22	%	11	%	25	%	12	%
Miles of natural gas transmission and distribution mains	3,232		5,338		3,907		8,770
Propane-air plants	1		-		-		-
Underground gas storage fields	-		3		2		7
Billion cubic feet of total working capacity of underground gas storage fields	-		2		8		15

Our other properties include office buildings, warehouses, garages, and repair shops.

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

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

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

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

Substantially all of the properties and plant of UE, CIPS, CILCO and IP are subject to the direct first liens of the indentures securing their mortgage bonds. In July 2006 and February 2007, AERG recorded open-ended mortgages and security agreements with respect to its E.D. Edwards and Duck Creek power plants. These plants serve as collateral to secure its obligations under multiyear, senior secured credit facilities entered into on July 14, 2006, and February 9,

2007, along with other Ameren subsidiaries. See Note 4 – Short-term Borrowings and Liquidity under Part II, Item 8, of this report for details of the credit facilities.

UE has conveyed most of its Peno Creek CT facility to the city of Bowling Green, Missouri, and leased the facility back from the city through 2022. Under the terms of this capital lease, UE is responsible for all operation and maintenance responsibilities for the facility. Ownership of the facility will transfer to UE at the expiration of the lease, at which time the property and plant will become subject to the lien of any outstanding UE first mortgage bond indenture.

In March 2006, UE purchased a CT facility located in Audrain County, Missouri, from NRG Audrain Holding, LLC, and NRG Audrain Generating LLC, both affiliates of NRG Energy, Inc. (collectively, NRG). As a part of this transaction, UE was assigned the rights of NRG as lessee of the CT facility under a long-term lease with Audrain County and assumed NRG’s obligations under the lease. The lease term will expire on December 1, 2023. Under the terms of this capital lease, UE has all operation and maintenance responsibilities for the facility, and ownership of the facility will be transferred to UE at the expiration of the lease. When ownership of the Audrain County CT facility is transferred to UE by the county, the property and plant will become subject to the lien of any outstanding UE first mortgage bond indenture.

See Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for information on mechanics’ liens filed against CILCO’s Duck Creek plant.

ITEM 3.

LEGAL PROCEEDINGS.

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

For additional information on legal and administrative proceedings, see Rates and Regulation under Item 1, Business, and Item 1A, Risk Factors, above. See also Liquidity and Capital Resources and Regulatory Matters in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7, and Note 2 – Rate and Regulatory Matters, and Note 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 2008 with respect to any of the Ameren Companies.

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

The executive officers of the Ameren Companies, including major subsidiaries, are listed below, along with their ages as of December 31, 2008, 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 12/31/08	Positions and Offices Held
Gary L. Rainwater	62	Chairman, Chief Executive Officer, President, and Director
Rainwater began his career with UE in 1979 as an engineer and has held various positions with UE and other Ameren subsidiaries during his employment. In 2004, Rainwater was elected to serve as chairman and chief executive officer of Ameren, UE, and Ameren Services in addition to his position as president. At that time, he was elected chairman of CILCORP and CILCO in addition to his position as chief executive officer and president of those companies, which he assumed in 2003. In 2004, upon Ameren’s acquisition of IP, Rainwater was also elected chairman, chief executive officer, and president of IP. He held the position of chairman of CIPS, CILCO and IP after relinquishing his position as president in October 2004. In 2007, Rainwater relinquished his positions as chairman, president, and chief executive officer of UE and Ameren Services and as chairman and chief executive officer of CIPS, CILCO and IP.

Warner L. Baxter	47	Executive Vice President and Chief Financial Officer, Chairman, Chief Executive Officer, President, and Chief Financial Officer (Ameren Services)
Baxter joined UE in 1995. He was elected senior vice president, finance, of Ameren, UE, CIPS, Ameren Services, and Genco in 2001 and of CILCORP and CILCO in 2003. Baxter was elected to the position of executive vice president and chief financial officer of Ameren, UE, CIPS, Genco, CILCORP, CILCO, and Ameren Services in 2003 and of IP in 2004. He was elected chairman, chief executive officer, president, and chief financial officer of Ameren Services effective in 2007.

Thomas R. Voss	61	Executive Vice President and Chief Operating Officer, Chairman, Chief Executive Officer, and President (UE)
Voss joined UE in 1969 as an engineer. He was elected senior vice president of UE, CIPS, and Ameren Services in 1999, of Genco in 2001, of CILCORP and CILCO in 2003, and of IP in 2004. In 2003, Voss was elected president of Genco; he relinquished his presidency of this company in 2004. He was elected to his present position at Ameren in 2005. In 2006, he was elected executive vice president of UE, CIPS, CILCORP, CILCO and IP. In 2007, Voss was elected chairman, chief executive officer, and president of UE. He relinquished his positions at CIPS, CILCORP, CILCO and IP in 2007.

Donna K. Martin	61	Senior Vice President and Chief Human Resources Officer
Martin joined Ameren Services in 2002 as vice president, human resources. In 2005, Martin was elected senior vice president and chief human resources officer of Ameren Services. She was elected to the same positions at Ameren in 2007.

Steven R. Sullivan	48	Senior Vice President, General Counsel, and Secretary
Sullivan joined Ameren, UE, CIPS, and Ameren Services in 1998 as vice president, general counsel, and secretary. He added those positions at Genco in 2000. In 2003, Sullivan was elected vice president, general counsel, and secretary of CILCORP and CILCO. He was elected to his present position at Ameren, UE, CIPS, Genco, CILCORP, CILCO, and Ameren Services in 2003, and at IP in 2004.

Jerre E. Birdsong	54	Vice President and Treasurer
Birdsong joined UE in 1977 and was elected treasurer of UE in 1993. He was elected treasurer of Ameren, CIPS, and Ameren Services in 1997, and Genco in 2000. In addition to being treasurer, in 2001 he was elected vice president at Ameren and at the subsidiaries listed above. Additionally, he was elected vice president and treasurer of CILCORP and CILCO in 2003, and of IP in 2004.

Martin J. Lyons	42	Senior Vice President and Chief Accounting Officer
Lyons joined Ameren, UE, CIPS, Genco, and Ameren Services in 2001 as controller. He was elected controller of CILCORP and CILCO in 2003. He was also elected vice president of Ameren, UE, CIPS, Genco, CILCORP, CILCO, and Ameren Services in 2003 and vice president and controller of IP in 2004. In 2007, his position at UE was changed to vice president and principal accounting officer. In 2008, Lyons was elected senior vice president and chief accounting officer of the Ameren Companies.

SUBSIDIARIES:


Name	Age at 12/31/08	Positions and Offices Held
Scott A. Cisel	55	Chairman, Chief Executive Officer, and President (CILCO, CIPS and IP)
Cisel joined CILCO in 1975. He was named senior vice president and leader of CILCO’s Sales and Marketing Business Unit in 2001. Cisel assumed the position of vice president and chief operating officer for CILCO in 2003, upon Ameren’s acquisition of that company. In 2004, Cisel was elected vice president of UE and president and chief operating officer of CIPS, CILCO and IP. In 2007, Cisel was elected chairman and chief executive officer of CIPS, CILCO and IP in addition to his position as president. He relinquished his position at UE in 2007.

Daniel F. Cole	55	Senior Vice President (CILCO, CIPS, CILCORP, IP and UE)
Cole joined UE in 1976 as an engineer. He was elected senior vice president of UE and Ameren Services in 1999, and of CIPS in 2001. He was elected president of Genco in 2001; he relinquished that position in 2003. He was elected senior vice president of CILCORP and CILCO in 2003, and of IP in 2004.

Adam C. Heflin	44	Senior Vice President and Chief Nuclear Officer (UE)
Heflin joined UE in 2005 as vice president of nuclear operations and was elected senior vice president and chief nuclear officer of UE in 2008. Prior to joining UE, Heflin served as Unit 2 plant manager at Arkansas Nuclear One, owned by Entergy Corporation. He joined Entergy Corporation’s nuclear operations in 1992.

Richard J. Mark	53	Senior Vice President (UE)
Mark joined Ameren Services in 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 2005, with responsibility for Missouri energy delivery. In 2007, Mark relinquished his position at Ameren Services.

Michael L. Moehn	39	Senior Vice President (Ameren Services)
Moehn joined Ameren Services as assistant controller in 2000. He was named director of Ameren Services’ corporate modeling and transaction support in 2001 and elected vice president of business services for Ameren Energy Resources Company in 2002. In 2004, Moehn was elected vice president of corporate planning for Ameren Services and relinquished his position at Ameren Energy Resources Company. In 2008, he was elected senior vice president of Ameren Services.

Michael G. Mueller	45	President (AFS)
Mueller joined UE in 1986 as an engineer. He was elected vice president of AFS in 2000 and president of AFS in 2004.

Charles D. Naslund	56	Chairman, Chief Executive Officer, and President (Resources Company), and President (Genco)
Naslund joined UE in 1974. He was elected vice president of power operations at UE in 1999, vice president of Ameren Services in 2000, and vice president of nuclear operations at UE in 2004. He relinquished his position at Ameren Services in 2001. Naslund was elected senior vice president and chief nuclear officer at UE in 2005. Effective in 2008, he was elected chairman, chief executive officer, and president of Resources Company and president of Genco. Naslund relinquished his position at UE in 2008.

Andrew M. Serri	47	President (Marketing Company)
Serri joined Marketing Company as vice president of sales and marketing in 2000. He was elected vice president of marketing and trading of Ameren Services in 2004, before being elected president of Marketing Company that same year. He relinquished his position at Ameren Services in 2007.

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

PART II

ITEM 5.

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

Ameren’s common stock is listed on the NYSE (ticker symbol: AEE). Ameren began trading on January 2, 1998, following the merger of UE and CIPSCO on December 31, 1997. On April 30, 2008, Ameren submitted to the NYSE a certificate of its chief executive officer certifying that he was not aware of any violation by Ameren of NYSE corporate governance listing standards.

Ameren common shareholders of record totaled 72,475 on January 30, 2009. The following table presents the price ranges, closing prices, and dividends paid per Ameren common share for each quarter during 2008 and 2007.

High

Low

Close

Dividends Paid

AEE 2008 Quarter Ended:

March 31

54.29

40.92

44.04

63 ¹ / 2

June 30

48.39

41.34

42.23

63 ¹ / 2

September 30

43.16

38.49

39.03

63 ¹ / 2

December 31

39.15

25.51

33.26

63 ¹ / 2

AEE 2007 Quarter Ended:

March 31

55.00

48.56

50.30

63 ¹ / 2

June 30

55.00

48.23

49.01

63 ¹ / 2

September 30

53.89

47.10

52.50

63 ¹ / 2

December 31

54.74

51.81

54.21

63 ¹ / 2

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

The following table sets forth the quarterly common stock dividend payments made by Ameren and its subsidiaries during 2008 and 2007:


(In millions)	2008 Quarter Ended								2007 Quarter Ended
Registrant	December 31		September 30		June 30		March 31			December 31		September 30		June 30		March 31
UE	$	71	$	88	$	28	$	77		$	21	$	119	$	47	$	80
CIPS		-		-		-		-			40		-		-		-
Genco		17		-		60		24			-		-		74		39
CILCORP		-		-		-		-			-		-		-		-
IP		15		15		15		15			61		-		-		-
Nonregistrants		32		30		30		17			10		13		11		12
Ameren	$	135	$	133	$	133	$	133		$	132	$	132	$	132	$	131

On February 13, 2009, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 38.5 cents per share. The common share dividend is payable March 31, 2009, to stockholders of record on March 11, 2009.

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.

None of the Ameren Companies purchased equity securities reportable under Item 703 of Regulation S-K during the period October 1 to December 31, 2008.

Performance Graph

The following graph shows Ameren’s cumulative total shareholder return during the five fiscal years ended December 31, 2008. The graph also shows the cumulative total returns of the S&P 500 Index and the Edison Electric Institute Index (EEI Index), which comprises most investor-owned electric utilities in the United States. The comparison assumes that $100 was invested on December 31, 2003, in Ameren common stock and in each of the indices shown, and it assumes that all of the dividends were reinvested.

LOGO


December 31,	2003		2004		2005		2006		2007		2008
Ameren	$	100.00	$	115.12	$	123.48	$	135.96	$	144.04	$	94.22
S&P 500 Index		100.00		110.88		116.32		134.69		142.09		89.51
EEI Index		100.00		122.84		142.56		172.15		200.66		148.69

Ameren management cautions that the stock price performance shown in the graph above should not be considered indicative of potential future stock price performance.

ITEM 6.

SELECTED FINANCIAL DATA.


For the years ended December 31, (In millions, except per share amounts)	2008		2007		2006		2005		2004
Ameren:
Operating revenues ⁽ ^a ⁾	$	7,839	$	7,562	$	6,895	$	6,780	$	5,135
Operating income ^(a ⁾		1,362		1,359		1,188		1,284		1,078
Net income ^(a)(b ⁾		605		618		547		606		530
Common stock dividends		534		527		522		511		479
Earnings per share – basic and diluted ⁽ ^a ⁾⁽ ^b ⁾		2.88		2.98		2.66		3.02		2.84
Common stock dividends per share		2.54		2.54		2.54		2.54		2.54
As of December 31:
Total assets	$	22,657	$	20,728	$	19,635	$	18,171	$	17,450
Long-term debt, excluding current maturities		6,554		5,689		5,285		5,354		5,021
Preferred stock subject to mandatory redemption		-		16		17		19		20
Total stockholders’ equity		6,963		6,752		6,583		6,364		5,800
UE:
Operating revenues	$	2,960	$	2,961	$	2,823	$	2,889	$	2,640
Operating income		514		590		620		640		673
Net income after preferred stock dividends		245		336		343		346		373
Dividends to parent		264		267		249		280		315
As of December 31:
Total assets	$	11,524	$	10,903	$	10,290	$	9,277	$	8,750
Long-term debt, excluding current maturities		3,673		3,208		2,934		2,698		2,059
Total stockholders’ equity		3,562		3,601		3,153		3,016		2,996


For the years ended December 31, (In millions, except per share amounts)	2008		2007		2006		2005		2004
CIPS:
Operating revenues	$	982	$	1,005	$	954	$	934	$	735
Operating income		42		49		69		85		58
Net income after preferred stock dividends		12		14		35		41		29
Dividends to parent		-		40		50		35		75
As of December 31:
Total assets	$	1,917	$	1,860	$	1,855	$	1,784	$	1,615
Long-term debt, excluding current maturities		421		456		471		410		430
Total stockholders’ equity		529		517		543		569		490
Genco:
Operating revenues	$	908	$	876	$	992	$	1,038	$	873
Operating income		330		258		131		257		265
Net income ^(b ⁾		175		125		49		97		107
Dividends to parent		101		113		113		88		66
As of December 31:
Total assets	$	2,244	$	1,968	$	1,850	$	1,811	$	1,955
Long-term debt, excluding current maturities		774		474		474		474		473
Subordinated intercompany notes (current and long-term)		87		126		163		197		283
Total stockholder’s equity		695		648		563		444		435
CILCORP:
Operating revenues	$	1,147	$	1,011	$	747	$	747	$	722
Operating income		120		134		64		61		61
Net income ⁽ ^b ⁾		42		47		19		3		10
Dividends to parent		-		-		50		30		18
As of December 31:
Total assets	$	2,865	$	2,459	$	2,250	$	2,243	$	2,156
Long-term debt, excluding current maturities		536		537		542		534		623
Preferred stock of subsidiary subject to mandatory redemption		-		16		17		19		20
Total stockholder’s equity		750		715		671		663		548
CILCO:
Operating revenues	$	1,147	$	1,011	$	747	$	742	$	688
Operating income		132		143		78		63		58
Net income after preferred stock dividends ⁽ ^b ⁾		68		74		45		24		30
Dividends to parent		-		-		65		20		10
As of December 31:
Total assets	$	2,294	$	1,862	$	1,650	$	1,557	$	1,381
Long-term debt, excluding current maturities		279		148		148		122		122
Preferred stock subject to mandatory redemption		-		16		17		19		20
Total stockholders’ equity		684		622		535		562		437
IP: ^(c)
Operating revenues	$	1,696	$	1,646	$	1,694	$	1,653	$	1,539
Operating income		103		109		141		202		216
Net income after preferred stock dividends ^(b ⁾		3		24		55		95		137
Dividends to parent		60		61		-		76		-
As of December 31:
Total assets	$	3,766	$	3,319	$	3,212	$	3,056	$	3,117
Long-term debt, excluding current maturities		1,150		1,014		772		704		713
Long-term debt to IP SPT, excluding current maturities		-		-		92		184		278
Total stockholders’ equity		1,251		1,308		1,346		1,287		1,280

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

(b)	For the year ended December 31, 2005, net income included income (loss) from cumulative effect of change in accounting principle of $(22) million ($(0.11) per share) for Ameren, $(16) million for Genco, $(2) million for CILCORP, $(2) million for CILCO, and $- million for IP.

(c)	Includes 2004 combined financial data under ownership by Ameren and IP’s former ultimate parent.

ITEM 7.

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

OVERVIEW

Ameren Executive Summary

Operations

In 2008 and early 2009, we were able to successfully execute on key aspects of our long-term strategic plan. Our strategic plan calls for generation excellence and improvement of customer service and satisfaction. UE’s Callaway nuclear plant completed its first-ever breaker-to-breaker run and completed a plant record 28-day refueling and maintenance outage in the fall of 2008. In addition, the equivalent availability for UE’s coal-fired generating units was a solid 88% as compared to 89% in 2007. Ameren’s Non-rate-regulated Generation business segment set new generation records, producing approximately 31 million total megawatthours, as equivalent availability for its coal-fired units was 85% compared to 81% in 2007.

Amidst the economic challenges facing us and our nation, we have remained focused on our customers and have made significant investments in our energy infrastructure to improve overall reliability and customer satisfaction. In Missouri, through UE’s Power On reliability program, we buried more than 100 miles of electric line, trimmed trees along more than 6,500 miles of overhead line, tested nearly 100,000 wood utility poles, and inspected more than 8,000 miles of electric line. In Illinois, we targeted the worst-performing circuits and aggressively trimmed trees in Illinois Regulated’s 40,000 square-mile territory and continued to automate its transmission system to elevate its reliability. We believe that high-quality customer service is essential to earning solid returns in our rate-regulated businesses.

In Missouri, UE received approval of an electric rate increase in January 2009 with new rates effective March 1, 2009. The authorized increase in annual electric revenues is approximately $162 million based on a 10.76% return on equity. The MoPSC rate order authorized a FAC, as well as a vegetation management and infrastructure inspection cost tracking mechanism. The FAC and tracking mechanisms improve UE’s ability to continue to invest in its infrastructure so that UE will be able to meet its customers’ expectations for safe and reliable service.

In Illinois, the ICC authorized in September 2008 new electric and gas rates for the Ameren Illinois Utilities effective October 1, 2008. These new rates provide approximately $161 million in additional annual revenue based on allowed returns on equity of nearly 10.7%. The ICC also approved an increase in the fixed non-volumetric monthly charge for natural gas residential and commercial customers such that the Ameren Illinois Utilities now recover 80% of delivery service costs through this charge versus the prior 53%. The remainder is recovered through volume-based charges. This will make our gas utility earnings less sensitive to volumetric swings.

Earnings

Ameren reported net income of $605 million, or $2.88 per share, for 2008 compared with net income of $618 million, or $2.98 per share, in 2007. The decline in earnings in 2008 versus 2007 was principally due to higher fuel and related transportation prices, increased spending on utility distribution system reliability, higher plant operations and maintenance costs, milder weather, and net unrealized mark-to-market losses on nonqualifying hedges, among other things.

Those items more than offset the positive items. The positive items included improved generating plant output and higher realized margins from Non-rate-regulated Generation operations, the absence of costs in 2008 that were incurred in January 2007 associated with electric outages caused by severe ice storms and the amount of these costs that UE will recover as a result of an accounting order issued by the MoPSC, the reduced impact in 2008 of the Illinois electric settlement agreement, the absence in 2008 of the March 2007 FERC order that resettled costs among MISO market participants retroactive to 2005 that was recorded in 2007 and subsequent recovery of a portion of these costs in 2008 through a MoPSC order, net increases in electric and natural gas rates, and a 2008 lump-sum settlement payment from a coal supplier for expected higher fuel costs in 2009 as a result of a premature mine closure and contract termination, among other things.

Liquidity

Cash flows from operations of $1.5 billion in 2008 at Ameren, along with other funds, were used to pay dividends to common shareholders of $534 million and to partially fund capital expenditures of $1.9 billion. The remaining capital expenditures were primarily funded with debt.

We have taken actions to build on our financial strength and enhance our financial flexibility in light of the current difficult economic and capital and credit market conditions. These actions included the February 2009 decision of Ameren’s board of directors to reduce its common dividend and accessing the capital markets to increase our available liquidity, as well as making significant reductions in our 2008 and projected 2009 spending plans while still meeting our reliability, environmental, and safety objectives.

Outlook

The global capital and credit markets experienced extreme volatility and disruption in 2008, and we expect those conditions to continue throughout 2009. We believe that the disruption in the capital and credit markets will further weaken global economic conditions. These weak economic conditions will likely result in volatility in the power and commodity markets, greater risk of defaults by our counterparties, weaker customer sales growth, particularly with respect to industrial sales, higher bad debt expense and possible impairment of goodwill and long-lived assets, among other things.

Over the next few years, we continue to expect to make significant investments in our electric and natural gas infrastructure to improve reliability of our distribution systems and to comply with environmental requirements. From 2009 through 2011, we expect our rate-regulated rate base to grow approximately 9% per year. Earnings growth in our rate-regulated businesses is expected to come from updating existing customer rates to reflect these investments and the current levels of costs UE and the Ameren Illinois Utilities are experiencing. We consider the 2008 and 2009 Illinois and Missouri rate orders to be constructive. However, the returns that UE and the Ameren Illinois Utilities expect to earn in 2009 are below levels allowed by the respective state utility commissions in their last rate orders. The new rates were based on historic test year data and 2009 costs are expected to be higher than the levels recovered in rates. This is especially true of financing costs in Illinois, where sharply higher debt financing costs, which were incurred after our rate cases were filed, are not being recovered in rates. UE and the Ameren Illinois Utilities will file more frequent rate cases requesting moderate rate increases, as well as continue to seek appropriate cost recovery and tracker mechanisms to mitigate regulatory lag.

In addition, we will continue to optimize Ameren’s Non-rate-regulated Generation’s assets, focusing on improving the output of these plants and related energy marketing. We believe Non-rate-regulated Generation’s plants will be well positioned for earnings growth in the future should energy prices improve.

We will incur significant costs in future years to comply with existing federal EPA and state regulations regarding SO ₂ , NOx, and mercury emissions from coal-fired power plants. Between 2009 and 2018, Ameren expects that certain Ameren Companies will be required to invest between $4.5 billion and $5.5 billion to retrofit their coal-fired power plants with pollution control equipment. Any pollution control investments will result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 50% of this investment is expected to be in our Missouri Regulated operations, and it is therefore expected to be recoverable from ratepayers.

Future initiatives regarding greenhouse gas emissions and global warming are subject to active consideration in the U.S. Congress. President Obama supports an economy-wide cap-and-trade greenhouse gas reduction program that would reduce emissions to 1990 levels by 2020 and to 80% below 1990 levels by 2050. President Obama has also indicated support for auctioning 100% of the emission allowances to be distributed under the legislation. Although we cannot predict the date of enactment or the requirements of any global warming legislation or regulations, it is likely that some form of federal greenhouse gas legislation or regulations will become law during President Obama’s administration. Potential impacts from proposed legislation could vary depending upon proposed CO ₂ emission limits, the timing of implementation of those limits, the method of allocating allowances, and provisions for cost containment measures.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs, which, in turn, could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force UE, Genco, CILCO (through AERG) and EEI and other similarly-situated electric power generators to close some coal-fired facilities and could lead to possible impairment of assets. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, CILCO’s (through AERG) and EEI’s results of operations, financial position, or liquidity.

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois, as discussed below. Dividends on Ameren’s common stock and the payment of other expenses by the Ameren and CILCORP holding companies 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.

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

Genco operates a non-rate-regulated electric generation business in Illinois and Missouri.

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

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

The financial statements of Ameren are prepared on a consolidated basis and therefore include the accounts of its majority-owned subsidiaries. All significant intercompany transactions have been eliminated. All tabular dollar amounts are expressed in millions, unless otherwise indicated.

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

RESULTS OF OPERATIONS

Earnings Summary

Our results of operations and financial position are affected by many factors. Weather, economic conditions, and the actions of key customers or competitors can significantly affect the demand for our services. Our results are also affected by seasonal fluctuations: winter heating and summer cooling demands. The vast majority of Ameren’s revenues are subject to state or federal regulation. This regulation has a material impact on the price we charge for our services. Non-rate-regulated Generation sales are also subject to market conditions for power. We principally use coal, nuclear fuel, natural gas, and oil for fuel in our operations. The prices for these commodities can fluctuate significantly due to the global economic and political environment, weather, supply and demand, and many other factors. We do have natural gas cost recovery mechanisms for our Illinois and Missouri gas delivery businesses and purchased power cost recovery mechanisms for our Illinois electric delivery businesses. As part of the electric rate order issued by the MoPSC on January 27, 2009, UE was granted permission to put in place a FAC, which was effective March 1, 2009. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, for a discussion of the January 27, 2009, MoPSC order in UE’s electric rate proceeding. Fluctuations in interest rates and conditions in the capital and credit markets affect our cost of borrowing and our pension and postretirement benefits costs. We employ various risk management strategies to reduce our exposure to commodity risk and other risks inherent in our business. The reliability of our power plants and transmission and distribution systems, the level of purchased power costs, operating and administrative costs, and capital investment are key factors that we seek to control to optimize our results of operations, financial position, and liquidity.

Ameren’s net income was $605 million ($2.88 per share) for 2008, $618 million ($2.98 per share) for 2007, and $547 million ($2.66 per share) for 2006.

Ameren’s net income decreased $13 million and earnings per share decreased 10 cents in 2008 compared with 2007. Net income increased in the Non-rate-regulated Generation segment by $71 million in 2008 compared to 2007, while net income in the Missouri Regulated and Illinois Regulated segments decreased by $47 million and $15 million, respectively. Other net income decreased $22 million in 2008 compared with 2007, primarily because of net unrealized mark-to-market losses on nonqualifying hedges mainly related to fuel-related transactions and reduced interest and dividend income.

Compared with 2007 earnings, 2008 earnings were negatively affected by:

higher fuel and related transportation prices, excluding net mark-to-market losses on fuel-related transactions (27 cents per share);

increased distribution system reliability expenditures (16 cents per share);

higher plant operations and maintenance expenses (16 cents per share);

unfavorable weather conditions (estimated at 16 cents per share);

net unrealized mark-to-market losses on nonqualifying hedges (11 cents per share);

higher financing costs (10 cents per share);

asset impairment charges recorded during 2008 to adjust the carrying value of CILCO’s (through AERG) Indian Trails and Sterling Avenue generation facilities to their estimated fair values as of December 31, 2008 (6 cents per share);

increased depreciation and amortization expense (6 cents per share);

the absence in 2008 of the reversal, recorded in 2007, of the Illinois Customer Elect electric rate increase phase-in plan accrual (5 cents per share);

higher labor and employee benefit costs (5 cents per share); and

higher bad debt expenses (3 cents per share).

Compared with 2007 earnings, 2008 earnings were favorably affected by:

higher realized electric margins in the Non-rate-regulated Generation segment;

the absence of costs in 2008 that were incurred in January 2007 associated with electric outages caused by severe ice storms and the amount of these costs that UE will recover as a result of an accounting order issued by the MoPSC, which was recorded as a regulatory asset in 2008 (16 cents per share);

the reduced impact in 2008 of the electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities electric customers under the Illinois electric settlement agreement (13 cents per share);

the absence in 2008 of a March 2007 FERC order that resettled costs among MISO market participants retroactive to 2005 that was recorded in 2007 and the subsequent recovery of a portion of these costs in 2008, through a MoPSC order (10 cents per share);

higher electric and natural gas delivery service rates in the Illinois Regulated segment pursuant to the ICC consolidated rate order for CIPS, CILCO, and IP issued in September 2008 (9 cents per share);

a settlement agreement with a coal mine owner reached in June 2008 that reimbursed Genco, in the form of a lump-sum payment, for increased costs for coal and transportation that it expects to incur in 2009 due to the premature closure of an Illinois mine at the end of 2007 (8 cents per share);

higher electric rates, lower depreciation expense and decreased income tax expense in the Missouri Regulated segment pursuant to the MoPSC electric rate order for UE issued in May 2007 (8 cents per share); and

the reduced impact of the Callaway nuclear plant refueling and maintenance outage in 2008, as

compared with the prior-year refueling and maintenance outage (4 cents per share).

The cents per share information presented above is based on average shares outstanding in 2007.

Ameren’s net income increased $71 million and earnings per share increased 32 cents in 2007 compared with 2006.

Compared with 2006 earnings, 2007 earnings were favorably affected by:

higher margins in the Non-rate-regulated Generation segment due to the replacement of below-market power sales contracts, which expired in 2006, with higher-priced contracts;

higher electric rates, lower depreciation expense, decreased income tax expense and $5 million in SO ₂ emission allowance sales in the Missouri Regulated segment pursuant to the MoPSC electric rate order for UE issued in May 2007 (21 cents per share);

decreased costs associated with outages caused by severe storms (17 cents per share);

the absence of costs in 2007 that were incurred in 2006 related to the reservoir breach at UE’s Taum Sauk plant (15 cents per share); and

favorable weather conditions (estimated at 14 cents per share).

Compared with 2006 earnings, 2007 earnings were negatively affected by:

the combined effect of the elimination of the Ameren Illinois Utilities’ bundled electric tariffs, implementation of new delivery service tariffs effective January 2, 2007, and the expiration of below-market power supply contracts;

higher fuel and related transportation prices (31 cents per share);

electric rate relief and customer assistance programs provided to certain Ameren Illinois Utilities’ electric customers under the Illinois electric settlement agreement (21 cents per share);

higher labor and employee benefit costs (18 cents per share);

higher financing costs (17 cents per share);

lower emission allowance sales (16 cents per share);

increases in distribution system reliability expenditures (15 cents per share);

reduced gains on the sale of noncore properties, including leveraged leases (15 cents per share);

increased depreciation and amortization expense (13 cents per share);

a planned refueling and maintenance outage at UE’s Callaway nuclear plant net of an unplanned outage at Callaway in 2006 (9 cents per share); and

higher bad debt expenses (8 cents per share).

The cents per share information presented above is based on average shares outstanding in 2006.

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, 2008, 2007 and 2006:


	2008		2007		2006
Net income:
UE ^(a)	$	245	$	336	$	343
CIPS		12		14		35
Genco		175		125		49
CILCORP		42		47		19
IP		3		24		55
Other ⁽ ^b ⁾		128		72		46
Ameren net income	$	605	$	618	$	547

(a)	Includes earnings from a non-rate-regulated 40% interest in EEI through February 29, 2008.

(b)	Includes earnings from EEI, other non-rate-regulated operations, as well as corporate general and administrative expenses, and intercompany eliminations. Includes a 40% interest in EEI prior to February 29, 2008 and an 80% interest in EEI since that date.

Below is a table of income statement components by segment for the years ended December 31, 2008, 2007 and 2006:


2008	Missouri Regulated			Illinois Regulated			Non-rate- regulated Generation			Other / Intersegment Eliminations			Total
Electric margin	$	1,924		$	817		$	1,188		$	(47	)	$	3,882
Gas margin		78			342			-			(5	)		415
Other revenues		3			-			-			(3	)		-
Other operations and maintenance		(922	)		(627	)		(356	)		48			(1,857	)
Depreciation and amortization		(329	)		(219	)		(109	)		(28	)		(685	)
Taxes other than income taxes		(240	)		(126	)		(26	)		(1	)		(393	)
Other income and expenses		53			11			-			(15	)		49
Interest expense		(193	)		(144	)		(99	)		(4	)		(440	)
Income taxes (benefit)		(134	)		(16	)		(217	)		40			(327	)
Minority interest and preferred dividends		(6	)		(6	)		(29	)		2			(39	)
Net Income (loss)	$	234		$	32		$	352		$	(13	)	$	605
2007
Electric margin	$	1,984		$	759		$	1,037		$	(51	)	$	3,729
Gas margin		70			317			-			(8	)		379
Other revenues		2			3			-			(5	)		-
Other operations and maintenance		(900	)		(550	)		(313	)		76			(1,687	)
Depreciation and amortization		(333	)		(217	)		(105	)		(26	)		(681	)
Taxes other than income taxes		(234	)		(121	)		(25	)		(1	)		(381	)
Other income and expenses		35			20			3			(8	)		50
Interest expense		(194	)		(132	)		(107	)		10			(423	)
Income taxes (benefit)		(143	)		(25	)		(182	)		20			(330	)
Minority interest and preferred dividends		(6	)		(7	)		(27	)		2			(38	)
Net Income	$	281		$	47		$	281		$	9		$	618
2006
Electric margin	$	1,898		$	824		$	756		$	(46	)	$	3,432
Gas margin		60			307			-			(3	)		364
Other revenues		2			2			1			(5	)		-
Other operations and maintenance		(800	)		(535	)		(283	)		62			(1,556	)
Depreciation and amortization		(335	)		(192	)		(106	)		(28	)		(661	)
Taxes other than income taxes		(230	)		(137	)		(24	)		-			(391	)
Other income and expenses		33			13			2			(17	)		31
Interest expense		(171	)		(95	)		(103	)		19			(350	)
Income taxes (benefit)		(184	)		(65	)		(78	)		43			(284	)
Minority interest and preferred dividends		(6	)		(7	)		(27	)		2			(38	)
Net Income	$	267		$	115		$	138		$	27		$	547

Margins

The following table presents the favorable (unfavorable) variations in the registrants’ electric and gas margins from the previous year. Electric margins are defined as electric revenues less fuel and purchased power costs. Gas margins are defined as gas revenues less gas purchased for resale. The table covers the years ended December 31, 2008, 2007, and 2006. We consider electric, interchange and gas margins useful measures to analyze the change in profitability of our electric and gas operations between periods. We have included the analysis below as a complement to the financial information we provide in accordance with GAAP. However, these margins may not be a presentation defined under GAAP, and they may not be comparable to other companies’ presentations or more useful than the GAAP information we provide elsewhere in this report.


2008 versus 2007	Ameren ^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Electric revenue change:
Effect of weather (estimate)	$	(59	)	$	(36	)	$	(6	)	$	-		$	(4	)	$	(4	)	$	(13	)
Electric rate increases and market price changes		149			16			5			45			18			18			22
Interchange revenues, excluding estimated weather impact of $53 million		(42	)		(47	)		-			-			-			-			-
Illinois settlement agreement, net of reimbursement		35			-			6			13			9			9			7
FERC-ordered MISO resettlements		(17	)		-			-			(12	)		(4	)		(4	)		-
Net mark-to-market gains on energy contracts		81			8			-			-			-			-			-
Illinois pass-through power costs		(72	)		-			(49	)		-			22			22			(45	)
Generation output and other		9			29			(8	)		(14	)		49			49			(4	)
Total electric revenue change	$	84		$	(30	)	$	(52	)	$	32		$	90		$	90		$	(33	)
Fuel and purchased power change:
Fuel:
Generation and other	$	25		$	31		$	-		$	26		$	(32	)	$	(32	)	$	-
Emission allowance costs		8			-			-			5			1			-			-
Net mark-to-market losses on fuel contracts		(75	)		(39	)		-			(18	)		(3	)		(3	)		-
Price		(93	)		(56	)		-			(13	)		(15	)		(15	)		-
Coal contract settlement for 2009		27			-			-			27			-			-			-
Purchased power		58			9			9			23			8			7			3
Illinois pass-through power costs		72			-			49			-			(22	)		(22	)		45
FERC-ordered MISO resettlements		47			23			8			-			4			4			12
Total fuel and purchased power change	$	69		$	(32	)	$	66		$	50		$	(59	)	$	(61	)	$	60
Net change in electric margins	$	153		$	(62	)	$	14		$	82		$	31		$	29		$	27
Net change in gas margins	$	36		$	8		$	7		$	-		$	(1	)	$	(1	)	$	18

2007 versus 2006	Ameren ^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Electric revenue change:
Effect of weather (estimate)	$	73		$	31		$	16		$	-		$	9		$	9		$	17
UE electric rate increase		29			29			-			-			-			-			-
Storm-related outages (estimate)		10			9			3			(3	)		-			-			1
JDA terminated December 31, 2006		-			(196	)		-			(97	)		-			-			-
Elimination of CILCO/AERG power supply agreement		108			-			-			-			108			108			-
Interchange revenues, excluding estimated weather impact of ($47) million		252			252			-			-			-			-			-
Illinois electric settlement agreement, net of reimbursement		(73	)		-			(11	)		(30	)		(20	)		(20	)		(14	)
FERC-ordered MISO resettlement – March 2007		17			-			-			12			4			4			-
Mark-to-market losses on energy contracts		(21	)		(13	)		-			-			-			-			-
Illinois rate redesign, generation repricing, growth and other (estimate)		288			11			36			2			167			167			(49	)
Total electric revenue change	$	683		$	123		$	44		$	(116	)	$	268		$	268		$	(45	)


2007 versus 2006	Ameren ^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
Fuel and purchased power change:
Fuel:
Generation and other	$	(35	)	$	(10	)	$	-		$	(50	)	$	15		$	14		$	-
Emission allowances sales (costs)		(38	)		(29	)		-			-			14			11			-
Mark-to-market gains (losses) on fuel contracts		23			9			-			6			1			1			-
Price		(98	)		(84	)		-			(5	)		(5	)		(5	)		-
JDA terminated December 31, 2006		-			97			-			196			-			-			-
Purchased power		(82	)		(5	)		(48	)		103			(113	)		(112	)		35
Entergy Arkansas, Inc. power purchase agreement		(12	)		(12	)		-			-			-			-			-
Elimination of CILCO/AERG power supply agreement		(108	)		-			-			-			(108	)		(108	)		-
FERC-ordered MISO resettlement – March 2007		(35	)		(11	)		(8	)		-			(4	)		(4	)		(12	)
Storm-related energy costs (estimate)		(1	)		(2	)		-			1			-			-			1
Total fuel and purchased power change	$	(386	)	$	(47	)	$	(56	)	$	251		$	(200	)	$	(203	)	$	24
Net change in electric margins	$	297		$	76		$	(12	)	$	135		$	68		$	65		$	(21	)
Net change in gas margins	$	15		$	10		$	2		$	-		$	5		$	5		$	1

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

2008 versus 2007

Ameren

Ameren’s electric margin increased by $153 million, or 4%, in 2008 compared with 2007. The following items had a favorable impact on Ameren’s electric margin:

Net mark-to-market gains on energy transactions of $81 million, primarily related to nonqualifying hedges of changes in market prices for electricity.

Improved Non-rate-regulated Generation plant availability due to the lack of an extended plant outage in 2008. Non-rate-regulated Generation’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 76% and 85%, respectively, in 2008 compared with 74% and 81%, respectively, in 2007.

The effect of rate increases. The Ameren Illinois Utilities’ net electric rate increase, effective October 1, 2008, increased electric margin by $27 million. UE’s electric rate increase, effective June 4, 2007, increased electric margin by $16 million.

The reduced impact of the Illinois electric settlement agreement increased electric margin by $35 million.

The absence in 2008 of a March 2007 FERC order that resettled costs among MISO participants retroactive to 2005 that was recorded in 2007 and the subsequent recovery of a portion of these costs in 2008 through a MoPSC order. The net benefit to electric margin in 2008 of these items was $30 million.

A settlement agreement with a coal mine owner reached in June 2008, which reimbursed Genco, in the form of a lump-sum payment, for increased costs for coal and transportation that it expects to incur in 2009 due to the premature closure of an Illinois mine at the end of 2007, increased electric margin by $27 million.

Other MISO net purchased power costs decreased by $23 million.

Lower Non-rate-regulated Generation emission allowance costs of $8 million.

Increased Non-rate-regulated Generation capacity sales of $6 million.

The following items had an unfavorable impact on Ameren’s electric margin for 2008 as compared with 2007:

Net mark-to-market losses on fuel-related transactions of $75 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

Unfavorable weather conditions, as evidenced by a 30% reduction in cooling degree-days, which decreased electric margin by an estimated $65 million. Compared to normal weather, cooling degree-days in 2008 were 5% lower.

Fuel prices increased by 6%.

Lower interchange margin due to reduced UE plant availability, partially offset by an 8% increase in realized prices and a 10% increase in hydroelectric generation. Nuclear plant availability was unfavorably affected by unplanned plant outages, which offset the shorter planned refueling and maintenance outage. UE’s coal-fired generating plants’ average capacity and equivalent availability factors were approximately 78% and 88%, respectively, in 2008 compared with 80% and 89%, respectively, in 2007.

Ameren’s gas margin increased by $36 million, or 9%, in 2008 compared with 2007. The following items had a favorable impact on Ameren’s gas margin:

Favorable weather conditions, as evidenced by a 13% increase in heating degree-days, which increased gas margin by an estimated $12 million. Compared to normal weather, heating degree-days in 2008 were 7% higher.

The effect of rate increases. The Ameren Illinois Utilities’ net gas rate increase, effective October 1, 2008, increased gas margin by $4 million. The UE gas rate increase, effective April 2007, increased gas margin by $3 million.

A September 2008 ICC rate order that concluded that a portion of previously expensed nonrecoverable purchased gas costs should be capitalized, which increased gas margin by $9 million.

A 2% increase in weather normalized sales volumes and favorable customer sales mix, which increased gas margin by $5 million.

Increased transportation revenues of $4 million.

Missouri Regulated

UE’s electric margin decreased $62 million, or 3%, in 2008 compared with 2007. The following items had an unfavorable impact on UE’s electric margin:

Unfavorable weather conditions, as evidenced by a 29% reduction in cooling degree-days, which decreased electric margin by an estimated $42 million.

Net mark-to-market losses on fuel-related transactions of $39 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

Fuel prices increased by 5%.

Lower replacement power insurance recoveries of $12 million due to the lack of an extended plant outage and an increase in insurance recovery deductible limits.

Lower interchange margin due to reduced plant availability, partially offset by an 8% increase in realized prices and a 10% increase in hydroelectric generation. Nuclear plant availability was unfavorably affected by unplanned plant outages, which offset the shorter planned refueling and maintenance outage. UE’s coal-fired generating plants’ average capacity and equivalent availability factors were approximately 78% and 88%, respectively, in 2008, compared with 80% and 89%, respectively in 2007.

The following items that had a favorable impact on electric margin in 2008 as compared with 2007:

The absence in 2008 of a March 2007 FERC order that resettled costs among MISO participants retroactive to 2005 that was recorded in 2007 and the subsequent recovery of a portion of these costs in 2008 through a MoPSC order. The net benefit to UE’s electric margin in 2008 of these items was $23 million.

Other MISO net purchased power costs decreased by $15 million.

UE’s electric rate increase, effective June 4, 2007, which increased electric margin by $16 million.

Net mark-to-market gains of $8 million, primarily related to nonqualifying hedges of changes in market prices for electricity.

UE’s gas margin increased by $8 million, or 11%, in 2008 compared with 2007. The following items had a favorable impact on gas margin:

The UE gas rate increase, effective April 2007, which increased gas margin by $3 million.

Favorable customer sales mix, which increased gas margin by $3 million.

Favorable weather conditions, as evidenced by a 12% increase in heating degree-days, which increased gas margin by an estimated $2 million.

Illinois Regulated

Illinois Regulated’s electric margin increased by $58 million, or 8%, and gas margin increased by $25 million, or 8%, in 2008 compared with 2007. The Ameren Illinois Utilities have a cost recovery mechanism for power purchased on behalf of their customers. These pass-through power costs do not impact margin; however, the electric revenues and offsetting purchased power costs fluctuate due primarily to customer switching and usage. See below for explanations of electric and gas margin variances for the Illinois Regulated segment.

CIPS

CIPS’ electric margin increased by $14 million, or 6%, in 2008 compared with 2007. The following items had a favorable impact on electric margin:

Reduced MISO purchased power costs of $8 million due to the absence of the March 2007 FERC order.

Other MISO net purchased power costs decreased by $5 million.

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $6 million.

The CIPS electric rate increase, effective October 1, 2008, increased electric margin by $5 million.

These favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 30% reduction in cooling degree-days, which decreased electric margin by an estimated $6 million.

CIPS’ gas margin increased by $7 million, or 10%, in 2008 compared with 2007. The following items had a favorable impact on gas margin:

Favorable customer sales mix, which increased gas margin by $3 million.

Favorable weather conditions, as evidenced by a 12% increase in heating degree-days, which increased gas margin by an estimated $2 million.

The CIPS gas rate increase, effective in October 2008, which increased gas margin by $1 million.

A September 2008 ICC rate order, that concluded that a portion of previously expensed nonrecoverable purchased gas costs should be capitalized, which increased gas margin by $1 million.

CILCO (Illinois Regulated)

The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for 2008 compared with 2007:


	2008 versus 2007
CILCO (Illinois Regulated)	$	17
CILCO (AERG)		12
Total change in electric margin	$	29

CILCO’s (Illinois Regulated) electric margin increased by $17 million, or 14%, in 2008 compared with 2007. The following items had a favorable impact on electric margin:

Increased delivery and generation service margins of $14 million due to increased sales volume and favorable customer sales mix, and the reduced impact of monthly MISO settlements that occurred in the prior year.

Reduced MISO purchased power costs of $4 million due to the absence of the March 2007 FERC order.

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $3 million.

These favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 28% reduction in cooling degree-days, which decreased electric margin by an estimated $4 million.

See Non-rate-regulated Generation below for an explanation of CILCO’s (AERG) electric margin in 2008 compared with 2007.

CILCO’s (Illinois Regulated) gas margin was comparable in 2008 and 2007. Favorable weather conditions, as evidenced by an 11% increase in heating degree-days, and improved customer sales mix, increased gas margins by an estimated $4 million. These favorable variances were offset by CILCO’s gas rate decrease, effective in October 2008.

IP’s electric margin increased by $27 million, or 7%, in 2008 compared with 2007. The following items had a favorable impact on electric margin:

The IP electric rate increase, effective October 1, 2008, which increased electric margin by $22 million.

Reduced MISO purchased power costs of $12 million due to the absence of the March 2007 FERC order.

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $7 million.

These favorable variances were partially offset by unfavorable weather conditions, as evidenced by a 34% reduction in cooling degree-days, which decreased electric margin by an estimated $13 million.

IP’s gas margin increased by $18 million, or 12%, in 2008 compared with 2007. The following items had a favorable impact on gas margin:

The IP gas rate increase, effective in October 2008, which increased gas margin by $8 million.

A September 2008 ICC rate order, that concluded that a portion of previously expensed nonrecoverable purchased gas costs should be capitalized, which increased gas margin by $7 million.

Favorable weather conditions, as evidenced by a 15% increase in heating degree-days, which increased gas margin by an estimated $6 million.

These favorable variances were partially offset by a 4% decrease in normalized sales volumes, which decreased gas margin $3 million.

Non-rate-regulated Generation

Non-rate-regulated Generation’s electric margin increased by $151 million, or 15%, in 2008 compared with 2007. Non-rate-regulated Generation’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 76% and 85%, respectively, in 2008 compared with 74% and 81%, respectively, in 2007. See below for explanations of electric margin variances for the Non-rate regulated Generation segment.

Genco

Genco’s electric margin increased by $82 million, or 16%, in 2008 compared with 2007. The following items had a favorable impact on electric margin:

Increased revenues allocated to Genco under its power supply agreement (Genco PSA) with Marketing Company. Revenues from the Genco PSA, which increased by 7% due primarily to the repricing of wholesale and retail electric power supply agreements, and an increase in reimbursable expenses in accordance with the Genco PSA.

Reduced purchased power costs of $17 million due to the absence of MISO resettlement costs experienced in early 2007.

The reduced impact of the Illinois electric settlement agreement, which increased electric margin by $13 million.

Gains on the sales of excess oil and off-system natural gas, which increased electric margin by $12 million.

Higher replacement power insurance recoveries of $9 million due to extended plant outages in 2008.

Lower emission allowance costs of $5 million due primarily to an increase in low-sulfur coal consumption in 2008.

The following items had an unfavorable impact on electric margin in 2008 compared with 2007:

Fuel prices increased by 2%.

Net mark-to-market losses on fuel-related transactions of $18 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

Reduced MISO-related revenues of $12 million due to the absence of the March 2007 FERC order.

Decreased power plant utilization due to system congestion. Genco’s baseload coal-fired generating plants’ equivalent availability factors were comparable year over year. However, the average capacity factor was approximately 73% in 2008 compared with 75% in 2007.

Decreased revenues of $9 million due to the termination of an operating lease in February 2008 under which Genco leased certain CTs at a Joppa, Illinois site to its former parent, Development Company. See Note 14 – Related Parties to our financial statements under Part II, Item 8, of this report, for additional information.

CILCO (AERG)

AERG’s electric margin increased by $12 million, or 7%, in 2008 compared with 2007. The following items had a favorable impact on electric margin:

Increased revenue allocated to AERG under its power supply agreement (AERG PSA) with Marketing Company. Revenues from the AERG PSA increased 24% due primarily to stronger generation performance as a result of the lack of an extended plant outage in 2008, the repricing of wholesale and retail electric power supply agreements, and an increase in reimbursable expenses in accordance with the AERG PSA. AERG’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 70% and 77%, respectively, in 2008 compared with 55% and 61%, respectively, in 2007.

The reduced impact of the Illinois electric settlement agreement increased electric margin by $6 million.

The following items had an unfavorable impact on electric margin in 2008 compared with 2007:

Fuel prices increased by 30%, primarily due to a greater percentage of higher-cost Illinois coal burned in 2008 and an increased amount of oil consumed during plant start-ups.

Reduced MISO-related revenues of $4 million due to the absence of the March 2007 FERC order.

Net mark-to-market losses on fuel-related transactions of $3 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

EEI

EEI’s electric margin increased by $10 million, or 4%, in 2008 compared with 2007, primarily because of an 8% increase in the average sales price for wholesale power.

The following items had an unfavorable impact on electric margin:

Fuel prices increased by 9%.

Net mark-to-market losses on fuel-related transactions of $8 million, primarily related to financial instruments that were acquired to mitigate the risk of rising diesel fuel price adjustments embedded in coal transportation contracts for the period 2008 through 2012.

Marketing Company

Market price fluctuations during 2008 resulted in nonaffiliated mark-to-market gains on energy transactions of $73 million, primarily related to nonqualifying hedges of changes in market prices for electricity.

2007 versus 2006

Ameren

Ameren’s electric margin increased by $297 million, or 9%, in 2007 compared with 2006. The following items had a favorable impact on Ameren’s electric margin:

More power sold by Non-rate-regulated Generation at market-based prices in 2007. These 2007 sales compared favorably with 2006 sales at below-market prices, pursuant to cost-based power supply agreements that expired on December 31, 2006.

Favorable weather conditions, as evidenced by a 19% increase in cooling degree-days, which increased electric margin by an estimated $35 million. Compared to normal weather, cooling degree-days in 2007 were 37% higher.

The UE electric rate increase, effective June 4, 2007, which increased electric margin by $29 million.

An increase in margin on interchange sales, primarily because of the termination of the JDA on December 31, 2006. This termination of the JDA provided UE with the ability to sell its excess power, which was originally obligated to Genco under the JDA at cost, in the spot market at higher prices. This increase was reduced by higher purchased power costs of $12 million associated with an agreement with Entergy Arkansas, Inc. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report, for more information on the UE power purchase agreement with Entergy Arkansas, Inc.

A 67% increase in hydroelectric generation because of improved water levels, which allowed additional generation to be used for interchange sales and reduced use of higher-priced energy sources, thereby increasing Ameren’s electric margin by $27 million.

Increased Non-rate-regulated Generation capacity sales of $11 million.

Reduced severe storm-related outages in 2007 compared with 2006, which negatively affected electric sales and resulted in a net reduction in overall electric margin of $9 million in 2006.

Insurance recoveries of $8 million related to power purchased to replace Taum Sauk generation. See Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, for additional information.

The following items had an unfavorable impact on Ameren’s electric margin in 2007 as compared with 2006:

The combined effect on the Ameren Illinois Utilities of the elimination of bundled tariffs, implementation of new delivery service tariffs effective January 2, 2007, and the expiration of below-market power supply contracts.

A 14% increase in fuel prices.

Rate relief and customer assistance programs under the Illinois electric settlement agreement, which reduced electric margin by $73 million.

The loss of wholesale margins at Genco from power acquired through the JDA, which terminated in 2006.

Decreased emission allowance sales of $53 million, offset by lower emission allowance costs of $15 million.

Net purchased power costs that were $18 million higher in 2007 because of a March 2007 FERC order that resettled costs among market participants retroactive to 2005.

Reduced plant availability. Ameren’s baseload nuclear and coal-fired generating plants’ average capacity and equivalent availability factors were approximately 78% and 86%, respectively, in 2007 compared with 80% and 88%, respectively, in 2006.

Ameren’s gas margin increased by $15 million, or 4%, in 2007. The following items had a favorable impact on Ameren’s gas margin:

Favorable weather conditions, as evidenced by an 8% increase in heating degree-days, which increased gas margin by an estimated $10 million. Compared to normal weather, heating degree-days in 2007 were 10% lower.

The UE gas rate increase that went into effect in April 2007, which increased gas margin by $4 million.

Missouri Regulated

UE’s electric margin increased $76 million, or 4%, in 2007 compared with 2006. The following items had a favorable impact on UE’s electric margin:

An increase in margin on interchange sales, primarily because of the termination of the JDA on December 31, 2006. The termination of the JDA allowed UE to sell its excess power, which was originally obligated to Genco under the JDA at cost, in the spot market at higher prices. This increase was reduced by higher purchased

power costs of $12 million associated with an agreement with Entergy Arkansas, Inc.

The electric rate increase that went into effect June 4, 2007, which increased electric margin by $29 million.

A 67% increase in hydroelectric generation because of improved water levels. This allowed additional generation to be used for interchange sales and reduced UE’s use of higher priced energy sources, thereby increasing UE’s electric margin by $27 million.

Favorable weather conditions, as evidenced by a 19% increase in cooling degree-days, which increased electric margin by an estimated $22 million.

Replacement power insurance recoveries of $20 million, including $8 million associated with Taum Sauk. See Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report, for additional information.

Increased transmission service revenues of $18 million due to the ancillary service agreement with CIPS, CILCO, and IP. See Note 14 – Related Party Transactions to our financial statements under Part II, Item 8, of this report, for additional information.

Decreased fuel costs due to the lack of $4 million in fees levied by FERC in 2006 upon completion of its cost study for generation benefits provided to UE’s Osage hydroelectric plant, and the May 2007 MoPSC rate order, which directed UE to transfer $4 million of the total fees to an asset account, which is being amortized over 25 years.

Reduced severe storm-related outages in 2007 compared with 2006, which negatively affected electric sales that year and resulted in a net reduction in overall electric margin of $7 million in 2006.

The following items had an unfavorable impact on electric margin in 2007 as compared with 2006:

Fuel prices increased by 21%.

A $29 million reduction in emission allowance revenues.

MISO purchased power costs that were $11 million higher due to the March 2007 FERC order.

Other MISO purchased power costs that were $20 million higher.

Reduced power plant availability because of planned maintenance activities. UE’s baseload nuclear and coal-fired generating plants’ average capacity and equivalent availability factors were approximately 81% and 89%, respectively, in 2007 compared with 84% and 90%, respectively, in 2006.

UE’s gas margin increased by $10 million, or 17%, in 2007 compared with 2006. The following items had a favorable impact on gas margin:

The UE gas rate increase effective in April 2007, which increased gas margin by $4 million.

Unrecoverable purchased gas costs totaling $4 million in 2006 that did not recur in 2007.

Favorable weather conditions, as evidenced by an 8% increase in heating degree-days, which increased gas margin by an estimated $2 million.

Illinois Regulated

Illinois Regulated’s electric margin decreased by $65 million, or 8%, and gas margin increased by $10 million, or 3%, in 2007 compared with 2006. See below for explanations of electric and gas margin variances for the Illinois Regulated segment.

CIPS

CIPS’ electric margin decreased by $12 million, or 5%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:

The combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs on January 2, 2007, and the expiration of below-market power supply contracts.

The Illinois electric settlement agreement, which reduced electric margin by $11 million.

MISO purchased power costs that increased by $8 million because of the March 2007 FERC order.

The following items had a favorable impact on electric margin in 2007 as compared with 2006:

Other MISO purchased power costs, excluding the effect of the March 2007 FERC order, that were $19 million lower, partly because of customers switching to third-party suppliers and the termination of the JDA agreement at the end of 2006.

Reduced severe storm-related outages in 2007 compared to those that occurred in 2006, which negatively affected electric sales and resulted in a net reduction in overall electric margin of $3 million in 2006.

Favorable weather conditions, as evidenced by a 20% increase in cooling degree-days, which increased electric margin by an estimated $6 million.

CIPS’ gas margin was comparable in 2007 and 2006.

CILCO (Illinois Regulated)

The following table provides a reconciliation of CILCO’s change in electric margin by segment to CILCO’s total change in electric margin for 2007 compared with 2006:


	2007 versus 2006
CILCO (Illinois Regulated)	$	(32	)
CILCO (AERG)		97
Total change in electric margin	$	65

CILCO’s (Illinois Regulated) electric margin decreased by $32 million, or 20%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:

The combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs on January 2, 2007, and the expiration of below-market power supply contracts.

The Illinois electric settlement agreement, which reduced electric margin by $7 million.

MISO purchased power costs that increased by $4 million, because of the March 2007 FERC order.

The following items had a favorable impact on electric margin in 2007 compared with 2006:

Other MISO purchased power costs, that were $4 million lower, partly because of customers switching to third-party suppliers.

Favorable weather conditions, as evidenced by an 18% increase in cooling degree-days, which increased electric margin by an estimated $2 million.

See Non-rate-regulated Generation below for an explanation of CILCO’s (AERG) electric margin in 2007 compared with 2006.

CILCO’s (Illinois Regulated) gas margin increased by $7 million, or 8%, in 2007 compared with 2006, primarily because of favorable weather conditions, as evidenced by a 7% increase in heating degree-days, increased industrial sales, and higher transportation volumes.

IP’s electric margin decreased by $21 million, or 5%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:

The combined effect of the elimination of bundled tariffs, implementation of new delivery service tariffs on January 2, 2007, and the expiration of below-market power supply contracts.

The Illinois electric settlement agreement, which reduced electric margin by $14 million.

MISO purchased power costs that increased by $12 million, because of the March 2007 FERC order.

The following items had a favorable impact on electric margin in 2007 compared with 2006:

Other MISO purchased power costs, that were $13 million lower, partly because of customers switching to third-party suppliers.

Favorable weather conditions, as evidenced by a 21% increase in cooling degree-days, which increased electric margin by an estimated $5 million.

Reduced severe storm-related outages in 2007 compared with those that occurred in 2006, which negatively affected electric sales and resulted in an estimated net reduction in overall electric margin of $2 million in 2006.

IP’s gas margin was comparable in 2007 and 2006.

Non-rate-regulated Generation

Non-rate-regulated Generation’s electric margin increased by $281 million, or 37%, in 2007 compared with 2006. Non-rate-regulated Generation’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 74% and 81%, respectively, in 2007 compared with 74% and 84%, respectively, in 2006. See below for explanations of electric margin variances for the Non-rate-regulated Generation segment.

Genco

Genco’s electric margin increased by $135 million, or 36%, in 2007 compared with 2006. The following items had a favorable impact on electric margin:

Selling power at market-based prices in 2007, compared with selling power at below-market prices in 2006, pursuant to a cost-based power supply agreement that expired on December 31, 2006.

Reduced purchased power costs due to the termination of the JDA.

Increased power plant availability, due to fewer planned outages in 2007, that reduced purchased power costs. Genco’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 75% and 86%, respectively, in 2007, compared with 66% and 82%, respectively, in 2006.

MISO-related revenues that were $12 million higher as a result of the March 2007 FERC order.

Other MISO purchased power costs that were $16 million lower.

A reduction of mark-to-market losses on fuel contracts of $6 million.

The following items had an unfavorable impact on electric margin in 2007 compared with 2006:

The loss of wholesale margins on sales of power acquired through the JDA, which terminated in 2006.

Costs of $30 million pursuant to the Illinois electric settlement agreement.

Fuel prices increased by 4%.

CILCO (AERG)

AERG’s electric margin increased by $97 million, or 87%, in 2007 compared with 2006. The following items had a favorable impact on electric margin:

Increased revenues due to selling power at market-based prices in 2007 compared with below-market prices in 2006, pursuant to a cost-based power supply agreement that expired on December 31, 2006.

Lower emission allowance costs of $11 million due to an increase in low sulfur coal consumption in 2007.

MISO-related revenues that were $4 million higher as a result of the March 2007 FERC order.

Other MISO purchased power costs that were $7 million lower.

Replacement power insurance recoveries of $7 million due to an extended plant outage.

The following items had an unfavorable impact on electric margin in 2007 compared with 2006:

Costs of $13 million pursuant to the Illinois electric settlement agreement.

Reduced plant availability because of an extended plant outage. AERG’s baseload coal-fired generating plants’ average capacity and equivalent availability factors were approximately 55% and 61%, respectively, in 2007, compared with 69% and 81%, respectively, in 2006.

Fuel prices increased by 5%.

EEI

EEI’s electric margin decreased by $8 million, or 3%, in 2007 compared with 2006. The following items had an unfavorable impact on electric margin:

The lack of emissions allowance sales in 2007, which increased 2006 electric margin by $30 million.

Fuel prices increased by 5%.

Reduced plant availability related to increased unit outages. EEI’s baseload coal-fired generating plant’s average capacity and equivalent availability factors were each approximately 92% in 2007, compared with 95% in 2006.

The decrease in margin was offset by a 12% increase in market prices at EEI in 2007.

Other Operations and Maintenance Expenses

2008 versus 2007

Ameren

Ameren’s other operations and maintenance expenses increased $170 million in 2008 compared with 2007, primarily because of higher distribution system reliability expenditures of $30 million, increased plant maintenance expenditures at coal-fired plants of $43 million due to outages, higher labor costs of $52 million, increased information technology costs of $10 million, and unrealized net mark-to-market adjustments of $22 million resulting from the lower market value of investments used to support Ameren’s deferred compensation plans. Bad debt expense also increased $10 million, primarily because of the continued transition to higher market-based rates at the Ameren Illinois Utilities. Additionally, in the first quarter of 2007, a $15 million accrual established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan was reversed because the plan was terminated, with no similar item in 2008.

In addition, other operations and maintenance expenses increased in 2008 by $14 million because of asset impairment charges recorded during the fourth quarter of 2008 to adjust the carrying value of CILCO’s (through AERG) Indian Trails and Sterling Avenue generation facilities to their estimated fair values as of December 31, 2008. CILCO recorded an asset impairment charge of $12 million related to the Indian Trails cogeneration facility as a result of the suspension of operations by the facility’s only customer. CILCORP recorded a $2 million impairment charge related to the Sterling Avenue CT based on the expected net proceeds to be generated from the sale of the facility in 2009. Because most of the Sterling Avenue asset carrying value is recorded at CILCORP, as a result of adjustments made during purchase accounting, the write-down of the carrying value of the Sterling Avenue CT did not result in an impairment loss at CILCO (AERG).

Reducing the unfavorable effect of these items were lower employee benefit costs of $10 million due to changes

in actuarial estimates and reduced storm expenditures of $18 million, primarily in UE’s service territory, in 2008 compared with 2007. Additionally, costs associated with the Callaway nuclear plant refueling and maintenance outage in 2008 were $5 million lower than those for the refueling in 2007. Other operations and maintenance expenses were further reduced in the current year by a MoPSC accounting order received in the second quarter of 2008, which resulted in UE recording a regulatory asset for $25 million of costs related to 2007 storms that had previously been expensed.

Variations in other operations and maintenance expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.

Missouri Regulated

UE’s other operations and maintenance expenses increased $22 million in 2008, as compared with 2007, primarily because of increased distribution system reliability expenditures of $16 million, higher labor costs of $37 million, increased plant maintenance expenditures at coal-fired plants of $29 million, and unrealized net mark-to-market adjustments resulting from the lower market value of investments used to support deferred compensation plans. Reducing the impact of these items was the effect of the MoPSC accounting order discussed above, a decrease in injuries and damages expenses between years, and the reduced impact of the Callaway refueling and maintenance outage in 2008 compared with the refueling in 2007. Storm repair expenditures also decreased by $31 million in 2008 compared with 2007, further reducing other operations and maintenance expenses.

Illinois Regulated

Other operations and maintenance expenses increased $77 million in the Illinois Regulated segment in 2008, compared with 2007.

CIPS

Other operations and maintenance expenses increased $24 million in 2008 compared with 2007. The increase was primarily because of higher distribution system reliability expenditures of $11 million, including storm costs, along with increased labor costs and bad debt expense. Additionally, the reversal in the first quarter of 2007 of an accrual of $4 million, established in 2006, for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan, with no similar item in 2008, resulted in higher other operations and maintenance expenses in 2008 compared with 2007.

CILCO (Illinois Regulated)

Other operations and maintenance expenses increased $8 million in 2008, as compared with 2007, primarily

because of increased storm costs of $5 million in 2008. Additionally, in the first quarter of 2007, CILCO (Illinois Regulated) reversed a $3 million accrual established in 2006 for the Illinois Customer Elect electric rate increase phase-in plan contributions, with no similar item in 2008. Lower employee benefit costs reduced the effect of these unfavorable items.

Other operations and maintenance expenses increased $47 million in 2008, as compared with 2007, primarily because of higher distribution system reliability expenditures of $17 million, including storm costs. Labor costs and bad debt expense increased by $6 million each, and unrealized net mark-to-market adjustments resulting from the lower market value of investments used to support deferred compensation plans also increased other operations and maintenance expenses between years. Additionally, in the first quarter of 2007, IP reversed an $8 million accrual established in 2006 for the Illinois Customer Elect electric rate increase phase-in plan contributions, with no similar item in 2008. Reducing the unfavorable effect of these items was a reduction in employee benefit costs.

Non-rate-regulated Generation

Other operations and maintenance expenses increased $43 million in the Non-rate-regulated Generation segment in 2008 compared with 2007.

Genco

Other operations and maintenance expenses increased $12 million at Genco in 2008, as compared with 2007, primarily because of higher plant maintenance costs of $9 million, due to scheduled outages, and increased labor costs of $5 million. Genco paid $3 million to the IPA in the prior year as part of the Illinois electric settlement agreement, with no similar item in 2008, reducing other operations and maintenance expenses between 2008 and 2007.

CILCO (AERG)

Other operations and maintenance expenses increased $25 million at CILCO (AERG) in 2008, as compared with 2007, primarily because of a $12 million impairment charge recorded in 2008 related to the Indian Trails cogeneration plant as discussed above, higher plant maintenance costs of $7 million due to scheduled outages, and increased labor costs of $3 million. CILCO (AERG) paid $1.5 million to the IPA in 2007 as part of the Illinois electric settlement agreement, with no similar item in 2008, reducing other operations and maintenance expenses between 2008 and 2007.

CILCORP (parent company only)

Other operations and maintenance expenses increased $3 million in 2008, as compared with 2007, primarily because of an asset impairment charge recorded in 2008 related to the Sterling Avenue CT discussed above.

EEI

Other operations and maintenance expenses were comparable in 2008 and 2007.

2007 versus 2006

Ameren

Ameren’s other operations and maintenance expenses increased $131 million in 2007 compared with 2006. Maintenance and labor costs associated with the Callaway nuclear plant refueling and maintenance outage in the second quarter of 2007 added $35 million. Distribution system reliability expenditures increased $49 million and employee benefits and non-Callaway labor costs were higher by $55 million in 2007 compared with 2006. Bad debt expenses increased $25 million in 2007, primarily as a result of the transition to higher electric rates in Illinois. Increases in maintenance at coal-fired power plants and injuries and damages reserves also contributed to higher other operations and maintenance expenses in 2007. We recognized reduced gains on sales of noncore property in 2007 of $4 million, compared with gains of $16 million in 2006. Additionally, other operations and maintenance expenses in 2007 included a payment of $4.5 million made to the IPA as part of the Illinois electric settlement agreement.

Reducing the effect of these items was the reversal in 2007 of an accrual of $15 million established in 2006 for contributions to assist customers through the Illinois Customer Elect electric rate increase phase-in plan. In 2006, we also recognized costs of $25 million related to the December 2005 Taum Sauk plant reservoir breach. Costs associated with storms in the spring and summer of 2006 and a major ice storm in the fourth quarter of 2006 exceeded the costs associated with an ice storm in January 2007 by $42 million, thereby reducing other operations and maintenance expenses in 2007 compared with 2006.

Variations in other operations and maintenance expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.

Missouri Regulated

Other operations and maintenance expenses increased in 2007 compared with 2006. Maintenance and labor costs associated with the Callaway nuclear plant refueling and maintenance outage in 2007 added $35 million to other operations and maintenance expenses compared with 2006. Higher distribution system reliability expenditures of $34 million, increased non-Callaway-related labor costs of $22 million, and insurance premiums of $19 million for replacement power coverage paid to a risk insurance affiliate also increased other operations and maintenance expenses in 2007 compared with 2006. Reducing the effect of these items was the absence in 2007 of costs recorded in 2006 related to the Taum Sauk plant reservoir breach

discussed above. Costs associated with storms in the spring and summer of 2006 and a major ice storm in the fourth quarter of 2006 exceeded the costs associated with an ice storm in January 2007 by $13 million, thereby reducing other operations and maintenance expenses in 2007 compared with 2006.

Illinois Regulated

Other operations and maintenance expenses increased $15 million in the Illinois Regulated segment in 2007 compared with 2006.

CIPS

Other operations and maintenance expenses increased $11 million in 2007 compared with 2006, primarily because of increased bad debt expenses, higher distribution system reliability expenditures, and increased injuries and damages reserves. The reversal in 2007 of the Illinois Customer Elect electric rate increase phase-in plan accrual of $4 million established in 2006 reduced the effect of these increases. Costs associated with storms in the spring and summer of 2006 and a major ice storm in the fourth quarter of 2006 were comparable with the costs associated with an ice storm in January 2007.

CILCO (Illinois Regulated)

Other operations and maintenance expenses were comparable between 2007 and 2006, as an increase in bad debt expenses was offset by the reversal of the Illinois Customer Elect electric rate increase phase-in plan accrual of $3 million established in 2006. Costs associated with storms had a minimal impact on CILCO (Illinois Regulated) other operations and maintenance expenses each year.

IP’s other operations and maintenance expenses were comparable between 2007 and 2006. Higher employee benefit costs increased other operations and maintenance expenses in 2007. Bad debt expenses increased $10 million in 2007, primarily as a result of the transition to higher electric rates in Illinois. Offsetting the effect of these items was the reversal in 2007 of the Illinois Customer Elect electric rate increase phase-in plan accrual of $8 million established in 2006 and a reduction of $24 million in storm repair costs between years.

Non-rate-regulated Generation

Other operations and maintenance expenses increased $30 million in the Non-rate-regulated Generation segment in 2007 compared with 2006.

Genco

Genco’s other operations and maintenance expenses increased $10 million in 2007 compared with 2006, primarily because of higher labor costs, the IPA payment of $3 million, and insurance premiums for replacement power coverage paid to a risk insurance affiliate.

CILCORP (parent company only)

Other operations and maintenance expenses were comparable between 2007 and 2006. Increased employee benefit costs in 2007 were offset by the absence in 2007 of a write-off in 2006, of an intangible asset established in conjunction with Ameren’s acquisition of CILCORP.

CILCO (AERG)

Other operations and maintenance expenses increased $11 million in 2007 compared with 2006, primarily because of higher power plant maintenance costs due to plant outages and the IPA payment of $1.5 million.

EEI

Other operations and maintenance expenses increased $3 million in 2007 compared with 2006, primarily because of higher power plant maintenance costs.

Depreciation and Amortization

2008 versus 2007

Ameren

Ameren’s depreciation and amortization expenses were comparable between periods. Increases in depreciation expense resulting from capital additions during the past year were mitigated by a reduction in expense because of changes in the useful lives of plant assets resulting from rate orders in 2007 in Missouri and 2008 in Illinois, as discussed below.

Variations in depreciation and amortization expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.

Missouri Regulated

Depreciation and amortization expenses decreased $4 million in 2008, compared with 2007, primarily because of the extension of UE’s nuclear and coal-fired plants’ useful lives for purposes of calculating depreciation expense in conjunction with a MoPSC electric rate order effective June 2007. Reducing the benefit of this item was an increase in capital additions over the past year.

Illinois Regulated

Depreciation and amortization expenses were comparable in 2008 and 2007 in the Illinois Regulated segment. As part of the consolidated electric and natural gas rate order issued by the ICC in September 2008, the ICC changed plant asset useful lives, effective October 1, 2008, which resulted in an increase in depreciation expense at IP and reductions in depreciation expense at CIPS and CILCO (Illinois Regulated). The effects of these changes in useful lives were partially offset by capital additions at CIPS and CILCO (Illinois Regulated). IP’s depreciation and

amortization expenses increased due to the effect of the rate order and capital additions.

Non-rate-regulated Generation

Depreciation and amortization expenses increased $4 million in the Non-rate-regulated Generation segment in 2008 compared with 2007. Depreciation and amortization expenses increased $8 million at CILCO (AERG) because of capital additions over the past year. Depreciation and amortization expenses decreased $4 million at Genco, primarily as a result of a depreciation study completed in September 2007, which was mitigated by capital additions.

2007 versus 2006

Ameren

Ameren’s depreciation and amortization expenses increased $20 million in 2007 over 2006. The increases were primarily because of amortization of a regulatory asset in 2007 at IP, as discussed below, and capital additions in 2006 and 2007. A decrease in depreciation expense as a result of the MoPSC electric rate order effective in June 2007, discussed above, somewhat mitigated that effect.

Variations in depreciation and amortization expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.

Missouri Regulated

Depreciation and amortization expenses in 2007 were comparable with 2006. Increased expenses associated with capital additions in 2006 and 2007 were offset by a reduction in depreciation as a result of the MoPSC electric rate order, effective June 2007, discussed above.

Illinois Regulated

Depreciation and amortization expenses increased $25 million in the Illinois Regulated segment in 2007 compared with 2006.

CIPS & CILCO (Illinois Regulated)

Depreciation and amortization expenses were comparable between 2007 and 2006.

Depreciation and amortization expenses, including amortization of regulatory assets on IP’s statement of income, increased $19 million in 2007 compared with 2006, primarily because of the start of amortization in 2007 of a regulatory asset associated with acquisition integration costs, as required by an ICC order, and capital additions.

Non-rate-regulated Generation

Depreciation and amortization expenses were comparable between 2007 and 2006 in the Non-rate-regulated Generation segment and for Genco, CILCORP (parent company only), CILCO (AERG) and EEI.

Taxes Other Than Income Taxes

2008 versus 2007

Ameren

Ameren’s taxes other than income taxes increased $12 million in 2008 compared with 2007, primarily because of higher property taxes and higher gross receipts taxes. Increases in property taxes were reduced by invested capital electricity distribution tax credits in the Illinois Regulated segment. These credits were related to payments made in a previous year.

Variations in taxes other than income taxes in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.

Missouri Regulated

UE’s taxes other than income taxes increased $6 million in 2008 compared with 2007, primarily because of higher property taxes.

Illinois Regulated

Taxes other than income taxes increased $5 million in 2008 compared with 2007 in the Illinois Regulated segment, primarily because of higher excise taxes at CIPS, CILCO (Illinois Regulated), and IP. Property taxes were comparable between years as increases in 2008 were mitigated by the favorable impact of the invested capital electricity distribution tax credits discussed above.

Non-rate-regulated Generation

Taxes other than income taxes were comparable between 2008 and 2007 in the Non-rate-regulated Generation segment and for Genco, CILCORP (parent company only), CILCO (AERG) and EEI.

2007 versus 2006

Ameren

Ameren’s taxes other than income taxes decreased $10 million in 2007 compared with 2006, primarily because of lower gross receipts and property taxes.

Variations in taxes other than income taxes for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.

Missouri Regulated

Taxes other than income taxes increased $4 million in 2007 over 2006, primarily because of increased gross receipts taxes.

Illinois Regulated

Taxes other than income taxes decreased $16 million in 2007 compared with 2006 in the Illinois Regulated segment. Taxes other than income taxes decreased $7 million at CIPS, $2 million at CILCO (Illinois Regulated), and $7 million at IP in 2007 compared with 2006, primarily as a result of reduced property taxes and excise taxes.

Non-rate-regulated Generation

Taxes other than income taxes were comparable between 2007 and 2006 for the Non-rate-regulated Generation segment and for Genco, CILCORP (parent company only), CILCO (AERG), and EEI.

Other Income and Expenses

2008 versus 2007

Ameren

Miscellaneous income increased $5 million in 2008 compared with 2007, primarily because of an increase at UE in allowance for funds used during construction, reduced by lower interest income. Miscellaneous expense increased $6 million in 2008 compared with 2007, primarily because of increased expenses associated with contributions to social programs.

Variations in other income and expenses in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.

Missouri Regulated

Miscellaneous income increased $24 million in 2008 compared with 2007, primarily because of an increase in allowance for funds used during construction. The increase in allowance for funds used during construction resulted from higher rates and increased construction-in-progress balances. Miscellaneous expenses were comparable in 2008 and 2007.

Illinois Regulated

Other income and expenses decreased $9 million in 2008 in the Illinois Regulated segment and at CIPS, CILCO (Illinois Regulated) and IP, compared with 2007, primarily because of lower interest income.

Non-rate-regulated Generation

Other income and expenses in the Non-rate-regulated Generation segment and at Genco, CILCORP (parent company only), CILCO (AERG) and EEI were comparable between 2008 and 2007.

2007 versus 2006

Ameren

Miscellaneous income increased $25 million in 2007 compared with 2006, primarily because of increased interest and investment income. Cash balances were higher because of uncertainty regarding the ultimate resolution of legislative and regulatory issues in Illinois. Miscellaneous expense increased $6 million in 2007 compared with 2006, primarily because we made contributions to our charitable trust and because Illinois Regulated made contributions of $5 million for energy efficiency and customer assistance programs as part of the Illinois electric settlement agreement. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.

Variations in other income and expenses for the Ameren, CILCORP and CILCO business segments and for the Ameren Companies between 2007 and 2006 were as follows.

Missouri Regulated

Other income and expenses were comparable in 2007 and 2006.

Illinois Regulated

Other income and expenses increased $7 million in the Illinois Regulated segment in 2007 compared with 2006, primarily because of increased interest income at IP. Other income and expenses were comparable between years at CIPS and CILCO (Illinois Regulated).

Non-rate-regulated Generation

Other income and expenses were comparable between 2007 and 2006 in the Non-rate-regulated Generation segment and for Genco, CILCORP (parent company only), CILCO (AERG), and EEI.

Interest

2008 versus 2007

Ameren

Interest expense increased $17 million in 2008 compared with 2007. Long-term debt issuances, net of maturities and redemptions, and the cost of refinancing auction-rate environmental improvement and pollution control revenue refunding bonds resulted in increased interest expense in 2008. See Insured Auction-Rate Tax-exempt Bonds under Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk of this report for additional information. These increases were reduced as a result of income tax settlements in 2008.

Variations in interest expense in Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.

Missouri Regulated

Interest expense was comparable in 2008 and 2007. Interest expense associated with the issuance of senior secured notes of $450 million, $250 million, and $425 million in June 2008, April 2008 and June 2007, respectively, was mitigated by a reduction in short-term borrowings due to the long-term debt financings. Senior secured notes were issued to refinance auction-rate environmental improvement revenue refunding bonds, to fund the maturity of $148 million of first mortgage bonds, and to reduce short-term borrowings. Additionally, interest expense was reduced by $8 million resulting from the income tax settlements noted above.

Illinois Regulated

Interest expense increased $12 million in the Illinois Regulated segment in 2008 compared with 2007.

CIPS

Interest expense decreased $7 million in 2008 compared with 2007, primarily because of reduced short-term borrowings. Additionally, interest expense was reduced by $3 million as a result of an income tax settlement.

CILCO (Illinois Regulated)

Interest expense was comparable in 2008 and 2007.

Interest expense increased $22 million in 2008 compared with 2007, primarily because of the issuance of $400 million, $337 million, and $250 million of senior secured notes at IP in October 2008, April 2008, and November 2007, respectively. The $337 million senior secured notes were issued to refinance auction-rate pollution control revenue refunding bonds, while the other debt issuances were used to reduce short-term borrowings.

Non-rate-regulated Generation

Interest expense decreased $8 million in the Non-rate-regulated Generation segment in 2008 compared with 2007.

Genco

Interest expense was comparable in 2008 and 2007. Increased interest expense resulting from the issuance of $300 million of senior unsecured notes in April 2008 was mitigated by a resulting reduction in short-term borrowings. Additionally, interest expense was reduced by $3 million as a result of an income tax settlement.

CILCORP (parent company only) and CILCO (AERG)

Interest expense decreased $3 million at CILCORP (parent company only) and $4 million at CILCO (AERG), in 2008 compared with 2007, primarily because of reduced short-term borrowings.

EEI

Interest expense was comparable in 2008 and 2007.

2007 versus 2006

Ameren

Interest expense increased $73 million in 2007 compared with 2006, primarily because of increased short-term borrowings, higher interest rates due to reduced credit ratings, and other items noted below. With the adoption of FIN 48 in 2007, we also began to record interest associated with uncertain tax positions as interest expense rather than income tax expense. These interest charges were $10 million for 2007. Reducing the effect of the above unfavorable items were maturities of $350 million of long-term debt in the first half of 2007 at Ameren and redemptions/maturities at the Ameren Companies as noted below.

Variations in interest expense for Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2007 and 2006 were as follows.

Missouri Regulated

Interest expense increased $23 million in 2007 over 2006, primarily because of increased short-term borrowings, higher interest rates due to reduced credit ratings, and the issuance of $425 million of senior secured notes in June 2007. Interest expense recorded in conjunction with uncertain tax positions was $3 million in 2007.

Illinois Regulated

Interest expense increased $37 million in the Illinois Regulated segment and increased at CIPS and IP in 2007 compared with 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings and the issuance of senior secured notes in 2007 and 2006. IP issued $250 million and $75 million of senior secured notes in November 2007 and June 2006, respectively. CIPS and CILCO (Illinois Regulated) issued $61 million and $96 million of senior secured notes, respectively, in June 2006. Reducing the effect of the above items was the maturity of $50 million of first mortgage bonds at CILCO (Illinois Regulated) in January 2007 and payments made on IP’s note payable to IP SPT in 2007 and 2006.

Non-rate-regulated Generation

Interest expense increased $4 million in the Non-rate-regulated Generation segment in 2007 compared with 2006.

CILCORP (parent company only) and CILCO (AERG)

Interest expense increased $3 million at CILCORP (parent company only) and $5 million at CILCO (AERG) in 2007 over 2006, primarily because of increased short-term borrowings and higher interest rates due to reduced credit ratings.

Genco

Interest expense decreased $5 million in 2007 compared with 2006, primarily because of reduced intercompany borrowings. Reducing this benefit was increased interest expense of $3 million recorded in conjunction with uncertain tax positions in 2007.

EEI

Interest expense was comparable in 2007 and 2006.

Income Taxes

2008 versus 2007

Ameren

Ameren’s effective tax rate was comparable in 2008 and 2007. Favorable impacts of state audit settlements and changes in state apportionment were offset by unfavorable permanent items related to company-owned life insurance as well as other variations discussed below at the Ameren Companies.

Variations in effective tax rates for Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2008 and 2007 were as follows.

Missouri Regulated

The effective tax rate increased in 2008 from 2007, primarily because of lower favorable net amortization of property-related regulatory assets and liabilities, along with decreased Internal Revenue Code Section 199 production activity deductions in 2008.

Illinois Regulated

The effective tax rate decreased in the Illinois Regulated segment in 2008 compared with 2007, because of the items detailed below.

CIPS

The effective tax rate decreased in 2008 from 2007, primarily because of the impact of net amortization of property-related regulatory assets and liabilities and permanent items on lower pretax income in 2008.

CILCO (Illinois Regulated)

The effective tax rate for 2008 was higher than the effective tax rate for 2007, primarily because of lower tax credits, lower favorable net amortization of property-related regulatory asset and liabilities, and lower favorable permanent benefits related to company-owned life insurance.

The effective tax rate for 2008 was higher than the effective tax rate for 2007, primarily because of lower favorable net amortization of property-related regulatory assets and liabilities, lower tax credits, and the impact of other permanent items as well as increased reserves for uncertain tax positions on lower pretax book income in 2008.

Non-rate-regulated Generation

The effective tax rate decreased in 2008 compared with 2007 in the Non-rate-regulated Generation segment, because of the items detailed below.

Genco

The effective tax rate decreased in 2008 from 2007, primarily because of the increased impact of Internal Revenue Code Section 199 production activity deductions and research tax credits.

CILCO (AERG)

The effective tax rate increased in 2008 compared with 2007, primarily because of the impact of Internal Revenue Code Section 199 production activity deductions.

CILCORP (parent company only)

The effective tax rate increased in 2008 compared with 2007, primarily because of the effect of state audit settlements.

EEI

The effective tax rate was comparable in 2008 and 2007.

2007 versus 2006

Ameren

Ameren’s effective tax rate increased between 2007 and 2006.

Variations in effective tax rates for Ameren’s, CILCORP’s and CILCO’s business segments and for the Ameren Companies between 2007 and 2006 were as follows.

Missouri Regulated

The effective tax rate decreased in 2007 from 2006, primarily because of the implementation of changes ordered by the MoPSC in UE’s 2007 electric rate order. These changes decreased the unfavorable effect of the net amortization of property-related regulatory assets and liabilities in 2007 compared to 2006, decreased reserves for uncertain tax positions in 2007 compared to increases in 2006, and increased Internal Revenue Code Section 199 production activity deductions in 2007 compared with 2006.

Illinois Regulated

The effective tax rate decreased in the Illinois Regulated segment in 2007 compared with 2006, because of the items detailed below.

CIPS

The effective tax rate increased, primarily because of higher reserves for uncertain tax positions in 2007 compared to 2006, the unfavorable effect of the net amortization of property-related regulatory assets and liabilities in 2007 compared to favorable net amortization of property-related regulatory assets and liabilities in 2006, lower permanent benefit for SFAS No. 106-2, as it relates to Medicare Part D provisions, and other miscellaneous items, offset by the increased impact of the amortization of investment tax credit, and other items on lower pretax book income.

CILCO (Illinois Regulated)

The effective tax rate decreased, primarily because of an increase in the permanent benefit for SFAS No. 106-2, as it relates to Medicare Part D provisions, along with an increase in the favorable effect of the net amortization of property-related regulatory assets and liabilities, and increased impact of the amortization of investment tax credit on lower pretax book income.

The effective tax rate decreased, primarily because of the favorable effect of the net amortization of property-related regulatory assets and liabilities in 2007 compared to unfavorable net amortization of property-related regulatory assets and liabilities in 2006.

Non-rate-regulated Generation

The effective tax rate increased in the Non-rate-regulated Generation segment in 2007 compared with 2006, because of the items detailed below.

Genco

The effective tax rate increased, primarily because of lower decreases in reserves for uncertain tax positions in

2007 compared to 2006, and decreased Internal Revenue Code Section 199 production activity deductions in 2007 compared to 2006.

CILCO (AERG)

The effective tax rate increased in 2007, primarily because of higher reserves for uncertain tax positions in 2007 compared to 2006 and decreased impact of amortization of investment tax credit on higher pretax book income, offset by increased Internal Revenue Code Section 199 production activity deductions in 2007 compared to 2006, and differences between the book and tax treatment of the sales of noncore properties in 2006.

CILCORP (parent company only)

The effective tax rate decreased, primarily because of a change in the permanent benefit for SFAS No. 106-2, as it relates to Medicare Part D provisions.

EEI

The effective tax rate decreased, primarily because of increased Internal Revenue Code Section 199 production activity deductions.

LIQUIDITY AND CAPITAL RESOURCES

The tariff-based gross margins of Ameren’s rate-regulated utility operating companies (UE, CIPS, CILCO (Illinois Regulated) and IP) continue to be a principal source of cash from operating activities for Ameren and its rate-regulated 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 Ameren, UE, CIPS, CILCO (Illinois Regulated) and IP. For operating cash flows, Genco and AERG rely on power sales to Marketing Company, which sold power through the September 2006 Illinois power procurement auction, financial contracts that were part of the Illinois electric settlement agreement, and the 2008 Illinois RFP process for energy and capacity that was used pursuant to the Illinois electric settlement agreement. Marketing Company is also selling power through other primarily market-based contracts with wholesale and retail customers. In addition to cash flows from operating activities, the Ameren Companies use available cash, credit facilities, money pool or other short-term borrowings from affiliates to support normal operations and other temporary capital requirements. The use of operating cash flows and short-term borrowings to fund capital expenditures and other investments may periodically result in a working capital deficit as was the case at December 31, 2008, for Ameren, UE, Genco, CILCORP, CILCO, and IP. The Ameren Companies may reduce their short-term borrowings with cash from operations or discretionarily with long-term borrowings, or in the case of Ameren subsidiaries, with equity infusions from Ameren. The Ameren Companies expect to incur significant capital expenditures over the next five years as they comply with environmental regulations and make significant investments in their electric and gas utility infrastructure to improve overall system reliability. Ameren intends to finance those capital expenditures and investments with a blend of equity and debt so that it maintains a capital structure in its rate-regulated businesses, containing approximately 50% to 55% equity. Consequently, we expect to make equity issuances in the future consistent with this objective, as well as to address any unanticipated events, should the need arise. We plan to implement our long-term financing plans for debt, equity or equity-linked securities in order to appropriately finance our operations, meet scheduled debt maturities and maintain financial strength and flexibility.

The global capital and credit markets experienced extreme volatility and disruption in 2008, and continue to experience volatility and disruption in 2009. See Outlook for a discussion of the implications of this volatility and disruption for the Ameren Companies and our plans to address these issues.

The following table presents net cash provided by (used in) operating, investing and financing activities for the years ended December 31, 2008, 2007 and 2006:


	Net Cash Provided By Operating Activities						Net Cash (Used In) Investing Activities									Net Cash Provided By (Used In) Financing Activities
	2008		2007		2006		2008			2007			2006			2008			2007			2006
Ameren ^(a)	$	1,533	$	1,102	$	1,279	$	(2,097	)	$	(1,468	)	$	(1,266	)	$	301		$	584		$	28
UE		545		588		734		(1,033	)		(700	)		(732	)		303			296			(21	)
CIPS		103		14		118		(57	)		(42	)		(66	)		(72	)		48			(46	)
Genco		244		255		138		(328	)		(210	)		(110	)		84			(44	)		(27	)
CILCORP		184		32		133		(318	)		(213	)		(90	)		128			183			(42	)
CILCO		209		74		153		(317	)		(212	)		(161	)		102			141			9
IP		180		28		172		(233	)		(180	)		(180	)		97			158			8

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

Cash Flows from Operating Activities

2008 versus 2007

Ameren’s cash from operating activities increased in 2008, compared to 2007, primarily because of higher electric and gas margins as discussed above, a $177 million decrease in income tax payments (net of refunds), and improved collections of receivables in 2008. The reduction in income tax payments was largely attributable to higher depreciation allowed for tax purposes. In 2007, receivables from the Ameren Illinois Utilities had increased due to the January 2, 2007, electric rate increases, related uncertainty surrounding a potential electric settlement agreement, and deterioration of collections. However, collections improved in 2008. Additionally, Ameren experienced an $87 million benefit to cash flows for 2008 as compared to 2007 because of the timing of cash receipts for MISO receivables. The Illinois electric settlement agreement also had a positive effect on cash from operations in 2008 compared with 2007. Cash outflows in accordance with the settlement, net of reimbursements from generators, were $84 million less in 2008 than in 2007. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a discussion of the Illinois electric settlement agreement. In addition, Ameren’s cash flows from operations increased in 2008 compared with 2007 because of a $40 million reduction in storm restoration costs, over-recovery under the PGAs, and a $27 million payment received by Genco in 2008 as part of a coal contract settlement for increased costs for coal and transportation that Genco expects to incur in 2009 due to the premature closure of an Illinois mine at the end of 2007. See Note 1 – Summary of Significant Accounting Policies to our Financial Statements under Part II, Item 8, for information on the coal contract settlement. Factors that offset, in part, the favorable variance in cash flows from operations in 2008 were a $93 million increase in cash payments related to the December 2005 Taum Sauk incident, net of insurance companies, an increase in gas inventories resulting from price increases, higher interest payments, and higher levels of collateral posted with suppliers.

At UE, cash from operating activities decreased in 2008, compared to 2007. The decrease is primarily due to a $24 million increase in net income tax payments in 2008, lower electric margins, increased system reliability expenditures as discussed in Results of Operations, and higher levels of net collateral posted with suppliers. Also contributing to the unfavorable variance in 2008 was a $93 million increase in cash payments related to the December 2005 Taum Sauk incident, net of insurance recoveries, and a $146 million net decrease in affiliate payables. Factors increasing cash from operations included a $34 million decrease in payments for storm restorations, a decrease in other operations and maintenance expenditures related to the Callaway nuclear plant refueling and maintenance outage in 2008 as compared with the 2007 refueling and maintenance outage, reduction in interest payments, and the collection in 2008 of an $85 million affiliate receivable. In addition, cash flows from

operations increased in 2008 compared with 2007 because of the timing of cash receipts for MISO receivables.

At CIPS, cash from operating activities increased in 2008 compared to 2007. The increase was primarily due to net income tax refunds of $21 million in 2008, compared with net income tax payments of $44 million in 2007, an increase in gas cost over-recovery from customers under the PGA, a $7 million increase in customer advances for construction, and favorable fluctuations in receivables and payables. In 2007, receivables increased due to the January 2, 2007, electric rate increases, related uncertainty surrounding a potential settlement agreement, and deterioration of collections. However, collections improved in 2008. The Illinois electric settlement agreement also had a positive effect on cash from operations in 2008 compared to 2007. CIPS’ cash outflows from the settlement, net of reimbursements from generators, were $26 million less in 2008 than in 2007. CIPS experienced favorable fluctuations in intercompany receivable and payable balances resulting from changes in its year-end 2008 income tax position and a receivable related to the Illinois electric settlement agreement compared with 2007. Partially offsetting the favorable variance in cash flow from operations was a larger increase in gas inventories during 2008 compared with 2007, a decrease in electric costs over-recovered from customers, and higher net levels of collateral posted with suppliers.

Genco’s cash from operating activities decreased in 2008 compared with 2007 primarily due to an increase in fuel inventory and an increase in net income tax payments of $13 million. Reducing the unfavorable variance in cash flow from operations were higher electric margins, a payment from an Illinois coal mine owner for the premature closure of an Illinois mine, as discussed above, and a $6 million reduction in funding required by the Illinois electric settlement agreement in 2008 compared with 2007.

Cash from operating activities increased for CILCORP and CILCO in 2008 compared to 2007. The increase was primarily due to net income tax refunds of $33 million and $15 million in 2008 compared with net income tax payments of $16 million and $35 million in 2007 at CILCORP and CILCO, respectively, higher electric margins, a reduction of coal inventory at AERG, an increase in gas cost recovered from customers under a PGA, an increase in electric cost over-recovered from customers, and favorable fluctuations in receivables and payables. In 2007, receivables increased due to the January 2, 2007 electric rate increases, related uncertainty surrounding a potential settlement agreement, and deterioration of collections. However, collections improved in 2008. The Illinois electric settlement agreement also had a positive effect on cash from operations in 2008 compared with 2007. The cash outflows from the settlement, including AERG’s obligation, were $16 million lower in 2008 than in 2007. CILCORP experienced favorable fluctuations in intercompany receivable and payable balances resulting from changes in its year-end 2008 income tax position and a receivable related to the Illinois electric settlement agreement

compared with 2007. Partially offsetting these increases in cash from operations were a larger increase in gas inventories during 2008 compared with 2007, as both price and volumes increased, and higher levels of collateral, net, posted with suppliers. Additionally, CILCORP’s operating cash flows in 2008 were reduced by $22 million compared with 2007 due to higher interest payments.

IP’s cash from operating activities increased in 2008, compared with 2007. The increase was primarily due to net income tax refunds of $43 million in 2008, compared with net income tax payments of $18 million in 2007, increased electric and gas margins, an increase in gas cost recovered from customers under a PGA, an increase in electric power costs over-recovered from customers, a $7 million increase in customer advances for construction, and favorable fluctuations in receivables and payables. In 2007, receivables increased due to the January 2, 2007, electric rate increases, related uncertainty surrounding a potential settlement agreement, and deterioration of collections. However, collections improved in 2008. The Illinois electric settlement agreement also had a positive effect on cash from operations in 2008 compared to 2007. IP cash outflows from the settlement, net of reimbursements from generators, were $35 million lower in 2008 than in 2007. IP experienced favorable fluctuations in intercompany receivable and payable balances resulting from changes in its year-end 2008 income tax position and a receivable related to the Illinois electric settlement agreement compared with 2007. In addition, operating cash required for major repairs in response to 2008 storms was $8 million less than major storm repairs in 2007. Partially offsetting these increases to operating cash flows was a $10 million increase in interest payments and higher net levels of collateral posted with suppliers in 2008.

2007 versus 2006

Ameren’s cash from operating activities decreased in 2007, as compared with 2006. This was primarily because of an increase in working capital investment as the collection of higher electric rates from Illinois electric customers lagged payments for power purchases, and past-due accounts increased because of the higher rates. The Illinois electric settlement agreement resulted in a 2007 net cash outflow of $88 million: $211 million of customer refunds, credits, and program funding, minus related reimbursements from nonaffiliated Illinois generators of $123 million. An additional payment of $4.5 million was made to fund the IPA. As of the end of 2007, $34 million was due from nonaffiliated generators. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a discussion of the Illinois electric settlement agreement. Other factors also reduced cash flow: increased interest payments as a result of lower credit ratings and increased debt. In addition, cash spent for fuel inventory increased because UE increased its inventory, and AERG experienced increased inventory as a result of an extended plant outage. Also reducing operating cash flows was a $25 million increase in pension and postretirement benefit contributions. In 2007, a $120 million decrease in

income taxes paid (net of refunds) benefited cash flows from operations in 2007. Increases in electric and gas margins of $296 million and $15 million, respectively, also benefited operating cash flows, but were reduced by higher operations and maintenance expenses, as discussed in Results of Operations.

At UE, cash from operating activities decreased in 2007, compared with 2006, primarily because of an increase in accounts receivable caused by higher prices for interchange power sales, colder weather in December 2007 than in December 2006, and increased electric rates. Further reducing cash flows in 2007, was an increase in interest payments and other operations and maintenance expenditures, including $35 million for the Callaway nuclear plant refueling and maintenance outage. In addition, UE increased its fuel inventory. Compared with 2006, cash flows from operations in 2007 benefited from an increase in margin, as discussed in Results of Operations, a decrease in cash paid for Taum Sauk incident-related costs (net of insurance recoveries) of $6 million, and a decrease in income tax payments (net of refunds) of $79 million.

At CIPS, cash from operating activities decreased in 2007, compared with 2006. The Illinois electric settlement agreement resulted in a 2007 net cash outflow of $19 million, including $74 million of customer refunds, credits, and program funding, and related reimbursements from nonaffiliated Illinois generators of $55 million. As of the end of 2007, $13 million was due from nonaffiliated generators. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a complete discussion of the Illinois electric settlement agreement. Cash from operations was further reduced by a decrease in electric margins and higher expenses, as discussed in Results of Operations. In addition, there was an increase in working capital investment, as the collection of higher electric rates from customers lagged payments for power purchases, and past-due customer accounts increased because of higher rates. Income tax payments (net of refunds) decreased $18 million, benefiting cash flows from operations.

Genco’s cash from operating activities increased in 2007 compared with 2006, primarily because electric margins increased, as discussed in Results of Operations, and because cash spent for fuel inventory decreased. In 2006, large cash outlays were made to replenish coal inventory after delivery disruptions caused by train derailments. Reducing these increases in cash from operating activities was an increase in income tax payments (net of refunds) of $41 million.

Cash from operating activities decreased for CILCORP and CILCO in 2007, compared with 2006. The Illinois electric settlement agreement resulted in a 2007 net cash outflow of $12 million: $41 million of customer refunds, credits, and program funding, minus related reimbursements from nonaffiliated Illinois generators of $29 million. As of the end of 2007, $7 million was due from nonaffiliated generators. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of

this report for a complete discussion of the Illinois electric settlement agreement. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, past-due customer accounts increased due to higher rates, and inventory levels increased at AERG due to an extended plant outage. In addition, income tax payments (net of refunds) increased $20 million for CILCORP and $18 million for CILCO. Increased electric and gas margins, as discussed in Results of Operations, benefited cash flows from operating activities.

IP’s cash from operating activities decreased in 2007, compared with 2006. The Illinois electric settlement agreement resulted in a 2007 net cash outflow of $24 million: $96 million of customer refunds, credits, and program funding, minus related reimbursements from nonaffiliated Illinois generators of $72 million. As of the end of 2007, $14 million was due from nonaffiliated generators. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for a complete discussion of the Illinois electric settlement agreement. Further reducing cash from operating activities compared to the prior year was a reduction in electric margins, as discussed in Results of Operations, and a $13 million increase in pension and postretirement benefit contributions. Working capital investment increased because the collection of higher electric rates from customers lagged payments for power purchases, and past-due customer accounts increased because of higher rates. Income tax payments (net of refunds) increased by $27 million, further reducing cash flows from operations.

Pension Funding

Ameren’s pension plans are funded in compliance with income tax regulations and to achieve federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Based on Ameren’s assumptions at December 31, 2008, and investment performance in 2008, and reflecting this pension funding policy, Ameren expects to make annual contributions of $90 million to $200 million in each of the next five years. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 61%, 6%, 10%, 9% and 14%, respectively. These amounts are estimates; the numbers may change with actual asset performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. In 2008, Ameren contributed $66 million to its pension plans. See Note 11 – Retirement Benefits to our financial statements under Part II, Item 8, of this report and Outlook for additional information.

Cash Flows from Investing Activities

2008 versus 2007

Ameren used more cash for investing activities during 2008, compared with 2007. Net cash used for capital expenditures increased in 2008 as a result of power plant scrubber projects, upgrades at various power plants, and reliability improvements of the transmission and distribution system. Additionally, increased purchases and higher prices resulted in a $105 million increase in nuclear fuel expenditures.

UE’s cash used in investing activities increased during 2008, compared with 2007. Nuclear fuel expenditures increased $105 million resulting from increased purchases for future refueling outages at its Callaway nuclear plant and higher prices. In addition, capital expenditures increased $249 million. This increase was a result of increased spending related to a power plant scrubber project, reliability improvements of the transmission and distribution system, and various plant upgrades. This increase was partially offset by UE’s receipt of $36 million in proceeds from intercompany note receivables with Ameren, and one of its subsidiaries.

CIPS’ cash used in investing activities during 2008 increased compared with 2007. Capital expenditures increased $17 million in 2008 from 2007 primarily because of reliability improvements of the transmission and distribution system. During both years, this was offset by cash received from payments on an intercompany note receivable.

Genco’s cash used in investing activities increased in 2008 compared with the same period in 2007. Capital expenditures increased $126 million, principally due to a power plant scrubber project. This increase was offset, in part, by a $7 million decrease in emission allowance purchases.

CILCORP’s and CILCO’s cash used in investing activities increased in 2008, compared with 2007. Cash used in investing activities increased as a result of a $65 million increase in capital expenditures, primarily due to a power plant scrubber project and plant upgrades at AERG. The receipt of net repayments of money pool advances in 2007 compared to 2008 also increased cash flows used in investing activities in 2008.

IP’s cash used in investing activities increased in 2008 compared with 2007. Capital expenditures increased by $8 million in 2008 from 2007 primarily because of reliability improvements of the transmission and distribution system. Net money pool advances increased by $44 million in 2008 compared with 2007.

2007 versus 2006

Ameren used more cash for investing activities in 2007 than in 2006. Net cash used for capital expenditures increased in 2007 as a result of power plant scrubber installation projects, other upgrades at various power plants, and reliability improvements of the transmission and

distribution systems, but this increase was reduced by the absence in 2007 of CT acquisitions that occurred in 2006. The $43 million decrease in 2007 of proceeds from sales of noncore properties also increased net cash used in investing activities. An $18 million decrease in emission allowance purchases benefited cash flows from investing activities, while cash received in 2007 for emission allowance sales was $66 million less than in the prior year, because remaining allowances are expected to be retained for environmental compliance needs.

UE’s cash used in investing activities decreased in 2007, compared with 2006, principally because of the $292 million expended for CT purchases in 2006 that was not spent in 2007. Otherwise, capital expenditures increased $135 million because of storm repair costs, a power plant scrubber installation project, and other upgrades at various power plants. Other impacts on cash used in investing activities were the absence of sales of noncore properties in 2007 compared with a $13 million sale in 2006, and the 2006 receipt of $67 million in proceeds from an intercompany note related to the transfer of UE’s Illinois territory to CIPS. Additionally, nuclear fuel expenditures increased $29 million in 2007 over 2006 because of a refueling outage, and sales of emission allowances decreased $35 million because remaining allowances are being retained for environmental compliance needs.

CIPS’ cash used in investing activities decreased in 2007, compared with 2006. CIPS’ investing cash flow was positively affected by a $3 million increase in proceeds from CIPS’ note receivable from Genco in 2007 compared with 2006 and the lack of a 2006 $17 million expenditure to repurchase its own outstanding bond. Capital expenditures were $3 million lower in 2007 than in 2006.

Genco had an increase in net cash used in investing activities for 2007, compared with 2006. This increase was due primarily to a $106 million increase in capital expenditures related to a scrubber project at one of its power plants and various other plant upgrades. Emission allowance purchases decreased by $6 million.

CILCORP’s and CILCO’s cash used in investing activities increased in 2007, compared with 2006. Cash flow used in investing activities increased as a result of a $135 million increase in capital expenditures, primarily due to a power plant scrubber project and other plant upgrades at AERG. The absence in 2007 of $11 million of proceeds received in 2006 from the sale of leveraged leases, and (for CILCORP only) the absence in 2007 of a 2006 note receivable payment from Ameren Energy Resources Company in the amount of $71 million related to the 2005 transfer of leveraged leases from CILCORP to Ameren Energy Resources Company, contributed to the increase in cash used in investing activities in 2007. The net year-over-year reduction of $83 million and $84 million in money pool advances for CILCORP and CILCO, respectively, and a $12 million reduction of emission allowance purchases benefited cash flows from investing activities in 2007.

IP’s net use of cash in investing activities for 2007 was comparable with 2006.

See Environmental Capital Expenditures below and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a further discussion of future environmental capital investment estimates.

Capital Expenditures

The following table presents the capital expenditures by the Ameren Companies for the years ended December 31, 2008, 2007, and 2006:


Capital Expenditures	2008		2007		2006
Ameren ^(a)	$	1,896	$	1,381	$	1,284
UE		874		625		782
CIPS		96		79		82
Genco		317		191		85
CILCORP		319		254		119
CILCO (Illinois Regulated)		61		64		53
CILCO (AERG)		258		190		66
IP		186		178		179

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

Ameren’s 2008 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE spent $149 million toward a scrubber at one of its power plants, and incurred storm damage-related expenditures of $12 million. CIPS and IP incurred storm damage-related expenditures of $7 million and $8 million, respectively. At Genco and AERG, there were cash outlays of $205 million and $137 million, respectively, for power plant scrubber projects. The scrubbers are necessary to comply with environmental regulations. Other capital expenditures were principally to maintain, upgrade and expand the reliability of the transmission and distribution systems of UE, CIPS, CILCO, and IP as well as various plant upgrades.

Ameren’s 2007 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE spent $101 million toward a scrubber at one of its power plants, and incurred storm damage-related expenditures of $56 million. IP incurred storm damage-related expenditures of $24 million. At Genco and AERG, there were cash outlays of $102 million and $76 million, respectively, for power plant scrubber projects. In conjunction with the scrubber project, AERG also made expenditures for a power plant boiler upgrade of $45 million. Other capital expenditures were principally to maintain, upgrade and expand the reliability of the transmission and distribution systems of UE, CIPS, CILCO, and IP as well as various plant upgrades.

Ameren’s 2006 capital expenditures principally consisted of the following expenditures at its subsidiaries. UE purchased three CTs totaling $292 million. In addition, UE spent $40 million toward a scrubber at one of its power plants, and incurred storm damage-related expenditures of

$47 million. CIPS and IP incurred storm damage-related expenditures of $16 million and $27 million, respectively. At Genco and AERG, there were cash outlays of $24 million and $11 million, respectively, for scrubber projects. Genco also made expenditures for a power plant boiler upgrade of $16 million. Other capital expenditures were principally to maintain, upgrade and expand the reliability of the transmission and distribution systems of UE, CIPS, CILCO, and IP.

The following table estimates the capital expenditures that will be incurred by the Ameren Companies from 2009 through 2013, including construction expenditures, capitalized interest and allowance for funds used during construction (except for Genco and AERG, which have no allowance for funds used during construction), and estimated expenditures for compliance with environmental standards:


	2009		2010 - 2013				Total
UE	$	835	$	3,335-	$	4,435	$	4,170-	$	5,270
CIPS		90		350-		475		440-		565
Genco		270		1,180-		1,500		1,450-		1,770
CILCO (Illinois Regulated)		75		250-		340		325-		415
CILCO (AERG)		85		440-		555		525-		640
IP		220		715-		960		935-		1,180
EEI		50		255-		335		305-		385
Other		60		75-		100		135-		160
Ameren ^(a)	$	1,685	$	6,600-	$	8,700		$ 8,285-	$	10,385

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

UE’s estimated capital expenditures include transmission, distribution and generation-related activities, as well as expenditures for compliance with new environmental regulations discussed below. CIPS’, CILCO’s (Illinois Regulated), and IP’s estimated capital expenditures are primarily for electric and gas transmission and distribution-related activities. Genco’s estimated capital expenditures are primarily for compliance with environmental regulations and upgrades to existing coal and gas-fired generating facilities. CILCO (AERG)’s estimate includes capital expenditures primarily for compliance with environmental regulations at AERG’s generating facilities, as well as generation-related activities.

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 or power may be purchased, among other things. In addition, Ameren and Genco are currently considering divestiture of some of Genco’s smaller non-rate-regulated generating units. 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.

As a result of the disruption and uncertainties in the capital and credit markets, we are actively evaluating

opportunities to defer or reduce our planned capital spending. This included reducing our 2009 expenditures from previously expected levels. See Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report for further discussion.

Environmental Capital Expenditures

Ameren, UE, Genco, AERG and EEI will incur significant costs in future years to comply with existing federal EPA and state regulations regarding SO ₂ , NO _x and mercury emissions from coal-fired power plants.

In May 2005, the EPA issued regulations with respect to SO ₂ and NO _x emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule). The federal Clean Air Interstate Rule requires generating facilities in 28 eastern states, including Missouri and Illinois where our generating facilities are located, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO ₂ emissions, annual NO _x emissions, and ozone season NO _x emissions. The cap-and-trade program for both annual and ozone season NO _x emissions went into effect on January 1, 2009. The SO ₂ emissions cap-and-trade program is scheduled to take effect in 2010.

In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Mercury Rule. The court ruled that the EPA erred in the method used to remove electric generating units from the list of sources subject to the maximum available control technology requirements under the Clean Air Act. The EPA and a group representing the electric utility industry filed petitions for rehearing; however, the court denied those petitions in May 2008. A group representing the electric utility industry and the EPA filed petitions for review of the U.S. Court of Appeals decision with the U.S. Supreme Court in September 2008 and October 2008, respectively. In February 2009, the EPA withdrew its petition to the U.S. Supreme Court. In February 2009, the U.S. Supreme Court denied the petition for review filed by a group representing the electric utility industry. The impact of this decision is that the EPA will move forward with a MACT standard for mercury emissions. The standard is expected to be available in draft form by mid to late 2009, and compliance is expected to be required in the 2013 to 2015 timeframe.

We are currently evaluating the impact that the court decision will have on our environmental compliance strategy. At this time, we are unable to predict the outcome of this legal proceeding, the actions the EPA or U.S. Congress may take in response to the court decision and the timing of such actions. We also cannot predict at this time the ultimate impact the court decision and resulting regulatory actions will have on our estimated capital costs for compliance with environmental rules.

program that cannot be used to facilitate the attainment of ambient air quality standards for ozone and fine particulate matter. In September 2008, the EPA as well as several environmental groups, a group representing the electric utility industry and the National Mining Association filed petitions for rehearing with the U.S. Court of Appeals. In December 2008, the U.S. Court of Appeals essentially reversed their July 2008 decision to vacate the federal Clean Air Interstate Rule. The U.S. Court of Appeals granted the EPA petition for reconsideration and decided to remand the rule to the EPA for further action to remedy the rule’s flaws in accordance with the U.S. Court of Appeals July 2008 opinion in the case. The impact of the decision is that the existing Illinois and Missouri rules to implement the federal Clean Air Interstate Rule will remain in effect until the federal Clean Air Interstate Rule is revised by the EPA at which point the Illinois and Missouri rules may be subject to change.

The state of Missouri adopted state rules to implement the federal Clean Air Interstate Rule for regulating SO ₂ and NO _x emissions from electric generating units in Missouri. The rules are a significant part of Missouri’s plan to attain existing ambient standards for ozone and fine particulates, as well as meeting the requirements of the federal Clean Air Visibility Rule. As a result of the Missouri rules, UE will manage emission allowances and install pollution control equipment. Missouri also adopted state rules to implement the federal Clean Air Mercury Rule; however, the state rules are not enforceable as a result of the U.S. Court of Appeals decision to vacate the federal Clean Air Mercury Rule.

We do not believe the court decision that vacated the federal Clean Air Mercury Rule will significantly affect pollution control obligations in Illinois. Under the MPS, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90% in exchange for accelerated installation of NO _x and SO ₂ controls. To comply with the rule, Genco, CILCO (AERG) and EEI have begun putting into service equipment designed to reduce mercury emissions. As a result of the Illinois rules, Genco, AERG and EEI will need to procure allowances and install pollution

control equipment. Current plans include the installation of scrubbers for SO ₂ reduction and optimizing operations of selective catalytic reduction (SCR) systems for NO _x reduction at certain coal-fired plants in Illinois.

In October 2008, Genco, CILCO (AERG) and EEI submitted a request for a variance from the MPS to the Illinois Pollution Control Board. In preparing this request, Genco, CILCO (AERG) and EEI worked with the Illinois EPA and agreed to the installation of more stringent SO ₂ and NO _x controls at various stages between 2010 and 2020 in order to make the variance proposal “environmentally neutral.” In January 2009, the Illinois Pollution Control Board denied the variance request on procedural grounds. Genco, CILCO (AERG) and EEI filed a motion for reconsideration in February 2009 and, with the Illinois EPA’s concurrence, seek to amend the MPS within a pending rulemaking pertaining to technical amendments of the underlying mercury regulations. Revisions to the MPS within that rulemaking will require Illinois Pollution Control Board approval. If approved, this variance or rule amendment could allow Genco to defer approximately $375 million of environmental capital expenditures from the 2009-2012 timeframe to the 2013-2015 timeframe. This amount is reduced from the $500 million disclosed in Genco’s Quarterly Report on Form 10-Q for the period ended September 30, 2008, because of revisions to the size and timing of projected environmental capital expenditures if no variance is granted. A decision is expected in 2009.

The EPA finalized regulations in March 2008 that will lower the ambient standard for ozone. States must submit their nonattainment plans in March 2009. A final action by the EPA to designate areas as nonattainment is expected in March 2010, and state implementation plans will need to be submitted in 2013 unless Illinois and Missouri seek extensions of various requirement dates. Additional emission reductions may be required as a result of future state implementation plans. At this time, we are unable to determine the impact such state actions would have on our results of operations, financial position, or liquidity.

The table below presents estimated capital costs that are based on current technology to comply with the federal Clean Air Interstate Rule and related state implementation plans through 2018 as well as federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility rule. The estimates described below could change depending upon additional federal or state requirements, the implementation of any revisions to the federal Clean Air Interstate Rule, the requirements under a mercury MACT standard, whether the variance or rule amendment request with respect to the Illinois MPS discussed above is granted, new technology, variations in costs of material or labor, or alternative compliance strategies, among other reasons. The timing of estimated capital costs may also be influenced by whether emission allowances are used to comply with any future rules, thereby deferring capital investment.


	2009		2010 - 2013				2014 - 2018				Total
UE ^(a)	$	100	$	525-	$	655	$	1,530-	$	1,885	$	2,155-	$	2,640
Genco		230		875-		1,085		95-		125		1,200-		1,440
AERG		55		365-		455		60-		80		480-		590
EEI		15		120-		155		530-		660		665-		830
Ameren	$	400	$	1,885-	$	2,350	$	2,215-	$	2,750	$	4,500-	$	5,500

(a)	UE’s expenditures are expected to be recoverable in rates over time.

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

2008 versus 2007

During the year ended December 31, 2008, the Ameren Companies issued $1.9 billion of senior debt. The proceeds were used to repurchase, redeem and fund maturities of $842 million of long-term debt, to reduce short-term borrowings, and to fund capital expenditures and other working capital needs at UE, CIPS, Genco, CILCO, and IP. During the year ended December 31, 2007, net short-term debt borrowings of $860 million and long-term borrowings of $674 million were used to fund $488 million of maturities of long-term debt, to fund working capital needs at Ameren subsidiaries and to build liquidity during a period of legislative uncertainty in Illinois. Additionally, CILCO redeemed the remaining shares of its 5.85% Class A preferred stock to complete the mandatory sinking fund redemption requirement resulting in a $16 million use of cash during 2008 compared with 2007. Benefiting 2008, compared with 2007, was a $63 million increase in proceeds from the issuance of Ameren common stock, which resulted from increased sales through Ameren’s 401(k) plan and DRPlus.

UE’s net cash from financing activities increased in the year ended December 31, 2008, compared with the year ended December 31, 2007. During 2008, UE used $699 million in proceeds from the issuance of senior secured notes to redeem outstanding auction-rate environmental improvement revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market, and to fund the current maturity of UE’s 6.75% first mortgage bonds. Additionally, net short-term borrowings increased $321 million. These borrowings were primarily used to fund working capital needs and capital expenditures. In 2007, UE issued $424 million in senior secured notes and received a $380 million capital contribution from Ameren to fund working capital requirements and to reduce net short-term debt borrowings.

CIPS had a net use of cash from financing activities in 2008, compared with a net source of cash in 2007. This change was because CIPS used net money pool borrowings and existing cash to fund a net reduction in short-term debt, to redeem $35 million of auction-rate environmental improvement revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market, and to fund the maturity of $15 million of its 5.375% senior secured notes during 2008. In 2007, CIPS used net short-term debt borrowings of $90 million to fund working capital needs and build liquidity and to fund $40 million of common stock dividends.

Genco issued $300 million of 7.00% senior unsecured notes during 2008, which resulted in a net source of cash from financing activities compared with a net use of cash in 2007. The proceeds from the issuance were used to fund capital expenditures and other working capital requirements, including a net reduction of $200 million of short-term borrowings during 2008 compared with 2007.

CILCORP’s and CILCO’s cash provided by financing activities decreased in 2008 compared with 2007. This decrease was primarily the result of CILCORP’s and CILCO’s net repayments of short-term borrowings during 2008 compared with 2007. These repayments were funded by a net increase in money pool borrowings of $98 million, primarily at AERG, and CILCO’s issuance of $150 million of its 8.875% senior secured notes. Partially offsetting the decrease were reduced redemptions and maturities of long-term debt in 2008. During 2008, $19 million of auction-rate environmental improvement revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market were redeemed at CILCO. In 2007, $50 million of CILCO’s 7.50% bonds matured. Also benefiting cash flows for the year ended December 31, 2008, were net borrowings of a $150 million direct loan from Ameren at CILCORP compared with $71 million net repayments during 2007.

IP’s cash from financing activities decreased in 2008, compared with 2007. During 2008, IP issued $730 million of senior secured notes and used the proceeds to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds that had adjusted to higher rates as a result of the collapse of the auction-rate securities market and repay short-term debt. Additionally, during 2008, IP funded $60 million of common stock dividends to Ameren and had net short-term debt repayments of $175 million. Comparatively, during 2007, IP issued $250 million of senior secured notes, paid $61 million of common stock dividends and had $100 million of net borrowings under the 2007 credit facility. These borrowings were used to fund $87 million of long-term debt maturities and $43 million of net money pool repayments to build liquidity in 2007.

2007 versus 2006

Ameren had an increase of $556 million in its net cash from financing activities in 2007, compared to 2006. Positive effects on cash included a net increase of $441 million in net short-term debt proceeds in 2007 over 2006, and a $442 million increase in the issuance of long-term debt. These increased proceeds were used to fund a $324 million increase in redemptions, repurchases, and maturities of long-term debt and to fund the working capital needs of UE, CIPS, CILCO and IP.

UE had a net source of cash from financing activities in 2007, compared with a net use of cash in 2006. The primary reasons for the change include a $380 million capital contribution from Ameren and the issuance of $424 million of senior secured notes in 2007. The proceeds were used to repay short-term debt and to fund working capital and capital expenditures. Other net uses of cash in 2007 included the repayment of a note Ameren issued in 2006 and an $18 million increase in common stock dividend payments.

CIPS had a net source of cash from financing activities in 2007, compared with a net use of cash in 2006. This was primarily the result of an increase of $55 million in net short-term debt proceeds in 2007 over 2006, and a $10 million

decrease in dividend payments. Cash was also positively affected in 2007 by a $20 million decrease in redemptions, repurchases, and maturities of long-term debt and the absence in 2007 of the 2006 payments of $67 million on an intercompany note with UE. Cash flows in 2006 benefited from $61 million in proceeds from long-term debt issuances that did not recur in 2007.

Genco had a net increase in cash used in financing activities for 2007 over 2006, principally because of a $125 million decrease in capital contributions received from Ameren. Cash benefited in 2007 by a $100 million increase in net proceeds from short-term debt.

CILCORP had a net source of cash from financing activities in 2007, compared with a net use of cash in 2006. CILCO’s cash provided by financing activities increased in 2007, compared with 2006. Net money pool repayments decreased $154 million at CILCORP and $161 million at CILCO. A net increase in short-term debt of $90 million at CILCORP and $15 million at CILCO in 2007 resulted in a positive effect on cash. In 2007, CILCORP and CILCO did not issue any dividends on common stock; in 2006 CILCORP issued $50 million and CILCO $65 million. As a result, cash flows from financing activities benefited in 2007 as compared to 2006. Additionally, in 2006 a note payable to Ameren was repaid, which resulted in a net use of cash of $113 million at CILCORP. Note payable repayments were only $71 million in 2007. These positive effects on cash were reduced by the lack of proceeds from the issuance of long-term debt in 2007 compared with $96 million at both CILCORP and CILCO in 2006.

IP had an increase in its net cash provided by financing activities in 2007 compared with 2006. This was primarily the result of an increase in proceeds from short-term debt and a $175 million increase from the issuance of long-term debt. The proceeds from the 2007 long-term debt issuance were used to repay borrowings under the Ameren utility money pool and under the 2007 credit facility. Other net uses of cash included $61 million of common stock dividends in 2007.

Short-term Borrowings and Liquidity

External short-term borrowings typically consist of drawings under committed bank credit facilities. See Note 4 – Short-term Borrowings and Liquidity to our financial statements under Part II, Item 8, of this report for additional information on credit facilities, short-term borrowing activity, relevant interest rates, and borrowings under Ameren’s utility and non-state-regulated subsidiary money pool arrangements.

The following table presents the various committed bank credit facilities of the Ameren Companies and AERG, and their availability as of December 31, 2008:


Credit Facility	Expiration	Amount Committed		Amount Available ^(a)
Ameren, UE and Genco:
Multiyear revolving ^(b)	July 2010	$	1,150	$	540	^(f)
CIPS, CILCORP, CILCO, IP and AERG:
2007 Multiyear revolving ^(c)(d)	January 2010		500		415
2006 Multiyear revolving ^(c)(e)	January 2010		500		220

(a)	After excluding $75 million and $17 million of unfunded Lehman Brothers Bank, FSB participations as of December 31, 2008, under the $1.15 billion credit facility and 2006 $500 million credit facility, respectively.

(b)	Ameren Companies may access this credit facility through intercompany borrowing arrangements.

(c)	See Note 4 – Short-term Borrowings and Liquidity to our financial statements under Part II, Item 8, of this report for discussion of the amendments to these facilities.

(d)

The maximum amount available to each borrower under this facility at December 31, 2008, including for the issuance of letters of credit, was limited as follows: CILCORP – $125 million, CILCO – $75 million, IP – $200 million and AERG – $100 million. CIPS and CILCO have the option of permanently reducing their ability to borrow under the 2006 $500 million credit facility and shifting such capacity, up to the same limits, to the 2007 $500 million credit facility. In July 2007, CILCO shifted $75 million of its sublimit under the 2006 $500 million credit facility to this facility.

(e)

The maximum amount available to each borrower under this facility at December 31, 2008, including for the issuance of letters of credit, was limited as follows: CIPS – $135 million, CILCORP – $50 million, CILCO – $75 million, IP – $150 million and AERG – $200 million. In July 2007, CILCO shifted $75 million of its capacity under this facility to the 2007 $500 million credit facility. Accordingly, as of December 31, 2008, CILCO had a sublimit of $75 million under this facility and a $75 million sublimit under the 2007 credit facility.

(f)	In addition to amounts drawn on this facility, the amount available is further reduced by standby letters of credit issued under the facility. The amount of such letters of credit at December 31, 2008, was $9 million.

Ameren can directly borrow under the $1.15 billion facility, as amended, up to the entire amount of the facility. UE can directly borrow under this facility up to $500 million on a 364-day basis. Genco can directly borrow under this facility up to $150 million on a 364-day basis. The amended facility will terminate on July 14, 2010, with respect to all borrowers thereunder. The termination date for UE and Genco is July 9, 2009, subject to the annual 364-day renewal provisions for their individual sublimits under the facility. This facility was also available for use, subject to applicable regulatory short-term borrowing authorizations, by EEI or other Ameren non-state-regulated subsidiaries 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, AERG, Marketing Company and AFS, 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. IP is not currently borrowing under the unilateral borrowing agreement.

On September 15, 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New York. As of December 31, 2008, Lehman Brothers Bank, FSB, a subsidiary of Lehman, had lending commitments of $100 million and $21 million under the $1.15 billion credit facility and the 2006 $500 million credit facility, respectively. At this time, we do not know if Lehman Brothers Bank, FSB will seek to assign to other parties any of its commitments under our credit facilities. Assuming Lehman Brothers Bank, FSB does not fund its pro-rata share of funding requests under these two facilities, and such participations are not assigned or otherwise transferred to other lenders, total

amounts accessible by the Ameren Companies and AERG will be limited to amounts not less than $1.05 billion under the $1.15 billion credit facility and $479 million under the 2006 $500 million credit facility. The Ameren Companies and AERG do not believe that the potential reduction in available capacity under the credit facilities if Lehman Brothers Bank, FSB does not fund its commitments will have a material impact on their liquidity.

On June 25, 2008, Ameren entered into a $300 million term loan agreement due June 24, 2009, which was fully drawn on June 26, 2008. See Note 4 – Short-term Borrowings and Liquidity to our financial statements under Part II, Item 8, of this report for additional information.

On January 21, 2009, Ameren entered into a $20 million term loan agreement due January 20, 2010, which was fully drawn on January 21, 2009. See Note 4 – Short-term Borrowings and Liquidity to our financial statements under Part II, Item 8, of this report for additional information.

Ameren Services is responsible for operation and administration of the money pool agreements. See Note 4 – Short-term Borrowings and Liquidity 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.

In addition to committed credit facilities, a further source of liquidity for the Ameren Companies from time to time is available cash and cash equivalents. At December 31, 2008, Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP had $92 million, less than $1 million, less than $1 million, $2 million, less than $1 million, less than $1 million and $50 million, respectively, of cash and cash equivalents.

The issuance of short-term debt securities by Ameren’s utility subsidiaries is subject to approval by FERC under the Federal Power Act. In March 2008, FERC issued an order authorizing these utility subsidiaries to issue short-term debt securities subject to the following limits on outstanding balances: UE – $1 billion, CIPS – $250 million, and CILCO – $250 million. The authorization was effective as of April 1, 2008, and terminates on March 31, 2010. IP has unlimited short-term debt authorization from FERC.

Genco was authorized by FERC in its March 2008 order to have up to $500 million of short-term debt outstanding at any time. AERG and EEI have unlimited short-term debt authorization from FERC.

The issuance of short-term debt securities by Ameren and CILCORP (parent) is not subject to approval by any regulatory body.

The Ameren Companies continually evaluate the 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.

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 2008, 2007 and 2006 for the Ameren Companies 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 5 – Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report.


	Month Issued, Redeemed, Repurchased or Matured	2008		2007		2006
Issuances
Long-term debt
UE:
6.40% Senior secured notes due 2017	June	$	-	$	424	$	-
6.00% Senior secured notes due 2018	April		250		-		-
6.70% Senior secured notes due 2019	June		449		-		-
CIPS:
6.70% Senior secured notes due 2036	June		-		-		61
Genco:
7.00% Senior notes due 2018	April		300		-		-
CILCO:
6.20% Senior secured notes due 2016	June		-		-		54
6.70% Senior secured notes due 2036	June		-		-		42
8.875% Senior secured notes due 2013	December		150		-		-
IP:
6.25% Senior secured notes due 2016	June		-		-		75
6.125% Senior secured notes due 2017	November		-		250		-
6.25% Senior secured notes due 2018	April		336		-		-
9.75% Senior secured notes due 2018	October		394		-		-
Total Ameren long-term debt issuances		$	1,879	$	674	$	232
Common stock
Ameren:
DRPlus and 401(k)	Various	$	154	$	91	$	96
Total common stock issuances		$	154	$	91	$	96
Total Ameren long-term debt and common stock issuances		$	2,033	$	765	$	328
Redemptions, Repurchases and Maturities
Long-term debt
Ameren:
2002 5.70% notes due 2007	February	$	-	$	100	$	-
Senior notes due 2007	May		-		250		-
UE:
City of Bowling Green capital lease (Peno Creek CT)	Various		4		4		4
2000 Series B environmental improvement bonds due 2035	April		63		-		-
2000 Series A environmental improvement bonds due 2035	May		64		-		-
2000 Series C environmental improvement bonds due 2035	May		60		-		-
1991 Series environmental improvement bonds due 2020	May		43		-		-
6.75% Series first mortgage bonds due 2008	May		148		-		-
CIPS:
7.05% First mortgage bonds due 2006	June		-		-		20
2004 Series pollution control bonds due 2025	April		35		-		-
5.375% Senior secured notes due 2008	December		15		-		-
CILCORP:
9.375% Senior bonds due 2029	Various		-		-		12


	Month Issued, Redeemed, Repurchased or Matured	2008		2007		2006
CILCO:
7.73% First mortgage bonds due 2025	July		-		-		21
7.50% First mortgage bonds due 2007	January		-		50		-
2004 Series pollution control bonds due 2039	April		19		-		-
IP:
Series 2001 Non-AMT bonds due 2028	May		112		-		-
Series 2001 AMT bonds due 2017	May		75		-		-
1997 Series A pollution control bonds due 2032	May		70		-		-
1997 Series B pollution control bonds due 2032	May		45		-		-
1997 Series C pollution control bonds due 2032	June		35		-		-
Note payable to IP SPT:
5.54% Series due 2007	Various		-		-		107
5.65% Series due 2008	Various		54		84		-
Preferred Stock
CILCO:
5.85% Series	July		16		1		1
Total Ameren long-term debt and preferred stock redemptions, repurchases and maturities		$	858	$	489	$	165

The following table presents information with respect to the Form S-3 shelf registration statements filed and effective for certain Ameren Companies as of December 31, 2008:


	Effective Date	Authorized Amount
Ameren ^(a)	November 2008	Not Limited
UE ^(b)	June 2008	Not Limited
CIPS ^(a)	November 2008	Not Limited
Genco ^(a)	November 2008	Not Limited
CILCO ^(a)	November 2008	Not Limited
IP ^(a)	November 2008	Not Limited

(a)	In November 2008, Ameren, as a well-known seasoned issuer, along with CIPS, Genco, CILCO and IP, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in November 2011.

(b)	In June 2008, UE, as a well-known seasoned issuer, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in June 2011.

In July 2008, Ameren filed a Form S-3 registration statement with the SEC authorizing the offering of six million additional shares of its common stock under DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, 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 its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan (including a subsidiary plan that is now merged into the Ameren 401(k) plan), Ameren issued 4.0 million, ($154 million) shares of common stock

in 2008, 1.7 million ($91 million) in 2007, and 1.9 million ($96 million) in 2006.

Ameren, UE, CIPS, Genco, CILCO and IP 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 that meets the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

Indebtedness Provisions and Other Covenants

See Note 4 – Short-term Borrowings and Liquidity and Note 5 – 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 (and applicable cross-default provisions) contained in our bank credit and term loan facilities and in certain of the Ameren Companies’ indenture agreements and articles of incorporation.

At December 31, 2008, the Ameren Companies were in compliance with their credit facility, term loan 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. 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 or make access to the capital markets uncertain or limited. Such events could increase our cost of capital and adversely affect our ability to access the capital markets.

Dividends

Ameren paid to its shareholders common stock dividends totaling $534 million, or $2.54 per share, in 2008, $527 million, or $2.54 per share, in 2007, and $522 million, or $2.54 per share, in 2006. This resulted in a payout rate based on net income of 88% in 2008, 85% in 2007, and 95% in 2006. Dividends paid to common shareholders in relation to net cash provided by operating activities for the same periods were 35% in 2008, 48% in 2007 and 41% in 2006.

On February 13, 2009, the board of directors of Ameren declared a quarterly dividend on Ameren’s common stock of 38.5 cents per share, payable on March 31, 2009, to shareholders of record on March 11, 2009. The board’s action was consistent with an annualized dividend of $1.54 per share, or a 39% reduction from the previous annual dividend level of $2.54 per share. The new annualized dividend rate of $1.54 per share would represent a payout rate of 53% based on 2008 net income.

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, as it has done in the past, the board of directors is expected to consider various issues, including Ameren’s overall payout ratio, payout ratios of our peers, projected cash flow and potential future cash flow requirements, historical earnings and cash flow, projected earnings, return on investments with similar risk characteristics, impacts of regulatory orders or legislation, and other key business considerations.

Certain of our financial agreements and corporate organizational documents contain covenants and conditions that, among other things, restrict the Ameren Companies’ payment of dividends in certain circumstances. At December 31, 2008, except as discussed below with respect to the 2007 $500 million credit facility and the 2006 $500 million credit facility, none of these circumstances existed at the Ameren Companies and, as a result, they were allowed to pay dividends.

UE would be restricted as to dividend payments on its common and preferred stock if it were to extend or defer interest payments on its subordinated debentures. CIPS’ articles of incorporation require its dividend payments on common stock 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 on common stock if debt service coverage ratios are below a defined threshold. CILCORP has common and preferred stock 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 on common stock relative to the ratio of its balance of retained earnings to the annual dividend requirement on its preferred stock.

The 2007 $500 million credit facility and the 2006 $500 million credit facility limit CIPS, CILCORP, CILCO and IP to common and preferred stock dividend payments of $10 million per year each if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, have received a below investment-grade credit rating from either Moody’s or S&P. With respect to AERG, which currently is not rated by Moody’s or S&P, the common and preferred stock dividend restriction will not apply if its ratio of consolidated total debt to consolidated operating cash flow, pursuant to a calculation defined in the facilities, is less than or equal to 3.0 to 1. CILCORP’s senior unsecured credit ratings from Moody’s and S&P are below investment-grade, causing it to be subject to this dividend payment limitation. As of December 31, 2008, AERG failed to meet the debt-to-operating cash flow ratio test in the 2007 and 2006 $500 million credit facilities. AERG therefore is currently limited in its ability to pay dividends to a maximum of $10 million per fiscal year. The other borrowers thereunder are not currently limited in their dividend payments by this provision of the 2007 or 2006 $500 million credit facilities.

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


	2008		2007		2006
UE	$	264	$	267	$	249
CIPS		-		40		50
Genco		101		113		113
CILCORP ^(a)		-		-		50
IP		60		61		-
Nonregistrants		109		46		60
Dividends paid by Ameren	$	534	$	527	$	522

(a)	CILCO paid to CILCORP dividends of $- million, $- million and $65 million for the years ended December 31, 2008, 2007 and 2006, respectively.

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 considers the declaration of the preferred stock dividends to shareholders of record on a certain date,

stating the date on which the dividend is payable and the amount to 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, 2008. 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 plans. These 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 ⁾	$	6,894	$	378	$	358	$	534	$	5,624
Short-term debt		1,174		1,174		-		-		-
Interest payments ⁽ ^d ⁾		5,210		444		831		787		3,148
Operating leases ⁽ ^e ⁾		392		39		66		54		233
Illinois electric settlement agreement		29		27		2		-		-
Other obligations ⁽ ^f ⁾		5,427		1,359		2,456		974		638
Total cash contractual obligations	$	19,126	$	3,421	$	3,713	$	2,349	$	9,643
UE:
Long-term debt and capital lease obligations ^(c)	$	3,684	$	4	$	8	$	383	$	3,289
Short-term debt		251		251		-		-		-
Intercompany note payable – Ameren		92		92		-		-		-
Interest payments ⁽ ^d ⁾		2,698		215		430		415		1,638
Operating leases ⁽ ^e ⁾		174		15		28		25		106
Other obligations ⁽ ^f ⁾		2,439		586		1,087		387		379
Total cash contractual obligations	$	9,338	$	1,163	$	1,553	$	1,210	$	5,412
CIPS:
Long-term debt ^(c)	$	422	$	-	$	150	$	-	$	272
Short-term debt		62		62		-		-		-
Borrowings from money pool		44		44		-		-		-
Interest payments ⁽ ^d ⁾		313		27		49		34		203
Operating leases ⁽ ^e ⁾		2		-		1		1		-
Illinois electric settlement agreement		4		4		-		-		-
Other obligations ⁽ ^f ⁾		369		110		135		78		46
Total cash contractual obligations	$	1,216	$	247	$	335	$	113	$	521
Genco:
Long-term debt ^(c)	$	775	$	-	$	200	$	-	$	575
Intercompany note payable – CIPS		87		42		45		-		-
Borrowings from money pool		80		80		-		-		-
Interest payments ⁽ ^d ⁾		739		60		100		86		493
Operating leases ⁽ ^e ⁾		143		9		17		17		100
Illinois electric settlement agreement		12		11		1		-		-
Other obligations ⁽ ^f ⁾		602		144		330		120		8
Total cash contractual obligations	$	2,438	$	346	$	693	$	223	$	1,176
CILCORP:
Long-term debt ⁽ ^b ⁾ ^(g ⁾	$	334	$	124	$	-	$	-	$	210
Short-term debt ^(g)		50		50		-		-		-
Borrowings from money pool		98		98		-		-		-
Intercompany note payable – Ameren		152		152		-		-		-
Interest payments ⁽ ^d ⁾ ^(g)		420		28		40		40		312
Operating leases ⁽ ^e ⁾		18		1		3		2		12
Illinois electric settlement agreement		7		7		-		-		-
Other obligations ⁽ ^f ⁾		797		178		332		171		116
Total cash contractual obligations	$	1,876	$	638	$	375	$	213	$	650


	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		After 5 Years
CILCO:
Long-term debt	$	279	$	-	$	-	$	151	$	128
Short-term debt		236		236		-		-		-
Borrowings from money pool		98		98		-		-		-
Interest payments ⁽ ^d ⁾		195		21		42		42		90
Operating leases ⁽ ^e ⁾		18		1		3		2		12
Illinois electric settlement agreement		7		7		-		-		-
Other obligations ⁽ ^f ⁾		797		178		332		171		116
Total cash contractual obligations	$	1,630	$	541	$	377	$	366	$	346
IP:
Long-term debt ⁽ ^b ⁾ ⁽ ^c ⁾	$	1,400	$	250	$	-	$	-	$	1,150
Interest payments ⁽ ^d ⁾		845		93		170		170		412
Operating leases ⁽ ^e ⁾		8		3		4		1		-
Illinois electric settlement agreement		6		5		1		-		-
Other obligations ⁽ ^f ⁾		616		173		267		87		89
Total cash contractual obligations	$	2,875	$	524	$	442	$	258	$	1,651

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

(b)	Excludes fair-market value adjustments of long-term debt of $49 million for CILCORP and $10 million for IP.

(c)	Excludes unamortized discount of $7 million at UE, $1 million at CIPS, $1 million at Genco, and $10 million at IP.

(d)	The weighted average variable-rate debt has been calculated using the interest rate as of December 31, 2008.

(e)

Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. Ameren’s $2 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)	See Other Obligations within Note 15 – Commitments and Contingencies under Part II, Item 8 of this report, for discussion of items represented herein.

(g)	Represents parent company only.

The Ameren Companies adopted the provisions of FIN 48, “Accounting for Uncertainty in Income Taxes” on January 1, 2007. As of December 31, 2008, the amounts of unrecognized tax benefits under the provisions of FIN 48 were $110 million, $20 million, $- million, $47 million, $25 million, $25 million and $- million for Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP, respectively. It is reasonably possible to expect that the settlement of an unrecognized tax benefit will result in an underpayment or overpayment of tax and related interest. However, there is a high degree of uncertainty with respect to the timing of cash payments or receipts associated with unrecognized tax benefits. The amount and timing of certain payments is not reliably estimable or determinable at this time. See Note 13 – Income Taxes under Part II, Item 8, of this report for information regarding the Ameren Companies’ unrecognized tax benefits and related liabilities for interest expense.

Off-Balance-Sheet Arrangements

At December 31, 2008, 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	Baa3	BBB-	BBB+
Senior unsecured debt	Baa3	BB+	BBB+
UE:
Issuer/corporate credit rating	Baa2	BBB-	A-
Secured debt	Baa1	BBB	A+
CIPS:
Issuer/corporate credit rating	Ba1	BBB-	BBB-
Secured debt	Baa3	BBB+	BBB+
Senior unsecured debt	Ba1	BBB-	BBB
Genco:
Issuer/corporate credit rating	-	BBB-	BBB+
Senior unsecured debt	Baa3	BBB-	BBB+
CILCORP:
Issuer/corporate credit rating	-	BBB-	BBB-
Senior unsecured debt	Ba2	BB+	BBB-
CILCO:
Issuer/corporate credit rating	Ba1	BBB-	BBB
Secured debt	Baa2	BBB+	A-
IP:
Issuer/corporate credit rating	Ba1	BBB-	BBB-
Secured debt	Baa3	BBB	BBB+

Moody’s Ratings Actions

On February 12, 2008, Moody’s affirmed the ratings of Ameren and Genco but changed their rating outlook to negative from stable. Moody’s placed the long-term credit ratings of UE under review for possible downgrade and affirmed UE’s commercial paper rating. In addition, Moody’s affirmed the ratings of CIPS, CILCORP, CILCO and IP and maintained a positive rating outlook on these four companies. According to Moody’s, the review of UE’s ratings was prompted by declining cash flow coverage metrics, increased operating costs, higher capital expenditures for environmental compliance and transmission and distribution system investment, and significant regulatory lag in the recovery of these costs. Moody’s stated that the negative outlook on the credit rating of Genco reflected Genco’s “position as a predominantly coal generating company that is likely to be seriously affected by more stringent environmental regulations, including a potential cap or tax on carbon emissions.” The negative outlook on the ratings of Ameren, according to Moody’s, reflects the factors that impacted its subsidiaries, UE and Genco.

On May 21, 2008, Moody’s lowered the credit ratings of UE to Baa1 for its senior secured debt and to Baa2 for its issuer rating and changed the rating outlook to stable. In its reasons for these actions, Moody’s reiterated the items noted above, attributing the declining cash flow metrics to increased fuel and purchased power costs, growing capital expenditures for environmental compliance and for transmission system reliability, and higher labor costs. They noted that UE was one of the few utilities in the country at the time of their report operating without fuel, purchased power, and environmental cost recovery mechanisms. Moody’s also placed UE’s commercial paper rating on review for possible downgrade due to its review of Ameren’s short-term rating as noted below. At the same time, the ratings of Ameren and Genco were changed from negative outlook to being on review for possible downgrade.

On August 13, 2008, Moody’s downgraded both the issuer and senior unsecured debt ratings of Ameren and the senior unsecured debt rating of Genco to Baa3 from Baa2 and changed the outlooks on these ratings to stable. Moody’s also downgraded the commercial paper ratings of Ameren and UE to P-3 from P-2. Moody’s stated that these downgrades were because of declining consolidated coverage ratios over the last several years and the expectation that ongoing cost pressures and the lack of timely regulatory recovery of some costs will prevent ratios from returning to historical levels in the near-term.

On January 29, 2009, Moody’s affirmed the ratings of CIPS, CILCORP, CILCO and IP and changed their rating outlooks to stable from positive. According to Moody’s, the change in the rating outlooks of these four companies was based on the near-term expiration of the 2007 and 2006 $500 million credit facilities in January 2010 and related

liquidity concerns. Moody’s also on January 29, 2009, affirmed the ratings of Ameren and UE with a stable outlook based on the January 2009 MoPSC electric rate order approving a rate increase and a FAC for UE.

On February 16, 2009, Moody’s affirmed the ratings of Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP with a stable outlook. The affirmation reflects Moody’s view that Ameren’s announcement to reduce its common dividend by 39% is a conservative, prudent, and credit positive action that will conserve cash and support financial coverage metrics. Moody’s stated that the more conservative dividend payout should also help facilitate the renewal of Ameren’s credit facilities that expire in 2010. They stated the dividend reduction should continue to reduce reliance on the credit facilities going forward and will likely be viewed favorably by lenders considering renewing or entering into new facilities with Ameren and its subsidiaries, which is important considering currently constrained credit market conditions. According to Moody’s, the stable outlook on Ameren, UE, CIPS, Genco, CILCORP, CILCO, and IP reflects recently constructive rate case outcomes at UE, CIPS, CILCO and IP, including the approval of a FAC at UE; the improving regulatory environments for investor-owned utilities in Illinois and Missouri; and Moody’s expectation that financial and cash flow coverage metrics should remain adequate to maintain current rating levels. In addition, Moody’s notes that the recent dividend reduction is supportive of the stable ratings outlooks and provides Ameren and its subsidiaries additional cushion at current rating levels.

S&P Ratings Actions

On March 19, 2008, S&P raised its senior unsecured debt ratings for CIPS to BBB- from B+ and for CILCORP to BB from B+.

On September 11, 2008, S&P upgraded its corporate credit ratings on CILCORP, CILCO, CIPS and IP to BBB- from BB. Senior secured debt ratings at CILCO and CIPS were upgraded to BBB+ from BBB and were upgraded at IP to BBB from BBB-. CILCORP’s senior unsecured debt rating was raised to BB+ from BB. All of Ameren’s other ratings were affirmed and all outlooks were stable. At the same time, S&P raised the business profiles of CIPS and IP to “strong” from “satisfactory.” The business profiles of CILCORP and CILCO remain “satisfactory.” S&P stated that the ratings upgrades were due to its assessment that the regulatory and political environment in Illinois will be reasonably supportive of investment grade credit quality with regard to the Ameren Illinois Utilities’ then pending rate cases. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for a discussion of the order issued by the ICC in these rate cases on September 24, 2008.

On February 25, 2009, S&P stated that it viewed the reduction in Ameren’s dividend as credit supportive. S&P did not make any changes in Ameren’s or its subsidiaries’ credit ratings or outlooks as a result of this action. S&P raised the business profile of UE to “excellent” from

“strong” to reflect the recent electric rate order issued by the MoPSC, which S&P viewed as constructive. See Note 2 – Rate and Regulatory Matters under Part II, Item 8, of this report for a discussion of the rate order issued by the MoPSC on January 27, 2009. S&P lowered the business profile of CILCO to “satisfactory” from “strong” reflecting S&P’s concerns regarding large capital expenditures needed to meet environmental compliance standards, while relying on falling market prices, due to the economic recession, for recovery.

Fitch Ratings Actions

On October 16, 2008, Fitch upgraded its issuer credit ratings on CILCO to BBB from BB+ and on CILCORP, CIPS and IP to BBB- from BB+. The senior secured debt ratings were raised at CIPS and IP to BBB+ from BBB and at CILCO to A- from BBB. Senior unsecured debt ratings were raised at CIPS and IP to BBB from BBB-, at CILCO to BBB+ from BBB-, and at CILCORP to BBB- from BB+. The outlook for each of these entities was changed to stable from rating watch positive. Fitch stated that the ratings upgrades were a result of the expected positive financial impact of electric and gas rate case decisions issued by the ICC in September 2008 and the reduction in business risk associated with the Illinois electric settlement agreement in 2007.

On February 17, 2009, Fitch stated that the reduction in Ameren’s common stock dividend and other cost cutting measures will be favorable to bondholders and credit quality. Fitch did not make any changes in Ameren’s or its subsidiaries’ ratings or outlooks as a result of this action.

Collateral Postings

Any adverse change in the Ameren Companies’ credit ratings may reduce access to capital and trigger additional collateral postings and prepayments. Such changes may also increase the cost of borrowing and fuel, power and gas supply, among other things, resulting in a negative impact on earnings. Collateral postings and prepayments made with external parties at December 31, 2008, were $109 million, $15 million, $26 million, $16 million, $16 million, and $36 million at Ameren, UE, CIPS, CILCORP, CILCO and IP, respectively. The amount of collateral external counterparties posted with Ameren was $7 million at December 31, 2008. Sub-investment-grade issuer or senior unsecured debt ratings (lower than “BBB-” or “Baa3”) at December 31, 2008, could have resulted in Ameren, UE, CIPS, Genco, CILCORP, CILCO or IP being required to post additional collateral or other assurances for certain trade obligations amounting to $202 million, $67 million, $24 million, $19 million, $36 million, $36 million, and $51 million, respectively. In addition, changes in commodity prices could trigger additional collateral postings and prepayments.

The cost of borrowing under our credit facilities can also increase or decrease depending upon the credit ratings of the borrower. 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. See Quantitative and Qualitative Disclosures About Market Risk –Interest Rate Risk under Part II, Item 7A, for information on credit rating changes with respect to insured tax-exempt auction-rate bonds.

OUTLOOK

Below are some key trends that may affect the Ameren Companies’ financial condition, results of operations, or liquidity in 2009 and beyond.

Economy and Capital and Credit Markets

The global capital and credit markets experienced extreme volatility and disruption in 2008, and we expect those conditions to continue throughout 2009 and potentially longer. Several factors have driven this situation, including deteriorating global economic conditions and the weakened condition of major financial institutions, as evidenced by the bankruptcy of Lehman. These conditions have led governments around the world to establish policies and programs that are designed to strengthen the global financial system, to enhance liquidity, and to restore investor confidence. We believe that these events have several implications for the capital and credit markets, the economy and our industry as a whole, including Ameren. They include the following:

Access to Capital Markets – The extreme disruption in the capital markets has limited the ability of many companies, including the Ameren Companies, to freely access the capital and credit markets to support their operations and to refinance debt. We are unable to predict how long these conditions will persist, but we expect the capital markets to remain uncertain throughout 2009 and potentially longer. However, we believe we will continue to have access to the capital markets on terms commercially acceptable to us, as evidenced by IP’s sale of $400 million in senior secured notes in October 2008 and CILCO’s sale of $150 million of senior secured notes in December 2008. CILCORP and IP have long-term debt maturities of $124 million and $250 million, respectively, in 2009. In addition, Ameren’s $300 million term loan agreement is due in 2009. We currently expect to issue approximately $650 million of debt at our rate-regulated utilities, $250 million at Ameren, and approximately $500 million at the non-rate-regulated generation subsidiaries in 2009.

Credit Facilities – At December 31, 2008, the Ameren Companies had in place revolving bank credit facilities aggregating $2.15 billion. In total, 18 financial institutions participated in these credit facilities. In January 2010, $1 billion of these facilities expire, and the revolving $1.15 billion facility expires in July 2010. Due to the Lehman bankruptcy filing, the size of these facilities was effectively reduced by up to $121 million. We cannot predict whether other lenders that are currently participating in our credit facilities will declare

bankruptcy or otherwise fail to honor their commitments thereunder, and thus reduce the level of access to credit facilities. We are actively developing plans and strategies to renew these facilities prior to their expiration dates. We are unable to predict the degree of success we will have in renewing or replacing any of these facilities and whether the size and terms of any new credit facilities will be comparable to the existing facilities.

Cost of Capital – The disruption in the capital and credit markets has led to higher financing costs compared with recent years. We expect this trend to continue while the current level of uncertainty in the financial markets persists.

Economic Conditions – We believe that the disruption in the capital and credit markets will further weaken global economic conditions. Limited access to capital and credit and higher cost of capital for businesses and consumers will reduce spending and investment, result in job losses, and pressure economic growth for the foreseeable future. These weak economic conditions will likely result in volatility in the power and commodity markets, greater risk of defaults by our counterparties, weaker customer sales growth, particularly with respect to industrial sales, higher bad debt expense, and possible impairment of goodwill and long-lived assets, among other things. The estimated fair values of CILCORP’s Illinois Regulated reporting unit and Non-rate-regulated Generation reporting unit exceeded carrying values by a nominal amount as of October 31, 2008, when we conducted our annual evaluation of goodwill. As a result, the failure in the future of either of these reporting units to achieve forecasted operating results and cash flows or a decrease in observable market multiples, may reduce their estimated fair value below their carrying value and would likely result in the recognition of a goodwill impairment charge. We will continue to monitor the actual and forecasted operating results and cash flows of these reporting units for signs of possible declines in estimated fair value and potential goodwill impairment. We would not necessarily expect any future goodwill impairment charge recorded at the CILCORP reporting unit level to also result in a goodwill impairment charge at the consolidated Ameren level because of the aggregation of reporting units. To date, the level of defaults by counterparties, lower sales growth, and bad debt expense resulting from the weak economy have not significantly affected the Ameren Companies. However, we are unable to predict the ultimate impact of these weak economic conditions on our results of operations, financial position, or liquidity.

Investment Returns – The disruption in the capital markets, coupled with weak global economic conditions, has adversely affected financial markets. As a result, we experienced lower than assumed investment returns in 2008 in our pension and postretirement benefit plans. The market value of plan assets in 2008 declined by 7% and 26% within the pension and postretirement benefit plans, respectively,

compared with assumed 2008 investment returns of 8.25% for both funds. These lower returns will increase our future pension and postretirement expenses and pension funding levels. Our future expenses and funding levels will also be affected by future discount rate levels. Based on Ameren’s assumptions at December 31, 2008, and investment performance in 2008, and reflecting Ameren’s pension funding policy, Ameren expects to make annual contributions of $90 million to $200 million in each of the next five years.

Operating and Capital Expenditures – The Ameren Companies will continue to make significant levels of investments and incur expenditures for their electric and natural gas utility infrastructure in order to improve overall system reliability, comply with environmental regulations, and improve plant performance. However, due to the significant level of disruption and uncertainties in the capital and credit markets, we are actively evaluating opportunities to defer or reduce planned capital spending and operating expenses to mitigate the risks associated with accessing these uncertain markets. We took action in this regard by reducing 2009 operating and capital expenditures from levels previously expected. Separately, Genco, AERG and EEI are seeking a variance from the Illinois Pollution Control Board to an environmental requirement in Illinois that, while “environmentally neutral,” would defer approximately $375 million of Genco’s environmental capital expenditures scheduled for 2009 through 2012 to subsequent years. Any expenditure control initiatives would be balanced against our continued long-term commitment to invest in our electric and natural gas infrastructure to provide safe, reliable electric and natural gas delivery services to our customers; to meet federal and state environmental, reliability, and other regulations; and the need to maintain a solid overall liquidity and credit ratings profile to meet our operating, capital and financing needs under challenging capital and credit market conditions.

Liquidity – At February 13, 2009, Ameren, on a consolidated basis, had available liquidity, in the form of cash on hand and amounts available under its existing credit facilities, of approximately $1.3 billion, excluding unfunded Lehman bank facility participation commitments, which was $448 million higher than the same time last year. We expect our available liquidity to remain at acceptable levels through the end of 2009 as we strategically access the capital markets and execute the expenditure control initiatives. However, we are unable to predict whether significant changes in economic conditions, further disruption in the capital and credit markets, or other unforeseen events could materially impact our estimate.

Although we believe that the uncertainty in the capital and credit markets will persist throughout 2009 and potentially longer, we do believe that actions taken by the U.S. government and governments around the world will

ultimately help ease the extreme volatility and disruption of these markets. In addition, we believe we will continue to have access to the capital markets on terms commercially acceptable to us. As discussed above, additional financings are expected through 2009, subject to market conditions. Also, in February 2009, Ameren’s board of directors made the decision to reduce the common stock dividend. The dividend was reduced to enhance Ameren’s financial strength and flexibility as the company executes its long-term business strategy through the dramatically weakened state of the economy and the continued uncertainties in the capital, credit, and commodity markets. In addition, Ameren’s board of directors was mindful of the company’s current business mix and need to make reliability and environmental infrastructure investments. Specifically, this dividend reduction would be consistent with an annual dividend level that would allow Ameren to retain approximately $215 million of cash annually, which would provide incremental funds to enhance reliability to meet our customers’ expectations; satisfy federal and state environmental requirements; reduce our reliance on dilutive equity and high cost debt financings; and enhance our access to the capital and credit markets. We believe that our expected operating cash flows, capital expenditures, and related financing plans (including accessing our existing credit facilities) will provide the necessary liquidity to meet our operating, investing, and financing needs through the end of 2009, at a minimum. However, there can be no assurance that significant changes in economic conditions, further disruptions in the capital and credit markets, or other unforeseen events will not materially impact our ability to execute our expected operating, capital or financing plans, including our plans to renew or replace our existing credit facilities.

Current Capital Expenditure Plans

Between 2009 and 2018, Ameren expects that certain Ameren Companies will be required to invest between $4.5 billion and $5.5 billion to retrofit their coal-fired power plants with pollution control equipment in compliance with emissions-related environmental laws and regulations. Any pollution control investments will result in decreased plant availability during construction and significantly higher ongoing operating expenses. Approximately 50% of this investment is expected to be in our Missouri Regulated operations, and it is therefore expected to be recoverable from ratepayers. The recoverability of amounts expended in Non-rate-regulated Generation operations will depend on whether market prices for power adjust as a result of market conditions reflecting increased environmental costs for generators.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs. Excessive costs to comply with future legislation or regulations might force Ameren and other similarly situated electric power generators to close some coal-fired facilities.

Investments to control carbon emissions at Ameren’s coal-fired power plants would significantly increase future capital expenditures and operation and maintenance expenses.

UE continues to evaluate its longer-term needs for new baseload and peaking electric generation capacity. At this time, UE does not expect to require new baseload generation capacity until 2018 to 2020. However, due to the significant time required to plan, acquire permits for, and build a baseload power plant, UE is actively studying future plant alternatives, including those that would use coal or nuclear fuel. In July 2008, UE filed a COLA with the NRC for a potential new nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. Pursuant to DOE’s procedures, in 2008 UE filed with the DOE Part I and Part II of its application for a loan guarantee to support the potential construction and operation of a new nuclear unit. UE has also signed contracts for certain long lead-time nuclear-unit related equipment (heavy forgings). The filing of the COLA and the DOE loan guarantee application and entering into these contracts does not mean a decision has been made to build a new nuclear unit. These are only the first steps in the regulatory licensing and procurement process. They are necessary actions to preserve the option to develop a new nuclear unit. As of December 31, 2008, UE spent $52 million and $6 million on the COLA and heavy forgings, respectively. If UE elects not to build a new nuclear unit, we believe the COLA and heavy forgings could be sold in the open market during this time of expected growth in the nuclear industry.

The Missouri Clean and Renewable Energy Construction Act was introduced in the Missouri Senate and House of Representatives in early 2009. This bill would allow the MoPSC to authorize the use of certain financing tools for constructing clean and renewable electric generation, including a tool that would allow utilities to recover the costs of financing and tax payments associated with a new generating plant while that plant is being constructed. UE has stated that legislation allowing timely recovery of financing costs during construction must be enacted in order for UE to elect to build a new nuclear unit to meet its baseload generation capacity needs. However, passage of such legislation does not commit or guarantee that UE will elect to build a new nuclear unit. UE is unable to predict whether this legislation will be adopted by lawmakers.

UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license by 20 years so that the operating license will expire in 2044. UE cannot predict whether or when the NRC will approve the license extension.

Over the next few years, we expect to make significant investments in our electric and natural gas infrastructure and to incur increased operations and maintenance expenses to improve overall system reliability. We are projecting higher labor and material costs for these capital expenditures. We expect these costs or investments at our rate-regulated businesses

to be ultimately recovered in rates, although regulatory lag could materially impact our cash flows and related financing needs.

Increased investments for environmental compliance, reliability improvement, and new baseload capacity will result in higher depreciation and financing costs.

Revenues

The earnings of UE, CIPS, CILCO and IP are largely determined by the regulation of their rates by state agencies. Rising costs, including fuel and related transportation, purchased power, labor, material, depreciation and financing costs, coupled with increased capital and operations and maintenance expenditures targeted at enhanced distribution system reliability and environmental compliance, are expected. Ameren, UE, CIPS, CILCO and IP anticipate regulatory lag until requests to increase rates to continue to recover such costs on a timely basis are granted by state regulators. Ameren, UE, CIPS, CILCO and IP expect more frequent rate cases will be necessary in the future. UE has agreed not to file a natural gas delivery rate case before March 15, 2010.

The ICC issued a consolidated order in September 2008 approving a net increase in annual revenues for electric delivery service of $123 million in the aggregate (CIPS – $22 million increase, CILCO–$3 million decrease and IP – $104 million increase) and a net increase in annual revenues for natural gas delivery service of $38 million in the aggregate (CIPS – $7 million increase, CILCO – $9 million decrease, and IP – $40 million increase), based on a 10.65% return on equity with respect to electric delivery service and a 10.68% return on equity with respect to natural gas delivery service. These rate changes were effective on October 1, 2008. Because of the Ameren Illinois Utilities’ pledge to keep the overall residential electric bill increase resulting from these rate changes during the first year to less than 10% for each utility, IP will not recover approximately $10 million in revenue in the first year the electric delivery service rates are in effect. Thereafter, residential electric delivery service rates will be adjusted to recover the full increase. In addition, the ICC changed the depreciable lives used in calculating depreciation expense for the Ameren Illinois Utilities’ electric and natural gas rates. As a result, annual depreciation expense for the Ameren Illinois Utilities will be reduced for financial reporting purposes by a net $13 million in the aggregate (CIPS – $4 million reduction, CILCO – $26 million reduction, and IP – $17 million increase).

Because of continuing investments in the Ameren Illinois Utilities’ infrastructure, rising operating costs and costs of capital, the Ameren Illinois Utilities are not expected to earn the return on equity allowed in the ICC September 2008 consolidated order. The Ameren Illinois Utilities’ return on equity in 2009 is estimated to be approximately 6%. As a result, rate case filings with the ICC are being targeted for late in the second quarter or early in the third quarter of 2009.

The MoPSC issued an electric rate order in January 2009 approving an increase in annual electric revenues of approximately $162 million based on a 10.76% return on equity, a capital structure composed of 52% common equity, and a rate base of $5.8 billion. The rate change was effective March 1, 2009. In addition, pursuant to the accounting order issued by the MoPSC in April 2008, the rate order concluded that the $25 million of operations and maintenance expenses incurred as a result of a severe ice storm in January 2007 should be amortized and recovered over a five-year period starting March 1, 2009. The MoPSC also allowed recovery of $12 million of costs associated with a March 2007 FERC order that resettled costs among MISO market participants. UE recorded a regulatory asset for these costs at December 31, 2008, which will be amortized and recovered over a two-year period beginning March 1, 2009.

Because of continuing investments in UE’s utility infrastructure, rising operating costs and costs of capital, UE is not expected to earn the return on equity allowed in the MoPSC’s January 2009 electric rate order during 2009. UE’s return on equity in 2009 is estimated to be approximately 8%. As a result, UE expects to file another electric rate case in Missouri later this year. The exact timing will depend on the timing and magnitude of cost increases and rate base additions, among other things.

In current and future rate cases, UE, CIPS, CILCO and IP will continue to seek cost recovery and tracking mechanisms from their state regulators to reduce regulatory lag. In the ICC consolidated electric and natural gas rate order issued in September 2008, the ICC rejected the Ameren Illinois Utilities’ requested rate adjustment mechanisms for electric infrastructure investments. As an alternative to the Ameren Illinois Utilities’ requested decoupling of natural gas revenues from sales volumes, the ICC order approved an increase in the percentage of costs to be recovered through fixed non-volumetric residential and commercial customer charges to 80% from 53%. This increase will impact 2009 quarterly results of operations and cash flows but is not expected to have any impact on annual margins. The ICC also approved an increase in the Supply Cost Adjustment (SCA) factors for the Ameren Illinois Utilities. The SCA is a charge applied only to the bills of customers who take their power supply from the Ameren Illinois Utilities. The change in the SCA factors is expected to result in increased electric revenues of $9.5 million per year in the aggregate (CIPS – $2.6 million, CILCO –$1.6 million, and IP – $5.3 million) covering the increased cost of administering the Ameren Illinois Utilities’ power supply responsibilities. In the MoPSC electric rate order issued in January 2009, the MoPSC approved UE’s implementation of a FAC and a vegetation management and infrastructure inspection cost tracking mechanism. The FAC allows an adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel

and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates, subject to MoPSC prudency review. The vegetation management and infrastructure inspection cost tracking mechanism provides for the tracking of expenditures that are greater or less than amounts provided for in UE’s annual revenues for electric service in a particular year, subject to a 10% limitation on increases in any one year. The tracked amounts may be reflected in rates set in future rate cases.

UE provides power to Noranda’s smelter plant in New Madrid, Missouri, which has historically used approximately four million megawatthours of power annually, making Noranda UE’s single largest customer. As a result of a major winter ice storm in January 2009, Noranda’s smelter plant experienced a power outage related to non-UE lines delivering power to the substation serving the plant. Noranda stated that the outage affected approximately 75% of the smelter plant’s capacity and that based on preliminary information and management’s initial assessment, restoring full plant capacity may take up to 12 months, with partial capacity phased in during the 12 month period. To the extent UE’s sales to Noranda are reduced, generation made available could be sold as off-system sales. However, the FAC approved in the 2009 MoPSC electric rate order would require UE to flow substantially all of the off-system revenues to customers. If this were to occur, and the Noranda smelter plant operates at 25% capacity for 12 months, UE estimates its pretax earnings during such period could be reduced by up to approximately $73 million due to the loss of up to approximately 3.2 million megawatthours of retail sales. In order to adjust the FAC for this unanticipated event, UE sought rehearing by the MoPSC of its January 2009 electric rate order in February 2009, to allow UE to first recover from the off-system sales any revenues it would lose as a result of the reduced tariff sales to Noranda with any excess revenues collected being provided to customers through the FAC. Also in February 2009, other parties to the rate case filed for rehearing of certain aspects of the MoPSC order. In February 2009, the MoPSC denied all rate case rehearing requests filed by UE and other parties. UE continues to consider other alternatives to recover any lost revenues resulting from the Noranda power outage.

The Illinois electric settlement agreement reached in 2007 provides approximately $1 billion over a four-year period that began in 2007 to fund rate relief for certain electric customers in Illinois, including approximately $488 million to customers of the Ameren Illinois Utilities. Funding for the settlement is coming from electric generators in Illinois and certain Illinois electric utilities. The Ameren Illinois Utilities, Genco, and AERG agreed to fund an aggregate of $150 million, of which

the following contributions remained to be made at December 31, 2008:


	Ameren	CIPS	CILCO (Illinois Regulated)	IP	Genco	CILCO (AERG)
2009 ^(a)	$ 26.6	$ 3.9	$ 1.9	$ 5.1	$ 10.8	$ 4.9
2010 ^(a)	1.9	0.3	0.1	0.4	0.8	0.3
Total	$ 28.5	$ 4.2	$ 2.0	$ 5.5	$ 11.6	$ 5.2

(a)	Estimated.

In January 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company. The plan outlined the wholesale products (capacity, energy swaps, and renewable energy credits) that the IPA will procure on behalf of the Ameren Illinois Utilities for the period of June 1, 2009, through May 30, 2014. The products will be procured through a RFP process, during the first half of 2009. The Ameren Illinois Utilities will be allowed to pass through to customers the costs of procuring electric power supply with no markup by the utility, plus any reasonable costs that the utility incurs in arranging and providing for the supply of electric power.

As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of their round-the-clock power requirements during the period June 1, 2008 to December 31, 2012, at then-relevant market prices. These financial contracts do not include capacity, are not load-following products and do not involve the physical delivery of energy. Under the terms of the Illinois electric settlement agreement, these financial contracts are deemed prudent, and the Ameren Illinois Utilities are permitted full recovery of their costs in rates.

In addition, the Illinois electric settlement agreement would allow the Ameren Illinois Utilities to lease or invest in generation facilities, subject to ICC approval.

Volatile power prices in the Midwest can affect the amount of revenues Ameren, UE (though to a lesser extent after the implementation of UE’s FAC), Genco, CILCO (through AERG) and EEI generate by marketing power into the wholesale and spot markets and can influence the cost of power purchased in the spot markets. Lower prices are expected in 2009 as compared with 2008.

The availability and performance of UE’s, Genco’s, AERG’s and EEI’s electric generation fleet can materially impact their revenues. Genco and AERG are seeking to raise the equivalent availability and capacity factors of their power plants over the long term through greater investments and a process improvement program. The Non-rate-regulated Generation segment expects to generate 30 million megawatthours of power in 2009 (Genco – 16 million, AERG – 7 million, EEI – 7 million) based on expected power prices in 2009. Should power

prices rise more than expected in 2009, the Non-rate-regulated Generation segment has the capacity and availability to sell more generation.

In 2008, two million contracted megawatthours of Genco’s and AERG’s legacy power supply agreements, which had an average embedded selling price of $33 per megawatthour, expired. These agreements were replaced with market-based sales.

The marketing strategy for the Non-rate-regulated Generation segment is to optimize generation output in a low risk manner to minimize volatility of earnings and cash flow, while seeking to capitalize on its low-cost generation fleet to provide solid, sustainable returns. To accomplish this strategy, the Non-rate-regulated Generation segment has established hedge targets for near-term years. Through a mix of physical and financial sales contracts, Marketing Company targets to hedge Non-rate-regulated Generation’s expected output by 80% to 90% for the following year, 50% to 70% for two years out, and 30% to 50% for three years out. As of February 13, 2009, Marketing Company had sold approximately 95% of Non-rate-regulated Generation’s expected 2009 generation, at an average price of $53 per megawatthour, and had sold approximately 60% of Non-rate-regulated Generation’s 2010 generation at an average price of $51 per megawatthour.

The development of ancillary services and capacity markets in MISO could increase the electric margins of UE, Genco, AERG and EEI. Ancillary services are services necessary to support the transmission of energy from generation resources to loads while maintaining reliable operation of the transmission provider’s system. MISO’s regional wholesale ancillary services market began in January 2009. We expect MISO will begin development of a capacity market now that its ancillary services market is in place. A capacity requirement obligates a load serving entity to acquire capacity sufficient to meet its obligations.

UE and the Ameren Illinois Utilities have committed to developing energy efficiency programs for their customers. UE expects it will spend $24 million on electric energy efficiency programs in 2009. That number will increase to $56 million annually by 2015. The Ameren Illinois Utilities expect to spend $14 million, $29 million, and $45 million in the 2008, 2009, and 2010 program years, respectively, in accordance with their electric energy efficiency and demand response plan approved by the ICC in 2007. The Ameren Illinois Utilities also expect to spend $2 million, $4 million, and $6 million in the 2009, 2010, and 2011 program years, respectively, in accordance with their natural gas energy efficiency plan approved by the ICC in 2008. The Illinois program years run from June 1 through May 31. The costs incurred by the Ameren Illinois Utilities are recoverable from customers through rate riders.

Future energy efficiency programs developed by UE, CIPS, CILCO and IP and others could also result in reduced demand for our electric generation and our electric and gas transmission and distribution services.

Fuel and Purchased Power

In 2008, 85% of Ameren’s electric generation (UE – 77%, Genco – 99%, AERG – 99%, EEI – 100%) was supplied by coal-fired power plants. About 96% of the coal used by these plants (UE –97%, Genco – 98%, AERG – 77%, EEI – 100%) was delivered by rail from the Powder River Basin in Wyoming. In the past, deliveries from the Powder River Basin have been restricted because of rail maintenance, weather, and derailments. As of December 31, 2008, coal inventories for UE, Genco, AERG and EEI were at targeted levels. Disruptions in coal deliveries could cause UE, Genco, AERG and EEI to pursue a strategy that could include reducing sales of power during low-margin periods, buying higher-cost fuels to generate required electricity, and purchasing power from other sources.

Genco is incurring incremental fuel costs in 2009 to replace coal from an Illinois mine that was prematurely closed by its owner at the end of 2007. A settlement agreement reached with the coal mine owner in June 2008 fully reimbursed Genco, in the form of a lump-sum payment of $60 million, for increased costs for coal and transportation that it incurred in 2008 ($33 million) and expects to incur in 2009 ($27 million). The entire settlement was recorded in 2008 earnings, so Ameren’s and Genco’s earnings in 2009 will be lower than they otherwise would have been.

The annual NO _x trading program under the federal Clean Air Interstate Rule was reinstated by the U.S. Court of Appeals for the District of Columbia in December 2008. At this time, Genco and AERG may not have sufficient NO _x allowances to meet forecasted 2009 obligations under the annual NO _x trading program. The costs of these allowances would depend on market prices at the time these allowances are purchased. Genco and AERG currently estimate that they could incur additional fuel expense in 2009 of $11 million and $5 million, respectively, to purchase additional NO _x allowances to come into compliance with the program.

Ameren’s fuel costs (including transportation) are expected to increase in 2009 and beyond. See Item 7A – Quantitative and Qualitative Disclosures About Market Risk of this report for additional information about the percentage of fuel and transportation requirements that are price-hedged for 2009 through 2013.

Other Costs

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 settled with the FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. In addition, UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and is in the process of rebuilding the facility. The estimated cost to rebuild the upper reservoir is in the range of $480 million. UE expects the Taum Sauk plant to be out of service through early 2010. UE believes

that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers. As a result of this breach, UE is engaged in litigation initiated by certain private parties and the Department of the Army, Corps of Engineers. We are unable to predict the timing or outcomes of this litigation, or its possible effect on UE’s results of operation, financial position, or liquidity. See Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a further discussion of Taum Sauk matters.

UE’s Callaway nuclear plant had a 28-day scheduled refueling and maintenance outage during the fourth quarter of 2008. UE’s Callaway nuclear plant’s next scheduled refueling and maintenance outage is in the spring of 2010. During a scheduled 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 premiums as a result of insurance market conditions and loss experience, among other things.

Other

Under an executory tolling agreement, CILCO purchased steam, chilled water, and electricity from Medina Valley, which CILCO in turn sold to an industrial

customer. In January 2009, CILCO transferred both the tolling agreement and the related power supply agreement with the industrial customer to Marketing Company. The transfer of these agreements is expected to benefit CILCO’s non-rate-regulated 2009 pretax operating generation income by $6 million compared with its 2008 operating income.

A ballot initiative passed by Missouri voters in November 2008 created a renewable energy portfolio requirement. UE and other Missouri investor-owned utilities will be required to purchase or generate electricity from renewable energy sources equaling at least 2% of native load sales by 2011, with that percentage increasing in subsequent years to at least 15% by 2021, subject to a 1% limit on customer rate impacts. At least 2% of each portfolio requirement must be derived from solar energy. Compliance with the renewable energy portfolio requirement can be achieved through the procurement of renewable energy or renewable energy credits. Rules are required to be issued by the MoPSC to implement the law. UE expects that any related costs or investments would ultimately be recovered in rates.

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, or 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 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report.

ACCOUNTING MATTERS

Critical Accounting Estimates

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. These estimates involve judgments regarding many factors which in and of themselves could materially affect the financial statements and disclosures. We have outlined below the critical accounting estimates 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 Estimate

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 probably no longer recoverable, we record a charge to earnings, which could be material. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for quantification of these assets by registrant.

Accounting Estimate

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.

Uncertainties Affecting Application

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. See the balance sheets for each of the Ameren Companies under Part II, Item 8, of this report for unbilled revenue amounts.

Derivative Financial Instruments

We account for derivative financial instruments under SFAS No. 133, “Accounting for Derivatives and Hedging Activities,” as amended, and related interpretations and measure their fair value in accordance with SFAS No. 157, “Fair Value Measurements,” and related interpretations. The identification and classification of a derivative and the fair value of such derivative must be determined. See Commodity Price Risk and Fair Value of Contracts in Quantitative and Qualitative Disclosures About Market Risk under Part II, Item 7A, Note 7 – Derivative Financial Instruments and Note 8 – Fair Value Measurements to our financial statements under Part II, Item 8, of this report.

Ameren’s ability to consume or produce notional values of derivative contracts

Market conditions in the energy industry, especially the effects of price volatility and liquidity

Valuation assumptions on longer term contracts due to lack of observable inputs

Effectiveness of our derivatives that have been designated as hedges

Counterparty default risk

Basis for Judgment

We determine whether to exclude the fair value of certain derivatives from valuation under the normal purchase and normal sales provisions of SFAS No. 133 based upon our intent and ability to physically deliver commodities purchased and sold. Further, our forecasted purchases and sales also support our designation of some fair-valued derivative instruments as cash flow hedges. Fair value of our derivatives is measured in accordance with SFAS No. 157, which provides a fair value hierarchy that prioritizes inputs to valuation techniques. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. Without observable inputs, we use certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risks inherent in the inputs to the valuation. Our valuations also reflect our own assessment of counterparty default risk using the best internal and external information available. If we were required to discontinue our use of the normal purchase and normal sales exception or cash flow hedge treatment for some of our contracts, the impact of changes in fair value for the applicable contracts could be material to our earnings.

Valuation of Goodwill, Intangible Assets, Long-Lived Assets, and Asset Retirement Obligations

We assess the carrying value of our goodwill, intangible assets, 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 and assumptions about the timing of asset removals

Basis for Judgment

Annually, or whenever events indicate a valuation may have changed, we use various valuation methodologies 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. See Note 1 – Summary of Significant Accounting Policies to our financial statements under Part II, Item 8, of this report for quantification of our goodwill and intangible assets.

Accounting Estimate

Benefit Plan Accounting

Based on actuarial calculations, we accrue costs of providing future employee benefits in accordance with SFAS Nos. 87, 106, 112 and 158, which provide guidance on benefit plan accounting. See Note 11 – Retirement Benefits to our financial statements under Part II, Item 8, of this report.

Uncertainties Affecting Application

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

Ability to recover certain benefit plan costs from our ratepayers

Changing market conditions impacting investment and interest rate environments

Basis for Judgment

Our ultimate selection of the discount rate, health care trend rate, and expected rate of return on pension and other plan assets is based on our consistent application of assumption-setting methodologies and our review of available historical, current, and projected rates, as applicable. See Note 11 – Retirement Benefits to our financial statements under Part II, Item 8, of this report for sensitivity of Ameren’s benefit plans to potential changes in these assumptions.

Impact of Future Accounting Pronouncements

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. Adjustments to rates are based on a regulatory process that reviews a historical 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. Our Non-rate-regulated Generation businesses do not have regulated recovery mechanisms.

Historically, in UE’s Missouri electric utility jurisdiction, there was no tariff for adjusting rates to accommodate changes in the cost of fuel for electric generation or the cost of purchased power. As a part of the electric rate order issued by the MoPSC on January 27, 2009, UE was granted permission to put in place, effective March 1, 2009, a FAC. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for information on UE’s electric rate order.

In July 2005, a law was enacted that enables the MoPSC to also put in place mechanisms for Missouri’s utilities to recover environmental costs directly from customers outside of a rate case proceeding. The MoPSC initiated a proceeding in December 2008 to develop revised rules for the environmental cost recovery mechanisms. Rules for the environmental cost recovery mechanism are expected to be approved by the MoPSC during the second

quarter of 2009 and will be effective once published in the Missouri Register. UE will not be able to implement an environmental cost recovery mechanism until so authorized by the MoPSC as part of a rate case proceeding.

Effective January 2, 2007, ICC-approved tariffs in Illinois allow CIPS, CILCO and IP to recover power supply costs from electric customers by adjusting rates to accommodate changes in power prices. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for information on the Illinois electric rate settlement agreement that addressed legislative and other efforts to limit full recovery of power costs in Illinois.

In our Missouri and Illinois retail gas utility jurisdictions, changes in gas costs are generally reflected in billings to gas customers through PGA clauses. During 2008, the MoPSC approved two UE requests to recover gas infrastructure replacement costs through the establishment of an ISRS. UE commenced recovering annual revenues of $2 million in the aggregate, effective in March and November 2008 through the ISRS.

UE, Genco, CILCORP and AERG 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, and to minimize the impact to their financial statements. See Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk under Part II, Item 7A, below for further information. Also see Note 2 – Rate and Regulatory Matters to our financial statements under Part II, Item 8, of this report for further information on the cost recovery mechanisms discussed above.

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 nonderivative, caused by fluctuations in market variables such as interest rates, commodity prices, and equity security prices. A derivative is a contract whose value is dependent on, or derived from, the value of some underlying asset. 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 and to pursue market opportunities within prudent risk parameters. Our risk management policies are set by a risk management steering committee, which is composed 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 have 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, 2008:


	Interest Expense			Net Income ^(a)
Ameren ^(b)	$	14		$	(9	)
UE		6			(3	)
CIPS		1			(1	)
Genco		1			(c	)
CILCORP		5			(3	)
CILCO		3			(2	)
IP		(c	)		(c	)

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

(b)	Includes intercompany eliminations.

(c)	Less than $1 million.

The estimated changes above do 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.

Insured Tax-exempt Auction-Rate Bonds

Certain auction-rate tax-exempt environmental improvement and pollution control revenue bonds previously issued for the benefit of UE, CIPS, CILCO and IP through governmental authorities were insured by “monoline” bond insurers. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a description and details of this indebtedness. As a result of developments in the capital markets with respect to residential mortgage-backed securities and collateralized debt obligations, the credit rating agencies have downgraded the credit ratings of the monoline bond insurers that insured such securities. As a result, our insured auction-rate bonds were similarly downgraded. In 2008, we experienced higher interest expense and/or “failed auctions,” in which there were not sufficient clearing bids in an auction to set the interest rate for a portion of our auction-rate bonds. According to press reports, many other series of auction-rate securities similarly experienced “failed auctions.”

To mitigate the effect of these credit ratings downgrades and the resulting impact on the interest rates of our auction-rate tax-exempt environmental improvement and pollution control revenue bonds, we redeemed all of UE’s, CIPS’, CILCO’s and IP’s outstanding auction-rate bonds, except for UE’s 1992 Series and 1998 Series A, B and C bonds, which had an aggregate balance of $207 million at December 31, 2008, and interest rates ranging from 1.313% to 9.975% during the year ended December 31, 2008. In April 2008, UE and IP issued senior secured notes in the principal amount of $250 million and $337 million, respectively, to refinance their auction-rate indebtedness. See Note 5 – Long-term Debt and Equity Financings under Part II, Item 8, of this report for a description of these redemptions and refinancings.

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. In 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 and executory contracts with market risk exposures. 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.

The 2007 increase in electric rates in Illinois, and a related increase in extended payment plan arrangements, resulted in an increase in the Ameren Illinois Utilities’ past-due accounts receivable balances during 2007 and the first quarter of 2008. Such past-due balances have improved during the last nine months of 2008, primarily as a result of enhanced collection efforts and an increase in the volume of write-offs of past-due balances deemed uncollectible. The Ameren Illinois Utilities will continue to monitor the impact of increased electric rates on customer collections and to make adjustments to their allowances for doubtful accounts, as deemed necessary, to ensure that such allowances are adequate to cover estimated uncollectible customer account balances.

At December 31, 2008, no single nonaffiliated customer represented more 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, CIPS, Genco, AERG, IP, AFS, and Marketing Company may have credit exposure associated with interchange or wholesale purchase and sale activity with nonaffiliated companies. At December 31, 2008, UE’s, CIPS’, Genco’s, CILCO’s, IP’s, AFS’, and Marketing Company’s combined credit exposure to nonaffiliated non-investment-grade trading counterparties related to interchange or wholesale purchases and sales was less than $1 million, net of collateral (2007 – less than $1 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. It 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 lease. We estimate our credit exposure to MISO associated with the MISO Day Two Energy Market to be $46 million at December 31, 2008 (2007 – $63 million).

The Ameren Illinois Utilities will be exposed to credit risk in the event of nonperformance by the parties contributing to the Illinois comprehensive rate relief and assistance programs under the Illinois electric settlement agreement. The agreement provides to certain electric customers of the Ameren Illinois Utilities $488 million in rate relief over a four-year period that commenced in 2007. Under funding agreements among the parties contributing to the rate relief and assistance programs, at the end of each month, the Ameren Illinois Utilities bill the participating generators for their proportionate share of that month’s rate relief and assistance, which is due in 30 days, or drawn from the funds provided by the generators’ escrow. See Note 2 – Rate and Regulatory Matters to our financial statements under Part II, of this report for additional information.

Equity Price Risk

Our costs for 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 with benchmark returns and for the effect of expenses paid from plan assets.

In future years, the costs of such plans reflected in net income, OCI, or regulatory assets, 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%. See Outlook in Management’s Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this report for discussion of the impact of 2008 investment returns.

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, 2008, this fund was invested primarily in domestic equity securities (55%) and debt securities (45%). It totaled $239 million (in 2007 – $307 million). By maintaining a portfolio that includes long-term equity investments, UE seeks to maximize the returns to be used 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. 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 its decommissioning costs, which would include unfavorable investment results, through electric rates.

Foreign Currency Risk

Ameren and UE are exposed to foreign currency exchange risk from UE’s procurement agreement related to construction of a potential new nuclear unit. This agreement provides a fixed price for heavy forgings as well as consulting services to aid with design certification. The agreement requires UE to pay for goods and services in euros. UE uses foreign currency forward contracts for the purchase of euros to mitigate the impact of changes in foreign currency exchange rates, which could affect the amount of U.S. dollars required to satisfy the obligation denominated in euros. To the extent the value of the U.S. dollar versus the euro declines, the effect would be reflected in construction work in process within property and plant, net, and would be subject to routine depreciation and impairment considerations.

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. Genco, AERG and EEI also seek to sell power forward to wholesale, municipal and industrial customers to limit exposure to changing prices. We also attempt to mitigate financial risks through risk management programs and policies, which include forward-hedging programs, and the use of derivative financial instruments (primarily forward contracts, futures contracts, option contracts, and financial swap contracts). However, a portion of the generation capacity of UE, Genco, AERG and EEI is not contracted through physical or financial hedge arrangements and is therefore exposed to volatility in market prices.

The following table shows how our earnings might decrease if power prices were to decrease by 1% on unhedged economic generation for 2009 through 2012:


		Net Income ^(a)
Ameren ^(b)		$ (27)
UE		(10)
Genco		(9)
CILCO (AERG)		(3)
EEI		(7)

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

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

Ameren also uses its portfolio management and trading capabilities both to manage risk and to deploy risk capital to generate additional returns. Due to our physical presence in the market, we are able to identify and pursue opportunities, which can generate additional returns through portfolio management and trading activities. All of this activity is performed within a controlled risk management process. We establish value at risk (VaR) and stop-loss limits that are intended to prevent any negative material financial impact.

On September 15, 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New York. At that time, UE, CIPS, Genco, IP, Marketing Company and AFS were counterparties with Lehman Brothers Commodity Services Inc. (Lehman Commodity Services), a subsidiary of Lehman, in energy commodity transactions that support their utility and generation businesses. The obligations of Lehman Commodity Services were guaranteed by Lehman, and the Lehman bankruptcy filing gives UE, CIPS, Genco, IP, Marketing Company and AFS the right to terminate any open transactions. On October 21, 2008, Ameren sent notice to Lehman Commodity Services terminating all transactions between UE, Genco, and Marketing Company and Lehman Commodity Services. As of December 31, 2008, Ameren’s and its subsidiaries’ direct exposure to Lehman Commodity Services, based on existing transactions and current market prices, was estimated to be less than $1 million before taxes, collectively.

We manage risks associated with changing prices of fuel for generation using similar techniques as those used to manage risks associated with changing market prices for electricity. Most UE, Genco and AERG fuel supply contracts are physical forward contracts. Genco, AERG and EEI do not have the ability to pass through higher fuel costs to their customers for electric operations. Prior to March 2009, UE did not have this ability either except through a general rate proceeding. As a part of the January 2009 MoPSC electric rate order, UE was granted permission to put a FAC in place which was effective March 1, 2009. The FAC allows UE to recover directly from its electric customers 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates, subject to MoPSC prudency review. Thus, UE remains exposed to 5% of changes in its fuel and purchased power costs, net of off-system revenues. UE, Genco, AERG and EEI have entered into long-term contracts with various suppliers to purchase coal 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. UE, Genco, AERG and EEI generally purchase coal up to five years in advance, but we may purchase coal beyond five years to take 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. UE, Genco, AERG and EEI typically hedge coal transportation forward to provide supply certainty and to mitigate transportation price volatility. Natural gas transportation expenses for Ameren’s gas distribution utility companies and the gas-fired generation units of UE, Genco, AERG and EEI are regulated by FERC through approved tariffs governing the rates,

terms and conditions of transportation and storage services. Certain firm transportation and storage capacity agreements held by the Ameren Companies include rights to extend the contracts prior to the termination of the

primary term. Depending on our competitive position, we are able in some instances to negotiate discounts to these tariff rates for our requirements.

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 no generation, that are price-hedged over the five-year period 2009 through 2013, as of December 31, 2008. The projected required supply of these commodities could be significantly affected by changes in our assumptions for such matters as customer demand of our electric generation and our electric and natural gas distribution services, generation output, and inventory levels, among other matters.


	2009		2010		2011 - 2013
Ameren:
Coal	95	%	86	%	22	%
Coal transportation	100		76		37
Nuclear fuel	100		100		81
Natural gas for generation	31		3		-
Natural gas for distribution ^(a)	84		36		13
Purchased power for Illinois Regulated ^(b)	80		57		32
UE:
Coal	96	%	90	%	23	%
Coal transportation	100		63		25
Nuclear fuel	100		100		81
Natural gas for generation	22		5		-
Natural gas for distribution ^(a)	85		45		13
CIPS:
Natural gas for distribution ^(a)	87	%	40	%	16	%
Purchased power ^(b)	80		57		32
Genco:
Coal	94	%	87	%	16	%
Coal transportation	100		67		45
Natural gas for generation	30		-		-
CILCORP/CILCO:
Coal (AERG)	89	%	67	%	31	%
Coal transportation (AERG)	100		67		46
Natural gas for distribution ^(a)	87		37		10
Purchased power ^(b)	80		57		32
IP:
Natural gas for distribution ^(a)	80	%	31	%	13	%
Purchased power ^(b)	80		57		32
EEI:
Coal	96	%	89	%	24	%
Coal transportation	100		100		67

(a)	Represents the percentage of natural gas price-hedged for peak winter season of November through March. The year 2009 represents January 2009 through March 2009. The year 2010 represents November 2009 through March 2010. This continues each successive year through March 2013.

(b)

Represents the percentage of purchased power price-hedged for fixed-price residential and small commercial customers with less than one megawatt of demand. Larger customers are purchasing power from the competitive markets. See Note 2 – Rate and Regulatory Matters and Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a discussion of the Illinois power procurement process and for additional information on the Ameren Illinois Utilities’ purchased power commitments.

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 2009 through 2013.


	Coal			Transportation
	Fuel Expense		Net Income ^(a)	Fuel Expense		Net Income ^(a)
Ameren ^(b)	$	37	$ (23)	$	17	$ (11)
UE		15	(10)		13	(8)
Genco		14	(8)		2	(1)
CILCORP		5	(3)		1	(1)
CILCO		5	(3)		1	(1)
EEI		3	(2)		1	(1)

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

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

In addition, coal and coal transportation costs are sensitive to the price of diesel fuel as a result of rail freight fuel surcharges. If diesel fuel costs were to increase or decrease by $0.25/gallon, Ameren’s fuel expense could increase or decrease by $13 million annually (UE – $7 million, Genco – $3 million, AERG – $1 million and EEI – $2 million). As of December 31, 2008, Ameren had price-hedged approximately 100% of expected fuel surcharges in 2009.

In the event of a significant change in coal prices, UE, Genco, AERG and EEI 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 fixed-priced and base-price-with- escalation agreements, or it uses inventories that provide some price hedge to fulfill its Callaway nuclear plant needs for uranium, conversion, enrichment, and fabrication services. There is no fuel reloading scheduled for 2009 or 2012. UE has price hedges for 87% of the 2010 to 2013 nuclear fuel requirements.

Although nuclear fuel market prices declined in 2008, pricing remains subject to an unpredictable supply and demand environment. UE has continued to follow a strategy of managing inventory of nuclear fuel as an inherent price hedge. New long-term uranium contracts are almost exclusively market-price-related with an escalating price floor. New long-term enrichment contracts usually have some market-price-related component. UE expects to enter into additional contracts from time to time in order to supply nuclear fuel during the expected life of the Callaway nuclear plant, at prices which cannot now be accurately

predicted. Unlike the electricity and natural gas markets, nuclear fuel markets have limited financial instruments available for price hedging, so most hedging is done through inventories and forward contracts, if they are available.

With regard to the electric generating operations for UE, Genco and AERG that are exposed to changes in market prices for natural gas used to run 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 MISO Day Two Energy Market. In addition, 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 the 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. Complex grid modeling tools are used to determine which FTRs to nominate in the FTR allocation process. There is a risk of incorrectly modeling the amount of FTRs needed, and there is the potential that the FTRs could be ineffective in mitigating transmission congestion charges.

With regard to UE’s natural gas distribution business and, commencing March 1, 2009, its electric distribution business, and to CIPS’, CILCO’s and IP’s electric and natural gas distribution businesses, exposure to changing market prices is in large part mitigated by the fact that there are cost recovery mechanisms in place. These cost recovery mechanisms allow UE, CIPS, CILCO and IP to pass on to retail customers prudently incurred fuel, purchased power and gas supply costs. UE’s, CIPS’, CILCO’s and IP’s strategy is designed to reduce the effect of market fluctuations for our regulated customers. The effects of price volatility cannot be eliminated. However, procurement strategies involve risk management techniques and instruments similar to those outlined earlier, as well as the management of physical assets.

With regard to our exposure for commodity price risk for construction and maintenance activities, Ameren is exposed to changes in market prices for metal commodities and labor availability.

See Supply for Electric Power under Part I, Item 1, of this report for the percentages of our historical needs satisfied by coal, nuclear power, natural gas, hydroelectric power, 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, FTRs and emission allowances.

Price fluctuations in natural gas, fuel, electricity, FTRs and emission allowances 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 7 – 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, 2008. We use various methods to determine the fair value of our contracts. In accordance with SFAS No. 157 hierarchy levels, our sources used to determine the fair value of these contracts were active quotes (Level 1), inputs corroborated by market data (Level 2), and other modeling and valuation methods that are not corroborated by market data (Level 3). All of these contracts have maturities of less than five years.


	Ameren ^(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
Fair value of contracts at beginning of year, net	$	13		$	7		$	38		$	(4	)	$	21		$	55
Contracts realized or otherwise settled during the period		(20	)		(17	)		2			4			4			10
Changes in fair values attributable to changes in valuation technique and assumptions		-			-			-			-			-			-
Fair value of new contracts entered into during the period		48			21			(25	)		(1	)		(23	)		(38	)
Other changes in fair value		(21	)		5			(99	)		-			(61	)		(161	)
Fair value of contracts outstanding at end of year, net	$	20		$	16		$	(84	)	$	(1	)	$	(59	)	$	(134	)

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

The following table presents maturities of derivative contracts as of December 31, 2008, based on the hierarchy levels used to determine the fair value of the contracts:


Sources of Fair Value	Maturity Less than 1 Year			Maturity 1 - 3 Years			Maturity 4 - 5 Years			Maturity in Excess of 5 Years		Total Fair Value
Ameren:
Level 1	$	(8	)	$	-		$	-		$	-	$	(8	)
Level 2 ^(a)		13			-			-			-		13
Level 3 ^(b)		46			(25	)		(6	)		-		15
Total	$	51		$	(25	)	$	(6	)	$	-	$	20
UE:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2 ^(a)		11			-			-			-		11
Level 3 ^(b)		14			(8	)		(1	)		-		5
Total	$	25		$	(8	)	$	(1	)	$	-	$	16
CIPS:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2 ^(a)		-			-			-			-		-
Level 3 ^(b)		(31	)		(41	)		(12	)		-		(84	)
Total	$	(31	)	$	(41	)	$	(12	)	$	-	$	(84	)
Genco:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2 ^(a)		-			-			-			-		-
Level 3 ^(b)		(1	)		-			-			-		(1	)
Total	$	(1	)	$	-		$	-		$	-	$	(1	)


Sources of Fair Value	Maturity Less than 1 Year			Maturity 1 - 3 Years			Maturity 4 - 5 Years			Maturity in Excess of 5 Years		Total Fair Value
CILCORP/CILCO:
Level 1	$	(4	)	$	-		$	-		$	-	$	(4	)
Level 2 ^(a)		-			-			-			-		-
Level 3 ^(b)		(25	)		(25	)		(5	)		-		(55	)
Total	$	(29	)	$	(25	)	$	(5	)	$	-	$	(59	)
IP:
Level 1	$	-		$	-		$	-		$	-	$	-
Level 2 ^(a)		-			-			-			-		-
Level 3 ^(b)		(56	)		(61	)		(17	)		-		(134	)
Total	$	(56	)	$	(61	)	$	(17	)	$	-	$	(134	)

(a)	Principally fixed-price vs. floating over-the-counter power swaps, power forwards, and fixed price vs. floating over-the-counter natural gas swaps.

(b)	Principally coal and SO ₂ option values based on a Black-Scholes model that includes information from external sources and our estimates. Level 3 also includes interruptible power forward and option contract values based on our estimates.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

of Ameren Corporation:

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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.

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, 2009

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

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, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008 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 13 to the financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholder

of Ameren Energy Generating Company:

As discussed in Note 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present 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 schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

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, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present 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 schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and financial statement schedules 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 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

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 and its subsidiary at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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 13 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain tax positions as of January 1, 2007.

/s/PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF INCOME

(In millions, except per share amounts)


	Year Ended December 31,
	2008		2007		2006
Operating Revenues:
Electric	$	6,367	$	6,283	$	5,600
Gas		1,472		1,279		1,295

Total operating revenues		7,839		7,562		6,895

Operating Expenses:
Fuel		1,275		1,167		1,018
Purchased power		1,210		1,387		1,150
Gas purchased for resale		1,057		900		931
Other operations and maintenance		1,857		1,687		1,556
Depreciation and amortization		685		681		661
Taxes other than income taxes		393		381		391

Total operating expenses		6,477		6,203		5,707

Operating Income		1,362		1,359		1,188

Other Income and Expenses:
Miscellaneous income		80		75		50
Miscellaneous expense		(31)		(25)		(19)

Total other income		49		50		31


Interest Charges		440		423		350


Income Before Income Taxes, Minority Interest, and Preferred Dividends of Subsidiaries		971		986		869

Income Taxes		327		330		284


Income Before Minority Interest and Preferred Dividends of Subsidiaries		644		656		585

Minority Interest and Preferred Dividends of Subsidiaries		39		38		38


Net Income	$	605	$	618	$	547


Earnings per Common Share – Basic and Diluted	$	2.88	$	2.98	$	2.66

Dividends per Common Share	$	2.54	$	2.54	$	2.54
Average Common Shares Outstanding		210.1		207.4		205.6

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

AMEREN CORPORATION

CONSOLIDATED BALANCE SHEET

(In millions, except per share amounts)


	December 31,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	92	$	355
Accounts receivable – trade (less allowance for doubtful accounts of $28 and $22, respectively)		502		570
Unbilled revenue		427		359
Miscellaneous accounts and notes receivable		292		262
Materials and supplies		842		735
Mark-to-market derivative assets		207		35
Other current assets		153		146

Total current assets		2,515		2,462

Property and Plant, Net		16,567		15,069
Investments and Other Assets:
Nuclear decommissioning trust fund		239		307
Goodwill		831		831
Intangible assets		167		198
Regulatory assets		1,732		1,158
Other assets		606		703

Total investments and other assets		3,575		3,197

TOTAL ASSETS	$	22,657	$	20,728

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	380	$	223
Short-term debt		1,174		1,472
Accounts and wages payable		813		687
Taxes accrued		54		84
Mark-to-market derivative liabilities		155		24
Other current liabilities		487		414

Total current liabilities		3,063		2,904

Long-term Debt, Net		6,554		5,689
Preferred Stock of Subsidiary Subject to Mandatory Redemption		-		16
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		2,131		2,046
Accumulated deferred investment tax credits		100		109
Regulatory liabilities		1,291		1,240
Asset retirement obligations		406		562
Pension and other postretirement benefits		1,495		839
Other deferred credits and liabilities		438		354

Total deferred credits and other liabilities		5,861		5,150

Preferred Stock of Subsidiaries Not Subject to Mandatory Redemption		195		195
Minority Interest in Consolidated Subsidiaries		21		22
Commitments and Contingencies (Notes 2, 14, 15 and 16)
Stockholders’ Equity:
Common stock, $.01 par value, 400.0 shares authorized – shares outstanding of 212.3 and 208.3, respectively		2		2
Other paid-in capital, principally premium on common stock		4,780		4,604
Retained earnings		2,181		2,110
Accumulated other comprehensive income		-		36

Total stockholders’ equity		6,963		6,752

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	22,657	$	20,728

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

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2008		2007		2006
Cash Flows From Operating Activities:
Net income	$	605	$	618	$	547
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sales of emission allowances		(8)		(8)		(60)
Gain on sales of noncore properties		-		(3)		(37)
Loss on asset impairments		14		-		-
Net mark-to-market gain on derivatives		(3)		(3)		(2)
Depreciation and amortization		705		735		656
Amortization of nuclear fuel		37		37		36
Amortization of debt issuance costs and premium/discounts		20		19		15
Deferred income taxes and investment tax credits, net		167		(28)		91
Minority interest		29		27		27
Other		(9)		12		13
Changes in assets and liabilities:
Receivables		25		(194)		173
Materials and supplies		(100)		(88)		(75)
Accounts and wages payable		57		-		(91)
Taxes accrued, net		(30)		21		(72)
Assets, other		63		49		(95)
Liabilities, other		183		(36)		85
Pension and other postretirement benefits		(4)		27		97
Counterparty collateral, net		(69)		(27)		(6)
Taum Sauk costs, net of insurance recoveries		(149)		(56)		(23)

Net cash provided by operating activities		1,533		1,102		1,279

Cash Flows From Investing Activities:
Capital expenditures		(1,896)		(1,381)		(992)
CT acquisitions		-		-		(292)
Proceeds from sales of noncore properties, net		-		13		56
Nuclear fuel expenditures		(173)		(68)		(39)
Purchases of securities – nuclear decommissioning trust fund		(520)		(142)		(110)
Sales of securities – nuclear decommissioning trust fund		497		128		98
Purchases of emission allowances		(12)		(24)		(42)
Sales of emission allowances		4		5		71
Other		3		1		(16)

Net cash used in investing activities		(2,097)		(1,468)		(1,266)

Cash Flows From Financing Activities:
Dividends on common stock		(534)		(527)		(522)
Capital issuance costs		(12)		(4)		(4)
Short-term debt, net		(298)		860		419
Dividends paid to minority interest holder		(30)		(21)		(28)
Redemptions, repurchases, and maturities:
Long-term debt		(842)		(488)		(164)
Preferred stock		(16)		(1)		(1)
Issuances:
Common stock		154		91		96
Long-term debt		1,879		674		232

Net cash provided by financing activities		301		584		28

Net change in cash and cash equivalents		(263)		218		41
Cash and cash equivalents at beginning of year		355		137		96

Cash and cash equivalents at end of year	$	92	$	355	$	137

Cash Paid During the Year:
Interest	$	450	$	422	$	320
Income taxes, net		106		283		403

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

AMEREN CORPORATION

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)


	December 31,
	2008		2007		2006
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		4,604		4,495		4,399
Reclassification of unearned compensation		-		-		(12)
Shares issued (less issuance costs of $-, $-, and $1, respectively)		154		91		96
Stock-based compensation cost		22		18		11
Tax benefit of stock option exercises		-		-		1

Other paid-in capital, end of year		4,780		4,604		4,495

Retained Earnings:
Beginning of year		2,110		2,024		1,999
Net income		605		618		547
Dividends		(534)		(527)		(522)
Adjustment to adopt FIN 48		-		(5)		-

Retained earnings, end of year		2,181		2,110		2,024

Accumulated Other Comprehensive Income (Loss):
Derivative financial instruments, beginning of year		9		60		40
Change in derivative financial instruments		39		(51)		20

Derivative financial instruments, end of year		48		9		60

Minimum pension liability, beginning of year		-		-		(64)
Change in minimum pension liability		-		-		64

Minimum pension liability, end of year		-		-		-

Deferred retirement benefit costs, beginning of year		27		2		-
Adjustment to adopt SFAS No. 158		-		-		2
Change in deferred retirement benefit costs		(75)		25		-

Deferred retirement benefit costs		(48)		27		2

Total accumulated other comprehensive income, end of year		-		36		62

Other:
Beginning of year		-		-		(12)
Reclassification of unearned compensation		-		-		12

Other, end of year		-		-		-

Total Stockholders’ Equity	$	6,963	$	6,752	$	6,583

Comprehensive Income, Net of Taxes:
Net income	$	605	$	618	$	547
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes (benefit) of $65, $(7), and $11, respectively		116		(12)		28
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $43, $22, and $3, respectively		(77)		(39)		(8)
Minimum pension liability adjustment, net of income taxes of $-, $-, and $41, respectively		-		-		64
Pension and other postretirement activity, net of taxes (benefit) of $(45), $1, and $-, respectively		(75)		25		-

Total Comprehensive Income, Net of Taxes	$	569	$	592	$	631


Common stock shares at beginning of year		208.3		206.6		204.7
Shares issued		4.0		1.7		1.9

Common stock shares at end of year		212.3		208.3		206.6

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

UNION ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF INCOME

(In millions)


	Year Ended December 31,
	2008		2007		2006
Operating Revenues:
Electric – excluding off-system	$	2,266	$	2,302	$	2,204
Electric – off-system		490		484		459
Gas		201		174		158
Other		3		1		2

Total operating revenues		2,960		2,961		2,823

Operating Expenses:
Fuel		672		608		492
Purchased power		160		192		261
Gas purchased for resale		123		104		98
Other operations and maintenance		922		900		787
Depreciation and amortization		329		333		335
Taxes other than income taxes		240		234		230

Total operating expenses		2,446		2,371		2,203

Operating Income		514		590		620

Other Income and Expenses:
Miscellaneous income		62		38		38
Miscellaneous expense		(9)		(7)		(8)

Total other income		53		31		30


Interest Charges		193		194		171


Income Before Income Taxes and Equity in Income of Unconsolidated Investment		374		427		479

Income Taxes		134		140		184


Income Before Equity in Income of Unconsolidated Investment		240		287		295

Equity in Income of Unconsolidated Investment, Net of Taxes		11		55		54


Net Income		251		342		349

Preferred Stock Dividends		6		6		6


Net Income Available to Common Stockholder	$	245	$	336	$	343

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

UNION ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEET

(In millions, except per share amounts)


	December 31,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	-	$	185
Accounts receivable – trade (less allowance for doubtful accounts of $8 and $6, respectively)		142		191
Unbilled revenue		111		118
Miscellaneous accounts and notes receivable		261		213
Advances to money pool		-		15
Accounts receivable – affiliates		32		90
Materials and supplies		339		301
Mark-to-market derivative assets		50		7
Other current assets		48		43

Total current assets		983		1,163

Property and Plant, Net		8,995		8,189
Investments and Other Assets:
Nuclear decommissioning trust fund		239		307
Intangible assets		48		56
Regulatory assets		907		697
Other assets		352		491

Total investments and other assets		1,546		1,551

TOTAL ASSETS	$	11,524	$	10,903

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	4	$	152
Short-term debt		251		82
Intercompany note payable – Ameren		92		-
Accounts and wages payable		360		315
Accounts payable – affiliates		151		212
Taxes accrued		20		78
Interest accrued		56		47
Taum Sauk pumped-storage hydroelectric facility liability		18		103
Other current liabilities		103		59

Total current liabilities		1,055		1,048

Long-term Debt, Net		3,673		3,208
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		1,372		1,273
Accumulated deferred investment tax credits		80		85
Regulatory liabilities		922		865
Asset retirement obligations		317		476
Pension and other postretirement benefits		494		297
Other deferred credits and liabilities		49		50

Total deferred credits and other liabilities		3,234		3,046

Commitments and Contingencies (Notes 2, 14, 15 and 16)
Stockholders’ Equity:
Common stock, $5 par value, 150.0 shares authorized – 102.1 shares outstanding		511		511
Other paid-in capital, principally premium on common stock		1,119		1,119
Preferred stock not subject to mandatory redemption		113		113
Retained earnings		1,794		1,855
Accumulated other comprehensive income		25		3

Total stockholders’ equity		3,562		3,601

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	11,524	$	10,903

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

UNION ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2008		2007		2006
Cash Flows From Operating Activities:
Net income	$	251	$	342	$	349
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sales of emission allowances		(5)		(5)		(34)
Net mark-to-market (gain) loss on derivatives		29		(2)		(7)
Gain on sale of noncore properties		-		-		(13)
Depreciation and amortization		329		333		335
Amortization of nuclear fuel		37		37		36
Amortization of debt issuance costs and premium/discounts		6		6		5
Deferred income taxes and investment tax credits, net		89		1		38
Other		(28)		(6)		(1)
Changes in assets and liabilities:
Receivables		85		(60)		52
Materials and supplies		(32)		(65)		(37)
Accounts and wages payable		(89)		42		21
Taxes accrued, net		(61)		12		7
Assets, other		22		39		(79)
Liabilities, other		61		(48)		49
Pension and other postretirement benefits		-		18		36
Taum Sauk costs, net of insurance recoveries		(149)		(56)		(23)

Net cash provided by operating activities		545		588		734

Cash Flows From Investing Activities:
Capital expenditures		(874)		(625)		(490)
CT acquisitions		-		-		(292)
Nuclear fuel expenditures		(173)		(68)		(39)
Changes in money pool advances, net		-		3		(18)
Proceeds from intercompany note receivable		36		-		67
Sale of noncore properties		-		-		13
Purchases of securities – nuclear decommissioning trust fund		(520)		(142)		(110)
Sales of securities – nuclear decommissioning trust fund		497		128		98
Sales of emission allowances		1		4		39

Net cash used in investing activities		(1,033)		(700)		(732)

Cash Flows From Financing Activities:
Dividends on common stock		(264)		(267)		(249)
Dividends on preferred stock		(6)		(6)		(6)
Capital issuance costs		(5)		(3)		-
Short-term debt, net		169		(152)		154
Changes in intercompany note payable – Ameren, net		92		(77)		77
Redemptions, repurchases, and maturities of long-term debt		(382)		(4)		(4)
Issuances of long-term debt		699		424		-
Capital contribution from parent		-		380		6
Other		-		1		1

Net cash provided by (used in) financing activities		303		296		(21)

Net change in cash and cash equivalents		(185)		184		(19)
Cash and cash equivalents at beginning of year		185		1		20

Cash and cash equivalents at end of year	$	-	$	185	$	1

Cash Paid During the Year:
Interest	$	196	$	218	$	144
Income taxes, net		130		106		185

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

UNION ELECTRIC COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)


	December 31,
	2008		2007		2006
Common Stock	$	511	$	511	$	511

Other Paid-in Capital:
Beginning of year		1,119		739		733
Capital contribution from parent		-		380		6

Other paid-in capital, end of year		1,119		1,119		739

Preferred Stock Not Subject to Mandatory Redemption		113		113		113

Retained Earnings:
Beginning of year		1,855		1,783		1,689
Net income		251		342		349
Common stock dividends		(264)		(267)		(249)
Preferred stock dividends		(6)		(6)		(6)
Dividend-in-kind to Ameren		(42)		-		-
Adjustment to adopt FIN 48		-		3		-

Retained earnings, end of year		1,794		1,855		1,783

Accumulated Other Comprehensive Income:
Derivative financial instruments, beginning of year		3		7		5
Change in derivative financial instruments		22		(4)		2

Derivative financial instruments, end of year		25		3		7

Minimum pension liability, beginning of year		-		-		(35)
Change in minimum pension liability		-		-		35

Minimum pension liability, end of year		-		-		-

Total accumulated other comprehensive income, end of year		25		3		7

Total Stockholders’ Equity	$	3,562	$	3,601	$	3,153

Comprehensive Income, Net of Taxes:
Net income	$	251	$	342	$	349
Unrealized net gain on derivative hedging instruments, net of income taxes of $22, $-, and $4, respectively		36		-		9
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $9, $2, and $4, respectively		(14)		(4)		(7)
Minimum pension liability adjustment, net of income taxes of $-, $-, and $22, respectively		-		-		35

Total Comprehensive Income, Net of Taxes	$	273	$	338	$	386

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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

STATEMENT OF INCOME

(In millions)


	Year Ended December 31,
	2008		2007		2006
Operating Revenues:
Electric	$	720	$	772	$	728
Gas		259		230		220
Other		3		3		6

Total operating revenues		982		1,005		954

Operating Expenses:
Purchased power		461		527		471
Gas purchased for resale		179		157		149
Other operations and maintenance		196		172		161
Depreciation and amortization		67		66		63
Taxes other than income taxes		37		34		41

Total operating expenses		940		956		885

Operating Income		42		49		69

Other Income and Expenses:
Miscellaneous income		11		17		17
Miscellaneous expense		(3)		(3)		(2)

Total other income		8		14		15


Interest Charges		30		37		31


Income Before Income Taxes		20		26		53

Income Taxes		5		9		15


Net Income		15		17		38

Preferred Stock Dividends		3		3		3


Net Income Available to Common Stockholder	$	12	$	14	$	35

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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

BALANCE SHEET

(In millions)


	December 31,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	-	$	26
Accounts receivable – trade (less allowance for doubtful accounts of $6 and $5, respectively)		79		62
Unbilled revenue		74		66
Miscellaneous accounts and notes receivable		1		1
Accounts receivable – affiliates		4		9
Current portion of intercompany note receivable – Genco		42		39
Current portion of intercompany tax receivable – Genco		9		9
Materials and supplies		70		66
Counterparty collateral asset		21		-
Other current assets		22		16

Total current assets		322		294

Property and Plant, Net		1,212		1,174
Investments and Other Assets:
Intercompany note receivable – Genco		45		87
Intercompany tax receivable – Genco		93		105
Regulatory assets		212		113
Other assets		33		87

Total investments and other assets		383		392

TOTAL ASSETS	$	1,917	$	1,860

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	-	$	15
Short-term debt		62		125
Accounts and wages payable		48		44
Accounts payable – affiliates		49		19
Borrowings from money pool		44		-
Taxes accrued		7		8
Customer deposits		16		16
Mark-to-market derivative liabilities		17		1
Mark-to-market derivative liabilities – affiliates		14		-
Other current liabilities		51		30

Total current liabilities		308		258

Long-term Debt, Net		421		456
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes and investment tax credits, net		268		269
Regulatory liabilities		234		265
Pension and other postretirement benefits		79		67
Other deferred credits and liabilities		78		28

Total deferred credits and other liabilities		659		629

Commitments and Contingencies (Notes 2, 14, and 15)
Stockholders’ Equity:
Common stock, no par value, 45.0 shares authorized – 25.5 shares outstanding		-		-
Other paid-in capital		191		191
Preferred stock not subject to mandatory redemption		50		50
Retained earnings		288		276

Total stockholders’ equity		529		517

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,917	$	1,860

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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

STATEMENT OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2008		2007		2006
Cash Flows From Operating Activities:
Net income	$	15	$	17	$	38
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		67		66		63
Amortization of debt issuance costs and premium/discounts		1		1		1
Deferred income taxes and investment tax credits, net		(2)		(27)		(13)
Changes in assets and liabilities:
Receivables		(8)		(19)		50
Materials and supplies		(4)		5		4
Accounts and wages payable		14		(48)		2
Taxes accrued, net		(1)		(2)		(16)
Assets, other		(5)		21		(12)
Liabilities, other		26		(3)		(5)
Pension and other postretirement benefits		-		3		6

Net cash provided by operating activities		103		14		118

Cash Flows From Investing Activities:
Capital expenditures		(96)		(79)		(82)
Proceeds from intercompany note receivable – Genco		39		37		34
Bond repurchase		-		-		(17)
Changes in money pool advances, net		-		-		(1)

Net cash used in investing activities		(57)		(42)		(66)

Cash Flows From Financing Activities:
Dividends on common stock		-		(40)		(50)
Dividends on preferred stock		(3)		(3)		(3)
Capital issuance costs		-		-		(1)
Short-term debt, net		(63)		90		35
Changes in money pool borrowings, net		44		-		(2)
Redemptions, repurchases, and maturities:
Long-term debt		(50)		-		(20)
Intercompany note payable		-		-		(67)
Issuances of long-term debt		-		-		61
Capital contribution from parent		-		1		1

Net cash provided by (used in) financing activities		(72)		48		(46)

Net change in cash and cash equivalents		(26)		20		6
Cash and cash equivalents at beginning of year		26		6		-

Cash and cash equivalents at end of year	$	-	$	26	$	6

Cash Paid (Refunded) During the Year:
Interest	$	32	$	36	$	27
Income taxes, net		(21)		44		62

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

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)


	December 31,
	2008		2007		2006
Common Stock	$	-	$	-	$	-

Other Paid-in Capital:
Beginning of year		191		190		189
Equity contribution from parent		-		1		1

Other paid-in capital, end of year		191		191		190

Preferred Stock Not Subject to Mandatory Redemption		50		50		50

Retained Earnings:
Beginning of year		276		302		329
Cumulative effect adjustment		-		-		(12)

Beginning of year – as adjusted		276		302		317
Net income		15		17		38
Common stock dividends		-		(40)		(50)
Preferred stock dividends		(3)		(3)		(3)

Retained earnings, end of year		288		276		302

Accumulated Other Comprehensive Income:
Derivative financial instruments, beginning of year		-		1		7
Change in derivative financial instruments		-		(1)		(6)

Derivative financial instruments, end of year		-		-		1

Minimum pension liability, beginning of year		-		-		(6)
Change in minimum pension liability		-		-		6

Minimum pension liability, end of year		-		-		-

Total accumulated other comprehensive income, end of year		-		-		1

Total Stockholders’ Equity	$	529	$	517	$	543

Comprehensive Income, Net of Taxes:
Net income	$	15	$	17	$	38
Unrealized net (loss) on derivative hedging instruments, net of income taxes (benefit) of $-, $-, and $(3), respectively		-		-		(5)
Reclassification adjustments for (gains) included in net income, net of income taxes of $-, $1, and $1, respectively		-		(1)		(1)
Minimum pension liability adjustment, net of income taxes of $-, $-, and $4, respectively		-		-		6

Total Comprehensive Income, Net of Taxes	$	15	$	16	$	38

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

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF INCOME

(In millions)


	Year Ended December 31,
	2008		2007		2006
Operating Revenues	$	908	$	876	$	992

Operating Expenses:
Fuel		377		344		298
Coal contract settlement		(60)		-		-
Purchased power		-		23		320
Other operations and maintenance		175		163		153
Depreciation and amortization		65		69		72
Taxes other than income taxes		21		19		18

Total operating expenses		578		618		861

Operating Income		330		258		131

Other Income and Expenses:
Miscellaneous income		1		-		-
Miscellaneous expense		(1)		-		-

Total other income		-		-		-


Interest Charges		55		55		60


Income Before Income Taxes		275		203		71

Income Taxes		100		78		22


Net Income	$	175	$	125	$	49

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

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED BALANCE SHEET

(In millions, except shares)


	December 31,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	2	$	2
Accounts receivable – affiliates		88		93
Miscellaneous accounts and notes receivable		15		12
Materials and supplies		122		93
Other current assets		10		4

Total current assets		237		204

Property and Plant, Net		1,950		1,683
Intangible Assets		49		63
Other Assets		8		18

TOTAL ASSETS	$	2,244	$	1,968

LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Short-term debt	$	-	$	100
Current portion of intercompany note payable – CIPS		42		39
Borrowings from money pool		80		54
Accounts and wages payable		82		61
Accounts payable – affiliates		58		57
Current portion of intercompany tax payable – CIPS		9		9
Taxes accrued		16		15
Other current liabilities		43		30

Total current liabilities		330		365

Long-term Debt, Net		774		474
Intercompany Note Payable – CIPS		45		87
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		136		161
Accumulated deferred investment tax credits		6		7
Intercompany tax payable – CIPS		93		105
Asset retirement obligations		49		47
Pension and other postretirement benefits		67		32
Other deferred credits and liabilities		49		42

Total deferred credits and other liabilities		400		394

Commitments and Contingencies (Notes 2, 14 and 15)
Stockholder’s Equity:
Common stock, no par value, 10,000 shares authorized – 2,000 shares outstanding		-		-
Other paid-in capital		503		503
Retained earnings		241		167
Accumulated other comprehensive loss		(49)		(22)

Total stockholder’s equity		695		648

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	2,244	$	1,968

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

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2008		2007		2006
Cash Flows From Operating Activities:
Net income	$	175	$	125	$	49
Adjustments to reconcile net income to net cash provided by operating activities:
Gain on sales of emission allowances		(2)		(2)		(1)
Net mark-to-market (gain) loss on derivatives		16		(2)		5
Depreciation and amortization		92		101		104
Deferred income taxes and investment tax credits, net		14		30		25
Other		-		1		(1)
Changes in assets and liabilities:
Receivables		(13)		10		16
Materials and supplies		(29)		3		(23)
Accounts and wages payable		(11)		(4)		3
Taxes accrued, net		(4)		(7)		(15)
Assets, other		10		3		(29)
Liabilities, other		(5)		(8)		(1)
Pension and other postretirement benefits		1		5		6

Net cash provided by operating activities		244		255		138

Cash Flows From Investing Activities:
Capital expenditures		(317)		(191)		(85)
Purchases of emission allowances		(13)		(20)		(26)
Sales of emission allowances		2		1		1

Net cash used in investing activities		(328)		(210)		(110)

Cash Flows From Financing Activities:
Dividends on common stock		(101)		(113)		(113)
Debt issuance costs		(2)		-		-
Short-term debt, net		(100)		100		-
Money pool borrowings, net		26		(69)		(80)
Intercompany note payable – CIPS		(39)		(37)		(34)
Issuances of long-term debt		300		-		-
Capital contribution from parent		-		75		200

Net cash provided by (used in) financing activities		84		(44)		(27)

Net change in cash and cash equivalents		-		1		1
Cash and cash equivalents at beginning of year		2		1		-

Cash and cash equivalents at end of year	$	2	$	2	$	1

Cash Paid During the Year:
Interest	$	61	$	59	$	51
Income taxes, net		62		49		8

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

AMEREN ENERGY GENERATING COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY

(In millions)


	December 31,
	2008		2007		2006
Common Stock	$	-	$	-	$	-

Other Paid-in Capital:
Beginning of year		503		428		228
Capital contribution from Ameren		-		75		200

Other paid-in capital, end of year		503		503		428

Retained Earnings:
Beginning of year		167		156		220
Net income		175		125		49
Common stock dividends		(101)		(113)		(113)
Adjustment to adopt FIN 48		-		(1)		-

Retained earnings, end of year		241		167		156

Accumulated Other Comprehensive Loss:
Derivative financial instruments, beginning of year		(1)		3		2
Change in derivative financial instruments		(5)		(4)		1

Derivative financial instruments, end of year		(6)		(1)		3

Minimum pension liability, beginning of year		-		-		(6)
Change in minimum pension liability		-		-		6

Minimum pension liability, end of year		-		-		-

Deferred retirement benefit costs, beginning of year		(21)		(24)		-
Adjustment to adopt SFAS No. 158		-		-		(24)
Change in deferred retirement benefit costs		(22)		3		-

Deferred retirement benefit costs, end of year		(43)		(21)		(24)

Total accumulated other comprehensive loss, end of year		(49)		(22)		(21)

Total Stockholder’s Equity	$	695	$	648	$	563

Comprehensive Income, Net of Taxes:
Net income	$	175	$	125	$	49
Unrealized net gain (loss) on derivative hedging instruments, net of income taxes (benefit) of $-, $(2), and $2, respectively		-		(3)		3
Reclassification adjustments for derivative gains included in net income, net of income taxes of $3, $1, and $1, respectively		(5)		(1)		(2)
Minimum pension liability, net of income taxes of $-, $-, and $4, respectively		-		-		6
Pension and other postretirement activity, net of taxes (benefit) of $(19), $5, and $-, respectively		(22)		3		-

Total Comprehensive Income, Net of Taxes	$	148	$	124	$	56

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

CILCORP INC.

CONSOLIDATED STATEMENT OF INCOME

(In millions)


	Year Ended December 31,
	2008		2007		2006
Operating Revenues:
Electric	$	771	$	681	$	413
Gas		375		329		333
Other		1		1		1

Total operating revenues		1,147		1,011		747

Operating Expenses:
Fuel		126		77		109
Purchased power		291		281		49
Gas purchased for resale		284		237		246
Other operations and maintenance		220		181		179
Depreciation and amortization		81		78		75
Taxes other than income taxes		25		23		25

Total operating expenses		1,027		877		683

Operating Income		120		134		64

Other Income and Expenses:
Miscellaneous income		2		5		2
Miscellaneous expense		(5)		(5)		(4)

Total other expenses		(3)		-		(2)


Interest Charges		55		64		52


Income Before Income Taxes and Preferred Dividends of Subsidiaries		62		70		10

Income Taxes (Benefit)		19		21		(11)


Income Before Preferred Dividends of Subsidiaries		43		49		21

Preferred Dividends of Subsidiaries		1		2		2


Net Income	$	42	$	47	$	19

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

100

CILCORP INC.

CONSOLIDATED BALANCE SHEET

(In millions, except shares)


	December 31,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	-	$	6
Accounts receivable – trade (less allowance for doubtful accounts of $3 and $2, respectively)		60		52
Unbilled revenue		65		54
Accounts and notes receivable – affiliates		59		48
Advances to money pool		2		1
Materials and supplies		131		110
Deferred taxes – current		24		17
Other current assets		27		23

Total current assets		368		311

Property and Plant, Net		1,710		1,494
Investments and Other Assets:
Goodwill		542		542
Intangible assets		35		41
Regulatory assets		188		32
Other assets		22		39

Total investments and other assets		787		654

TOTAL ASSETS	$	2,865	$	2,459

LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Current maturities of long-term debt	$	126	$	-
Short-term debt		286		520
Borrowings from money pool		98		-
Intercompany note payable – Ameren		152		2
Accounts and wages payable		117		75
Accounts payable – affiliates		84		34
Taxes accrued		4		3
Other current liabilities		97		54

Total current liabilities		964		688

Long-term Debt, Net		536		537
Preferred Stock of Subsidiary Subject to Mandatory Redemption		-		16
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		212		193
Accumulated deferred investment tax credits		5		6
Regulatory liabilities		59		92
Pension and other postretirement benefits		216		127
Other deferred credits and liabilities		104		66

Total deferred credits and other liabilities		596		484

Preferred Stock of Subsidiary Not Subject to Mandatory Redemption		19		19
Commitments and Contingencies (Notes 2, 14 and 15)
Stockholder’s Equity:
Common stock, no par value, 10,000 shares authorized – 1,000 shares outstanding		-		-
Other paid-in capital		627		627
Retained earnings		100		58
Accumulated other comprehensive income		23		30

Total stockholder’s equity		750		715

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	2,865	$	2,459

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

101

CILCORP INC.

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2008		2007		2006
Cash Flows From Operating Activities:
Net income	$	42	$	47	$	19
Adjustments to reconcile net income to net cash provided by operating activities:
Net mark-to-market loss on derivatives		9		-		1
Depreciation and amortization		81		87		91
Amortization of debt issuance costs and premium/discounts		1		1		1
Deferred income taxes and investment tax credits		20		(5)		10
Loss on asset impairments		14		-		-
Other		-		1		8
Changes in assets and liabilities:
Receivables		(32)		(45)		36
Materials and supplies		(21)		(17)		(8)
Accounts and wages payable		65		(21)		(8)
Taxes accrued, net		11		(2)		1
Assets, other		(10)		10		-
Liabilities, other		15		(12)		-
Pension and postretirement benefits		(11)		(12)		(18)

Net cash provided by operating activities		184		32		133

Cash Flows From Investing Activities:
Capital expenditures		(319)		(254)		(119)
Proceeds from affiliate note receivable		-		-		71
Money pool advances, net		(1)		41		(42)
Purchases of emission allowances		-		-		(12)
Sales of emission allowances		-		-		1
Other		2		-		11

Net cash used in investing activities		(318)		(213)		(90)

Cash Flows From Financing Activities:
Dividends on common stock		-		-		(50)
Capital issuance costs		(1)		-		(2)
Short-term debt, net		(234)		305		215
Intercompany note payable – Ameren, net		150		(71)		(113)
Money pool borrowings, net		98		-		(154)
Redemptions, repurchases, and maturities of:
Long-term debt		(19)		(50)		(33)
Preferred stock		(16)		(1)		(1)
Issuances of long-term debt		150		-		96

Net cash provided by (used in) financing activities		128		183		(42)

Net change in cash and cash equivalents		(6)		2		1
Cash and cash equivalents at beginning of year		6		4		3

Cash and cash equivalents at end of year	$	-	$	6	$	4

Cash Paid (Refunded) During the Year:
Interest	$	72	$	50	$	53
Income taxes, net		(33)		16		(4)

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

102

CILCORP INC.

CONSOLIDATED STATEMENT OF STOCKHOLDER’S EQUITY

(In millions)


	December 31,
	2008		2007		2006
Common Stock	$	-	$	-	$	-

Other Paid-in Capital:
Beginning of year		627		627		640
Common stock dividends		-		-		(42)
Contribution from intercompany sale of leveraged leases		-		-		29

Other paid-in capital, end of year		627		627		627

Retained Earnings:
Beginning of year		58		11		-
Net income		42		47		19
Common stock dividends		-		-		(8)

Retained earnings, end of year		100		58		11

Accumulated Other Comprehensive Income:
Derivative financial instruments, beginning of year		1		4		25
Change in derivative financial instruments		(1)		(3)		(21)

Derivative financial instruments, end of year		-		1		4

Minimum pension liability, beginning of year		-		-		(2)
Change in minimum pension liability		-		-		2

Minimum pension liability, end of year		-		-		-

Deferred retirement benefit costs, beginning of year		29		29		-
Adjustment to adopt SFAS No. 158		-		-		29
Change in deferred retirement benefit costs		(6)		-		-

Deferred retirement benefit costs, end of year		23		29		29

Total accumulated other comprehensive income, end of year		23		30		33

Total Stockholder’s Equity	$	750	$	715	$	671

Comprehensive Income, Net of Taxes:
Net income	$	42	$	47	$	19
Unrealized net (loss) on derivative hedging instruments, net of income taxes (benefit) of $-, $(1), and $(13), respectively		-		(1)		(20)
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $1, $1, and $1, respectively		(1)		(2)		(1)
Minimum pension liability adjustment, net of income taxes of $-, $-, and $2, respectively		-		-		2
Pension and other postretirement activity, net of taxes (benefit) of $(5), $-, and $-, respectively		(6)		-		-

Total Comprehensive Income, Net of Taxes	$	35	$	44	$	-

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

103

CENTRAL ILLINOIS LIGHT COMPANY

CONSOLIDATED STATEMENT OF INCOME

(In millions)


	Year Ended December 31,
	2008		2007		2006
Operating Revenues:
Electric	$	771	$	681	$	413
Gas		375		329		333
Other		1		1		1

Total operating revenues		1,147		1,011		747

Operating Expenses:
Fuel		121		71		99
Purchased power		291		280		49
Gas purchased for resale		284		237		246
Other operations and maintenance		217		184		180
Depreciation and amortization		77		73		70
Taxes other than income taxes		25		23		25

Total operating expenses		1,015		868		669

Operating Income		132		143		78

Other Income and Expenses:
Miscellaneous income		2		5		1
Miscellaneous expense		(5)		(6)		(4)

Total other expenses		(3)		(1)		(3)


Interest Charges		21		27		18


Income Before Income Taxes		108		115		57

Income Taxes		39		39		10


Net Income		69		76		47

Preferred Stock Dividends		1		2		2


Net Income Available to Common Stockholder	$	68	$	74	$	45

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

104

CENTRAL ILLINOIS LIGHT COMPANY

CONSOLIDATED BALANCE SHEET

(In millions)


	December 31,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	-	$	6
Accounts receivable – trade (less allowance for doubtful accounts of $3 and $2, respectively)		60		52
Unbilled revenue		65		54
Accounts receivable – affiliates		51		45
Materials and supplies		131		110
Other current assets		42		27

Total current assets		349		294

Property and Plant, Net		1,734		1,492
Investments and Other Assets:
Intangible assets		1		1
Regulatory assets		188		32
Other assets		22		43

Total investments and other assets		211		76

TOTAL ASSETS	$	2,294	$	1,862

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Short-term debt	$	236	$	345
Borrowings from money pool		98		-
Accounts and wages payable		117		75
Accounts payable – affiliates		83		34
Taxes accrued		8		3
Other current liabilities		88		45

Total current liabilities		630		502

Long-term Debt, Net		279		148
Preferred Stock Subject to Mandatory Redemption		-		16
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		171		155
Accumulated deferred investment tax credits		5		6
Regulatory liabilities		206		220
Pension and other postretirement benefits		216		127
Other deferred credits and liabilities		103		66

Total deferred credits and other liabilities		701		574

Commitments and Contingencies (Notes 2, 14 and 15)
Stockholders’ Equity:
Common stock, no par value, 20.0 shares authorized – 13.6 shares outstanding		-		-
Other paid-in capital		429		429
Preferred stock not subject to mandatory redemption		19		19
Retained earnings		240		172
Accumulated other comprehensive income (loss)		(4)		2

Total stockholders’ equity		684		622

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,294	$	1,862

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

105

CENTRAL ILLINOIS LIGHT COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2008		2007		2006
Cash Flows From Operating Activities:
Net income	$	69	$	76	$	47
Adjustments to reconcile net income to net cash provided by operating activities:
Net mark-to-market loss on derivatives		9		-		1
Depreciation and amortization		77		74		82
Amortization of debt issuance costs and premium/discounts		1		1		1
Deferred income taxes and investment tax credits, net		15		(1)		13
Loss on asset impairment		12		-		-
Other		-		-		5
Changes in assets and liabilities:
Receivables		(27)		(42)		33
Materials and supplies		(21)		(17)		(8)
Accounts and wages payable		65		(6)		(19)
Taxes accrued, net		12		(2)		-
Assets, other		(7)		2		13
Liabilities, other		15		(12)		(15)
Pension and postretirement benefits		(11)		1		-

Net cash provided by operating activities		209		74		153

Cash Flows From Investing Activities:
Capital expenditures		(319)		(254)		(119)
Money pool advances, net		-		42		(42)
Purchases of emission allowances		-		-		(12)
Sales of emission allowances		-		-		1
Other		2		-		11

Net cash used in investing activities		(317)		(212)		(161)

Cash Flows From Financing Activities:
Dividends on common stock		-		-		(65)
Dividends on preferred stock		(1)		(2)		(2)
Capital issuance costs		(1)		-		(2)
Short-term debt, net		(109)		180		165
Money pool borrowings, net		98		-		(161)
Redemptions, repurchases, and maturities of:
Long-term debt		(19)		(50)		(21)
Preferred stock		(16)		(1)		(1)
Issuances of long-term debt		150		-		96
Capital contribution from parent		-		14		-

Net cash provided by financing activities		102		141		9

Net change in cash and cash equivalents		(6)		3		1
Cash and cash equivalents at beginning of year		6		3		2

Cash and cash equivalents at end of year	$	-	$	6	$	3

Cash Paid (Refunded) During the Year:
Interest	$	32	$	38	$	19
Income taxes, net		(15)		35		17

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

106

CENTRAL ILLINOIS LIGHT COMPANY

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(In millions)


	December 31,
	2008		2007		2006
Common Stock	$	-	$	-	$	-

Other Paid-in Capital:
Beginning of year		429		415		415
Capital contribution from parent		-		14		-

Other paid-in capital, end of year		429		429		415


Preferred Stock Not Subject to Mandatory Redemption		19		19		19

Retained Earnings:
Beginning of year		172		99		119
Net income		69		76		47
Common stock dividends		-		-		(65)
Preferred stock dividends		(1)		(2)		(2)
Adjustment to adopt FIN 48		-		(1)		-

Retained earnings, end of year		240		172		99

Accumulated Other Comprehensive Income (Loss):
Derivative financial instruments, beginning of year		1		4		25
Change in derivative financial instruments		(1)		(3)		(21)

Derivative financial instruments, end of year		-		1		4

Minimum pension liability, beginning of year		-		-		(16)
Change in minimum pension liability		-		-		16

Minimum pension liability, end of year		-		-		-

Deferred retirement benefit costs, beginning of year		1		(2)		-
Adjustment to adopt SFAS No. 158		-		-		(2)
Change in deferred retirement benefit costs		(5)		3		-

Deferred retirement benefit costs, end of year		(4)		1		(2)

Total accumulated other comprehensive income (loss), end of year		(4)		2		2

Total Stockholders’ Equity	$	684	$	622	$	535

Comprehensive Income, Net of Taxes:
Net income	$	69	$	76	$	47
Unrealized net (loss) on derivative hedging instruments, net of income taxes (benefit) of $-, $(1), and $(13), respectively		-		(1)		(20)
Reclassification adjustments for derivative (gains) included in net income, net of income taxes of $1, $1, and $1, respectively		(1)		(2)		(1)
Minimum pension liability adjustment, net of income taxes of $-, $-, and $10, respectively		-		-		16
Pension and other postretirement activity, net of taxes (benefit) of $(4), $2, and $-, respectively		(5)		3		-

Total Comprehensive Income, Net of Taxes	$	63	$	76	$	42

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

107

ILLINOIS POWER COMPANY

CONSOLIDATED STATEMENT OF INCOME

(In millions)


	Year Ended December 31,
	2008		2007		2006
Operating Revenues:
Electric	$	1,071	$	1,104	$	1,149
Gas		620		540		543
Other		5		2		2

Total operating revenues		1,696		1,646		1,694

Operating Expenses:
Purchased power		654		714		738
Gas purchased for resale		452		390		394
Other operations and maintenance		318		271		271
Depreciation and amortization		85		80		77
Amortization of regulatory assets		17		16		-
Taxes other than income taxes		67		66		73

Total operating expenses		1,593		1,537		1,553

Operating Income		103		109		141

Other Income and Expenses:
Miscellaneous income		11		14		6
Miscellaneous expense		(5)		(5)		(4)

Total other income		6		9		2


Interest Charges		99		77		49


Income Before Income Taxes		10		41		94

Income Taxes		5		15		37


Net Income		5		26		57

Preferred Stock Dividends		2		2		2


Net Income Available to Common Stockholder	$	3	$	24	$	55

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

108

ILLINOIS POWER COMPANY

CONSOLIDATED BALANCE SHEET

(In millions)


	December 31,
	2008		2007
ASSETS
Current Assets:
Cash and cash equivalents	$	50	$	6
Accounts receivable – trade (less allowance for doubtful accounts of $12 and $9, respectively)		152		137
Unbilled revenue		133		118
Accounts receivable – affiliates		23		17
Advances to money pool		44		-
Materials and supplies		144		134
Other current assets		77		38

Total current assets		623		450

Property and Plant, Net		2,329		2,220
Investments and Other Assets:
Goodwill		214		214
Regulatory assets		553		316
Other assets		47		119

Total investments and other assets		814		649

TOTAL ASSETS	$	3,766	$	3,319

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Current maturities of long-term debt	$	250	$	-
Current maturities of long-term debt payable to IP SPT		-		56
Short-term debt		-		175
Accounts and wages payable		94		85
Accounts payable – affiliates		105		36
Taxes accrued		8		7
Customer deposits		50		40
Mark-to-market derivative liabilities		36		8
Mark-to-market derivative liabilities – affiliates		20		-
Other current liabilities		85		32

Total current liabilities		648		439

Long-term Debt, Net		1,150		1,014
Deferred Credits and Other Liabilities:
Accumulated deferred income taxes, net		176		148
Regulatory liabilities		76		129
Pension and other postretirement benefits		314		189
Other deferred credits and liabilities		151		92

Total deferred credits and other liabilities		717		558

Commitments and Contingencies (Notes 2, 14 and 15)
Stockholders’ Equity:
Common stock, no par value, 100.0 shares authorized – 23.0 shares outstanding		-		-
Other paid-in-capital		1,194		1,194
Preferred stock not subject to mandatory redemption		46		46
Retained earnings		7		64
Accumulated other comprehensive income		4		4

Total stockholders’ equity		1,251		1,308

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	3,766	$	3,319

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

109

ILLINOIS POWER COMPANY

CONSOLIDATED STATEMENT OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2008		2007		2006
Cash Flows From Operating Activities:
Net income	$	5	$	26	$	57
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		93		105		21
Amortization of debt issuance costs and premium/discounts		9		8		4
Deferred income taxes		26		4		75
Other		-		(1)		-
Changes in assets and liabilities:
Receivables		(36)		(65)		71
Materials and supplies		(10)		(12)		-
Accounts and wages payable		57		(44)		(17)
Taxes accrued, net		3		-		(8)
Assets, other		(8)		(16)		(13)
Liabilities, other		46		28		(8)
Pension and other postretirement benefits		(5)		(5)		(10)

Net cash provided by operating activities		180		28		172

Cash Flows From Investing Activities:
Capital expenditures		(186)		(178)		(179)
Money pool advances, net		(44)		-		-
Other		(3)		(2)		(1)

Net cash used in investing activities		(233)		(180)		(180)

Cash Flows From Financing Activities:
Dividends on common stock		(60)		(61)		-
Dividends on preferred stock		(2)		(2)		(2)
Capital issuance costs		(5)		(2)		(1)
Short-term debt, net		(175)		100		75
Money pool borrowings, net		-		(43)		(32)
Redemptions, repurchases and maturities of long-term debt		(337)		-		-
Issuance of long-term debt		730		250		75
IP SPT maturities		(54)		(87)		(86)
Overfunding of TFNs		-		3		(21)

Net cash provided by financing activities		97		158		8

Net change in cash and cash equivalents		44		6		-
Cash and cash equivalents at beginning of year		6		-		-

Cash and cash equivalents at end of year	$	50	$	6	$	-

Cash Paid (Refunded) During the Year:
Interest	$	76	$	66	$	39
Income taxes, net		(43)		18		(9)

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)


	December 31,
	2008		2007		2006
Common Stock	$	-	$	-	$	-

Other Paid-in Capital:
Beginning of year		1,194		1,194		1,196
Other		-		-		(2)

Other paid-in capital, end of year		1,194		1,194		1,194

Preferred Stock Not Subject to Mandatory Redemption		46		46		46

Retained Earnings:
Beginning of year		64		101		46
Net income		5		26		57
Common stock dividends		(60)		(61)		-
Preferred stock dividends		(2)		(2)		(2)

Retained earnings, end of year		7		64		101

Accumulated Other Comprehensive Income:
Derivative financial instruments, beginning of year		-		-		(1)
Change in derivative financial instruments		-		-		1

Derivative financial instruments, end of year		-		-		-

Deferred retirement benefit costs, beginning of year		4		5		-
Adjustment to adopt SFAS No. 158		-		-		5
Change in deferred retirement benefit costs		-		(1)		-

Deferred retirement benefit costs, end of year		4		4		5

Total accumulated other comprehensive income, end of year		4		4		5

Total Stockholders’ Equity	$	1,251	$	1,308	$	1,346

Comprehensive Income, Net of Taxes:
Net income	$	5	$	26	$	57
Unrealized net (loss) on derivative hedging instruments, net of income taxes (benefit) of $-, $-, and $(1), respectively		-		-		(2)
Reclassification adjustments for derivative losses included in net income, net of income taxes (benefit) of $-, $-, and $(2), respectively		-		-		3
Pension and other postretirement activity, net of taxes of $-, $-, and $-, respectively		-		(1)		-

Total Comprehensive Income, Net of Taxes	$	5	$	25	$	58

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, 2008

NOTE 1– SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

Ameren, headquartered in St. Louis, Missouri, is a public utility holding company under PUHCA 2005, administered by FERC. Ameren’s primary assets are the common stock of its subsidiaries. Ameren’s subsidiaries are separate, independent legal entities with separate businesses, assets and liabilities. These subsidiaries operate rate-regulated electric generation, transmission and distribution businesses, rate-regulated natural gas transmission and distribution businesses, and non-rate-regulated electric generation businesses in Missouri and Illinois. Dividends on Ameren’s common stock and the payment of other expenses by the Ameren and CILCORP holding companies 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. 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 2.8 million and includes the Greater St. Louis area. UE supplies electric service to 1.2 million customers and natural gas service to 126,000 customers.

CIPS, or Central Illinois Public Service Company, also known as AmerenCIPS, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. CIPS was incorporated in Illinois in 1902. It supplies electric and gas utility service to portions of central, west central and southern Illinois having an estimated population of 1.1 million in an area of 20,500 square miles. CIPS supplies electric service to 393,000 customers and natural gas service to 185,000 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. Genco owns

2,557 megawatts of coal-fired electric generating capacity and 1,663 megawatts of natural gas and oil-fired electric generating capacity.

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 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 0.6 million. CILCO supplies electric service to 214,000 customers and natural gas service to 216,000 customers. AERG, a non-rate-regulated wholly-owned subsidiary of CILCO, owns 1,125 megawatts of coal-fired electric generating capacity and 15 megawatts of oil-fired electric generating capacity. CILCORP was incorporated in Illinois in 1985.

IP, or Illinois Power Company, also known as AmerenIP, operates a rate-regulated electric and natural gas transmission and distribution business in Illinois. 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 1.5 million in an area of 15,000 square miles, contiguous to our other service territories. IP supplies electric service to 627,000 customers and natural gas service to 421,000 customers, including most of the Illinois portion of the Greater St. Louis area.

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, which until February 29, 2008, was held 40% by UE and 40% by Development Company. Ameren consolidates EEI for financial reporting purposes. UE reported EEI under the equity method until February 29, 2008. Effective February 29, 2008, UE’s and Development Company’s ownership interests in EEI were transferred to Resources Company through an internal reorganization. UE’s interest in EEI was transferred at book value indirectly through a dividend to Ameren. See Note 14 – Related Party Transactions for additional information.

The following table presents summarized financial information of EEI (in millions):


For the years ended December 31,	2008		2007		2006
Operating revenues	$	520	$	427	$	371
Operating income		226		216		227
Net income		142		136		136
As of December 31,
Current assets	$	76	$	69	$	58
Noncurrent assets		140		124		108
Current liabilities		93		60		70
Noncurrent liabilities		43		10		17

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The financial statements of Ameren, Genco, CILCORP and CILCO are prepared on a consolidated basis. CIPS has no subsidiaries and therefore is not consolidated. UE had a subsidiary in 2007 and 2006 (Union Electric Development Corporation), but in January 2008 this subsidiary was transferred to Ameren in the form of a stock dividend. In March 2008 it was merged into an Ameren nonregistrant subsidiary. Accordingly, UE’s financial statements were prepared on a consolidated basis for 2007 and 2006 only. IP had a subsidiary in 2007 and 2006 (Illinois Gas Supply Company) that was dissolved at December 31, 2007. Accordingly, IP’s financial statements were prepared on a consolidated basis for 2007 and 2006 only. 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) that are 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.

Regulation

Certain Ameren subsidiaries are 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 2 – Rate and Regulatory Matters for further information.

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 represents our best estimate of existing accounts receivable that will ultimately be uncollectible. The allowance is calculated by applying estimated write-off factors to various classes of outstanding receivables, including unbilled revenue. The write-off factors used to estimate uncollectible accounts are based upon consideration of both historical collections experience and management’s best estimate of future collections success given the existing collections environment.

Materials and Supplies

Materials and supplies are recorded at the lower of cost or market. Cost is determined using the average-cost method. Materials are charged to inventory when purchased and then expensed or capitalized to plant, as appropriate, when installed. The following table presents a breakdown of materials and supplies for each of the Ameren Companies at December 31, 2008 and 2007:


	Ameren ^(a)		UE		CIPS		Genco		CILCORP		CILCO		IP
2008:
Fuel ^(b)	$	290	$	139	$	-	$	92	$	32	$	32	$	-
Gas stored underground		277		32		54		-		75		75		117
Other materials and supplies		275		168		16		30		24		24		27
	$	842	$	339	$	70	$	122	$	131	$	131	$	144
2007:
Fuel ^(b)	$	253	$	129	$	-	$	67	$	36	$	36	$	-
Gas stored underground		245		30		52		-		52		52		110
Other materials and supplies		237		142		14		26		22		22		24
	$	735	$	301	$	66	$	93	$	110	$	110	$	134

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

(b)	Consists of coal, oil, paint, propane, and tire chips.

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,

including nuclear refueling and maintenance outages, 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 that do not constitute legal obligations are expensed as incurred. Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Asset Retirement Obligations below and Note 3 – Property and Plant, Net, for further information.

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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 2008, 2007 and 2006 generally ranged from 3% to 4% of the average depreciable cost. Due to the ICC consolidated electric and gas rate order that became effective on October 1, 2008, annual depreciation expense for the Ameren Illinois Utilities will be reduced for financial reporting purposes by a net $13 million in the aggregate (CIPS – $4 million reduction, CILCO – $26 million reduction, and IP – $17 million increase).

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 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 and 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 2008, 2007 and 2006:


	2008		2007		2006
Ameren	1% - 7	%	6% - 7	%	6% - 9	%
UE	7		6		6
CIPS	1		6		9
CILCORP/CILCO	1		7		6
IP	5		6		6

Goodwill and Intangible Assets

Goodwill. Goodwill represents the excess of the purchase price of an acquisition over the fair value of the net assets acquired. As of December 31, 2008, Ameren, CILCORP, and IP had goodwill of $831 million, $542 million, and $214 million, respectively. Ameren’s and IP’s goodwill relates to the acquisition of IP in 2004. Ameren’s and CILCORP’s goodwill relates to the acquisition of CILCORP in 2003. Ameren’s goodwill also includes an additional 20% ownership interest in EEI acquired in 2004 as well as the acquisition of Medina Valley in 2003.

In accordance with the specific provisions of SFAS No. 142, “Goodwill and Other Intangible Assets,” we test goodwill for impairment at the reporting unit level. Ameren has identified three reporting units, which also represent Ameren’s reportable segments and operating segments under SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information.” The Ameren reporting units include Missouri Regulated, Illinois Regulated, and Non-rate-regulated Generation. Ameren’s reporting units have been defined and goodwill is evaluated at the operating

segment level because we believe the components within each operating segment have similar economic characteristics. The following table details how goodwill has been assigned to the reporting units:


	Missouri Regulated		Illinois Regulated		Non-rate-regulated Generation			Total
Ameren	$	-	$	411	$	420	^(a)	$	831	^(a)
CILCORP		-		197		345			542
IP		-		214		-			214

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

We evaluate goodwill for impairment as of October 31 of each year, or more frequently if events and circumstances indicate that the asset might be impaired. Impairment testing of goodwill is a two-step process. The first step involves a comparison of the estimated fair value of a reporting unit with its carrying amount. If the estimated fair value of the reporting unit exceeds the carrying value, goodwill of the reporting unit is considered unimpaired. If the carrying amount of the reporting unit exceeds its estimated fair value, the second step is performed to measure the amount of impairment, if any. The second step requires a calculation of the implied fair value of goodwill.

The goodwill impairment test performed in the fourth quarter of 2008 did not require a second step assessment; it indicated no impairment of Ameren’s, CILCORP’s or IP’s goodwill. The fair value of Ameren’s, CILCORP’s and IP’s reporting units was estimated based on a probability-weighted discounted cash flow model that considered multiple operating scenarios. Key assumptions in the determination of fair value included the use of an appropriate discount rate, estimated five-year future cash flows, and an exit value based on observable market multiples. We use our best estimates in making these evaluations and consider various factors, including forward price curves for energy, fuel costs, the regulatory environment, and operating costs. The failure to achieve projected future operating results and cash flows, or adjustments to other valuation assumptions, could change our estimate of reporting unit fair value, in which case we might be required, at a later date, to record an impairment charge related to goodwill.

At Ameren and IP, either (1) a decrease in the forecasted cash flows of ten percent, (2) an increase in the discount rate of one percentage point, or (3) a decrease of the market multiple by one would not have resulted in the carrying value of any of the reporting units exceeding their fair values.

The estimated fair values of CILCORP’s Illinois Regulated reporting unit and Non-rate-regulated Generation reporting unit exceeded carrying values by a nominal amount as of October 31, 2008. As a result, the failure in the future of either of these reporting units to achieve forecasted operating results and cash flows may reduce its estimated fair value below its carrying value and would likely result in the recognition of a goodwill impairment charge. CILCORP will continue to monitor the actual and forecasted operating results and cash flows and observable market multiples of these reporting units for signs of

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possible declines in estimated fair value and potential goodwill impairment. Ameren would not necessarily expect any future goodwill impairment charge recorded at the CILCORP reporting unit level to also result in a goodwill impairment charge at the consolidated Ameren level because of the aggregation of reporting units.

Intangible Assets. We evaluate intangible assets for impairment if events or changes in circumstances indicate that their carrying amount might be impaired. Ameren’s, UE’s, Genco’s, CILCORP’s and CILCO’s intangible assets at December 31, 2008 and 2007, consisted of emission allowances. See also Note 15 – Commitments and Contingencies for additional information on emission allowances.

The following table presents the SO ₂ and NO _x emission allowances held and the related aggregate SO ₂ and NO _x emission allowance book values that were carried as intangible assets as of December 31, 2008. Emission allowances consist of various individual emission allowance certificates and do not have expiration dates. Emission allowances are charged to fuel expense as they are used in operations.


SO ₂ and NO _x in tons	SO ₂ ^(a)	NO _x ^(b)	Book Value ⁽ ^c ⁾
Ameren ^(d)	3,014,000	15,035	$	167	^(e)
UE	1,640,000	5,505		48
Genco	720,000	8,125		49
CILCORP ^(f)	337,000	209		35
CILCO (AERG)	337,000	209		1
EEI	317,000	1,196		9

(a)	Vintages are from 2008 to 2018. Each company possesses additional allowances for use in periods beyond 2018.

(b)	Vintage is 2008.

(c)

The book value at December 31, 2008, represents SO ₂ and NO _x emission allowances for use in periods through 2031. The book value at December 31, 2007, for Ameren, UE, Genco, CILCORP, CILCO (AERG), and EEI was $198 million, $56 million, $63 million, $41 million, $1 million, and $9 million, respectively.

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

(e)	Includes $26 million of fair-market value adjustments recorded in connection with Ameren’s acquisition of an additional 20% ownership interest in EEI.

(f)	Includes fair-market value adjustments recorded in connection with Ameren’s acquisition of CILCORP.

The following table presents the amortization expense based on usage of emission allowances, net of gains from emission allowance sales, for Ameren, UE, Genco, CILCORP, and CILCO (AERG) during the years ended December 31, 2008, 2007, and 2006:


	2008			2007			2006
Ameren ^(a)(b)	$	28		$	35		$	(3	)
UE		(5	)		(5	)		(34	)
Genco		25			30			30
CILCORP ^(b)		6			7			21
CILCO (AERG)		(c	)		1			11

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

(b)	Includes allowances consumed that were recorded through purchase accounting.

(c)	Less than $1 million.

Impairment of Long-lived Assets

We evaluate long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Whether impairment has occurred is determined by comparing the estimated undiscounted cash flows attributable to the assets with the carrying value of the assets. If the carrying value exceeds the undiscounted cash flows, we recognize the amount of the impairment by estimating the fair value of the assets and recording a provision for loss. During the fourth quarter of 2008, asset impairment charges were recorded to adjust the carrying value of CILCO’s (AERG’s) Indian Trails and Sterling Avenue generation facilities to their estimated fair values as of December 31, 2008. CILCO recorded an asset impairment charge of $12 million related to the Indian Trails cogeneration facility as a result of the suspension of operations by the facility’s only customer. CILCORP recorded a $2 million impairment charge related to the Sterling Avenue CT based on the expected net proceeds to be generated from the sale of the facility in 2009. These charges were recorded in Operating Expenses – Other Operations and Maintenance Expense in the applicable statements of income and were included with Non-rate-regulated Generation segment results.

Investments

Ameren and UE evaluate for impairment the investments held in UE’s nuclear decommissioning trust fund. Losses on assets in the trust fund could result in higher funding requirements for decommissioning costs, which we believe would be recovered in electric rates paid by UE’s customers. Accordingly, Ameren and UE recognize a regulatory asset on their balance sheets for losses on investments held in the nuclear decommissioning trust fund. See Note 9 – Nuclear Decommissioning Trust Fund Investments for additional information.

Environmental Costs

Environmental costs are recorded on an undiscounted basis when it is probable that a liability has been incurred and that the amount of the liability can be reasonably estimated. Estimated environmental expenditures 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.

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Revenue

Operating 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 revenues for service rendered but unbilled at the end of each accounting period.

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.

Nuclear Fuel and Purchased Gas Costs

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

In UE’s, CIPS’, CILCO’s, and IP’s retail natural gas utility jurisdictions, changes in gas costs are generally reflected in billings to their natural gas utility customers through PGA clauses. The difference between actual natural gas costs and costs billed to customers in a given period are deferred and included in Other Current Assets or Other Current Liabilities in the balance sheets of UE, CIPS, CILCO and IP. The deferred amounts are either billed or refunded to their natural gas utility customers prospectively in a subsequent period.

Accounting for MISO Transactions

MISO-related purchase and sale transactions are recorded by Ameren, UE, CIPS, CILCO and IP using settlement information provided by MISO. These purchase and sale transactions are accounted for on a net hourly position. We record net purchases in a single hour in Operating Expenses – Purchased Power and net sales in a single hour in Operating Revenues – Electric in our statements of income. On occasion, prior period transactions will be resettled outside the routine settlement process due to a change in MISO’s tariff or a material interpretation thereof. In these cases, Ameren, UE, CIPS, CILCO and IP recognize expenses associated with resettlements once the resettlement is probable and the resettlement amount can be estimated. Ameren, UE, CIPS, CILCO and IP recognize revenues associated with resettlements in accordance with SEC Staff Accounting Bulletin No. 101, “Revenue Recognition in Financial Statements.”

Stock-based Compensation

In accounting for stock-based compensation, Ameren measures the cost of employee services received in exchange for an award of equity instruments by the grant-date fair value of the award over the requisite service period.

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

Excise Taxes

Excise taxes imposed on us are reflected on Missouri electric, Missouri gas, and Illinois gas customer bills. They are recorded gross in Operating Revenues and Operating Expenses – Taxes Other Than Income Taxes on the statement of income. Excise taxes reflected on Illinois electric customer bills are imposed on the consumer and are therefore not included in revenues and expenses. They are recorded as tax collections payable and included in Operating Expenses – Taxes Accrued. The following table presents excise taxes recorded in Operating Revenues and Operating Expenses – Taxes Other than Income Taxes for the years ended 2008, 2007 and 2006:


	2008		2007		2006
Ameren	$	172	$	166	$	169
UE		109		110		106
CIPS		16		15		16
CILCORP		13		11		12
CILCO		13		11		12
IP		34		30		35

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, that is, equity and temporary differences related to property and plant acquired before 1976 that were unrecognized temporary differences prior to the adoption of SFAS No. 109.

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

UE, CIPS, Genco, CILCORP, CILCO, and IP are parties to a tax sharing agreement with Ameren that provides for the allocation of consolidated tax liabilities. The tax sharing

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agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. Any net benefit attributable to the parent is reallocated to other members. That allocation is treated as a contribution to the capital of the party receiving the benefit.

Minority Interest and Preferred Dividends of Subsidiaries

For the years ended December 31, 2008, 2007, and 2006, Ameren had minority interest expense related to EEI of $29 million, $27 million, and $27 million, respectively, and preferred dividends of subsidiaries of $10 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 2008, 2007, and 2006. The number of stock options, restricted stock shares, and performance share units outstanding was immaterial. The assumed stock option conversions increased the number of shares outstanding in the diluted earnings per share calculation by 16,841 shares in 2008, 35,545 shares in 2007, and 38,438 shares in 2006.

Accounting Changes and Other Matters

SFAS No. 157, Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157, which defines fair value, establishes a framework for measuring fair value, and expands required disclosures about fair value measurements. SFAS No. 157 clarifies that fair value is a market-based measurement that should be based on the assumptions that market participants would use in pricing an asset or liability. See Note 8 – Fair Value Measurements for additional information on our adoption of SFAS No. 157.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment of SFAS No. 115

In February 2007, the FASB issued SFAS No. 159, which permits companies to choose to measure at fair value many financial instruments and certain assets and liabilities that are not currently required to be measured at fair value on an instrument-by-instrument basis. Entities electing the fair value option will be required to recognize changes in fair value in earnings and to expense upfront cost and fees associated with the item for which the fair value option is elected. SFAS No. 159 was effective as of the beginning of our 2008 fiscal year. We did not elect the fair value option for any of our eligible financial instruments or other items.

FSP FIN 39-1, Amendment of FASB Interpretation No. 39

In April 2007, the FASB issued FSP FIN 39-1, effective for us as of the beginning of our 2008 fiscal year. FSP FIN 39-1 permits companies to offset fair value amounts

recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a liability) against fair value amounts recognized for derivative instruments that are executed with the same counterparty under the same master netting arrangement. We did not elect to adopt FSP FIN 39-1 for any of our eligible financial instruments or other items.

SFAS No. 141 (Revised 2007), Business Combinations

In December 2007, the FASB issued SFAS No. 141(R), which replaces SFAS No. 141. SFAS No. 141(R) applies to all transactions in which an entity obtains control of one or more businesses and combinations without the transfer of consideration. SFAS No. 141(R) requires the acquiring entity in a business combination to recognize assets acquired and liabilities assumed in the transaction at fair value; it requires certain contingent assets and liabilities acquired be recognized at their fair values on the acquisition date; and it requires expensing of acquisition-related costs as incurred, among other provisions. SFAS No. 141(R) was effective as of January 1, 2009. It applies prospectively to business combinations completed on or after that date.

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an amendment of ARB No. 51

In December 2007, the FASB issued SFAS No. 160, which establishes accounting and reporting standards for minority interests, which will be recharacterized as noncontrolling interests. Under the provisions of SFAS No. 160, noncontrolling interests will be classified as a component of equity separate from the parent’s equity; purchases or sales of equity interests that do not result in a change in control will be accounted for as equity transactions; net income attributable to the noncontrolling interest will be included in consolidated net income in the statement of income; and upon a loss of control, the interest sold, as well as any interest retained, will be recorded at fair value, with any gain or loss recognized in earnings. SFAS No. 160 was effective for us as of the beginning of our 2009 fiscal year. It applies prospectively, except for the presentation and disclosure requirements, for which it applies retroactively. This standard is applicable to the minority interest in EEI, as EEI is 80% owned by Ameren.

SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities – an amendment of SFAS No. 133

In March 2008, the FASB issued SFAS No. 161, which requires enhanced disclosures about (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and its related interpretations, and (3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures

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about fair value amounts of and gains and losses on derivative instruments, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS No. 161 was effective in the first quarter of 2009. The adoption of SFAS No. 161 did not have a material impact on our results of operations, financial position, or liquidity, because it provides enhanced disclosure requirements only.

FSP SFAS No. 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active

In October 2008, the FASB issued FSP SFAS No. 157-3, which clarifies the application of SFAS No. 157 in a market that is not active. FSP SFAS No. 157-3 provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP SFAS No. 157-3 was effective upon issuance, and it applied retroactively to periods for which financial statements had not yet been issued. The adoption of FSP SFAS No. 157-3 did not have a material impact on our results of operations, financial condition, or liquidity.

FSP SFAS No. 140-4 and FIN 46(R), Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities

In December 2008, FASB issued FSP SFAS No. 140-4 and FIN 46(R), effective for us as of December 31, 2008.

FSP SFAS No. 140-4 and FIN 46(R) require enhanced qualitative and quantitative information about an enterprise’s involvement with a variable-interest entity (VIE) and its continuing involvement with transferred financial assets. For VIEs, enhanced qualitative and quantitative information about an enterprise’s involvement with a VIE, financial or other support provided by the enterprise to the VIE, and the methodology applied in determining whether an enterprise is the primary beneficiary should be disclosed. See Variable-interest Entities below for further information.

FSP SFAS No. 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets

In December 2008, FASB issued FSP SFAS No. 132(R)-1, which will be effective for us as of December 31, 2009. FSP SFAS No. 132(R)-1 requires additional disclosures related to pension and other postretirement benefit plan assets. Additional disclosures include the investment allocation decision-making process, the fair value of each major category of plan assets as well as the inputs and valuation techniques used to measure fair value and significant concentrations of risk within the plan assets. The adoption of FSP SFAS No. 132(R)-1 will not have a material impact on our results of operations, financial position or liquidity, because it provides enhanced disclosure requirements only.

Asset Retirement Obligations

SFAS No. 143, “Accounting for Asset Retirement Obligations , ” and FIN 47, “Accounting for Conditional Asset Retirement Obligations” – an Interpretation of FASB Statement No. 143 , require 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. Ameren, UE, Genco, CILCORP, and CILCO have recorded AROs for retirement costs associated with UE’s Callaway nuclear plant decommissioning costs, asbestos removal, ash ponds, and river structures. In addition, Ameren, UE, CIPS, and IP have recorded AROs for the disposal of certain transformers.

Asset removal costs accrued by our rate-regulated operations that do not constitute legal obligations are classified as a regulatory liability. See Note 2 – Rate and Regulatory Matters.

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The following table provides a reconciliation of the beginning and ending carrying amount of AROs for the years 2008 and 2007:


	Ameren ^(a)(b)			UE ^(b)			CIPS			Genco			CILCORP/ CILCO			IP
Balance at December 31, 2006	$	553		$	491		$	2		$	35		$	17		$	2
Liabilities incurred		1			1			-			-			-			-
Liabilities settled		(2	)		(1	)		-			(1	)		(c	)		-
Accretion in 2007 ⁽ ^d ⁾		32			28			(c	)		2			1			(c	)
Change in estimates ^(e)		(17	)		(43	)		(c	)		16			10			-
Balance at December 31, 2007	$	567		$	476		$	2		$	52		$	28		$	2
Liabilities settled		(4	)		(c	)		-			(1	)		(2	)		(c	)
Accretion in 2008 ⁽ ^d ⁾		33			27			(c	)		3			2			(c	)
Change in estimates ^(f)		(186	)		(186	)		-			(c	)		(c	)		-
Balance at December 31, 2008	$	410		$	317		$	2		$	54		$	28		$	2

(a)	Ameren amounts do not equal total due to AROs at EEI.

(b)	The nuclear decommissioning trust fund assets of $239 million and $307 million as of December 31, 2008 and 2007, respectively, are restricted for decommissioning of the Callaway nuclear plant.

(c)	Less than $1 million.

(d)	Substantially all accretion expense was recorded as an increase to regulatory assets.

(e)	UE, Genco and CILCO changed estimates related to retirement costs for their ash ponds. Additionally, UE changed estimates related to its Callaway nuclear plant decommissioning costs.

(f)	UE changed estimates related to its Callaway nuclear plant decommissioning costs based on a cost study performed in 2008, a change in assumptions related to plant life, and a decline in the cost escalation factor assumptions.

Variable-interest Entities

According to FIN 46R, “Variable-interest Entities,” an entity is considered a variable-interest entity (VIE) if it does not have sufficient equity to finance its activities without assistance from variable-interest holders, or if its equity investors lack any of the following characteristics of a controlling financial interest: control through voting rights, the obligation to absorb expected losses, or the right to receive expected residual returns. Ameren and its subsidiaries review its equity interests, debt obligations, leases, contracts, and other agreements to determine its relationship to a VIE. We have determined that the following significant VIEs were held by the Ameren Companies at December 31, 2008:

Leveraged lease and affordable housing partnership investments . Ameren has investments in affordable housing and low-income real estate development partnership arrangements that are variable interests. Ameren also has an investment in a leveraged lease. We have concluded that Ameren is not the primary beneficiary of any of the VIEs related to these investments because Ameren would not absorb a majority of the entity’s losses. These investments are classified as Other Assets on Ameren’s consolidated balance sheet. The maximum exposure to loss as a result of these variable interests is limited to the investments in these arrangements. At December 31, 2008, and December 31, 2007, Ameren had investments in affordable housing and low-income real estate development partnerships of $82 million and $100 million, respectively. At December 31, 2008, and December 31, 2007, Ameren had a net investment in a leveraged lease of $9 million. For these variable interests, Ameren is a limited partner. It owns less than

a 50 percent interest and receives the benefits and accepts the risks consistent with its limited partner interest. In 2008, a subsidiary of UE that owned affordable housing partnerships was eliminated in an internal reorganization. Those investments were transferred to a nonregistrant Ameren subsidiary.

IP’s variable interest in IP SPT was eliminated, as the TFNs for which the IP SPT was established were redeemed in September 2008. IP had indemnified IP SPT; IP was liable to IP SPT if IP did not bill the applicable charges to its customers on behalf of IP SPT or if it did not remit the collections to IP SPT. However, the note holders were considered the primary beneficiaries of this special-purpose trust. Accordingly, Ameren and IP did not consolidate IP SPT.

Coal Contract Settlement

In June 2008, Genco entered into an agreement with a coal mine owner. The owner provided Genco with a lump-sum payment of $60 million in July 2008 due to the coal supplier’s premature closing of a mine and the early termination of a coal supply contract. The settlement agreement compensates Genco, in total, for higher fuel costs it incurred in 2008 ($33 million) and expects to incur in 2009 ($27 million) as a result of the mine closure and contract termination.

NOTE 2 – RATE AND REGULATORY MATTERS

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

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Missouri

2007 Electric Rate Order

In May 2007, the MoPSC issued an order, as clarified, granting UE a $43 million increase in base rates for electric service based on a return on equity of 10.2% and a capital structure of 52% common equity. New electric rates became effective June 4, 2007.

In July 2007, UE and other parties appealed certain aspects of the MoPSC decision, to the Circuit Court of Cole County in Jefferson City, Missouri and subsequently to the Court of Appeals for the Western District of Missouri. In January 2009, the Court of Appeals for the Western District of Missouri issued an order affirming, in all respects, the order issued by the MoPSC in May 2007, and the time to appeal this court decision has expired.

2009 Electric Rate Order

In April 2008, UE filed a request with the MoPSC to increase its annual revenues for electric service by $251 million. The electric rate increase request proposed an average increase in electric rates of 12.1%. It was based on a 10.9% return on equity, a capital structure composed of 52% common equity, a rate base of $5.9 billion, and a test year ended March 31, 2008, with updates for known and measurable changes through September 30, 2008.

As part of the proceeding, UE requested that the MoPSC also approve implementation of a FAC and a vegetation management and infrastructure inspection cost recovery mechanism.

On January 27, 2009, the MoPSC issued an order approving an increase for UE in annual revenues for electric service of approximately $162 million based on a 10.76% return on equity, a capital structure composed of 52% common equity, and a rate base of $5.8 billion. The rate changes necessary to implement the provisions of the MoPSC’s order were effective March 1, 2009, with the MoPSC’s acceptance of conforming tariffs filed by UE. The MoPSC order also included the following significant provisions:

Approval of the implementation of a FAC. The mechanism provides for the adjustment of electric rates three times per year for a pass-through to customers of 95% of changes in fuel and purchased power costs, net of off-system revenues, including MISO costs and revenues, above or below the amount set in base rates, subject to MoPSC prudency review.

Approval of the implementation of a vegetation management and infrastructure inspection cost tracking mechanism. The mechanism provides for the tracking of expenditures that are more or less than amounts provided for in UE’s annual revenues for electric service in a particular year, subject to a 10% limitation on increases in any one year. The tracked amounts may be reflected in rates set in future rate cases.

Pursuant to an accounting order issued by the MoPSC in April 2008 that gave UE the ability to seek direct recovery of all or a portion of operations and maintenance expenses incurred as a result of a severe ice storm in January 2007, the rate order concluded that the $25 million of operations and maintenance expenses incurred as a result of the severe ice storm should be amortized and recovered over a five-year period starting March 1, 2009. UE recorded these costs as a regulatory asset in 2008.

Allowance for recovery of $12 million of costs associated with a March 2007 FERC order that resettled costs among MISO market participants. The costs were previously expensed. A regulatory asset was recorded at December 31, 2008, and will be amortized over a two-year period starting March 1, 2009.

UE provides power to Noranda’s smelter plant in New Madrid, Missouri. This plant has historically used approximately four million megawatthours of power annually, making Noranda UE’s single largest customer and constituting approximately 8% of UE’s total electric sales.

As a result of a major winter ice storm in Southeastern Missouri in January 2009, Noranda’s smelter plant experienced a power outage related to non-UE lines delivering power to the substation serving the plant. Noranda stated that the outage affected approximately 75% of the smelter plant’s capacity. In addition, Noranda stated that based on preliminary information and management’s initial assessment, restoring full plant capacity may take up to 12 months, with partial capacity phased in during the 12 month period.

To the extent UE’s sales to Noranda are reduced, generation made available could be sold as off-system sales. However, the FAC approved in the January 2009 electric rate order would require UE to pass through substantially all of the off-system revenues to customers.

In order to adjust the FAC for this unanticipated event, UE sought rehearing by the MoPSC of its January 2009 electric rate order on February 5, 2009, to allow UE to first recover from the off-system sales any revenues it would lose as a result of the reduced tariff sales to Noranda with any excess revenues collected being provided to customers through the FAC. Also in February 2009, other parties to the rate case filed for rehearing of certain aspects of the MoPSC order. In February 2009, the MoPSC denied all rate order rehearing requests filed by UE and other parties. UE continues to consider other alternatives to recover any lost revenues resulting from the Noranda power outage. UE cannot predict whether court appeals will be filed by other parties to the rate case.

Environmental Cost Recovery Mechanism

A Missouri law enacted in July 2005 enables the MoPSC to put in place an environmental cost recovery mechanism for Missouri’s utilities. The law also includes

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rate case filing requirements, a 2.5% annual rate increase cap for the environmental cost recovery mechanism, and prudency reviews, among other things. The MoPSC initiated a proceeding in December 2008 to develop revised rules for the cost recovery mechanism. Rules for the environmental cost recovery mechanism are expected to be approved by the MoPSC during the second quarter of 2009 and will be effective once published in the Missouri Register. UE will not be able to implement an environmental cost recovery mechanism until so authorized by the MoPSC as part of a rate case proceeding.

Renewable Energy Portfolio Requirement

A ballot initiative passed by Missouri voters in November 2008 that created a renewable energy portfolio requirement. UE and other Missouri investor-owned utilities will be required to purchase or generate electricity from renewable energy sources equaling at least 2% of native load sales by 2011, with that percentage increasing in subsequent years to at least 15% by 2021, subject to a 1% limit on customer rate impacts. At least 2% of each portfolio requirement must be derived from solar energy. Compliance with the renewable energy portfolio requirement can be achieved through the procurement of renewable energy or renewable energy credits. Rules are required to be issued by the MoPSC to implement the law. UE expects that any related costs or investments would ultimately be recovered in rates.

Illinois

2008 Electric and Natural Gas Delivery Service Rate Order

On September 24, 2008, the ICC issued a consolidated order approving a net increase in annual revenues for electric delivery service of $123 million in the aggregate (CIPS – $22 million increase, CILCO – $3 million decrease, and IP – $104 million increase) and a net increase in annual revenues for natural gas delivery service of $38 million in the aggregate (CIPS – $7 million increase, CILCO – $9 million decrease, and IP – $40 million increase), based on a 10.65% return on equity with respect to electric delivery service and 10.68% return on equity with respect to natural gas delivery service. These rate changes were effective on October 1, 2008. Because of the Ameren Illinois Utilities’ pledge to keep the overall residential electric bill increase resulting from these rate changes to less than 10% for each utility during the first year, IP will not be able to recover approximately $10 million in revenue in the first year electric delivery service rates are in effect. Thereafter, residential electric delivery service rates will be adjusted to recover the full increase.

In addition, the ICC in its order changed the depreciable lives used in calculating depreciation expense for the Ameren Illinois Utilities’ electric and natural gas rates. As a result, annual depreciation expense for the Ameren Illinois Utilities will be reduced for financial reporting purposes by a net $13 million in the aggregate (CIPS – $4 million reduction, CILCO – $26 million reduction, and IP – $17 million increase).

The ICC rejected the Ameren Illinois Utilities’ requested rate adjustment mechanisms for electric infrastructure investments. As an alternative to the Ameren Illinois Utilities’ requested decoupling of natural gas revenues from sales volumes, the ICC order approved an increase in the percentage of costs to be recovered through fixed non-volumetric residential and commercial customer charges, to 80% from 53%. This increase will impact 2009 quarterly results of operations and cash flows, but is not expected to have any impact on annual margins. The ICC also approved an increase in the Supply Cost Adjustment (SCA) factors for the Ameren Illinois Utilities. The SCA is a charge applied only to the bills of customers who take their power supply from the Ameren Illinois Utilities. The change in the SCA factors is expected to result in increased electric revenues of $9.5 million per year in the aggregate (CIPS – $2.6 million, CILCO – $1.6 million, and IP – $5.3 million), which is expected to cover the increased cost of administering the Ameren Illinois Utilities’ power supply responsibilities.

In October 2008, CIPS, CILCO and IP and other parties requested that the ICC rehear certain aspects of its September 2008 consolidated order. In November 2008, the ICC denied all rate order rehearing requests filed by the Ameren Illinois Utilities and other parties. In December 2008, the Illinois attorney general appealed to the Appellate Court of Illinois, Fourth District, the ICC’s denial of the rehearing request. The Ameren Illinois Utilities cannot predict the outcome of the court appeal.

Illinois Electric Settlement Agreement

In 2007, key stakeholders in Illinois agreed to avoid rate rollback and freeze legislation that would impose a tax on electric generation. These stakeholders wanted to address the increase in electric rates and the future power procurement process in Illinois. The terms of the agreement included a comprehensive rate relief and customer assistance program. The Illinois electric settlement agreement provided approximately $1 billion of funding from 2007 to 2010 for rate relief for certain electric customers in Illinois, including approximately $488 million for customers of the Ameren Illinois Utilities. Pursuant to the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco, and CILCO (AERG) agreed to make aggregate contributions of $150 million over the four-year period, with $60 million coming from the Ameren Illinois Utilities (CIPS – $21 million; CILCO – $11 million; IP – $28 million), $62 million from Genco, and $28 million from CILCO (AERG). See Note 15 – Commitments and Contingencies for information on the remaining contributions to be made as of December 31, 2008.

The Ameren Illinois Utilities, Genco, and CILCO (AERG) recognize in their financial statements the costs of their respective rate relief contributions and program funding in a manner corresponding with the timing of the funding. Ameren, CIPS, CILCO (Illinois Regulated), IP, Genco, and CILCO (AERG) incurred charges to earnings, primarily recorded as a reduction to electric operating revenues,

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during the year ended December 31, 2008, of $42 million, $6 million, $3 million, $8 million, $17 million, and $8 million, respectively (year ended December 31, 2007 –$82 million, $12 million, $7 million, $15 million, $33 million, and $15 million, respectively) under the terms of the Illinois electric settlement agreement.

Other electric generators and utilities in Illinois agreed to contribute $851 million to the comprehensive rate relief and customer assistance program. Contributions by the other electric generators (the generators) and utilities to the comprehensive program are subject to funding agreements. Under these agreements, at the end of each month, the Ameren Illinois Utilities send a bill, due in 30 days, to the generators and utilities for their proportionate share of that month’s rate relief and assistance. If any escrow funds have been provided by the generators, these funds will be drawn upon first prior to seeking reimbursement from the generators. At December 31, 2008, Ameren, CIPS, CILCO (Illinois Regulated) and IP had receivable balances from nonaffiliated Illinois generators for reimbursement of customer rate relief and program funding of $15 million, $5 million, $3 million, and $7 million, respectively. See Note 14 – Related Party Transactions for information on the impact of intercompany settlements.

The Illinois electric settlement agreement provides that if legislation is enacted in Illinois before August 1, 2011, freezing or reducing retail electric rates, or imposing or authorizing a new tax, special assessment, or fee on the generation of electricity, then the remaining commitments under the Illinois electric settlement agreement would expire, and any funds set aside in support of the commitments would be refunded to the utilities and Generators.

Power Procurement Plan

As part of the Illinois electric settlement agreement, the reverse auction used for power procurement in Illinois was discontinued. It was replaced with a new power procurement process led by the IPA, which was established as a part of the Illinois electric settlement agreement, beginning in 2009. In January 2009, the ICC approved the electric power procurement plan filed by the IPA for both the Ameren Illinois Utilities and Commonwealth Edison Company. The plan outlined the wholesale products (capacity, energy swaps and renewable energy credits) that the IPA will procure on behalf of the Ameren Illinois Utilities for the period June 1, 2009, through May 30, 2014. The products are expected to be procured through a RFP process during the first half of 2009.

Except for those that expired in May 2008, existing supply contracts from the September 2006 reverse power procurement auction remain in place. In the September 2006 auction, the Ameren Illinois Utilities procured power to serve the electric load needs of fixed-price residential and small commercial customers, with one-third of the supply contracts expiring in each of May 2008, 2009, and 2010. The Ameren Illinois Utilities used RFP processes in early

2008 to replace the supply contracts that expired in May 2008. See Note 15 – Commitments and Contingencies for information on the Ameren Illinois Utilities’ purchased power agreements.

Natural Gas Energy Efficiency Plans

In February 2008, the Ameren Illinois Utilities filed a consolidated natural gas energy efficiency plan with the ICC. In October 2008, the ICC issued an order approving the Ameren Illinois Utilities’ natural gas energy efficiency plan as well as the cost recovery mechanism by which the program costs will be recovered from natural gas customers. The natural gas energy efficiency plan includes annual reduction targets in natural gas usage as well as spending limits for the 2009, 2010, and 2011 program years of $2 million, $4 million, and $6 million, respectively.

ICC Reliability Audit

In August 2007, the ICC retained Liberty Consulting Group to investigate, analyze, and report to the ICC on the Ameren Illinois Utilities’ transmission and distribution systems and reliability following the July 2006 wind storms and a November 2006 ice storm. In October 2008, Liberty Consulting Group presented the ICC with a final report containing recommendations for the Ameren Illinois Utilities to improve their systems and their response to emergencies. The ICC directed the Ameren Illinois Utilities to present to the ICC a plan to implement Liberty Consulting Group’s recommendations. The plan was submitted to the ICC in November 2008. The Ameren Illinois Utilities are currently in discussions with the ICC and Liberty Consulting Group about this matter. Liberty Consulting Group will monitor the Ameren Illinois Utilities’ efforts to implement the recommendations and any initiatives that the Ameren Illinois Utilities undertake. At this time, we are unable to determine the impact such implementation will have on our results of operations, financial position, or liquidity.

Federal

Regional Transmission Organization

UE, CIPS, CILCO and IP are transmission-owning members of MISO, which is a FERC-regulated RTO that provides transmission tariff administration services for electric transmission systems. In early 2004, UE received authorization from the MoPSC to participate in MISO for a five-year period, with further participation subject to approval by the MoPSC. The MoPSC required UE to file a

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study evaluating the costs and benefits of its participation in MISO prior to the end of the five-year period. The MoPSC also directed UE to enter into a service agreement with MISO to provide transmission service to UE’s bundled retail customers. The service agreement’s primary function was to ensure that the MoPSC continued to set the transmission component of UE’s rates to serve its bundled retail load. Among other things, the service agreement provided that UE would not pay MISO for transmission service to UE’s bundled retail customers. FERC approved the service agreement in the form that was acceptable to the MoPSC.

Due to changes to MISO’s allocation of transmission revenues to transmission owners, UE believed it should receive incremental annual transmission revenues of $60 million as of February 2008 in accordance with its service agreement with MISO. Numerous transmission owners in MISO, along with MISO itself as the tariff administrator, filed with FERC in December 2007 requesting changes to the MISO tariff to prevent UE from collecting these additional transmission revenues. In December 2007, UE filed a protest to these proposed MISO tariff changes, calling them unauthorized and improper in light of the MoPSC’s requirement for the service agreement between UE and MISO discussed above. In February 2008, FERC issued an order accepting the tariff changes proposed by MISO and by certain transmission owners in MISO. In March 2008, UE filed a request with FERC for a rehearing of its order. In April 2008, FERC suspended UE’s request for rehearing to permit time for further consideration by FERC. UE is unable to predict if or when FERC may issue a further order in this proceeding.

As required by the MoPSC, UE filed a study in November 2007 with the MoPSC evaluating the costs and benefits of UE’s participation in MISO. UE’s filing noted a number of uncertainties associated with the cost-benefit study, including issues associated with the UE-MISO service agreement and MISO revenue allocation, as discussed above. In June 2008, a stipulation and agreement among UE, the MoPSC staff, MISO and other parties to the proceeding was filed with the MoPSC, which provides for UE’s continued, conditional MISO participation through April 30, 2012. The stipulation and agreement gives UE the right to seek permission from the MoPSC for early withdrawal from MISO if UE determines that sufficient progress toward mitigating some of the continuing uncertainties respecting its MISO participation is not being made. The MoPSC issued an order, effective September 19, 2008, approving the stipulation and agreement.

Seams Elimination Cost Adjustment

Pursuant to a series of FERC orders, FERC put Seams Elimination Cost Adjustment (SECA) charges into effect on December 1, 2004, subject to refund and hearing procedures. The SECA charges were a transition mechanism in place for 16 months, from December 1, 2004, to March 31, 2006, to compensate transmission owners in the MISO and PJM for revenues lost when FERC

eliminated the regional through-and-out rates previously applicable to transactions crossing the border between the MISO and PJM. The SECA charge was 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 as of December 1, 2004. The MISO transmission owners (including UE, CIPS, CILCO and IP) and the PJM transmission owners filed their proposed SECA charges in November 2004, as compliance filings pursuant to FERC order. A FERC administrative law judge issued an initial decision in August 2006, recommending that FERC reject both of the SECA compliance filings (the filing for SECA charges made by the transmission owners in the MISO and the filing for SECA charges made by the transmission owners in PJM). There is no date scheduled for FERC to act on the initial decision. Both before and after the initial decision, various parties (including UE, CIPS, CILCO and IP as part of the group of MISO transmission owners) filed numerous bilateral or multiparty settlements. To date, FERC has approved many of the settlements, and has rejected none of the settlements. Neither the MISO transmission owners, including UE, CIPS, CILCO and IP, nor the PJM transmission owners have been able to settle with all parties. During the transition period of December 1, 2004, to March 31, 2006, Ameren, UE, CIPS, and IP received net revenues from the SECA charge of $10 million, $3 million, $1 million, and $6 million, respectively. CILCO’s net SECA charges were less than $1 million. Until FERC acts on the pending settlements and issues a final order on the initial decision, we cannot predict the ultimate impact of the SECA proceedings on UE’s, CIPS’, CILCO’s and IP’s costs and revenues.

FERC Order – MISO Charges

In May 2007, UE, CIPS, CILCO and IP filed with the U.S. Court of Appeals for the District of Columbia Circuit an appeal of FERC’s March 2007 order involving the reallocation of certain MISO operational costs among MISO participants retroactive to 2005. In August 2007, the court granted FERC’s motion to hold the appeal in abeyance until the end of the continuing proceedings at FERC regarding these costs. Other MISO participants also filed appeals. On August 10, 2007, UE, CIPS, CILCO, and IP filed a complaint with FERC regarding the MISO tariff’s allocation methodology for these same MISO operational charges. In November 2007, FERC issued two orders relative to these allocation matters. One of these orders addressed requests for rehearing of prior orders in the proceedings, and one concerned MISO’s compliance with FERC’s orders to date in the proceedings. In December 2007, UE, CIPS, CILCO and IP requested FERC’s clarification or rehearing of its November 2007 order regarding MISO’s compliance with FERC’s orders. UE, CIPS, CILCO, and IP maintained that MISO was required to reallocate certain of MISO’s operational costs among MISO market participants, which would result in refunds to UE, CIPS, CILCO, and IP retroactive to April 2006. On November 7, 2008, FERC granted the request for clarification and directed MISO to

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reallocate certain costs and provide refunds as requested. On November 10, 2008, FERC granted relief requested in the complaints filed by UE, CIPS, CILCO, IP and others regarding these same MISO operational charges and directed MISO to calculate refunds for the period from August 10, 2007, forward.

Several parties to these proceedings have protested MISO’s proposed implementation of these refunds, have requested rehearing of FERC’s orders and, in some cases, have appealed FERC’s orders to the courts. Additional amounts may be receivable or due depending on the final outcome of these proceedings.

UE Power Purchase Agreement with Entergy Arkansas, Inc.

In July 2007, FERC issued a series of orders addressing a complaint filed by the Louisiana Public Service Commission (LPSC) against Entergy Arkansas, Inc. (Entergy) and certain of its affiliates, which alleged unjust and unreasonable cost allocations. As a result of the FERC orders, Entergy began billing UE for additional charges under a 165-megawatt power purchase agreement. Additional charges are expected to continue during the remainder of the term of the power purchase agreement, which expires August 25, 2009. Although UE was not a party to the FERC proceedings that gave rise to these additional charges, UE has intervened in related FERC proceedings. UE filed a complaint with FERC against Entergy and Entergy Services, Inc. in April 2008 to challenge the additional charges. In September 2008, the presiding FERC administrative law judge issued an initial decision finding that Entergy’s allocation of such additional charges to UE is just and reasonable. FERC is expected to issue an order with respect to the administrative law judge’s initial decision in 2009. UE is unable to predict whether FERC will grant it any relief.

Additionally, LPSC appealed FERC’s orders regarding LPSC’s complaint against Entergy to the U.S. Court of Appeals for the District of Columbia. In April 2008, that court ordered further FERC proceedings regarding the LPSC complaint. The court ordered FERC to explain its previous denial of retroactive refunds and the implementation of prospective charges. FERC’s decision on remand of the

retroactive impact of these issues could have a financial impact on UE. UE is unable to predict how FERC will respond to the court’s decision. UE estimates that it could incur an additional expense of up to $25 million if FERC orders retroactive application for the years 2001 to 2005. However, UE would contest such an order vigorously. Based on existing facts and circumstances, UE believes that the likelihood of incurring this $25 million expense is not probable. Thus no liability has been recorded as of December 31, 2008. UE plans to participate in any proceeding that FERC initiates to address the court’s decision.

Nuclear Combined Construction and Operating License Application

In July 2008, UE filed an application with the NRC for a combined construction and operating license for a potential new 1,600 megawatt nuclear unit at UE’s existing Callaway County, Missouri, nuclear plant site. This COLA filing is not a commitment to build another nuclear unit, but it is a necessary step to preserve the option to develop a new nuclear unit in the future. The regulatory process for a COLA involves a comprehensive review, estimated by the NRC to require up to 42 months for completion.

As authorized by the Energy Policy Act of 2005, the DOE may make available up to $18.5 billion in loan guarantees in connection with debt financing of certain new nuclear unit projects. Pursuant to DOE’s procedures, in 2008 UE filed with the DOE Part I and Part II of its application for a loan guarantee to support the potential construction and operation of a new nuclear unit. UE’s loan guarantee application is not a commitment to build another nuclear unit, and there is no assurance that the DOE will provide any such guarantee to UE.

Pumped-storage Hydroelectric Facility Relicensing

In June 2008, UE filed a relicensing application with FERC to operate its Taum Sauk pumped-storage hydroelectric facility for another 40 years. The current FERC license expires on June 30, 2010. Approval and relicensure are expected in 2012. Operations are permitted to continue under the current license while the renewal is pending.

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Regulatory Assets and Liabilities

In accordance with SFAS No. 71, UE, CIPS, CILCO and IP defer certain costs pursuant to actions of regulators or based on the expected ability to recover such costs in rates charged to customers. UE, CIPS, CILCO and IP also defer certain amounts pursuant to actions of regulators or based on the expectation that such amounts will be returned to customers in future rates. The following table presents our regulatory assets and regulatory liabilities at December 31, 2008 and 2007:


	Ameren ^(a)		UE		CIPS		CILCORP		CILCO		IP
2008:
Regulatory assets:
Pension and postretirement benefit costs ⁽ ^b)(c ⁾	$	936	$	410	$	107	$	125	$	125	$	294
Income taxes ^(c)(d)		255		248		6		-		-		1
Asset retirement obligation ⁽ ^c ^)(e)		65		60		2		1		1		2
Callaway costs ^(f)		58		58		-		-		-		-
Unamortized loss on reacquired debt ⁽ ^c ^)(g)		63		30		5		5		5		23
Recoverable costs – contaminated facilities ⁽ ^c ^)(h)		97		-		18		8		8		71
IP integration ⁽ⁱ⁾		33		-		-		-		-		33
Recoverable costs – debt fair value adjustment ^(j)		10		-		-		-		-		10
Financial contracts ^(k)		-		-		42		22		22		64
Derivatives marked-to-market ^(l)		118		16		27		25		25		50
SO ₂ emission allowances sale tracker ^(m)		13		13		-		-		-		-
FERC-ordered MISO resettlements-March 2007 ⁽ⁿ⁾		12		12		-		-		-		-
Vegetation management and infrastructure inspection cost tracker ^(o)		9		9		-		-		-		-
Storm costs ^(p)		33		33		-		-		-		-
Demand-side costs ^(q)		4		4		-		-		-		-
Reserve for workers’ compensation liabilities ^(c)(r)		15		9		3		-		-		3
Other ⁽ ^c ⁾⁽ ^s ⁾		11		5		2		2		2		2
Total regulatory assets	$	1,732	$	907	$	212	$	188	$	188	$	553
Regulatory liabilities:
Income taxes ⁽ ^t ⁾	$	180	$	154	$	14	$	12	$	12	$	-
Removal costs ⁽ ^u ⁾		1,018		675		220		47		194		76
Emission allowances ⁽ ^v ⁾		47		47		-		-		-		-
Pension and postretirement benefit costs tracker ^(w)		41		41		-		-		-		-
MISO resettlements ^(x)		5		5		-		-		-		-
Total regulatory liabilities	$	1,291	$	922	$	234	$	59	$	206	$	76
2007:
Regulatory assets:
Pension and postretirement benefit costs ⁽ ^b)(c ⁾	$	395	$	161	$	75	$	19	$	19	$	140
Income taxes ^(c)(d)		255		248		6		-		-		1
Asset retirement obligation ⁽ ^c ^)(e)		188		183		2		1		1		2
Callaway costs ^(f)		62		62		-		-		-		-
Unamortized loss on reacquired debt ⁽ ^c ^)(g)		59		28		4		5		5		22
Recoverable costs – contaminated facilities ⁽ ^c ^)(h)		106		-		24		5		5		77
IP integration ⁽ⁱ⁾		50		-		-		-		-		50
Recoverable costs – debt fair value adjustment ^(j)		20		-		-		-		-		20
Derivatives marked-to-market ^(l)		3		-		1		-		-		2
SO ₂ emission allowances sale tracker ^(m)		7		7		-		-		-		-
Other ⁽ ^c ⁾⁽ ^y ⁾		13		8		1		2		2		2
Total regulatory assets	$	1,158	$	697	$	113	$	32	$	32	$	316
Regulatory liabilities:
Income taxes ⁽ ^t ⁾	$	195	$	162	$	19	$	14	$	14	$	-
Removal costs ⁽ ^u ⁾		980		638		208		60		188		74
Emission allowances ⁽ ^v ⁾		56		56		-		-		-		-
Pension and postretirement benefit costs tracker ^(w)		8		8		-		-		-		-
Financial contracts ^(k)		-		-		38		18		18		55
Derivatives marked-to-market ⁽ ^l ⁾		1		1		-		-		-		-
Total regulatory liabilities	$	1,240	$	865	$	265	$	92	$	220	$	129

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

(b)

These costs are being amortized in proportion to the recognition of prior service costs (credits), transition obligations (assets) and actuarial losses (gains) attributable to Ameren’s pension plan and postretirement benefit plans. Ameren believes it is probable that these costs will be recovered through rates in future periods. See Note 11 – Retirement Benefits for additional information.

(c)	These assets do not earn a return.

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(d)	Offset to certain deferred tax liabilities for expected recovery of future income taxes when paid. See Note 13 – Income Taxes for amortization period.

(e)	Recoverable costs for AROs at our rate-regulated operations, including net realized and unrealized gains and losses related to the nuclear decommissioning trust fund investments. See Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.

(f)

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.

(g)	Losses related to reacquired 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.

(h)	The recoverable portion of accrued environmental site liabilities, primarily collected from electric and gas customers through ICC-approved cost recovery riders in Illinois. The period of recovery will depend on the timing of actual expenditures.

(i)	Reorganization costs related to the integration of IP into the Ameren system and the restructuring of IP. Pursuant to the ICC order approving Ameren’s acquisition of IP, these costs are recoverable in rates through 2010.

(j)	A portion of IP’s unamortized debt fair value adjustment recorded upon Ameren’s acquisition of IP at September 30, 2004. This portion is being amortized over the remaining life of the related debt beginning with the expiration of the electric rate freeze in Illinois on January 1, 2007.

(k)	Financial contracts entered into by the Ameren Illinois Utilities with Marketing Company, as part of the Illinois electric settlement agreement. See Illinois – Power Procurement Plan discussion above for additional information.

(l)	Deferral of SFAS No. 133 natural gas-related derivative mark-to-market gains and losses.

(m)	A regulatory tracking mechanism for gains on sales of SO ₂ emission allowances, net of SO ₂ premiums incurred under the terms of coal procurement contracts, plus any SO ₂ discounts received under such contracts, as approved in a MoPSC order.

(n)

Costs associated with a March 2007 FERC order that resettled costs among MISO market participants. The costs were previously charged to expense but were recorded as a regulatory asset and will be amortized over a two-year period beginning March 1, 2009, as approved by the January 2009 MoPSC electric rate order.

(o)

UE’s vegetation management and infrastructure inspection costs incurred from January 1, 2008, through December 31, 2008, relating to compliance with the MoPSC vegetation management and infrastructure rules. The costs incurred between January 1, 2008, through September 30, 2008, will be amortized over three years beginning March 1, 2009, as approved by the January 2009 MoPSC electric rate order. The amortization period for the costs incurred between October 1, 2008 through December 31, 2008, will be determined in the next UE rate case.

(p)

Actual storm costs in a test year that exceed the MoPSC staff’s normalized storm costs for rate purposes. The 2006 storm costs are being amortized over a five-year period which began June 4, 2007. The 2008 storm costs are being amortized over a five-year period beginning March 1, 2009. In addition, the balance includes January 2007 ice storm costs that UE will recover as a result of a MoPSC accounting order issued in April 2008. These costs will be amortized over five years beginning March 1, 2009, as approved by the January 2009 MoPSC electric rate order.

(q)	Demand-side costs including the costs of developing, implementing and evaluating customer energy efficiency and demand response programs. These costs are being amortized over a ten-year period beginning March 1, 2009, as approved by the January 2009 MoPSC rate order.

(r)	Reserve for workers’ compensation liabilities. Ameren believes it is probable that these costs will be recovered through electric and gas rates in future periods.

(s)

Includes costs related to the Ameren Illinois Utilities November 2007 electric and natural gas delivery service rate cases. The costs associated with the Ameren Illinois Utilities electric delivery service rate cases are being amortized over a three-year period; the costs associated with the Ameren Illinois Utilities natural gas delivery service rate cases are being amortized over a five-year period, as approved in the 2008 ICC rate order. In addition, the balance includes funding for the low-income weatherization and energy efficiency programs.

(t)	Unamortized portion of investment tax credit and federal excess deferred taxes. See Note 13 – Income Taxes for amortization period.

(u)	Estimated funds collected for the eventual dismantling and removal of plant from service, net of salvage value, upon retirement related to our rate-regulated operations. See discussion in Note 1 – Summary of Significant Accounting Policies – Asset Retirement Obligations.

(v)	The deferral of gains on emission allowance vintage swaps UE entered into during 2005.

(w)	A regulatory tracking mechanism for the difference between the level of pension and postretirement benefit costs incurred by UE under GAAP and the level of such costs built into electric rates effective June 4, 2007, as approved in a MoPSC order.

(x)	A portion of UE’s expected refund relating to MISO resettlements associated with the November 2008 FERC orders. See Federal – FERC Order – MISO Charges discussion above for additional information.

(y)	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 that was amortized over 14 years through 2007.

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.

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NOTE 3 – PROPERTY AND PLANT, NET

The following table presents property and plant, net for each of the Ameren Companies at December 31, 2008 and 2007:


	Ameren ^(a)		UE		CIPS		Genco		CILCORP ^(b)		CILCO (Illinois Regulated)		CILCO (AERG)		IP
2008:
Property and plant, at original cost:
Electric	$	21,244	$	13,214	$	1,744	$	2,451	$	1,348	$	954	$	948	$	1,840
Gas		1,505		347		365		-		227		506		-		565
Other		381		76		6		6		44		3		2		21
		23,130		13,637		2,115		2,457		1,619		1,463		950		2,426
Less: Accumulated depreciation and amortization		8,499		5,539		915		1,013		279		721		329		152
		14,631		8,098		1,200		1,444		1,340		742		621		2,274
Construction work in progress:
Nuclear fuel in process		190		190		-		-		-		-		-		-
Other		1,746		707		12		506		370		12		359		55
Property and plant, net	$	16,567	$	8,995	$	1,212	$	1,950	$	1,710	$	754	$	980	$	2,329
2007:
Property and plant, at original cost:
Electric	$	20,325	$	12,670	$	1,682	$	2,423	$	1,196	$	921	$	827	$	1,740
Gas		1,421		332		350		-		209		488		-		530
Other		354		71		5		4		42		3		1		21
		22,100		13,073		2,037		2,427		1,447		1,412		828		2,291
Less: Accumulated depreciation and amortization		8,196		5,437		878		972		231		697		329		111
		13,904		7,636		1,159		1,455		1,216		715		499		2,180
Construction work in progress:
Nuclear fuel in process		103		103		-		-		-		-		-		-
Other		1,062		450		15		228		278		22		256		40
Property and plant, net	$	15,069	$	8,189	$	1,174	$	1,683	$	1,494	$	737	$	755	$	2,220

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

(b)	Includes CILCO (Illinois Regulated) and CILCO (AERG) with adjustments due to purchase accounting.

In March 2006, following the receipt of all required regulatory approvals, UE completed the purchase of a 640-megawatt CT facility located in Audrain County, Missouri, at a price of $115 million from NRG Audrain Holding LLC, and NRG Audrain Generating LLC, both affiliates of NRG Energy Inc. (collectively, NRG). As a part of this transaction, UE was assigned the rights of NRG as lessee of the CT facility under a long-term lease with Audrain County, and UE assumed NRG’s obligations under the lease. The lease will expire on December 1, 2023.

Also in March 2006, following the receipt of all required regulatory approvals, UE completed the purchase from subsidiaries of Aquila Inc., of the 510-megawatt Goose Creek CT facility in Piatt County, Illinois, at a price of $106 million, and the 340-megawatt Raccoon Creek CT facility located in Clay County, Illinois, at a price of $71 million.

The following table provides accrued capital expenditures at December 31, 2008, 2007 and 2006, which represent noncash investing activity excluded from the statements of cash flows:


	Ameren ^(a)		UE		CIPS		Genco		CILCORP		CILCO		IP
2008:
Accrued capital expenditures	$	213	$	110	$	3	$	41	$	45	$	45	$	14
2007:
Accrued capital expenditures	$	153	$	76	$	3	$	28	$	35	$	35	$	7
2006:
Accrued capital expenditures	$	159	$	92	$	5	$	22	$	15	$	15	$	20

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

NOTE 4 – SHORT-TERM BORROWINGS AND LIQUIDITY

The liquidity needs of the Ameren Companies are typically supported through the use of available cash and drawings under committed bank credit facilities.

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The following table summarizes the borrowing activity and relevant interest rates under the $1.15 billion credit facility described below for the years ended December 31, 2008 and 2007, respectively, and excludes letters of credit issued under this credit facility:


	Ameren (Parent)			UE			Genco			Total
2008:
Average daily borrowings outstanding during 2008	$	389		$	154		$	41		$	584
Outstanding short-term debt at period end		275			251			-			526
Weighted-average interest rate during 2008		3.58	%		3.25	%		3.97	%		3.52	%
Peak short-term borrowings during 2008	$	675		$	493		$	150		$	1,068
Peak interest rate during 2008		7.25	%		5.65	%		5.53	%		7.25	%
2007:
Average daily borrowings outstanding during 2007	$	198		$	292		$	22		$	512
Outstanding short-term debt at period end		550			82	^(a)		100			732	^(a)
Weighted-average interest rate during 2007		5.75	%		5.66	%		5.43	%		5.68	%
Peak short-term borrowings during 2007	$	550		$	506		$	100		$	856
Peak interest rate during 2007		8.25	%		8.25	%		5.76	%		8.25	%

(a)	Includes issuances under commercial paper programs of $80 million at Ameren and UE supported by this facility as of December 31, 2007.

The following table summarizes the borrowing activity and relevant interest rates under the 2007 $500 million credit facility described below for the years ended December 31, 2008 and 2007:


	CIPS		CILCORP (Parent)			CILCO (Parent)			IP			AERG			Total
2008:
Average daily borrowings outstanding during 2008	$	-	$	100		$	56		$	133		$	95		$	384
Outstanding short-term debt at period end		-		-			-			-			85			85
Weighted-average interest rate during 2008		-		4.62	%		4.02	%		4.28	%		3.95	%		4.25	%
Peak short-term borrowings during 2008	$	-	$	125		$	75		$	200		$	150		$	500
Peak interest rate during 2008		-		6.66	%		6.47	%		6.15	%		6.22	%		6.66	%
2007:
Average daily borrowings outstanding during 2007	$	-	$	105		$	36		$	134		$	80		$	355
Outstanding short-term debt at period end		-		125			75			175			65			440
Weighted-average interest rate during 2007		-		6.94	%		6.43	%		6.59	%		6.86	%		6.74	%
Peak short-term borrowings during 2007	$	-	$	125		$	75		$	200		$	100		$	500
Peak interest rate during 2007		-		8.63	%		6.47	%		6.64	%		7.02	%		8.63	%

The following table summarizes the borrowing activity and relevant interest rates under the 2006 $500 million credit facility described below for the years ended December 31, 2008 and 2007, respectively:


	CIPS			CILCORP (Parent)			CILCO (Parent)			IP			AERG			Total
2008:
Average daily borrowings outstanding during 2008	$	58		$	50		$	37		$	27		$	151		$	323
Outstanding short-term debt at period end		62			50			-			-			151			263
Weighted-average interest rate during 2008		4.21	%		4.50	%		3.78	%		4.08	%		3.94	%		4.07	%
Peak short-term borrowings during 2008	$	135		$	50		$	75		$	150		$	200		$	465
Peak interest rate during 2008		6.31	%		7.01	%		5.98	%		6.50	%		7.01	%		7.01	%
2007:
Average daily borrowings outstanding during 2007	$	98		$	49		$	63		$	63		$	107		$	380
Outstanding short-term debt at period end		125			50			40			-			165			380
Weighted-average interest rate during 2007		6.52	%		6.89	%		6.35	%		6.56	%		6.84	%		6.63	%
Peak short-term borrowings during 2007	$	135		$	50		$	100		$	125		$	200		$	500
Peak interest rate during 2007		8.25	%		7.04	%		6.47	%		6.64	%		8.25	%		8.25	%

At December 31, 2008, Ameren and certain of its subsidiaries had $2.15 billion of committed credit facilities, consisting of the three facilities shown above, in the amounts of $1.15 billion, $500 million, and $500 million, maturing in July 2010, January 2010, and January 2010, respectively.

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borrowers. The termination date for UE and Genco is July 9, 2009, subject to the annual 364-day renewal provisions of the facility.

Under the $1.15 billion credit facility, the principal amount of each revolving loan will be due and payable no later than the final maturity of the facility in the case of Ameren and the last day of the then-applicable 364-day period in the case of UE and Genco. Swingline loans will be made on same-day notice and will mature five business days after they are made.

Ameren, UE and Genco will use the proceeds of any borrowings under the facility for general corporate purposes. These purposes include working capital and funding loans under the Ameren money pool arrangements.

The $1.15 billion credit facility may be used to support the commercial paper programs of Ameren and UE. However, Ameren and UE are currently limited in their access to the commercial paper market as a result of downgrades in their short-term credit ratings. Access to the $1.15 billion credit facility, the 2006 $500 million credit facility, and the 2007 $500 million credit facility for the Ameren Companies is subject to reduction as borrowings are made by affiliates.

CIPS, CILCORP, CILCO, IP and AERG are parties to the 2007 $500 million credit facility and to the 2006 $500 million credit facility.

The obligations of each borrower under the 2006 $500 million credit facility and the 2007 $500 million credit facility are several and not joint, and are not guaranteed by Ameren or any other subsidiary of Ameren. The maximum amount available to each borrower under the 2006 $500 million credit facility, including for issuance of letters of credit on its behalf, is limited as follows: CIPS – $135 million, CILCORP – $50 million, CILCO – $75 million, IP – $150 million and AERG – $200 million. Each of the companies has drawn various loans under this credit facility. Under the 2007 $500 million credit facility, the maximum amount available to each borrower, including for issuance of letters of credit on its behalf, is limited as follows: CILCORP – $125 million, CILCO – $75 million, IP – $200 million and AERG – $100 million. CIPS and CILCO have the option of permanently reducing their borrowing authority under the 2006 $500 million credit facility and shifting, in one or more transactions, such capacity to the 2007 $500 million credit facility up to the same limits. The total borrowing authority of CIPS and CILCO under the 2006 $500 million credit facility and the 2007 $500 million credit facility cannot at any time exceed $135 million and $150 million, respectively, in the aggregate. Until either CIPS or CILCO elects to increase its borrowing capacity under the 2007 $500 million credit facility and issue first mortgage bonds as security for its obligations thereunder, as described below, it will not be considered a borrower under the 2007 $500 million credit facility and will not be subject to the covenants thereof (except as a subsidiary of a borrower). The borrowing companies will use the proceeds

of any borrowings for working capital and other general corporate purposes. However, a portion of the borrowings by AERG may be limited to financing or refinancing the development, management and operation of any of its projects or assets. The 2006 and 2007 $500 million credit facilities will terminate on January 14, 2010.

The obligations of CIPS, CILCO and IP under the 2006 $500 million facility are secured by the issuance of first mortgage bonds by each such utility under its respective mortgage indenture in the amounts of $135 million, $75 million, and $150 million, respectively. The obligations of CILCO and IP under the 2007 $500 million credit facility are secured by the issuance of first mortgage bonds in the amounts of $75 million and $200 million, respectively. If either CIPS or CILCO elects to transfer borrowing authority from the 2006 $500 million credit facility to the 2007 $500 million credit facility, it must retire an appropriate amount of first mortgage bonds issued with respect to the 2006 $500 million credit facility and issue new bonds in an equal amount to secure its obligations under the 2007 $500 million credit facility. In July 2007, CILCO permanently reduced its $150 million of borrowing authority under the 2006 $500 million credit facility by $75 million and shifted that amount of capacity to the 2007 $500 million credit facility. CILCO is now considered a borrower under both credit facilities and is subject to the covenants of both. The obligations of CILCORP under both the 2006 $500 million credit facility and the 2007 $500 million credit facility are secured by a pledge of the common stock of CILCO. The obligations of AERG under both the 2006 $500 million credit facility and the 2007 $500 million credit facility are secured by a mortgage and security interest in its E.D. Edwards and Duck Creek power plants and related licenses, permits, and similar rights.

On September 15, 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New York. As of December 31, 2008, Lehman Brothers Bank, FSB, a subsidiary of Lehman, had lending commitments of $100 million and $21 million under the $1.15 billion credit facility and the 2006 $500 million credit facility, respectively. Assuming Lehman Brothers Bank, FSB does not fund its pro-rata share of funding or letter of credit issuance requests under these two facilities, and such participations are not assigned or otherwise transferred to other lenders, total amounts accessible by the Ameren Companies and AERG will be limited to amounts not less than $1.05 billion under the $1.15 billion credit facility and $479 million under the 2006 $500 million credit facility.

Based on outstanding borrowings under the $1.15 billion credit facility and the 2007 and 2006 $500 million credit facilities (including reductions for $9 million of letters of credit issued under the $1.15 billion credit facility and unfunded Lehman participations under the $1.15 billion credit facility and the 2006 $500 million credit facility), the available amounts under the facilities at December 31, 2008, were $540 million, $415 million, and $220 million, respectively.

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On June 25, 2008, Ameren entered into a $300 million term loan agreement due June 24, 2009, which was fully drawn on June 26, 2008. If Ameren issues capital stock or other equity interests (except for director or employee benefit or dividend reinvestment plan purposes), or certain equity-like hybrid securities, or certain additional indebtedness in amounts exceeding $25 million, Ameren is required under the term loan agreement to use the resulting net proceeds to prepay amounts borrowed under the agreement. The lenders under the term loan agreement have waived this prepayment requirement to the extent that the net proceeds from the issuance of certain funded indebtedness are applied to repurchase or to redeem indebtedness of CILCORP. Additionally, if Ameren replaces its $1.15 billion credit facility with one or more credit facilities having a total available commitment in excess of $1.15 billion, Ameren is required under the term loan agreement to prepay amounts borrowed thereunder in an amount equal to the excess of the new commitments over $1.15 billion. Such mandatory prepayments are without premium or penalty (except for any funding indemnity due in respect of Eurodollar loans).

Borrowings under the $300 million term loan agreement will bear interest, at the election of Ameren, at (1) a Eurodollar rate plus a margin, which margin is subject to a floor of 0.90% per annum and a cap of 1.50% per annum, or (2) a rate equal to the higher of the prime rate or the federal funds effective rate plus 0.50% per year. Ameren used the proceeds borrowed under the term loan agreement to reduce amounts borrowed under the $1.15 billion credit facility, which thereby made additional amounts available for borrowing under that credit facility. The average annual interest rate for borrowing under the $300 million term loan agreement was 3.93% from its inception through December 31, 2008. The obligations of Ameren under the term loan agreement are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under the term loan agreement.

On January 21, 2009, Ameren entered into a $20 million term loan agreement due January 20, 2010, which was fully drawn on January 21, 2009. Borrowings under the $20 million term loan agreement will bear interest, at the election of Ameren, at (1) a rate equal to the applicable LIBOR rate plus 1.70% per annum, or (2) a rate equal to the highest of the prime rate, the federal funds effective rate plus 0.50% per annum and the applicable LIBOR rate plus 2.00% per annum. The obligations of Ameren under the $20 million term loan agreement are unsecured. No subsidiary of Ameren is a party to, guarantor of, or borrower under the agreement.

Indebtedness Provisions and Other Covenants

The Ameren Companies’ bank credit facilities contain provisions that, among other things, place restrictions on their ability to incur liens, sell assets, and merge with other entities. The $1.15 billion credit facility contains provisions that limit total indebtedness of each of Ameren, UE and Genco to 65% of total consolidated capitalization pursuant

to a calculation defined in the facility. Exceeding these debt levels would result in a default under the $1.15 billion credit facility.

The $1.15 billion credit facility also contains provisions for default, including cross-defaults, with respect to a borrower. Defaults can result from an event of default under any other facility covering indebtedness of that borrower or certain of its subsidiaries in excess of $50 million in the aggregate. The obligations of Ameren, UE and Genco under the facility are several and not joint, and except under limited circumstances, the obligations of UE and Genco are not guaranteed by Ameren or any other subsidiary. CIPS, CILCORP, CILCO, IP and AERG are not considered subsidiaries for purposes of the cross-default or other provisions.

Under the $1.15 billion credit facility, restrictions apply limiting investments in and other transfers to CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries by Ameren and certain subsidiaries. Additionally, CIPS, CILCORP, CILCO, IP, AERG and their subsidiaries are excluded for purposes of determining compliance with the 65% total consolidated indebtedness to total consolidated capitalization financial covenant in the facility.

Both the 2007 $500 million credit facility and the 2006 $500 million credit facility entered into by CIPS, CILCORP, CILCO, IP and AERG limit the indebtedness of each borrower to 65% of consolidated total capitalization pursuant to a calculation set forth in the facilities. Events of default under these facilities apply separately to each borrower (and, except in the case of CILCORP, to their subsidiaries). An event of default under these facilities does not constitute an event of default under the $1.15 billion credit facility, or vice versa. In addition, if CIPS’, CILCO’s or IP’s senior secured long-term debt securities or first mortgage bonds, or CILCORP’s senior unsecured long-term debt securities, should receive a below-investment-grade credit rating from either Moody’s or S&P, then each such borrower will be limited to common and preferred stock dividend payments of $10 million per year while such below-investment-grade credit rating is in effect. On July 26, 2006, Moody’s downgraded CILCORP’s senior unsecured long-term debt credit rating to below-investment-grade, causing it to be subject to this dividend payment limitation. No similar restriction applies to AERG, which is currently not rated by Moody’s or S&P, if its debt-to-operating- cash-flow ratio, as set forth in these facilities, is less than or equal to a 3.0 to 1.0 ratio. As of December 31, 2008, AERG failed to meet the debt-to-operating-cash-flow ratio test in the 2007 and 2006 $500 million credit facilities. AERG’s ability to pay dividends is therefore currently limited to a maximum of $10 million per fiscal year. CIPS, CILCO and IP are not currently limited in their dividend payments by this provision of the 2007 $500 million or 2006 $500 million credit facilities. Ameren’s access to dividends from CILCO and AERG is currently limited by dividend restrictions at CILCORP.

The 2007 $500 million credit facility and the 2006 $500 million credit facility also limit the amount of other

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secured indebtedness issuable by each borrower. For CIPS, CILCO and IP, other secured debt is limited to that permitted under their respective mortgage indentures. For CILCORP, other debt secured by the pledge of CILCO common stock is limited (1) under the 2007 $500 million credit facility to $425 million (in addition to the principal amount of CILCORP’s outstanding senior notes and senior bonds and its obligations under the 2006 $500 million credit facility) and (2) under the 2006 $500 million credit facility to $500 million (including the principal amount of CILCORP’s outstanding senior notes and senior bonds and amounts drawn on the 2007 $500 million credit facility). For AERG, other debt secured on an equal basis with its obligations under the facilities is limited to $100 million by the 2007 $500 million credit facility (excluding amounts drawn by AERG under the 2006 $500 million credit facility) and $200 million by the 2006 $500 million credit facility. The limitations on other secured debt at CILCORP and AERG in the 2007 $500 million credit facility are subject to adjustment based on the borrowing sublimits of these entities under this facility or under the 2006 $500 million credit facility. In addition, the 2007 $500 million credit facility and the 2006 $500 million credit facility prohibit CILCO from issuing any preferred stock if, after such issuance, the aggregate liquidation value of all CILCO preferred stock issued after February 9, 2007, and July 14, 2006, respectively, would exceed $50 million.

Under the 2007 $500 million and 2006 $500 million credit facilities, each of CIPS, CILCO and IP was originally required to reserve future bonding capacity under its respective mortgage indentures (that is, it agreed to forgo the issuance of additional mortgage bonds otherwise permitted under the terms of each mortgage indenture). On March 26, 2008, CIPS, CILCO and IP and other parties to the credit facilities entered into amendments to the credit facilities, that eliminated this requirement.

The $300 million term loan agreement entered into in June 2008 has terms similar to the $1.15 billion credit facility, except that amounts repaid under the term loan agreement may not be reborrowed. The term loan agreement also contains nonfinancial covenants, including restrictions on the ability to incur liens, dispose of assets, and merge with other entities. In addition, the term loan agreement has nonfinancial covenants to limit the ability of Ameren to invest in or transfer assets to other entities, including affiliates. The events of default under the term loan agreement, including a cross-default to the occurrence of an event of default under the $1.15 billion credit facility or any other agreement covering indebtedness of Ameren and its subsidiaries in excess of $25 million in the aggregate, are similar to those contained in the $1.15 billion credit facility. Each of CIPS, CILCORP, CILCO, IP, AERG and each of their subsidiaries is excluded from the definition of “subsidiary” under the term loan agreement and accordingly is not subject to certain of the covenants, representations, or warranties under the term loan agreement. The term loan agreement requires Ameren to maintain consolidated indebtedness of not more then 65%

of consolidated total capitalization pursuant to a calculation defined in the term loan agreement.

Under the $20 million term loan agreement entered into in January 2009, Ameren may elect, for up to three 30-day periods, to pay down and reduce to zero the outstanding principal balance. The term loan agreement also contains nonfinancial covenants, including restrictions on the ability to incur liens, dispose of assets, and merge with other entities. In addition, the term loan agreement has nonfinancial covenants to limit the ability of Ameren to invest in or transfer assets to other entities, including affiliates. The events of default under the term loan agreement, including a cross-default to the occurrence of an event of default under the $1.15 billion credit facility or any other agreement covering indebtedness of Ameren and its subsidiaries in excess of $50 million in the aggregate, are similar to those contained in the $1.15 billion credit facility. Each of CIPS, CILCORP, CILCO, IP, AERG and each of their subsidiaries is excluded from the definition of “subsidiary” under the term loan agreement and accordingly is not subject to certain of the covenants, representations, or warranties under the agreement. The term loan agreement requires Ameren to maintain a consolidated capitalization ratio of not more than 65% pursuant to a calculation defined in the agreement.

As of December 31, 2008, the ratios of total indebtedness to total consolidated capitalization, calculated in accordance with the provisions of the $1.15 billion credit facility for Ameren, UE and Genco were 54%, 51% and 53%, respectively. The ratios for CIPS, CILCORP, CILCO, IP and AERG, calculated in accordance with the provisions of the 2006 $500 million credit facility and the 2007 $500 million credit facility, were 51%, 60%, 48%, 53% and 45%, respectively. The ratio for Ameren calculated in accordance with the provisions of the $300 million term loan agreement was 54%.

None of Ameren’s credit facilities or financing arrangements contain credit rating triggers that would cause an event of default or acceleration of repayment of outstanding balances. At December 31, 2008, management believes that the Ameren Companies were in compliance with their credit facilities and term loan agreement provisions and covenants .

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 the operation and administration of the money pool agreements.

Utility

Through the utility money pool, the pool participants may access the committed credit facilities. CIPS, CILCO and IP borrow from each other through the utility money pool

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agreement subject to applicable regulatory short-term borrowing authorizations. 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 2006 $500 million and the 2007 $500 million credit facilities. 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 contribute funds from 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 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, 2008, was 2.85% (2007 – 5.80%).

Non-state-regulated Subsidiaries

Ameren Services, Resources Company, Genco, AERG, Marketing Company, AFS, and other non-state-regulated Ameren subsidiaries have the ability, subject to Ameren parent company authorization and applicable regulatory short-term borrowing authorizations, to access funding from Ameren’s $1.15 billion credit facility through a non-state-regulated subsidiary money pool agreement. 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 remit funds from other external sources. See the discussion above for the amount available under the $1.15 billion credit facility at December 31, 2008. The non-state-regulated subsidiary money pool was established to coordinate and to provide short-term cash and working capital for Ameren’s non-state-regulated activities. 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. The average interest rate for borrowing under the non-state-regulated subsidiary money pool for the year ended December 31, 2008 was 3.51% (2007 – 5.14%).

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, 2008, 2007, and 2006.

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 pool agreement, together with any outstanding external short-term borrowings by IP, may not exceed $500 million, pursuant to authorization from the ICC. IP is not currently borrowing under the unilateral borrowing agreement. Ameren Services is responsible for operation and administration of the agreement.

NOTE 5 – LONG-TERM DEBT AND EQUITY FINANCINGS

The following table presents long-term debt outstanding for the Ameren Companies as of December 31, 2008 and 2007:


	2008		2007
UE:
First mortgage bonds: ^(a)
6.75% Series due 2008	$	-	$	148
5.25% Senior secured notes due 2012 ^(b)		173		173
4.65% Senior secured notes due 2013 ^(b)		200		200
5.50% Senior secured notes due 2014 ^(b)		104		104
4.75% Senior secured notes due 2015 ^(b)		114		114
5.40% Senior secured notes due 2016 ^(b)		260		260
6.40% Senior secured notes due 2017 ^(b)		425		425
6.00% Senior secured notes due 2018 ^(b)		250		-
5.10% Senior secured notes due 2018 ^(b)		200		200
6.70% Senior secured notes due 2019 ^(b)		450		-
5.10% Senior secured notes due 2019 ^(b)		300		300
5.00% Senior secured notes due 2020 ^(b)		85		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		300

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	2008			2007
Environmental improvement and pollution control revenue bonds: ^(a)(b)(c)(d)
1991 Series due 2020		-			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
2000 Series B due 2035		-			63
2000 Series C due 2035		-			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)		82			86
Audrain County capital lease (Audrain County CT)		240			240
Total long-term debt, gross		3,684			3,366
Less: Unamortized discount and premium		(7	)		(6	)
Less: Maturities due within one year		(4	)		(152	)
Long-term debt, net	$	3,673		$	3,208
CIPS:
First mortgage bonds: ^(a)
5.375% Senior secured notes due 2008 ^(b)	$	-		$	15
6.625% Senior secured notes due 2011 ^(b)		150			150
7.61% Series 1997-2 due 2017		40			40
6.125% Senior secured notes due 2028 ^(b)		60			60
6.70% Senior secured notes due 2036 ^(b)		61			61
Environmental improvement and pollution control revenue bonds:
2004 Series due 2025 ^(a) ^(b)(c)(d)		-			35
2000 Series A 5.50% due 2014		51			51
1993 Series C-1 5.95% due 2026		35			35
1993 Series C-2 5.70% due 2026		8			8
1993 Series B-1 due 2028 ^(d)		17			17
Total long-term debt, gross		422			472
Less: Unamortized discount and premium		(1	)		(1	)
Less: Maturities due within one year		-			(15	)
Long-term debt, net	$	421		$	456
Genco:
Unsecured notes:
Senior notes Series D 8.35% due 2010	$	200		$	200
Senior notes Series F 7.95% due 2032		275			275
Senior notes Series H 7.00% due 2018		300			-
Total long-term debt, gross		775			475
Less: Unamortized discount and premium		(1	)		(1	)
Long-term debt, net	$	774		$	474
CILCORP (Parent): ⁽ ^f ⁾
Unsecured notes:
8.70% Senior notes due 2009 ^(g)	$	124		$	124
9.375% Senior bonds due 2029 ^(g)		210			210
Fair-market value adjustments		49			55
Total long-term debt, gross		383			389
Less: Maturities due within one year		(126	)		-
Long-term debt, net	$	257		$	389

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	2008			2007
CILCO:
First mortgage bonds: ^(a)
8.875% Senior secured notes due 2013 ^(b)	$	150		$	-
6.20% Senior secured notes due 2016 ^(b)		54			54
6.70% Senior secured notes due 2036 ^(b)		42			42
Environmental improvement and pollution-control revenue bonds: ^(a)(c)
Series 2004 due 2039 ^(b)(d)		-			19
6.20% Series 1992B due 2012		1			1
5.90% Series 1993 due 2023		32			32
Total long-term debt, gross		279			148
Less: Maturities due within one year		-			-
Long-term debt, net	$	279		$	148
CILCORP consolidated long-term debt, net	$	536		$	537
IP:
Mortgage bonds: ^(a)
7.50% Series due 2009	$	250		$	250
6.25% Senior secured notes due 2016 ^(b)		75			75
6.125% Senior secured notes due 2017 ^(b)		250			250
6.250% Senior secured notes due 2018 ^(b)		337			-
9.750% Senior secured notes due 2018 ^(b)		400			-
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
1997 Series A, B and C due 2032 ^(d)		-			150
Series 2001 Non-AMT due 2028 ^(d)		-			112
Series 2001 AMT due 2017 ^(d)		-			75
Fair-market value adjustments		10			18
Total long-term debt, gross		1,410			1,018
Less: Unamortized discount and premium		(10	)		(4	)
Less: Maturities due within one year		(250	)		-
Long-term debt, net	$	1,150		$	1,014
Long-term debt payable to IP SPT:
5.65% due 2008 A-7	$	-		$	86
Less: Overfunded amount		-			(32	)
Fair-market value adjustments		-			2
Total long-term debt payable to IP SPT		-			56
Less: Maturities due within one year		-			(56	)
Long-term debt payable to IP SPT, net	$	-		$	-
Ameren consolidated long-term debt, net	$	6,554		$	5,689

(a)

At December 31, 2008, 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, CILCO, or IP, respectively, and will remain secured at each company until the following series are no longer outstanding with respect to that company: UE – 5.45% Series due 2028 (currently callable at 102% of par, declining to 101% of par in October 2009 and 100% of par in October 2010), 6.00% Series due 2018 and 6.70% Series due 2019; CIPS – 7.61% Series 1997-2 due 2017 (currently callable at 103.04% of par declining annually thereafter to 100% of par in June 2012) which, pursuant to a covenant contained in the 6.70% Series due 2036, may not be called in full prior to June 15, 2009; CILCO – 6.20% Series 1992B due 2012 (currently callable at 100% of par) 5.90% Series 1993 due 2023 (currently callable at 100% of par) and 8.875% Series due 2013; IP – 7.50% Series due 2009, 6.125% Series due 2017, 6.25% Series due 2018, 9.75% Series due 2018 and all IP pollution control revenue bonds.

(c)	Environmental improvement or pollution control series secured by first mortgage bonds. In addition, all of the series except UE’s 5.45% Series, CILCO’s 6.20% Series 1992B, and 5.90% Series 1993 bonds are backed by an insurance guarantee policy.

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(d)	Interest rates, and the periods during which such rates apply, vary depending on our selection of certain defined rate modes. Maximum interest rates could range up to 18% depending upon the series of bonds. The average interest rates for the years 2008 and 2007 were as follows:


	2008		2007			2008		2007
UE 1991 Series	Retired		3.66	%	CIPS Series 2004	Retired		3.68%
UE 1992 Series	3.66	%	3.72	%	CIPS 1993 Series B-1	1.98	%	3.25%
UE 1998 Series A	3.97	%	3.69	%	CILCO Series 2004	Retired		3.68%
UE 1998 Series B	3.71	%	3.66	%	IP 1997 Series A	Retired		3.93	%
UE 1998 Series C	4.06	%	3.66	%	IP 1997 Series B	Retired		3.89	%
UE 2000 Series A	Retired		3.55	%	IP 1997 Series C	Retired		3.84	%
UE 2000 Series B	Retired		3.55	%	IP Series 2001 (AMT)	Retired		3.89	%
UE 2000 Series C	Retired		3.56	%	IP Series 2001 (Non-AMT)	Retired		3.69	%

(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. UE has not elected to defer any interest payments.

(f)	CILCORP’s long-term debt is secured by a pledge of the common stock of CILCO.

(g)	These notes are subject to a revocable tender offer whereby holders may receive up to $1,057.50 and $1,230, respectively, for each $1,000 principal amount of 8.70% senior notes due 2009 and 9.375% senior bonds due 2029 tendered.

The following table presents the aggregate maturities of long-term debt, including current maturities, for the Ameren Companies at December 31, 2008:


	UE			CIPS			Genco			CILCORP (Parent)			CILCO		IP			Ameren Consolidated
2009	$	4		$	-		$	-		$	126	^(a)	$	-	$	250		$	380
2010		4			-			200			-			-		-			204
2011		4			150			-			-			-		-			154
2012		178			-			-			-			1		-			179
2013		205			-			-			-			150		-			355
Thereafter		3,289			272			575			210			128		1,150			5,624
Total	$	3,684	⁽ ^b)	$	422	⁽ ^b)	$	775	⁽ ^b)	$	336	^(c)	$	279	$	1,400	⁽ ^b) ⁽ ^d)	$	6,896

(a)	Includes $2 million of fair-market value adjustments related to CILCORP’s current maturities of long-term debt.

(b)	Excludes unamortized discount and premium of $7 million, $1 million, $1 million, and $10 million at UE, CIPS, Genco, and IP, respectively.

(c)	Excludes $47 million related to CILCORP’s long-term debt fair-market value adjustments.

(d)	Excludes $10 million related to IP’s long-term debt fair-market value adjustments.

All of the Ameren Companies expect to fund maturities of long-term debt, short-term debt and contractual obligations through a combination of cash flow from operations and external financing. See Note 4 – Short-term Borrowings and Liquidity for a discussion of external financing availability.

The following table presents information with respect to the Form S-3 shelf registration statements filed and effective for certain Ameren Companies as of December 31, 2008:


	Effective Date	Authorized Amount
Ameren ^(a ⁾	November 2008	Not limited
UE ^(b)	June 2008	Not limited
CIPS ^(a ⁾	November 2008	Not limited
Genco ^(a ⁾	November 2008	Not limited
CILCO ^(a ⁾	November 2008	Not limited
IP ^(a ⁾	November 2008	Not limited

(a)	In November 2008, Ameren, as a well-known seasoned issuer, along with CIPS, Genco, CILCO and IP, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in November 2011.

(b)	In June 2008, UE, as a well-known seasoned issuer, filed a Form S-3 shelf registration statement registering the issuance of an indeterminate amount of certain types of securities, which expires in June 2011.

Ameren

Ameren’s acquisitions of CILCORP and IP resulted in fair value adjustments to long-term debt of $111 million and $195 million, respectively. The fair value adjustments are being amortized to interest expense over the remaining life or to the expected redemption date of each debt issuance. As of December 31, 2008, the remaining unamortized balance of the fair-market value adjustments for CILCORP and IP were $49 million and $10 million, respectively. At IP, the amortization of fair value adjustments is offset in interest expense by a related amortization of a regulatory asset. See Note 2 – Rate and Regulatory Matters for more information on the regulatory asset.

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The following table presents the amortization of the CILCORP and IP fair value adjustments for the succeeding five years:


	CILCORP		IP
2009	$	5	$	5
2010		2		(a	)
2011		2		(a	)
2012		2		(a	)
2013		2		(a	)
Thereafter		36		4

(a)	Amount is less than $1 million.

In July 2008, Ameren filed a Form S-3 registration statement with the SEC authorizing the offering of six million additional shares of its common stock under the DRPlus. Shares of common stock sold under DRPlus are, at Ameren’s option, newly issued shares, 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 selling newly issued shares of common stock under its 401(k) plan pursuant to an effective SEC Form S-8 registration statement. Under DRPlus and its 401(k) plan (including a subsidiary plan that has now been merged into the Ameren 401(k) plan), Ameren issued 4.0 million, 1.7 million, and 1.9 million shares of common stock in 2008, 2007, and 2006, respectively, which were valued at $154 million, $91 million, and $96 million for the respective years.

In February 2007, $100 million of Ameren’s 5.70% notes matured and were retired.

In May 2007, $250 million of Ameren’s senior notes matured and were retired.

In June 2007, UE issued $425 million of 6.40% senior secured notes due June 15, 2017, with interest payable semi-annually on June 15 and December 15 of each year, beginning in December 2007. These notes are secured by first mortgage bonds. UE received net proceeds of $421 million, which were used to repay short-term debt.

In connection with UE’s June 2007 issuance of $425 million of senior secured notes, UE agreed, that so long as those senior secured notes are outstanding, it will not, prior to June 15, 2012, optionally redeem, purchase or otherwise retire in full its outstanding first mortgage bonds not subject to release provisions, thus causing a first mortgage bond release date to occur. Such release date is the date at which the security provided by the pledge under UE’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness ranking equally with any other outstanding senior unsecured indebtedness of UE. UE further agreed that the interest rate for these $425 million of senior secured notes will be subject to an increase of up to

a maximum of 2.00% if such release date occurs between June 15, 2012, and June 15, 2017 (the maturity date of the $425 million senior secured notes), and if Moody’s or S&P downgrades the rating assigned to these senior secured notes below investment grade as a result of the release within 30 days of such release (subject to extension if and for so long as the rating for such senior secured notes is under consideration for possible downgrade).

In April 2008, UE issued $250 million of 6.00% senior secured notes due April 1, 2018, with interest payable semiannually on April 1 and October 1 of each year, beginning in October 2008. These notes are secured by first mortgage bonds. UE received net proceeds of $248 million, which were used to redeem certain of UE’s outstanding auction-rate environmental improvement revenue refunding bonds discussed below and to repay short-term debt. In connection with this issuance of $250 million of senior secured notes, UE agreed, that so long as these senior secured notes are outstanding, it will not, prior to maturity, cause a first mortgage bond release date to occur.

In April 2008, $63 million of UE’s Series 2000B auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest.

In May 2008, $43 million of UE’s Series 1991, $64 million of UE’s Series 2000A and $60 million of UE’s Series 2000C auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest. Also, in May 2008, $148 million of UE’s 6.75% Series first mortgage bonds matured and were retired.

In June 2008, UE issued $450 million of 6.70% senior secured notes due February 1, 2019, with interest payable semiannually on February 1 and August 1 of each year, beginning in February 2009. These notes are secured by first mortgage bonds. UE received net proceeds of $446 million, which was used to repay short-term debt. A portion of that debt had been incurred so that UE could pay at maturity the 6.75% Series first mortgage bonds noted above. In connection with this issuance of $450 million of senior secured notes, UE agreed, that so long as these senior secured notes are outstanding, it will not, prior to maturity, cause a first mortgage bond release date to occur.

CIPS

In April 2008, $35 million of CIPS’ Series 2004 auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest.

In December 2008, $15 million of CIPS’ 5.375% senior secured notes matured and were retired.

Genco

In April 2008, Genco issued and sold, with registration rights in a private placement, $300 million of 7.00% senior unsecured notes due April 15, 2018, with interest payable semiannually on April 15 and October 15 of each year, beginning in October 2008. Genco received net proceeds of

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$298 million, which is used to fund capital expenditures, to repay short-term debt, and for general corporate purposes. Genco exchanged the outstanding unregistered unsecured notes for registered unsecured notes in July 2008.

CILCORP

As discussed above, in conjunction with Ameren’s acquisition of CILCORP, CILCORP’s long-term debt was increased to fair value by $111 million. Amortization related to fair-value adjustments was $6 million, $6 million, and $6 million for the years ended December 31, 2008, 2007, and 2006, respectively, and costs related to repayments were $- million, $- million, and $2 million for the years ended December 31, 2008, 2007, and 2006, respectively. These amounts were included in interest expense in the Consolidated Statements of Income of Ameren and CILCORP.

See Note 4 – Short-term Borrowings and Liquidity regarding CILCORP’s pledge of the common stock of CILCO as security for its obligations under the 2006 $500 million credit facility and the 2007 $500 million credit facility.

In September 2008, CILCORP commenced a cash tender offer for any and all of its outstanding 8.70% senior notes due 2009 ($123.755 million aggregate principal amount) and its 9.375% senior bonds due 2029 ($210.565 million aggregate principal amount), collectively, the “notes.” Concurrent with the tender offer, CILCORP solicited consents from the holders of the notes to certain proposed amendments to the indenture governing these securities. Any holder tendering securities as part of this offer is deemed to consent to the proposed amendments. No consents will be accepted separate from a tender of such holder’s securities. The amendments would eliminate certain restrictive covenants in the indenture and the notes. The total consideration for each $1,000 principal amount of 2009 notes validly tendered on or prior to the current consent and expiration date, which has been extended to April 30, 2009, is $1,057.50. The total consideration includes a consent payment of $40 per $1,000 principal amount of such 2009 notes tendered on or prior to such date. The total consideration for each $1,000 principal amount of 2029 bonds validly tendered on or prior to the current April 30, 2009, consent and expiration date is $1,230, which includes a consent payment of $50 per $1,000 principal amount of such 2029 bonds tendered on or prior to such date. Holders validly tendering and not withdrawing notes on or before the extended consent and expiration date are eligible to receive the applicable total consideration. In addition, tenders of notes, including previously tendered notes, may be withdrawn (and related consents may be rescinded) at any time prior to April 30, 2009. As of January 28, 2009, CILCORP had received consents, net of those rescinded, from the holders of $121.3 million, or 98.0%, of its outstanding 2009 8.70% senior notes and $206.6 million, or 98.1%, of its outstanding 2029 bonds. Consummation of the tender offer and the consent solicitation is subject to a number of conditions, including the absence of certain adverse legal

and market developments, as described in the offer to purchase. CILCORP has reserved the right to amend, further extend, terminate, or waive any conditions to the tender offer and the consent solicitation at any time. The impact on CILCORP’s net income of the tender offer is expected to be approximately $3 million, if consummated.

CILCO

In July 2007, 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. The redemption satisfied CILCO’s mandatory sinking fund redemption requirement for this series of preferred stock for 2007.

In April 2008, $19 million of CILCO’s Series 2004 auction-rate environmental improvement revenue refunding bonds were redeemed at par value plus accrued interest.

In July 2008, CILCO redeemed the remaining 165,000 shares of its 5.85% Class A preferred stock at a redemption price of $100 per share plus accrued and unpaid dividends. The redemption completed CILCO’s mandatory redemption obligations for this series of preferred stock.

In December 2008, CILCO issued $150 million of 8.875% senior secured notes due December 15, 2013, with interest payable semiannually on June 15 and December 15 of each year, beginning in June 2009. These notes are secured by first mortgage bonds. CILCO received net proceeds of $149 million, which were used to repay short-term debt. In connection with this issuance of $150 million of senior secured notes, CILCO agreed, that so long as these senior secured notes are outstanding, it will not, prior to maturity, cause a first mortgage bond release date to occur. The mortgage bond release date is the date at which the security provided by the pledge under CILCO’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness.

As discussed above, 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 $13 million for the year ended December 31, 2006, and was included in interest expense in the consolidated statements of income of Ameren and IP. Beginning in 2007, the amortization related to fair value adjustments was recoverable in rates and a regulatory asset was established. See Note 2 – Rate and Regulatory Matters for more information.

In November 2007, IP issued and sold, with registration rights in a private placement, $250 million of 6.125% senior secured notes due November 15, 2017, with interest payable semiannually on May 15 and November 15 of each year, beginning in May 2008. These notes are

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secured by mortgage bonds, which are subject to fallaway provisions as defined in the related financing agreements. IP received net proceeds of $248 million, which were used to repay short-term debt. IP exchanged the outstanding unregistered secured notes for registered secured notes in April 2008.

In April 2008, IP issued and sold, with registration rights in a private placement, $337 million of 6.25% senior secured notes due April 1, 2018, with interest payable semiannually on April 1 and October 1 of each year, beginning in October 2008. IP received net proceeds of $334 million, which were used to redeem all of IP’s outstanding auction-rate pollution control revenue refunding bonds during May and June 2008, as discussed below. In connection with IP’s April 2008 issuance of $337 million of senior secured notes, IP agreed, that so long as these senior secured notes are outstanding, it will not, prior to maturity, cause a first mortgage bond release date to occur. The mortgage bond release date is the date at which the security provided by the pledge under IP’s first mortgage indenture would no longer be available to holders of any outstanding series of its senior secured notes and such indebtedness would become senior unsecured indebtedness. IP exchanged the outstanding unregistered secured notes for registered secured notes in June 2008.

In May 2008, IP redeemed its $112 million Series 2001 Non-AMT, $75 million Series 2001 AMT, $70 million 1997

Series A, and $45 million 1997 Series B auction-rate pollution control revenue bonds at par value plus accrued interest. In June 2008, IP redeemed its $35 million 1997 Series C auction-rate pollution control revenue bonds at par value plus accrued interest.

In September 2008, IP redeemed the remaining portion of its $54 million principal amount 5.65% note payable to IP SPT. Previous redemptions occurred in the first and second quarters of 2008 for $19 million and $20 million, respectively. This was the remaining outstanding amount of $864 million of TFNs issued by the IP SPT in December 1998, as allowed under the Illinois Electric Utility Transition Funding Law.

In October 2008, IP issued and sold, with registration rights in a private placement, $400 million of 9.75% senior secured notes due November 15, 2018, with interest payable semiannually on November 15 and May 15 of each year, beginning in May 2009. IP received net proceeds of $391 million, which were used to repay short-term debt. In connection with IP’s October 2008 issuance of $400 million of senior secured notes, IP agreed that, so long as these senior secured notes are outstanding, it will not, prior to maturity, cause a first mortgage bond release date to occur. In February 2009, IP commenced an offer to exchange the outstanding unregistered secured notes for registered secured notes.

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. UE, CIPS, CILCO and IP are required to meet certain ratios to issue 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, 2008, at an assumed interest and dividend rate of 8%.


	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	³ 2.0	3.0	$	1,102	³ 2.5	40.4	$	1,126
CIPS	³ 2.0	2.1		33	³ 1.5	1.4		-
CILCO	³ 2.0 ^(d)	13.5		181	³ 2.5	51.4		331	^(e)
IP	³ 2.0	2.0		296	³ 1.5	1.0		-

(a)	Coverage required on the annual interest charges on first mortgage bonds outstanding and to be issued. Coverage is not required in certain cases when additional first mortgage bonds are issued on the basis of retired bonds.

(b)

Amount of bonds issuable based either on meeting required coverage ratios or unfunded property additions, whichever is more restrictive. The amounts shown also include bonds issuable based on retired bond capacity of $161 million, $18 million, $44 million and $286 million, at UE, CIPS, CILCO and IP, respectively.

(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)

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, 2008, CILCO had earnings equivalent to at least 31% of the principal amount of all mortgage bonds outstanding.

(e)	See Note 4 – Short-term Borrowings and Liquidity for a discussion regarding a restriction on the issuance of preferred stock by CILCO under the 2006 $500 million credit facility and the 2007 $500 million credit facility.

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 $1.8 billion of free and unrestricted retained earnings at December 31, 2008.


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CILCO’s articles of incorporation contain certain provisions that prohibit the payment of dividends on its common stock (1) from either paid-in surplus or any surplus created by a reduction of stated capital or capital stock, or (2) if at the time of dividend declaration, there shall not remain to the credit of earned surplus account (after deducting the amount of such dividends) an amount at least equal to two times the annual dividend requirement on all outstanding shares of CILCO’s preferred stock.

Genco’s and CILCORP’s indentures include provisions that require the companies to maintain certain debt service coverage and/or debt-to-capital ratios in order for the companies to pay dividends, to make certain principal or interest payments, to make certain loans to or investments in affiliates, or to incur additional indebtedness. The following table summarizes these ratios for the 12 months ended December 31, 2008:


	Required Interest Coverage Ratio		Actual Interest Coverage Ratio	Required Debt-to- Capital Ratio		Actual Debt-to- Capital Ratio
Genco ^(a)	³ 1.75	^(b)	6.9	£ 60	%	51	%
CILCORP ^(c)	³ 2.2		3.8	£ 67	%	32	%

(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)	Ratio excludes amounts payable under Genco’s intercompany note to CIPS. The ratio must be met both for the prior four fiscal quarters and for the succeeding four six-month periods.

(c)	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 direct or indirect subsidiaries.

Genco’s debt incurrence-related ratio restrictions and restricted payment limitations under its indenture 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. Even if CILCORP is not in compliance with these restrictions, CILCORP may still make 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, 2008, CILCORP’s senior long-term debt ratings from S&P, Moody’s and Fitch were BB+, Ba2, and BBB-, respectively. The common stock of CILCO is pledged as security to the holders of CILCORP’s senior notes and bonds and credit facility obligations.

In order for the Ameren Companies to issue securities in the future, they will have to comply with any applicable tests in effect at the time of any such issuances.

Off-Balance-Sheet Arrangements

At December 31, 2008, 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 6 – OTHER INCOME AND EXPENSES

The following table presents Other Income and Expenses for each of the Ameren Companies for the years ended December 31, 2008, 2007 and 2006:


	2008			2007			2006
Ameren: ^(a)
Miscellaneous income:
Interest and dividend income	$	15		$	27		$	10
Interest income on industrial development revenue bonds		28			28			28
Allowance for equity funds used during construction		28			5			4
Other		9			15			8
Total miscellaneous income	$	80		$	75		$	50
Miscellaneous expense:
Donations	$	(13	)	$	(13	)	$	(5	)
Other		(18	)		(12	)		(14	)
Total miscellaneous expense	$	(31	)	$	(25	)	$	(19	)
UE:
Miscellaneous income:
Interest and dividend income	$	5		$	4		$	3
Interest income on industrial development revenue bonds		28			28			28
Allowance for equity funds used during construction		28			4			3
Other		1			2			4
Total miscellaneous income	$	62		$	38		$	38
Miscellaneous expense:
Donations	$	(3	)	$	(2	)	$	(2	)
Other		(6	)		(5	)		(6	)
Total miscellaneous expense	$	(9	)	$	(7	)	$	(8	)

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	2008			2007			2006
CIPS:
Miscellaneous income:
Interest and dividend income	$	9		$	16		$	15
Other		2			1			2
Total miscellaneous income	$	11		$	17		$	17
Miscellaneous expense:
Donations	$	(2	)	$	(2	)	$	(1	)
Other		(1	)		(1	)		(1	)
Total miscellaneous expense	$	(3	)	$	(3	)	$	(2	)
Genco:
Miscellaneous income:
Interest and dividend income	$	1		$	-		$	-
Total miscellaneous income	$	1		$	-		$	-
Miscellaneous expense:
Other	$	(1	)	$	-		$	-
Total miscellaneous expense	$	(1	)	$	-		$	-
CILCORP:
Miscellaneous income:
Interest and dividend income	$	1		$	4		$	2
Other		1			1			-
Total miscellaneous income	$	2		$	5		$	2
Miscellaneous expense:
Donations	$	(2	)	$	(1	)	$	(1	)
Other		(3	)		(4	)		(3	)
Total miscellaneous expense	$	(5	)	$	(5	)	$	(4	)
CILCO:
Miscellaneous income:
Interest and dividend income	$	1		$	4		$	1
Other		1			1			-
Total miscellaneous income	$	2		$	5		$	1
Miscellaneous expense:
Donations	$	(2	)	$	(1	)	$	(1	)
Other		(3	)		(5	)		(3	)
Total miscellaneous expense	$	(5	)	$	(6	)	$	(4	)
IP:
Miscellaneous income:
Interest and dividend income	$	5		$	8		$	4
Other		6			6			2
Total miscellaneous income	$	11		$	14		$	6
Miscellaneous expense:
Donations	$	(3	)	$	(3	)	$	(1	)
Other		(2	)		(2	)		(3	)
Total miscellaneous expense	$	(5	)	$	(5	)	$	(4	)

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

NOTE 7 – DERIVATIVE FINANCIAL INSTRUMENTS

We use derivatives principally to manage the risk of changes in market prices for natural gas, fuel, electricity, and emission allowances. Price fluctuations in natural gas, fuel, and electricity may 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; 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

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these do not qualify for hedge accounting or the normal purchase and normal sales exceptions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended.

Accordingly, such contracts are recorded at fair value. Changes in the fair value are charged or credited to the income statement in the period in which the change occurs. 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.

The following table presents the pretax net gain (loss) for the years ended December 31, 2008, 2007 and 2006, of power hedges included in Operating Revenues – Electric. This pretax net gain (loss) represents the impact of discontinued cash flow hedges, the ineffective portion of cash flow hedges, and the reversal of amounts previously recorded in OCI for transactions that have since been delivered or settled:


Gains (Losses)	2008		2007		2006
Ameren	$	103	$	40	$	9
UE		7		-		11
Genco		-		-		2
IP		-		-		(7	)

(a)	Includes amounts from Ameren registrants and non-registrant subsidiaries.

Other Derivatives

The following table represents the net change in market value for the years ended December 31, 2008, 2007 and 2006, of option and swap transactions used to manage

our positions in SO ₂ allowances, coal, heating oil, FTRs and power. Certain of these transactions are treated as nonhedge transactions under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. The net changes in the market value of nonhedge power and gas transactions are recorded in Operating Revenues – Electric, and Operating Revenues – Gas, while the net changes in the market value of coal, heating oil, and SO ₂ options and swaps is recorded as Operating Expenses – Fuel.


Gains (Losses)	2008			2007			2006
SO ₂ options and swaps:
Ameren ^(a)	$	-		$	8		$	(2	)
UE		-			6			4
Genco		-			1			(4	)
Coal options:
Ameren ^(a)		-			2			(2	)
UE		-			2			(2	)
Heating oil options:
Ameren ^(a)		(53	)		6			(2	)
UE		(26	)		1			-
Genco		(16	)		1			-
CILCORP/CILCO		(3	)		-			-
FTRs:
Ameren ^(a)		3			-			-
UE		2			-			-
Nonhedge power swaps and forwards:
Ameren ^(a)		2			(2	)		-
Gas forwards and swaps:
Ameren ^(a)		(12	)		-			-
UE		(3	)		-			-
CILCORP/CILCO		(6	)		-			-

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

During the third quarter ended September 30, 2008, UE entered into foreign currency forward contracts. These derivative instruments are intended to fix the amount of U.S. dollars UE will pay for future equipment deliveries denominated in euros as part of a firm commitment to purchase heavy forgings, which would be used in building a second nuclear unit. These forward contracts qualify as fair value hedges and, as a result, both the derivative positions and the foreign currency exposure on the firm commitment are recorded at fair value. Changes in the fair value of both the derivative instrument and the hedged item are recorded in earnings. For the year ended December 31, 2008, this hedging program was highly effective, resulting in no impact to net income.

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The following table presents the carrying value of all derivative instruments and the amount of pretax net gains (losses) on derivative instruments in Accumulated OCI, regulatory assets, or regulatory liabilities, at December 31, 2008 and 2007:


	Ameren ^(a)			UE			CIPS			Genco			CILCORP/ CILCO			IP
2008:
Derivative instruments carrying value:
Other current assets	$	207		$	50		$	-		$	-		$	-		$	-
Other assets		47			-			-			-			-			-
Other current liabilities		155			24			31			1			29			56
Other deferred credits and liabilities ^(b ⁾		79			10			53			-			30			78
Gains (losses) deferred in Accumulated OCI:
Power forwards ^(c ⁾		84			40			-			-			-			-
Interest rate swaps ^(d)(e)		(11	)		-			-			(11	)		-			-
Gains (losses) deferred in regulatory assets or liabilities:
Gas forwards and futures contracts ^(f)		(118	)		(16	)		(27	)		-			(25	)		(50	)
Financial contracts ^(g)		-			-			(56	)		-			(29	)		(85	)
2007:
Derivative instruments carrying value:
Other current assets	$	35		$	7		$	1		$	2		$	2		$	2
Other assets		9			1			38			-			20			61
Other current liabilities		24			1			1			6			1			8
Other deferred credits and liabilities		7			-			-			-			-			-
Gains (losses) deferred in Accumulated OCI:
Power forwards		15			4			-			-			-			-
Interest rate swaps		(2	)		-			-			(2	)		-			-
Gas swaps and futures contracts		-			-			-			-			1			-
Coal options		1			1			-			-			-			-
Gains (losses) deferred in regulatory assets or liabilities:
Gas forwards and futures contracts		(2	)		1			(1	)		-			-			(2	)
Financial contracts ^(g)		-			-			40			-			19			57

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

(b)	Includes Ameren’s and UE’s carrying value of fair value foreign currency forward contracts.

(c)	Represents the mark-to-market value for the hedged portion of electricity price exposure for periods of up to three years, including $123 million and $39 million in 2009 at Ameren and UE, respectively.

(d)

Includes 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. The carrying value at December 31, 2008 was $2 million.

(e)

Includes a loss associated with interest rate swaps at Genco. The swaps were executed during the fourth quarter of 2007 as a partial hedge of interest rate risks associated with Genco’s April 2008 debt issuance. The cumulative gain and loss on the interest rate swaps will be amortized over a 10-year period that began in April 2008. The carrying value at December 31, 2008, was $13 million.

(f)	Represents gains associated with natural gas swaps and futures contracts. The swaps are a partial hedge of our natural gas requirements through October 2012 at UE, through March 2013 at CIPS and IP, and through March 2012 at CILCORP and CILCO.

(g)

Current losses deferred as regulatory assets of $14 million at CIPS, $7 million at CILCO, and $21 million at IP that were recorded in other current assets at December 31, 2008. Current gains deferred as regulatory liabilities include $2 million at CIPS, $1 million at CILCO, and $2 million at IP that were recorded in other current liabilities at December 31, 2007.

As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company. These financial contracts are derivative instruments being accounted for as cash flow hedges at the Ameren Illinois Utilities and Marketing Company. Consequently, the Ameren Illinois Utilities and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value in regulatory assets or liabilities for the Ameren Illinois Utilities and OCI at Marketing Company. In Ameren’s consolidated financial statements, all financial statement effects of the derivative instruments are eliminated. See Note 2 – Rate and Regulatory Matters for additional information on these financial contracts.

Derivative instruments are subject to various credit- related losses in the event of nonperformance by

counterparties to the contracts. In order to mitigate these risks, collateral requirements are established. As of December 31, 2008, Ameren, UE, CIPS, CILCORP, CILCO and IP had collateral postings with external parties of $109 million, $15 million, $26 million, $16 million, $16 million, and $36 million, respectively. The amount of collateral external counterparties posted with Ameren was $7 million at December 31, 2008. The amounts of collateral external counterparties posted with UE, CIPS, CILCORP, CILCO, and IP were immaterial at December 31, 2008. See Note 14 – Related Party Transactions for information regarding collateral postings with affiliates.

On September 15, 2008, Lehman filed for protection under Chapter 11 of the federal Bankruptcy Code in the U.S. Bankruptcy Court in the Southern District of New York. On October 21, 2008, Ameren sent notice to Lehman

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Commodity Services terminating all transactions between Genco, UE, and Marketing Company and Lehman Commodity Services. As of December 31, 2008, Ameren’s and its subsidiaries’ direct exposure to Lehman Commodity Services, based on existing transactions and current market prices, was estimated to be less than $1 million before taxes, collectively.

NOTE 8 – FAIR VALUE MEASUREMENTS

SFAS No. 157 provides a framework for measuring fair value for all assets and liabilities that are measured and reported at fair value. The Ameren Companies adopted SFAS No. 157 as of the beginning of their 2008 fiscal year for financial assets and liabilities and as of the beginning of their 2009 fiscal year for nonfinancial assets and liabilities, except those already reported at fair value on a recurring basis. The impact of the adoption of SFAS No. 157 for financial assets and liabilities at January 1, 2008, and for nonfinancial assets and liabilities at January 1, 2009, was not material. SFAS No. 157 defines fair value as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. We use various methods to determine fair value, including market, income, and cost approaches. With these approaches, we adopt certain assumptions that market participants would use in pricing the asset or liability, including assumptions about risk or the risks inherent in the inputs to the valuation. Inputs to valuation can be readily observable, market-corroborated, or unobservable. We use valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. SFAS No. 157 also establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. All financial assets and liabilities carried at fair value are classified and disclosed in one of the following three hierarchy levels:

Level 1 : Inputs based on quoted prices in active markets for identical assets or liabilities. Level 1 assets and liabilities primarily include exchange-traded derivatives and assets including U.S. treasury securities and listed equity securities, such as those held in UE’s Nuclear Decommissioning Trust Fund.

Level 2 : Market-based inputs corroborated by third-party brokers or exchanges based on transacted market data. Level 2 assets and liabilities include certain assets held in UE’s Nuclear Decommissioning Trust Fund, including corporate bonds and other fixed-income securities, and certain over-the-counter derivative instruments, including natural gas swaps and financial power transactions. Derivative instruments classified as Level 2 are valued using corroborated observable inputs, such as pricing services or prices from similar instruments

that trade in liquid markets. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. To derive our forward view to price our derivative instruments at fair value, we average the midpoints of the bid/ask spreads. To validate forward prices obtained from outside parties, we compare the pricing to recently settled market transactions. Additionally, a review of all sources is performed to identify any anomalies or potential errors. Further, we consider the volume of transactions on certain trading platforms in our reasonableness assessment of the averaged midpoint.

Level 3 : Unobservable inputs that are not corroborated by market data. Level 3 assets and liabilities are valued based on internally developed models and assumptions or methodologies that use significant unobservable inputs. Level 3 assets and liabilities include derivative instruments that trade in less liquid markets, where pricing is largely unobservable, including the financial contracts entered into between the Ameren Illinois Utilities and Marketing Company as part of the Illinois electric settlement agreement. We value Level 3 instruments using pricing models with inputs that are often unobservable in the market, as well as certain internal assumptions. Our development and corroboration process entails obtaining multiple quotes or prices from outside sources. As a part of our reasonableness review, a review of all sources is performed to identify any anomalies or potential errors.

We perform an analysis each quarter to determine the appropriate hierarchy level of the assets and liabilities subject to SFAS No. 157. Financial assets and liabilities are classified in their entirety according to the lowest level of input that is significant to the fair value measurement. All assets and liabilities whose fair value measurement is based on significant unobservable inputs are classified as Level 3.

We consider nonperformance risk in our valuation of derivative instruments by analyzing the credit standing of our counterparties and considering any counterparty credit enhancements (e.g., collateral). SFAS No. 157 also requires that the fair value measurement of liabilities reflect the nonperformance risk of the reporting entity, as applicable. Therefore, we have factored the impact of our credit standing as well as any potential credit enhancements into the fair value measurement of both derivative assets and derivative liabilities. Included in our valuation, and based on current market conditions, is a valuation adjustment for counterparty default derived from market data such as the price of credit default swaps, bond yields, and credit ratings. Ameren recorded $5 million in losses in the fourth quarter of 2008 related to valuation adjustments for counterparty default risk. At December 31, 2008, the counterparty default risk valuation adjustment related to net derivative (assets) liabilities totaled $(1) million, $- million, $9 million, $6 million, and $16 million for Ameren, UE, CIPS, CILCORP/CILCO and IP, respectively.

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The following table sets forth, by level within the fair value hierarchy, our assets and liabilities measured at fair value on a recurring basis as of December 31, 2008:


		Quoted Prices in Active Markets for Identified Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Other Unobservable Inputs (Level 3)		Total
Assets:
Ameren ^(a)	Other current assets	$	-	$	-	$	6	$	6
	Derivative assets ^(b)		1		19		234		254
	Nuclear Decommissioning Trust Fund ^(c)		164		81		2		247
UE	Derivative assets		-		14		36		50
	Nuclear Decommissioning Trust Fund ^(c)		164		81		2		247
CIPS	Derivative assets ^(b)		-		-		-		-
Genco	Derivative assets ^(b)		-		-		-		-
CILCORP/CILCO	Derivative assets ^(b)		-		-		-		-
IP	Derivative assets ^(b)		-		-		-		-
Liabilities:
Ameren ^(a)	Derivative liabilities ^(b)	$	9	$	6	$	219	$	234
UE	Derivative liabilities ^(b)		-		3		31		34
CIPS	Derivative liabilities ^(b)		-		-		84		84
Genco	Derivative liabilities ^(b)		-		-		1		1
CILCORP/CILCO	Derivative liabilities ^(b)		4		-		55		59
IP	Derivative liabilities ^(b)		-		-		134		134

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

(b)	The derivative asset and liability balances are presented net of counterparty credit considerations.

(c)	Balance excludes ($8) million of receivables, payables, and accrued income, net.

The following table summarizes the changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the year ended December 31, 2008:


				Realized and Unrealized Gains (Losses)								Total Realized and Unrealized Gains (Losses)			Purchases, Issuances, and Other Settlements, Net								Change in Unrealized Gains (Losses) Related to Assets/ Liabilities Still Held at December 31, 2008
		Beginning Balance at January 1, 2008		Included in Earnings ^(a)			Included In OCI		Included in Regulatory Assets/ Liabilities			Total Realized and Unrealized Gains (Losses)			Purchases, Issuances, and Other Settlements, Net			Net Transfers Into (Out of) Level 3		Ending Balance at December 31, 2008
Other current assets	Ameren	$	-	$	-		$	-	$	-		$	-		$	-		$	6	$	6		$	-
Net derivative	Ameren	$	19	$	(18	)	$	13	$	(35	)	$	(40	)	$	8		$	28	$	15		$	(206	)
contracts	UE		3		1			13		13			27			(42	)		17		5			(6	)
	CIPS		38		(1	)		-		(127	)		(128	)		6			-		(84	)		(106	)
	Genco		1		(2	)		-		-			(2	)		-			-		(1	)		-
	CILCORP/CILCO		21		(34	)		-		(43	)		(77	)		1			-		(55	)		(62	)
	IP		55		(1	)		-		(209	)		(210	)		21			-		(134	)		(174	)
Nuclear	Ameren	$	5	$	-		$	-	$	-		$	-		$	(3	)	$	-	$	2		$	-
Decommissioning Trust Fund	UE		5		-			-		-			-			(3	)		-		2			-

(a)	Net gains and losses on power options are recorded in Operating Revenues – Electric, while net gains and losses on coal, heating oil, and SO ₂ options and swaps are recorded as Operating Expenses – Fuel.

Transfers in or out of Level 3 represent either (1) existing assets and liabilities that were previously categorized as a higher level but were recategorized to Level 3 because the inputs to the model became unobservable during the period, or (2) existing assets and liabilities that were previously classified as Level 3 but were recategorized to a higher level because the lowest significant input became observable during the period. Transfers between Level 2 and Level 3 were primarily caused by changes in availability of financial power trades observable on electronic exchanges compared with previous periods for the year ended December 31, 2008. Any reclassifications are reported as transfers in/out of Level 3 at the fair value measurement reported at the beginning of the period in which the changes occur.

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The Ameren Companies’ carrying amounts of cash and cash equivalents, accounts receivable, short-term borrowings, and accounts payable approximate fair value because of the short-term nature of these instruments. The estimated fair value of long-term debt and preferred stock is based on the quoted market prices for same or similar issues for companies with similar credit profiles or on the current rates offered to the Ameren Companies for similar financial instruments.

The following table presents the carrying amounts and estimated fair values of our long-term debt and preferred stock at December 31, 2008 and 2007:


	2008				2007
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Ameren: ^(a)
Long-term debt and capital lease obligations (including current portion)	$	6,934	$	6,144	$	5,912	$	5,821
Preferred stock		195		100		211		147
UE:
Long-term debt and capital lease obligations (including current portion)	$	3,677	$	3,156	$	3,360	$	3,255
Preferred stock		113		62		113		85
CIPS:
Long-term debt (including current portion)	$	421	$	371	$	471	$	472
Preferred stock		50		22		50		27
Genco:
Long-term debt (including current portion)	$	774	$	661	$	474	$	510
CILCORP:
Long-term debt (including current portion)	$	662	$	630	$	537	$	516
Preferred stock		19		10		35		27
CILCO:
Long-term debt (including current portion)	$	279	$	255	$	148	$	149
Preferred stock		19		10		35		27
IP:
Long-term debt (including current portion)	$	1,400	$	1,326	$	1,070	$	1,067
Preferred stock		46		24		46		32

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

NOTE 9 – NUCLEAR DECOMMISSIONING TRUST FUND INVESTMENTS

UE has investments in debt and equity securities that are held in a trust fund for the purpose of funding the decommissioning of its Callaway nuclear plant. See Note 16 – Callaway Nuclear Plant for further information. We have classified these investments as available for sale, and we have recorded all such investments at their fair market value at December 31, 2008, and 2007.

Investments by the nuclear decommissioning trust fund have a target allocation of 60% to 70% in equity securities with the balance invested in fixed-income securities. Due to recent market conditions, the equity securities weighting was below targeted levels at December 31, 2008. In January 2009, UE rebalanced its investments to align with its targeted equity securities weighting.

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, 2008, 2007 and 2006:


	2008		2007		2006
Proceeds from sales	$	497	$	128	$	98
Gross realized gains		5		4		2
Gross realized losses		8		3		2

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. See Note 2 – Rate and Regulatory Matters.

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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, 2008 and 2007:


Security Type	Cost			Gross Unrealized Gain	Gross Unrealized Loss	Fair Value
2008:
Debt securities	$	109		$ 5	$ 3	$	111
Equity securities		123		40	29		134
Cash		2		-	-		2
Other ^(a)		(8	)	-	-		(8	)
Total	$	226		$ 45	$ 32	$	239
2007:
Debt securities	$	109		$ 3	$ 1	$	111
Equity securities		104		97	7		194
Cash		1		-	-		1
Other ^(a)		1		-	-		1
Total	$	215		$ 100	$ 8	$	307

(a)	Represents payables relating to pending security purchases, net of receivables related to pending securities sales and interest receivables.

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, 2008:

We have unrealized losses relating to certain available-for-sale investments included in our decommissioning trust fund, recorded as regulatory assets as discussed above. Decommissioning will not occur until the operating license for our nuclear facility expires. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. 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. They are aggregated by investment category and the length of time that individual securities have been in a continuous unrealized loss position, at December 31, 2008:


	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	$	20	$	2	$	7	$	1	$	27	$	3
Equity securities		30		16		6		13		36		29
Total	$	50	$	18	$	13	$	14	$	63	$	32

NOTE 10 – STOCKHOLDER RIGHTS PLAN AND PREFERRED STOCK

Stockholder Rights Plan

In 1998, Ameren’s board of directors adopted a share purchase rights plan designed to assure stockholders of fair and equal treatment in the event of a proposed takeover. The rights were exercisable only if a person or group acquired 15% or more of Ameren’s outstanding common stock or announced a tender offer that would result in ownership by a person or group of 15% or more of the Ameren common stock. Ameren’s stockholder rights plan expired on October 9, 2008, and Ameren’s Board of Directors decided not to renew it.

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 of $1 par value preference stock authorized and CILCO has 2 million shares of no par value preference stock authorized, with no such preference stock outstanding. IP has 5 million shares of no par value serial preferred stock authorized and 5 million shares of no par value preference stock authorized, with no such serial preferred stock and preference stock outstanding. No shares of preference stock have been issued by any of the Ameren Companies.

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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, 2008 and 2007:


		Redemption Price (per share)		2008			2007
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	105.62	5		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	102.17	6		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
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					(33	)		(33	)
Total Ameren				$	195		$	195

(a)	In the event of voluntary liquidation, $105.50.

(b)	Declining to $100 per share in 2012.

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.

We adopted the provisions of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132(R),” effective December 31, 2006. SFAS No. 158 requires employers to recognize the overfunded or underfunded positions of defined benefit postretirement plans, including pension plans, as an asset or liability in their balance sheets. Employers must also recognize as a component of OCI, net

of tax, the gains or losses and prior service costs or credits that arise during the period but are not recognized as components of net periodic benefit cost. Upon adoption of this provision, Ameren recorded the unfunded obligation of its defined benefit and postretirement benefit plans. The unfunded obligation is the difference between plan assets and the projected benefit obligation for defined benefit plans or accumulated postretirement benefit obligation for postretirement benefit plans. Ameren’s adoption of SFAS No. 158 resulted in increases (decreases) to Ameren’s, UE’s, CIPS’, Genco’s, CILCORP’s, CILCO’s, and IP’s accrued pension and other postretirement benefits of $406 million, $234 million, $95 million, $36 million, $(51) million, $55 million, and $(8) million, respectively. UE, CIPS, CILCO and IP recorded regulatory assets of $270 million, $108 million, $63 million, and $205 million, respectively, based on the expected recovery of these costs from ratepayers. The adoption of SFAS No. 158 had no

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material impact on accumulated other comprehensive income at Ameren. CILCORP and IP recognized gains in accumulated other comprehensive income of $29 million and $5 million, respectively, net of taxes, as a result of SFAS No. 158 obligations being reduced from those previously recognized. Genco and CILCO recorded a charge to accumulated other comprehensive income of $25 million and $2 million, respectively, net of taxes.

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. Projected rates of return for each asset class were estimated 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 with benchmark returns and for the effect of expenses paid from plan assets.

Pension benefits are based on the employees’ years of service and compensation. Ameren’s pension plans are funded in compliance with income tax regulations and to achieve federal funding or regulatory requirements. As a result, Ameren expects to fund its pension plans at a level equal to the greater of the pension expense or the legally required minimum contribution. Taking into consideration our assumptions at December 31, 2008, the investment performance in 2008, and our pension funding policy, Ameren expects to make annual contributions of $90 million to $200 million in each of the next five years. We expect UE’s, CIPS’, Genco’s, CILCO’s, and IP’s portion of the future funding requirements to be 61%, 6%, 10%, 9%, and 14%, respectively. These amounts are estimates. They may change with actual investment performance, changes in interest rates, any pertinent changes in government regulations, and any voluntary contributions. Our policy for postretirement benefits is primarily to fund the Voluntary Employee Beneficiary Association (VEBA) trusts to match the annual postretirement expense.

The following table presents the benefit liability recorded in the balance sheets of each of the Ameren Companies as of December 31, 2008:


	2008
Ameren ^(a)	$	1,499
UE		496
CIPS		79
Genco		67
CILCORP		216
CILCO		216
IP		314

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

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The following table presents the funded status of our pension and postretirement benefit plans for the years ended December 31, 2008 and 2007:


	2008						2007
	Pension Benefits ^(a)			Postretirement Benefits ^(a)			Pension Benefits ^(a)			Postretirement Benefits ^(a)
Change in benefit obligation:
Net benefit obligation at beginning of year	$	3,076		$	1,253		$	3,120		$	1,297
Service cost		60			18			63			21
Interest cost		186			70			180			72
Plan amendments		2			-			3			-
Participant contributions		-			14			-			12
Actuarial (gain) loss		145			(105	)		(126	)		(83	)
Reflection of Medicare Part D:
Benefits paid		(166	)		(73	)		(164	)		(71	)
Less federal subsidy on benefits paid		-			5			-			5
Net benefit obligation at end of year		3,303			1,182			3,076			1,253
Accumulated benefit obligation at end of year		3,051			(b	)		2,837			(b	)
Change in plan assets:
Fair value of plan assets at beginning of year		2,698			787			2,608			742
Actual return on plan assets		(205	)		(187	)		202			49
Employer contributions		66			47			52			51
Federal subsidy on benefits paid		-			5			-			4
Participant contributions		-			14			-			12
Benefits paid		(166	)		(73	)		(164	)		(71	)
Fair value of plan assets at end of year		2,393			593			2,698			787
Funded status – deficiency		910			589			378			466
Accrued benefit cost at December 31	$	910		$	589		$	378		$	466
Amounts recognized in the balance sheet consist of:
Current liability	$	2		$	2		$	3		$	2
Noncurrent liability		908			587			375			464
Total	$	910		$	589		$	378		$	466
Amounts recognized in regulatory assets consist of:
Net actuarial loss	$	597		$	327		$	142		$	233
Prior service cost (credit)		40			(40	)		49			(45	)
Transition obligation		-			12			-			16
Amounts recognized in accumulated OCI consist of:
Net actuarial (gain) loss		57			43			(34	)		17
Prior service cost (credit)		10			(16	)		10			(20	)
Transition obligation		-			-			-			-
Total	$	704		$	326		$	167		$	201

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

(b)	Not applicable.

Ameren’s current reconciliation of funded status shows certain amounts that will be recognized as a benefit cost in future years. The unrecognized loss in postretirement benefits is largely a result of declining discount rates over the past several years and market losses on plan assets.

No plan assets are expected to be returned to Ameren during 2009.

The market value of plan assets in 2008 declined by 7% and 26% for the pension and postretirement benefit plans, respectively. In 2008, investment losses in Ameren’s pension plan were partially offset by a gain on interest rate swaps, which had a notional value of $700 million at December 31, 2008. The swaps were intended to mitigate the impacts on the funded status of the plan resulting from decreases in the discount rate in the calculation of the pension liability. During 2008, U.S. Treasury yields declined significantly, resulting in Ameren’s pension plan recognizing a $336 million net gain from its interest rate swaps. Ameren closed its interest rate swap position in early 2009. Ameren’s postretirement benefit plan did not have a similar interest rate hedge.

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The following table presents the assumptions used to determine our benefit obligations at December 31, 2008 and 2007:


	Pension Benefits				Postretirement Benefits
	2008		2007		2008		2007
Discount rate at measurement date	5.75	%	6.15	%	5.75	%	6.05	%
Increase in future compensation	4.00		4.00		4.00		4.00
Medical cost trend rate (initial)	-		-		7.00		9.00
Medical cost trend rate (ultimate)	-		-		5.00		5.00
Years to ultimate rate	-		-		4 years		4 years

The following table presents the cash contributions made to our defined benefit retirement plan qualified trusts and to our postretirement plans during 2008 and 2007:


	Pension Benefits				Postretirement Benefits
	2008		2007		2008		2007
Ameren ^(a)	$	66	$	52	$	47	$	51
UE		36		28		13		27
CIPS		5		5		2		4
Genco		5		4		-		-
CILCORP		7		4		8		13
CILCO		7		4		8		13
IP		11		9		24		7

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

Ameren determines the discount rate assumptions by using 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 based on the yields of more than 300 high-quality, noncallable corporate bonds with maturities between zero and 30 years. A theoretical spot-rate curve constructed from this yield curve is then used as a guide to develop a 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 table presents our target allocations for 2009 and our pension and postretirement plan asset categories as of December 31, 2008 and 2007. Ameren’s pension plan debt security weighting was at the high end of the target allocation range at the end of 2008. Due to current market conditions, Ameren expects the debt security weighting will remain near the high end of the target allocation range in 2009.


Asset Category	Target Allocation 2009		Percentage of Plan Assets at December 31,
Asset Category	Target Allocation 2009		2008		2007
Pension Plan:
Equity securities	30 - 80	%	36	%	52	%
Debt securities	25 - 60		56		40
Real estate	0 - 10		6		6
Other	0 - 10		2		2
Total			100	%	100	%
Postretirement Plan:
Equity securities	30 - 80	%	51	%	62	%
Debt securities	15 - 55		43		33
Other	0 - 15		6		5
Total			100	%	100	%

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The following table presents the components of the net periodic benefit cost for our pension and postretirement benefit plans during 2008, 2007 and 2006:


	Pension Benefits		Postretirement Benefits
	Ameren ^(a)		Ameren ^(a)
2008:
Service cost	$ 60		$ 18
Interest cost	186		70
Expected return on plan assets	(213	)	(58	)
Amortization of:
Transition obligation	-		2
Prior service cost	11		(8	)
Actuarial loss	3		9
Net periodic benefit cost	$ 47		$ 33
2007:
Service cost	$ 63		$ 21
Interest cost	180		72
Expected return on plan assets	(206	)	(53	)
Amortization of:
Transition obligation	-		2
Prior service cost	11		(8	)
Actuarial loss	22		24
Net periodic benefit cost	$ 70		$ 58
2006:
Service cost	$ 63		$ 22
Interest cost	173		72
Expected return on plan assets	(198	)	(50	)
Amortization of:
Transition obligation	-		2
Prior service cost	11		(7	)
Actuarial loss	42		35
Net periodic benefit cost	$ 91		$ 74

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

The estimated amounts that will be amortized from regulatory assets and accumulated OCI into net periodic benefit cost in 2009 are as follows:


	Pension Benefits	Postretirement Benefits
	Ameren ^(a)	Ameren ^(a)
Regulatory assets:
Net actuarial loss	$ 39	$ 20
Prior service cost (credit)	8	(4	)
Transition obligation	-	4
Accumulated OCI:
Net actuarial loss	$ 1	$ -
Prior service cost (credit)	2	(3	)
Transition obligation	-	-
Total	$ 50	$ 17

(a)	Includes amounts for Ameren registrant and nonregistrant subsidiaries

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 subject to amortization is amortized on a straight-line basis over 10 years.

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UE, CIPS, Genco, CILCORP, CILCO and IP are responsible for their share of the pension and postretirement costs. The following table presents the pension costs and the postretirement benefit costs incurred for the years ended December 31, 2008, 2007 and 2006:


	Pension Costs							Postretirement Costs
	2008			2007		2006		2008		2007		2006
Ameren ^(a)	$	47		$	70	$	91	$	33	$	58	$	74
UE		35			44		51		13		26		40
CIPS		7			10		11		3		6		9
Genco		5			7		9		2		3		3
CILCORP		(2	)		-		10		1		8		9
CILCO		5			8		13		6		13		14
IP		(2	)		4		9		14		13		13

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

The expected pension and postretirement benefit payments from qualified trust and company funds and the federal subsidy for postretirement benefits related to prescription drug benefits, which reflect expected future service, are as follows:


	Pension Benefits				Postretirement Benefits
	Paid from Qualified Trust		Paid from Company Funds		Paid from Qualified Trust		Paid from Company Funds		Federal Subsidy
2009	$	192	$	3	$	83	$	2	$	5
2010		194		3		89		2		6
2011		200		3		94		3		6
2012		207		3		97		3		6
2013		213		2		100		3		6
2014 - 2018		1,183		10		530		13		33

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, 2008, 2007 and 2006:


	Pension Benefits						Postretirement Benefits
	2008		2007		2006		2008		2007		2006
Ameren, UE, CIPS , Genco, CILCORP, CILCO and IP:
Discount rate at measurement date	6.15	%	5.85	%	5.60	%	6.05	%	5.80	%	5.60	%
Expected return on plan assets ^(a)	8.25		8.50		8.50		8.25		8.50		8.50
Increase in future compensation	4.00		4.00		3.25		4.00		4.00		3.25
Medical cost trend rate (initial)	-		-		-		9.00		9.00		8.00
Medical cost trend rate (ultimate)	-		-		-		5.00		5.00		5.00
Years to ultimate rate	-		-		-		4 years		4 years		3 years

(a)	The Ameren Companies will utilize an expected return on plan assets of 8% in 2009.

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


	Pension				Postretirement
	Service Cost and Interest Cost		Projected Benefit Obligation		Service Cost and Interest Cost			Postretirement Benefit Obligation
0.25% decrease in discount rate	$	1	$	104	$	-		$	30
0.25% increase in salary scale		2		13		-			-
1.00% increase in annual medical trend		-		-		2			29
1.00% decrease in annual medical trend		-		-		(2	)		(26	)

Other

Ameren sponsors a 401(k) plan for eligible employees. The Ameren plan covered all eligible employees of the Ameren Companies at December 31, 2008. The plans allowed employees to contribute a portion of their base pay in accordance with specific guidelines. Ameren matched a percentage of the employee contributions up to certain limits. Ameren’s matching contributions to the 401(k) plan totaled $23 million, $21 million, and $19 million in 2008,

2007, and 2006, respectively. Prior to February 1, 2008, CIPS employees represented by IBEW Local 702 were covered by a separate 401(k) plan. The CIPS-related 401(k) plan was merged into the Ameren plan effective February 1, 2008. CIPS’ matching contributions to the CIPS-related 401(k) plan were less than $1 million annually in 2008, 2007 and 2006.

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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, 2008, 2007 and 2006:


	2008		2007		2006
Ameren ^(a)	$	23	$	21	$	19
UE		14		14		13
CIPS		2		1		1
Genco		2		1		1
CILCORP		2		2		2
CILCO		2		2		2
IP		2		3		2

(a)	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 (1998 Plan), was replaced prospectively by the 2006 Omnibus Incentive Compensation Plan (2006 Plan) effective May 2, 2006. The 2006 Plan provides for a maximum of 4 million common shares to be available for grant to eligible employees and directors. No new awards may be granted under the 1998 Plan; however, previously granted awards continue to vest or to be exercisable in accordance with their original terms and conditions. The 2006 Plan awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards, and other stock-based awards.

A summary of nonvested shares as of December 31, 2008, and changes during the year ended December 31, 2008, under the 1998 Plan and the 2006 Plan are presented below:


	Performance Share Units			Restricted Shares
	Shares		Weighted-average Fair Value Per Unit	Shares		Weighted-average Fair Value Per Share
Nonvested at January 1, 2008	669,403		$ 57.88	316,768		$ 46.23
Granted ^(a)	495,847		32.35	-		-
Dividends	-		-	13,364		38.91
Unearned or forfeited ^(b)	(213,854	)	55.82	(2,163	)	48.19
Earned and vested ^(c)	(275,419	)	49.37	(114,286	)	44.05
Nonvested at December 31, 2008	675,977		$ 43.28	213,683		$ 47.46

(a)	Includes performance share units (share units) granted to certain executive and nonexecutive officers and other eligible employees in February 2008 under the 2006 Plan.

(b)	Includes share units granted in 2006 that were not earned based on performance provisions of the awarded grants.

(c)

Includes share units granted in 2006 that vested as of December 31, 2008, that were earned pursuant to the provisions of the award grants. Also includes share units that vested due to attainment of retirement eligibility by certain employees. Actual shares issued for retirement-eligible employees will vary depending on actual performance over the three-year measurement period.

Ameren recorded compensation expense of $22 million, $18 million, and $11 million for the years ended December 31, 2008, 2007, and 2006, respectively, and a related tax benefit of $8 million, $7 million, and $4 million for the years ended December 31, 2008, 2007, and 2006, respectively. As of December 31, 2008, total compensation cost of $13 million related to nonvested awards not yet recognized is expected to be recognized over a weighted-average period of 19 months.

Performance Share Units

Performance share unit awards were granted under the 1998 Plan and the 2006 Plan from 2006 to 2008. With these awards, a share unit will vest and entitle an employee to receive shares of Ameren common stock (plus accumulated dividends) if, at the end of the three-year performance period, Ameren has achieved certain performance goals and the individual remains employed by Ameren. The exact number of shares issued pursuant to a share unit will vary from 0% to 200% of the target award, depending on actual company performance relative to the performance goals. When a share unit awarded from 2006 to 2008 vests, Ameren will issue the related shares to the

employee two years after vesting, but dividends on the shares will be paid to the employee at the same time they are paid to other shareholders.

The fair value of each share unit awarded in February 2008 under the 2006 Plan was determined to be $32.35, based on Ameren’s closing common share price of $44.30 per share at the grant date and lattice simulations used to estimate expected share payout based on Ameren’s attainment of certain financial measures relative to the designated peer group. The significant assumptions used to calculate fair value also included a three-year risk-free rate of 2.264%, dividend yields of 2.3% to 5.4% for the peer group, volatility of 14.43% to 21.51% for the peer group, and Ameren’s maintenance of its $2.54 annual dividend over the performance period.

The fair value of each share unit awarded in February 2007 under the 2006 Plan was determined to be $59.60. That figure was based on Ameren’s closing common share price of $53.99 per share at the grant date and lattice simulations used to estimate expected share payout based on Ameren’s attainment of certain financial measures relative to the designated peer group. The significant

153

assumptions used to calculate fair value also included a three-year risk-free rate of 4.735%, dividend yields of 2.3% to 5.2% for the peer group, volatility of 12.91% to 18.33% for the peer group, and Ameren’s maintenance of its $2.54 annual dividend over the performance period.

Restricted Stock

Restricted stock awards in Ameren common stock were granted under the 1998 Plan from 2001 to 2005. Restricted shares have the potential to vest over a seven-year period from the date of grant if the company achieves certain performance levels. An accelerated vesting provision included in this plan reduces the vesting period from seven years to three years if the earnings growth rate exceeds a prescribed level.

Stock Options

Ameren

Options in Ameren common stock were granted under the 1998 Plan 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. There have not been any stock options granted since December 31, 2000. Outstanding options of 85,800 at December 31, 2008, expire on various dates through 2010. There is no expense from stock options for the years ended December 31, 2008, 2007 and 2006, as all options granted were fully vested.

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, 2008, 2007 and 2006:


	Ameren		UE		CIPS		Genco		CILCORP		CILCO		IP
2008:
Statutory federal income tax rate:	35	%	35	%	35	%	35	%	35	%	35	%	35	%
Increases (decreases) from:
Permanent items ⁽ ^a ⁾	(1	)	1		(1	)	(2	)	(3	)	(1	)	7
Depreciation differences	-		(1	)	(2	)	-		(1	)	(1	)	-
Amortization of investment tax credit	(1	)	(1	)	(10	)	-		(1	)	(1	)	-
State tax	4		3		5		5		4		5		5
Reserve for uncertain tax positions	(1	)	(1	)	(1	)	(1	)	1		-		2
Other ⁽ ^b ⁾	(2	)	-		(1	)	(1	)	(4	)	(1	)	1
Effective income tax rate	34	%	36	%	25	%	36	%	31	%	36	%	50	%
2007:
Statutory federal income tax rate:	35	%	35	%	35	%	35	%	35	%	35	%	35	%
Increases (decreases) from:
Permanent items ⁽ ^a ⁾	(2	)	(2	)	2		(1	)	(5	)	(2	)	1
Depreciation differences	-		-		3		-		(2	)	(1	)	(3	)
Amortization of investment tax credit	(1	)	(1	)	(6	)	(1	)	(2	)	(1	)	-
State tax	4		4		6		5		3		3		5
Reserve for uncertain tax positions	(1	)	(1	)	-		-		-		-		-
Other ⁽ ^c ⁾	(1	)	(2	)	(4	)	-		1		-		(1	)
Effective income tax rate	34	%	33	%	36	%	38	%	30	%	34	%	37	%
2006:
Statutory federal income tax rate:	35	%	35	%	35	%	35	%	35	%	35	%	35	%
Increases (decreases) from:
Permanent items ⁽ ^a ⁾	(2	)	(2	)	-		(4	)	(d	)	(5	)	1
Sales of noncore properties	(2	)	-		-		-		(d	)	(2	)	-
Nondeductible expenses	1		2		-		-		(d	)	-		-
Depreciation differences	1		2		(5	)	-		(d	)	(3	)	-
Amortization of investment tax credit	(1	)	(1	)	(3	)	(1	)	(d	)	(2	)	-
State tax	4		3		5		5		(d	)	5		5
Reserve for uncertain tax positions	(1	)	-		(2	)	(2	)	(d	)	(11	)	-
Other ⁽ ^c ⁾	(2	)	(1	)	(1	)	(2	)	(d	)	-		(1	)
Effective income tax rate	33	%	38	%	29	%	31	%	(d	)	17	%	40	%

(a)

Permanent items are treated differently for book and tax purposes and primarily include Internal Revenue Code Section 199 production activity deductions for Ameren, UE, Genco, CILCORP and CILCO, company-owned life insurance for Ameren, CILCORP and CILCO, SFAS No. 106-2 Medicare Part D for Ameren, UE, Genco, CILCORP and CILCO, employee stock ownership plan dividends for Ameren, and nondeductible expenses for IP.

(b)	Primarily includes settlements with state taxing authorities for Ameren, state apportionment changes for Ameren, CIPS, Genco, CILCORP, and CILCO, research credits for Ameren, Genco, CILCORP, and CILCO and low-income housing tax credits for Ameren and CIPS.

(c)	Primarily includes low-income housing tax credits for Ameren, UE, CIPS, Genco, CILCORP, and IP.

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(d)

The 2006 difference between the reported federal income tax benefit and income tax expense calculated using the statutory rate resulted primarily from tax benefits from permanent effects of company-owned life insurance ($1 million), Internal Revenue Code Section 199 production activity deductions ($1 million), plant-related depreciation differences ($2 million), investment tax credit amortization ($1 million), adjustments to reserves for uncertain tax positions ($6 million), reconciliation of tax return to accrual ($2 million), leveraged leases ($1 million) and state tax impact of $1 million.

The following table presents the components of income tax expense (benefit) for the years ended December 31, 2008, 2007 and 2006:


	Ameren ^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
2008:
Current taxes:
Federal	$	165		$	37		$	4		$	81		$	15		$	25		$	(11	)
State		10			5			3			15			(9	)		5			(11	)
Deferred taxes:
Federal		130			86			2			5			6			9			17
State		31			11			(2	)		-			8			1			10
Deferred investment tax credits, amortization		(9	)		(5	)		(2	)		(1	)		(1	)		(1	)		-
Total income tax expense	$	327		$	134		$	5		$	100		$	19		$	39		$	5
2007:
Current taxes:
Federal	$	311		$	105		$	21		$	49		$	21		$	36		$	3
State		17			8			2			9			6			5			(2	)
Deferred taxes:
Federal		7			22			(10	)		17			1			1			11
State		4			10			(2	)		4			(6	)		(2	)		3
Deferred investment tax credits, amortization		(9	)		(5	)		(2	)		(1	)		(1	)		(1	)		-
Total income tax expense	$	330		$	140		$	9		$	78		$	21		$	39		$	15
2006:
Current taxes:
Federal	$	179		$	123		$	21		$	(6	)	$	(16	)	$	3		$	(33	)
State		33			22			7			4			(3	)		(1	)		(3	)
Deferred taxes:
Federal		80			52			(7	)		20			4			2			63
State		2			(7	)		(4	)		5			5			7			10
Deferred investment tax credits, amortization		(10	)		(6	)		(2	)		(1	)		(1	)		(1	)		-
Total income tax expense (benefit)	$	284		$	184		$	15		$	22		$	(11	)	$	10		$	37

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

The following table presents the deferred tax assets and deferred tax liabilities recorded as a result of temporary differences at December 31, 2008 and 2007:


	Ameren ^(a)			UE			CIPS			Genco			CILCORP			CILCO			IP
2008:
Accumulated deferred income taxes, net liability (asset):
Plant related	$	2,377		$	1,427		$	182		$	289		$	242		$	242		$	205
Deferred intercompany tax gain/basis step-up		4			(3	)		90			(87	)		-			-			-
Regulatory assets (liabilities), net		37			44			(4	)		-			(3	)		(3	)		-
Deferred benefit costs		(281	)		(92	)		(5	)		(32	)		(54	)		(59	)		(1	)
Purchase accounting		38			-			-			-			43			-			(33	)
Leveraged leases		6			-			-			-			-			-			-
Asset retirement obligation		(27	)		5			-			(21	)		(11	)		(11	)		-
Other		(19	)		(12	)		(10	)		2			(29	)		(13	)		(10	)
Total net accumulated deferred income tax liabilities ⁽ ^b ⁾	$	2,135		$	1,369		$	253		$	151		$	188		$	156		$	161
2007:
Accumulated deferred income taxes, net liability (asset):
Plant related	$	2,186		$	1,355		$	171		$	276		$	224		$	224		$	149
Deferred intercompany tax gain/basis step-up		4			(4	)		99			(95	)		-			-			-
Regulatory assets (liabilities), net		36			42			(2	)		-			(3	)		(3	)		-
Deferred benefit costs		(209	)		(91	)		(8	)		(11	)		(60	)		(54	)		30
Purchase accounting		33			-			-			-			45			-			(42	)
Leveraged leases		7			-			-			-			-			-			-
Asset retirement obligation		(35	)		(11	)		-			(14	)		(9	)		(9	)		-
Other		(39	)		(39	)		(10	)		12			(21	)		(10	)		(2	)
Total net accumulated deferred income tax liabilities ⁽ ^c ⁾	$	1,983		$	1,252		$	250		$	168		$	176		$	148		$	135

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

(b)

Includes $3 million, $5 million, $24 million, $15 million, and $15 million as current assets recorded in the balance sheets for UE, CIPS, CILCORP, CILCO, and IP, respectively. Includes $4 million and $15 million as current liabilities recorded in the balance sheets for Ameren and Genco, respectively.

(c)	Includes $61 million, $21 million, $8 million, $17 million, $7 million and $13 million as current assets recorded in the balance sheets for Ameren, UE, CIPS, CILCORP, CILCO, and IP, respectively. Includes $7 million as current liabilities recorded in the balance sheet for Genco.

Ameren, CILCORP and IP have Illinois net operating loss carryforwards of $15 million, $11 million, and $4 million, respectively. These will begin to expire in 2019.

On February 20, 2009, the Illinois Supreme Court handed down its decision in Exelon Corporation v. The Department of Revenue , which concluded that an electric utility in Illinois qualifies for the Illinois investment tax credit. The decision in the case may have implications for the Ameren Companies’ income, sales, and use taxes. The Ameren Companies are assessing the impact the decision may have on their results of operations, financial position or liquidity.

FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes – an Interpretation of SFAS No. 109 (FIN 48)

On January 1, 2007, the Ameren Companies adopted the provisions of FIN 48, which addresses the determination of whether tax benefits claimed or expected to be claimed on an income tax return should be recorded in the financial statements.

A reconciliation of the change in the unrecognized tax benefit balance from January 1, 2007, to December 31, 2008, is as follows:


	Ameren			UE			CIPS			Genco			CILCORP			CILCO			IP
Unrecognized tax benefits – January 1, 2007	$	155		$	58		$	15		$	36		$	18		$	18		$	12
Increases based on tax positions prior to 2007		31			4			-			10			3			3			-
Decreases based on tax positions prior to 2007		(21	)		(8	)		(3	)		(8	)		-			-			(2	)
Increases based on tax positions related to 2007		17			6			-			6			5			5			-
Changes related to settlements with taxing authorities		(60	)		(28	)		(12	)		(4	)		(7	)		(7	)		(10	)
Decreases related to the lapse of statute of limitations		(6	)		(6	)		-			-			-			-			-
Unrecognized tax benefits – December 31, 2007	$	116		$	26		$	-		$	40		$	19		$	19		$	-
Increases based on tax positions prior to 2008		16			2			-			4			2			2			-
Decreases based on tax positions prior to 2008		(46	)		(13	)		-			(9	)		(4	)		(4	)		-
Increases based on tax positions related to 2008		31			6			-			13			8			8			-
Changes related to settlements with taxing authorities		(7	)		(1	)		-			(1	)		-			-			-
Decreases related to the lapse of statute of limitations		-			-			-			-			-			-			-
Unrecognized tax benefits – December 31, 2008	$	110		$	20		$	-		$	47		$	25		$	25		$	-
Total unrecognized tax benefits (detriments) that, if recognized, would impact the effective tax rates as of December 31, 2008	$	12		$	1		$	-		$	(2	)	$	-		$	-		$	-

As of January 1, 2007, the Ameren Companies adopted a policy of recognizing interest expense (income) and penalties accrued on tax liabilities on a pretax basis as interest expense (income) or miscellaneous expense in the statements of income. Prior to January 1, 2007, the Ameren Companies recognized such items in the provision for taxes on a net-of-tax basis.

A reconciliation of the change in the liability (receivable) for interest on unrecognized tax benefits from January 1, 2007, to December 31, 2008, is as follows:


	Ameren			UE			CIPS			Genco			CILCORP		CILCO		IP
Liability (receivable) for interest – January 1, 2007	$	12		$	5		$	1		$	4		$	1	$	1	$	-
Interest expense (income) for 2007		5			-			-			3			1		1		-
Liability (receivable) for interest – December 31, 2007	$	17		$	5		$	1		$	7		$	2	$	2	$	-
Interest expense (income) for 2008		(7	)		(3	)		(1	)		(3	)		-		-		-
Liability (receivable) for interest – December 31, 2008	$	10		$	2		$	-		$	4		$	2	$	2	$	-

As of January 1, 2007, December 31, 2007, and December 31, 2008, the Ameren Companies have accrued no amount for penalties with respect to unrecognized tax benefits.

Ameren is currently under U.S. federal income tax examination by the Internal Revenue Service for years 2005, 2006, and 2007. State income tax returns are generally subject to examination for a period of three years after filing of the return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. The Ameren Companies do not now have material state income tax issues under examination, administrative appeals, or litigation.

156

It is reasonably possible that events will occur during the next 12 months that would cause the total amount of unrecognized tax benefits for the Ameren Companies to increase or decrease. However, the Ameren Companies do not believe such increases or decreases would be material to their financial condition or results of operations.

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.

Illinois Electric Settlement Agreement

As part of the Illinois electric settlement agreement, the Ameren Illinois Utilities, Genco, and AERG agreed to make aggregate contributions of $150 million over four years as part of a comprehensive program providing $1 billion of funding for rate relief to certain Illinois electric customers, including customers of the Ameren Illinois Utilities. At December 31, 2008, CIPS, CILCO and IP had receivable balances from Genco for reimbursement of customer rate relief of $1 million, less than $1 million, and $1 million, respectively. Also at December 31, 2008, CIPS, CILCO and IP had receivable balances from AERG for reimbursement of customer rate relief of less than $1 million, less than $1 million, and $1 million, respectively. During the year ended December 31, 2008, Genco incurred charges to earnings of $17 million for customer rate relief contributions and program funding reimbursements to the Ameren Illinois Utilities (CIPS – $6 million, CILCO – $3 million, IP – $8 million), and AERG incurred charges to earnings of $8 million (CIPS – $3 million, CILCO – $1 million, and IP – $4 million). The Ameren Illinois Utilities recorded most of the reimbursements received from Genco and AERG as electric revenue with an immaterial amount recorded as miscellaneous revenue.

Also as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company (for the benefit of Genco and AERG), to lock in energy prices for 400 to 1,000 megawatts annually of their round-the-clock power requirements during the period June 1, 2008, to December 31, 2012, at relevant market prices. These financial contracts do not include capacity, are not load-following products, and do not involve the physical delivery of energy. These financial contracts are derivative instruments being accounted for as cash flow hedges at the Ameren Illinois Utilities and Marketing Company. Consequently, the Ameren Illinois Utilities and Marketing Company record the fair value of the contracts on their respective balance sheets and the changes to the fair value

in regulatory assets or liabilities for the Ameren Illinois Utilities and OCI at Marketing Company. Below are the contracted volumes and prices per megawatthour.


Period	Volume	Price per Megawatthour
June 1, 2008 – December 31, 2008	400 MW	$	47.45
January 1, 2009 – May 31, 2009	400 MW		49.47
June 1, 2009 – December 31, 2009	800 MW		49.47
January 1, 2010 – May 31, 2010	800 MW		51.09
June 1, 2010 – December 31, 2010	1,000 MW		51.09
January 1, 2011 – December 31, 2011	1,000 MW		52.06
January 1, 2012 – December 31, 2012	1,000 MW		53.08

Electric Power Supply Agreements

The following table presents the amount of physical gigawatthour sales under related party electric power supply agreements for the years ended December 31, 2008, 2007, and 2006:


	December 31,
	2008	2007	2006

Genco sales to Marketing Company ^(a)	-	-	21,941
Marketing Company sales to CIPS ^(a)	-	-	12,593
Genco sales to Marketing Company ^(b)	16,551	17,425	-
AERG sales to Marketing Company ⁽ ^b ⁾	6,677	5,316	-
Marketing Company sales to CIPS ⁽ ^c ⁾	2,050	2,396	-
Marketing Company sales to CILCO ⁽ ^c ⁾	909	1,167	-
Marketing Company sales to IP ⁽ ^c ⁾	2,870	3,493	-

(a)	These agreements expired or terminated on December 31, 2006.

(b)

(c)	Marketing Company contracted with CIPS, CILCO, and IP to provide power based on the results of the Illinois reverse auction in September 2006. The values in this table reflect the physical sales volumes provided in that agreement.

In December 2006, Genco and Marketing Company entered into a new power supply agreement (Genco PSA) whereby Genco agreed to sell and Marketing Company agreed to purchase all of the capacity available from Genco’s generation fleet and all the associated energy. On March 28, 2008, Genco and Marketing Company entered into an amendment of the Genco PSA. Under the amendment, Genco is liable to Marketing Company in the event of an unplanned outage or derate (reduction in rated capacity) due to sudden, unanticipated failure or accident within the generating plant site of one or more of its generating units. Genco’s liability in such case will be for the positive difference, if any, between the market price of capacity and/or energy Genco does not deliver and the contract price under the Genco PSA for that capacity and/or energy. Genco has insurance with an affiliate company that covers many, but not all, of these situations, subject to deductibles and policy limits. An unplanned outage or derate that continues for one year or more is an event of

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default under the Genco PSA. In the event of Marketing Company’s unexcused failure to receive energy under the Genco PSA, Marketing Company would be required to pay Genco the positive difference, if any, between the contract price and the price actually received by Genco, acting in a commercially reasonable manner, to resell the unreceived energy, less any reasonable related transmission, ancillary service, or brokerage costs.

Also in December 2006, AERG and Marketing Company entered into a power supply agreement (AERG PSA) whereby AERG agreed to sell and Marketing Company agreed to purchase all of the capacity available from AERG’s generation fleet and all the associated energy. On March 28, 2008, AERG and Marketing Company entered into an amendment of the AERG PSA that is substantially identical to the amendment to the Genco PSA described above. Under the amendment, AERG is liable to Marketing Company in the event of an unplanned outage or derate due to sudden, unanticipated failure or accident within the generating plant site of one or more of its generating units. AERG’s liability in such case will be for the positive difference, if any, between the market price of capacity and/or energy AERG does not deliver and the contract price under the AERG PSA for that capacity and/or energy. AERG has insurance with an affiliate company that covers many, but not all of these situations, subject to deductibles and policy limits. An unplanned outage or derate that continues for one year or more is an event of default under the AERG PSA. In the event of Marketing Company’s unexcused failure to receive energy under the AERG PSA, Marketing Company would be required to pay AERG the positive difference, if any, between the contract price and the price actually received by AERG, acting in a commercially reasonable manner, to resell the unreceived energy, less any reasonable related transmission, ancillary service, or brokerage costs.

Both the Genco PSA and the AERG PSA will continue through December 31, 2022, and from year to year thereafter unless either party elects to terminate the agreement by providing the other party with no less than six months advance written notice.

In accordance with a January 2006 ICC order, an auction was held in September 2006 to procure power for CIPS, CILCO and IP beginning January 1, 2007. Through the auction, Marketing Company contracted with CIPS, CILCO and IP to provide power for residential and small commercial customers (less than one megawatt of demand) as follows:


	Term Ending
Term	May 31, 2008 17 Months		May 31, 2009 29 Months		May 31, 2010 41 Months
Megawatts ^(a)		300		750		750
Cost per megawatthour	$	64.77	$	64.75	$	66.05

(a)	Before impact to Ameren Illinois Utilities’ load due to customer switching.

One-third of the Ameren Illinois Utilities’ supply contracts that served the load needs of their fixed-price residential and small commercial customers, and all of the

supply contracts that served large commercial and industrial customers, expired on May 31, 2008. To replace these expired supply contracts, the Ameren Illinois Utilities used RFP processes in early 2008, pursuant to the Illinois electric settlement agreement, to contract for the necessary energy and capacity requirements for the period from June 1, 2008, through May 31, 2009. Marketing Company was one of the winning suppliers in the Ameren Illinois Utilities’ energy and capacity RFPs. Marketing Company entered into financial instruments that fixed the price that the Ameren Illinois Utilities will pay for about two million megawatthours at approximately $60 per megawatthour. Marketing Company contracted to supply a portion of the Ameren Illinois Utilities’ capacity for $6 million. In addition, UE contracted to supply a portion of the Ameren Illinois Utilities’ capacity for $1 million.

Separately, the Ameren Illinois Utilities used an RFP process to procure ancillary services for 2007 and 2008 required to maintain reliable operation of their transmission systems. Both UE and Marketing Company were among the winning suppliers in both years’ ancillary services RFPs. In January 2009, the Ameren Illinois Utilities began procuring ancillary services from the MISO ancillary services market.

On June 1, 2008, FERC accepted an electric resource sharing agreement among the Ameren Illinois Utilities for various joint costs of the Ameren Illinois Utilities, including capacity, renewable energy credits, and rate swaps. The purpose of the agreement is to allocate these costs among the Ameren Illinois Utilities in an equitable manner, based on their respective retail loads.

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 years’ notice.

Generator Interconnection Agreement

In 2008, Genco and CIPS signed an agreement requiring Genco to fund the construction costs of upgrades to CIPS’ transmission system. The transmission upgrades are required to support the additional electric power upgrades being made at Genco’s Coffeen power plant. Under the agreement, Genco will pay CIPS for the costs of the transmission upgrades. When the transmission assets are placed in service, CIPS will be required to repay Genco, with interest, for the costs of the transmission upgrades. At December 31, 2008, CIPS had recorded $2 million in Other Deferred Credits and Liabilities and Genco had recorded $2 million in Accounts Receivable – Affiliates. These transactions were eliminated in consolidation on Ameren’s financial statements.

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Joint Dispatch Agreement

Prior to December 31, 2006, UE and Genco dispatched electric generation under a joint dispatch agreement among UE, CIPS and Genco. UE and Genco had the option to serve their load requirements from their own generation first, and then each could give its affiliates access to any available generation at incremental cost. Any excess generation not used by UE or Genco to serve load requirements was sold to third parties on a short-term basis. To allocate power costs between UE and Genco, an intercompany sale was recorded by the company providing the power. By mutual consent of UE, CIPS, and Genco, the JDA was terminated on December 31, 2006.

The following table presents the amount of gigawatthour sales under the JDA during the year ended December 31, 2006:


		2006
UE sales to Genco		10,072
Genco sales to UE		3,917

The following table presents the short-term power sales margins under the JDA for UE and Genco during the year ended December 31, 2006:


	2006
UE	$	108
Genco		33
Total	$	141

Support Services Agreements

Costs of support services provided by Ameren Services, AFS, and Ameren Energy, Inc., until December 31, 2007, to their affiliates, including wages, employee benefits, professional services, and other expenses are based on, or are an allocation of, actual costs incurred. Ameren Energy, Inc. was dissolved on December 31, 2007.

Executory Tolling, Gas Sales, and Transportation Agreements

Under an executory tolling agreement, CILCO purchased steam, chilled water, and electricity from Medina Valley. In January 2009, CILCO transferred the tolling agreement to Marketing Company. In connection with the tolling agreement, Medina Valley purchases gas to fuel its generating facility from AFS under a fuel supply and services agreement.

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

Transitional Funding Securitization Financing Agreement

See Note 1 – Summary of Significant Accounting Policies for further information. In 2008, the TFNs were redeemed.

Money Pools

See Note 5 – Long-term Debt and Equity Financings for discussion of affiliate borrowing arrangements.

Intercompany Borrowings

Genco’s subordinated note payable to CIPS associated with the transfer in 2000 of CIPS’ electric generating assets and related liabilities to Genco matures on May 1, 2010. On May 1, 2005, Genco issued to CIPS an amended and restated subordinated promissory note in the principal amount of $249 million with an interest rate of 7.125% per year. Interest income and expense for this note recorded by CIPS and Genco, respectively, was $7 million, $10 million, and $12 million for the years ended December 31, 2008, 2007, and 2006, respectively.

CILCORP had outstanding borrowings directly from Ameren of $152 million and $2 million, at December 31, 2008 and 2007, respectively. The average interest rate on these borrowings was 3.6% for the year ended December 31, 2008 (2007 – 5.14%). CILCORP recorded interest expense of $1 million, less than $1 million, and $7 million for Ameren borrowings for the years ended December 31, 2008, 2007, and 2006, respectively.

UE had outstanding borrowings directly from Ameren of $92 million at December 31, 2008. The average interest rate on these borrowings was 3.6% for the year ended December 31, 2008. UE recorded interest expense of $1 million, $4 million, and $1 million for Ameren borrowings for the years ended December 31, 2008, 2007, and 2006, respectively.

At December 31, 2007, UE held a $30 million intercompany note receivable from its wholly owned subsidiary, Union Electric Development Corporation. This note was transferred to Ameren Development Company from Union Electric Development Corporation in connection with the merger discussed below under Intercompany Transfers. The note was paid off in November 2008. The average interest rate on this note while outstanding during 2008 was 5.17%. UE recorded interest revenue of $2 million for this note for the year ended December 31, 2008.

Collateral Postings

Under the terms of the power supply agreements between Marketing Company and the Ameren Illinois Utilities, which were entered into as part of the September 2006 Illinois power procurement auction, cash collateral must be posted by Marketing Company under certain market conditions to protect the Ameren Illinois Utilities in the event of nonperformance by Marketing Company. The collateral postings are unilateral, meaning that Marketing Company as the supplier is the only counterparty required to post collateral. At December 31, 2008, there were no collateral postings by Marketing Company related to the 2006 auction power supply agreements, and at December 31, 2007, Marketing Company had posted $1 million, less than $1 million, and $1 million for the benefit of CIPS, CILCO, and IP, respectively.

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In addition, under the terms of the 2008 Illinois power procurement RFPs, cash collateral must be posted by Marketing Company and the Ameren Illinois Utilities under certain market conditions. The collateral postings are bilateral, meaning that either counterparty may be required to post collateral. As of December 31, 2008, the Ameren Illinois Utilities had cash collateral postings as follows with Marketing Company: CIPS – $7 million, CILCO – $4 million, and IP – $11 million. These bilateral collateral postings were eliminated in consolidation on Ameren’s financial statements.

Operating Leases

Under an operating lease agreement, Genco leased certain CTs at a Joppa, Illinois, site to its former parent, Development Company, for an initial term of 15 years, expiring September 30, 2015. Genco recorded operating revenues from the lease agreement of $2 million, $11 million, and $11 million for the three years ended December 31, 2008, 2007, and 2006, respectively. Under an electric power supply agreement with Marketing Company, Development Company supplied the capacity and energy from these leased units to Marketing Company, which in turn supplied the energy to Genco. By mutual

agreement of the parties, this lease agreement and this power supply agreement were terminated in February 2008, when an internal reorganization merged Development Company into Resources Company.

Intercompany Transfers

On January 1, 2008, UE transferred its interest in Union Electric Development Corporation at book value to Ameren by means of a $3 million dividend-in-kind. On March 31, 2008, Union Electric Development Corporation was merged into Ameren Development Company, with Ameren Development Company surviving the merger.

On February 29, 2008, UE contributed its entire 40% ownership interest in EEI, book value of $39 million, to Resources Company, in exchange for a 50% interest in Resources Company, and then immediately transferred its interest in Resources Company to Ameren by means of a $39 million dividend-in-kind. Also on February 29, 2008, Development Company, which formerly held a 40% ownership interest in EEI, merged into Ameren Energy Resources Company, which then merged into Resources Company. As a result, Resources Company now has an 80% ownership interest in EEI and consolidates it accordingly.

The following table presents the impact on UE, CIPS, Genco, CILCORP, CILCO, and IP of related party transactions for the years ended December 31, 2008, 2007 and 2006. It is based primarily on the agreements discussed above and the money pool arrangements discussed in Note 4 – Short-term Borrowings and Liquidity.


Agreement	Income Statement Line Item		UE			CIPS			Genco			CILCORP ^(a)			IP
Genco and AERG power supply	Operating Revenues	2008	$	(b	)	$	(b	)	$	893		$	344		$	(b	)
agreements with Marketing Company		2007		(b	)		(b	)		831			279			(b	)
Ancillary services and capacity agreements	Operating Revenues	2008		13			(b	)		(b	)		(b	)		(b	)
with CIPS, CILCO and IP ^(c)		2007		18			(b	)		(b	)		(b	)		(b	)
Power supply agreement with Marketing	Operating Revenues	2006		(b	)		(b	)		793			5			(b	)
Company – expired December 31, 2006
UE and Genco gas transportation agreement	Operating Revenues	2008		1			(b	)		(b	)		(b	)		(b	)
		2007		1			(b	)		(b	)		(b	)		(b	)
		2006		1			(b	)		(b	)		(b	)		(b	)
JDA – terminated December 31, 2006	Operating Revenues	2006		196			(b	)		97			(b	)		(b	)
Genco gas sales to distribution companies	Operating Revenues	2008		(b	)		(b	)		7			(b	)		(b	)
Total Operating Revenues		2008	$	14		$	(b	)	$	900		$	344		$	(b	)
		2007		19			(b	)		831			279			(b	)
		2006		197			(b	)		890			5			(b	)
UE and Genco gas transportation agreement	Fuel	2008	$	(b	)	$	(b	)	$	1		$	(b	)	$	(b	)
		2007		(b	)		(b	)		1			(b	)		(b	)
		2006		(b	)		(b	)		1			(b	)		(b	)
CIPS, CILCO and IP agreements with	Purchased Power	2008	$	(b	)	$	145		$	(b	)	$	65		$	204
Marketing Company ^(d)		2007		(b	)		157			(b	)		76			227
Ancillary services and capacity agreements	Purchased Power	2008		(b	)		4			(b	)		2			7
with UE ^(c)		2007		(b	)		6			(b	)		3			9
Ancillary services agreement with Marketing Company	Purchased Power	2008		(b	)		6			(b	)		3			8
		2007		(b	)		3			(b	)		1			4
JDA – terminated December 31, 2006	Purchased Power	2006		97			(b	)		196			(b	)		(b	)
Power supply agreement with Marketing	Purchased Power	2006		(b	)		448			(b	)		1			(b	)
Company – expired December 31, 2006
Executory tolling agreement with Medina Valley	Purchased Power	2008		(b	)		(b	)		(b	)		39			(b	)
		2007		(b	)		(b	)		(b	)		38			(b	)
		2006		(b	)		(b	)		(b	)		39			(b	)
Total Purchased Power		2008	$	(b	)	$	155		$	(b	)	$	109		$	219
		2007		(b	)		166			(b	)		118			240
		2006		97			448			196			40			(b	)
Insurance recoveries	Operating Revenues and	2008	$	(e	)	$	(b	)	$	(11	)	$	(4	)	$	(b	)
	Purchased Power	2007		(12	)		(b	)		(2	)		(7	)		(b	)

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Agreement	Income Statement Line Item		UE			CIPS			Genco			CILCORP ^(a)			IP
Gas purchases from Genco	Gas Purchased for Resale	2008	$	(b	)	$	(e	)	$	(b	)	$	6		$	(b	)
Ameren Services support services agreement	Other Operations and	2008	$	130		$	50		$	28		$	51		$	76
	Maintenance	2007		137			47			24			49			73
		2006		136			47			23			48			71
Ameren Energy, Inc. support services agreement	Other Operations and	2008		(f	)		(b	)		(f	)		(b	)		(b	)
	Maintenance	2007		8			(b	)		(e	)		(b	)		(b	)
		2006		7			(b	)		2			(b	)		(b	)
AFS support services agreement	Other Operations and	2008		7			2			3			2			2
	Maintenance	2007		6			2			2			2			2
		2006		5			1			2			2			2
Insurance premiums ^(g)	Other Operations and	2008		8			(b	)		4			3			(b	)
	Maintenance	2007		19			(b	)		4			2			(b	)
Total Other Operations and Maintenance Expenses		2008	$	145		$	52		$	35		$	56		$	78
		2007		170			49			30			53			75
		2006		148			48			27			50			73
Money pool borrowings (advances)	Interest (Expense)	2008	$	(e	)	$	(e	)	$	(e	)	$	(e	)	$	(e	)
	Income	2007		(e	)		(e	)		8			(e	)		1
		2006		(e	)		2			10			4			2

(a)	Amounts represent CILCORP and CILCO activity.

(b)	Not applicable.

(c)	Represents ancillary services to the Ameren Illinois Utilities in 2007 and 2008 and capacity to the Ameren Illinois Utilities beginning in June 2008.

(d)	Represents power supply costs under agreements entered into as part of the Illinois September 2006 auction and the 2008 energy and capacity RFPs.

(e)	Amount less than $1 million.

(f)	Ameren Energy, Inc. was eliminated December 31, 2007, through an internal reorganization.

(g)	Represents insurance premiums paid to an affiliate for replacement power, property damage and terrorism coverage.

NOTE 15 – COMMITMENTS AND CONTINGENCIES

We are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions, and governmental 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 these notes to our financial statements, will not have a material adverse effect on our results of operations, financial position, or liquidity.

See also Note 1 – Summary of Significant Accounting Policies, Note 2 – Rate and Regulatory Matters, Note 14 – Related Party Transactions and Note 16 – Callaway Nuclear Plant in this report.

Callaway Nuclear Plant

The following table presents insurance coverage at UE’s Callaway nuclear plant at December 31, 2008. The property coverage and the nuclear liability coverage must be renewed on October 1 and January 1, respectively, of each year.


Type and Source of Coverage	Maximum Coverages		Maximum Assessments for Single Incidents
Public liability and nuclear worker liability:
American Nuclear Insurers	$ 300	^(a)	$ -
Pool participation	10,461		117.5	^(b)
	$10,761	^(c)	$ 117.5
Property damage:
Nuclear Electric Insurance Ltd.	$ 2,750	^(d)	$ 21.6
Replacement power:
Nuclear Electric Insurance Ltd	$ 490	^(e)	$ 8.5
Energy Risk Assurance Company	$ 64	^(f)	$ -

(a)	Provided through mandatory participation in an industry-wide retrospective premium assessment program.

(b)

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 $17.5 million per year.

(c)	Limit of liability for each incident under Price-Anderson. This limit is subject to change to account for the effects of inflation and changes in the number of licensed reactors.

(d)	Provides for $500 million in property damage and decontamination, excess property insurance, and premature decommissioning coverage up to $2.25 billion for losses in excess of the $500 million primary coverage.

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(e)	Provides the replacement power cost insurance in the event of a prolonged accidental outage at a nuclear plant. 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.

(f)

Provides the replacement power cost insurance in the event of a prolonged accidental outage at a nuclear plant. The coverage commences after the first 52 weeks of insurance coverage from Nuclear Electric Insurance Ltd. and is for a weekly indemnity of $900,000 for 71 weeks in excess of the $3.6 million per week set forth above. Energy Risk Assurance Company is an affiliate and has reinsured this coverage with third-party insurance companies. See Note 14 – Related Party Transactions for more information on this affiliate transaction.

The Price-Anderson Act is a federal law that limits the liability for claims from an incident involving any licensed United States commercial nuclear power facility. The limit is based on the number of licensed reactors. The limit of liability and the maximum potential annual payments are adjusted at least every five years for inflation to reflect changes in the Consumer Price Index. The five-year inflationary adjustment as prescribed by the most recent Price-Anderson Act renewal was effective October 29, 2008. Owners of 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.

After the terrorist attacks on September 11, 2001, Nuclear Electric Insurance Ltd. confirmed that losses resulting from terrorist attacks would be covered under its policies. However, Nuclear Electric Insurance Ltd. imposed an industry-wide aggregate policy limit of $3.24 billion within a 12-month period for coverage for such terrorist acts.

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 is at risk for any uninsured losses. If a serious nuclear incident were to occur, it could have a material adverse effect on Ameren’s and UE’s results of operations, financial position, or liquidity.

Leases

The following table presents our lease obligations at December 31, 2008:


	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		After 5 Years
Ameren: ^(a)
Capital lease payments ^(b)	$	717	$	32	$	65	$	65	$	555
Less amount representing interest		395		28		56		55		256
Present value of minimum capital lease payments		322		4		9		10		299
Operating leases ^(c)		392		39		66		54		233
Total lease obligations	$	714	$	43	$	75	$	64	$	532
UE:
Capital lease payments ^(b)	$	717	$	32	$	65	$	65	$	555
Less amount representing interest		395		28		56		55		256
Present value of minimum capital lease payments		322		4		9		10		299
Operating leases ^(c)		174		15		28		25		106
Total lease obligations	$	496	$	19	$	37	$	35	$	405
CIPS:
Operating leases ^(c)	$	2	$	-	$	1	$	1	$	-
Genco:
Operating leases ^(c)	$	143	$	9	$	17	$	17	$	100
CILCORP and CILCO:
Operating leases ^(c)	$	18	$	1	$	3	$	2	$	12
IP:
Operating leases ^(c)	$	8	$	3	$	4	$	1	$	-

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

(b)	See Properties under Part I, Item 2 of this report for further information.

(c)

Amounts related to certain real estate leases and railroad licenses have indefinite payment periods. Ameren’s $2 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.

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We lease various facilities, office equipment, plant equipment, and rail cars under operating leases. We also have capital leases relating to UE’s Peno Creek and Audrain County CT facilities. The following table presents total rental expense, included in other operations and maintenance expenses, for the years ended December 31, 2008, 2007 and 2006:


	2008		2007		2006
Ameren ^(a)	$	19	$	15	$	15
UE		20		19		20
CIPS		9		9		9
Genco		2		2		2
CILCORP and CILCO		7		7		6
IP		13		12		11

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

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. We also have entered into various long-term commitments for the purchase of electricity and natural gas for distribution. The following table presents the estimated fuel, electric capacity, and natural gas commitments at December 31, 2008. In addition, the following table presents in the Other column minimum purchase commitments for heavy forgings contracts related to a potential second nuclear unit, meter reading contracts, and an Ameren tax credit obligation. Ameren’s tax credit obligation is a $75 million note payable issued for an investment in a low-income real estate development partnership to acquire New Markets Tax Credits. This note payable was netted against the related investment in Other Assets at December 31, 2008, as Ameren has a legally enforceable right to offset it under FIN 39.


	Coal		Gas		Nuclear		Electric Capacity			Other		Total
Ameren: ^(a)
2009	$	728	$	486	$	68	$	14		$	63	$	1,359
2010		841		399		75		-			89		1,404
2011		652		268		53		-			79		1,052
2012		440		176		67		-			79		762
2013		31		82		59		-			40		212
Thereafter ^(b)		-		173		173		-			292		638
Total	$	2,692	$	1,584	$	495	$	14		$	642	$	5,427
UE:
2009	$	393	$	80	$	68	$	14		$	31	$	586
2010		429		67		75		-			57		628
2011		313		47		53		-			46		459
2012		136		32		67		-			46		281
2013		-		23		59		-			24		106
Thereafter ^(b)		-		38		173		-			168		379
Total	$	1,271	$	287	$	495	$	14		$	372	$	2,439
CIPS:
2009	$	-	$	106	$	-	$	(c	)	$	4	$	110
2010		-		71		-		-			2		73
2011		-		60		-		-			2		62
2012		-		44		-		-			2		46
2013		-		30		-		-			2		32
Thereafter ^(b)		-		28		-		-			18		46
Total	$	-	$	339	$	-	$	-		$	30	$	369
Genco:
2009	$	134	$	10	$	-	$	-		$	-	$	144
2010		185		8		-		-			-		193
2011		129		8		-		-			-		137
2012		112		5		-		-			-		117
2013		-		3		-		-			-		3
Thereafter ^(b)		-		8		-		-			-		8
Total	$	560	$	42	$	-	$	-		$	-	$	602

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	Coal		Gas		Nuclear		Electric Capacity			Other		Total
CILCORP and CILCO:
2009	$	62	$	113	$	-	$	(c	)	$	3	$	178
2010		84		93		-		-			3		180
2011		85		64		-		-			3		152
2012		79		40		-		-			3		122
2013		31		15		-		-			3		49
Thereafter ^(b)		-		91		-		-			25		116
Total	$	341	$	416	$	-	$	-		$	40	$	797
IP:
2009	$	-	$	162	$	-	$	(c	)	$	11	$	173
2010		-		158		-		-			10		168
2011		-		88		-		-			11		99
2012		-		54		-		-			11		65
2013		-		11		-		-			11		22
Thereafter ^(b)		-		8		-		-			81		89
Total	$	-	$	481	$	-	$	-		$	135	$	616

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

(b)	Commitments for natural gas and nuclear fuel are until 2021 and 2020, respectively.

(c)

At December 31, 2008, less than $1 million of electric capacity contracts were executed for the Ameren Illinois Utilities for 2009 with approximately 33% of the capacity resources dedicated to CIPS, 17% to CILCO, and 50% to IP. For 2009, approximately one-third of the Ameren Illinois Utilities capacity was obtained through the Illinois power procurement auction. The IPA plans to go forward with RFPs to purchase capacity for the Ameren Illinois Utilities during the first half of 2009. See below for additional information.

Ameren Illinois Utilities’ Purchased Power Agreements

Commencing January 1, 2007, CIPS, CILCO and IP were required to obtain all electric supply requirements for customers who do not purchase electric supply from third-party suppliers. The power procurement costs incurred by CIPS, CILCO and IP are passed directly to their customers. CIPS, CILCO and IP entered into power supply contracts with the winning bidders, including their affiliate, Marketing Company, in the Illinois reverse power procurement auction held in September 2006. Under these contracts, the electric suppliers are responsible for providing to CIPS, CILCO and IP energy, capacity, certain transmission, volumetric risk management, and other services necessary for the Ameren Illinois Utilities to serve the electric load needs of residential and small commercial customers (with less than one megawatt of demand) at an all-inclusive fixed price. These contracts commenced on January 1, 2007, with one-third of the supply contracts expiring in each of May 2008, 2009 and 2010.

One-third of the Ameren Illinois Utilities’ supply contracts that served the load needs of their fixed-price residential and small commercial customers, and all of the supply contracts that served large commercial and industrial customers, expired on May 31, 2008. The Ameren Illinois Utilities used RFP processes in early 2008 to replace these expired supply contracts, pursuant to the Illinois electric settlement agreement. Specifically, the Ameren Illinois Utilities used RFPs to procure energy swaps, capacity, and renewable energy credits for the period June 1, 2008, through May 31, 2009. The Ameren Illinois Utilities contracted to purchase approximately two million megawatthours of energy swaps at an average price of $60 per megawatthour. As a result of a capacity RFP, the Ameren Illinois Utilities contracted to purchase about 1,800 megawatts of capacity at an average price of $50 per MW-day. A renewable energy credits RFP resulted in the Ameren Illinois Utilities contracting to purchase 415,000 credits at an average price of $17 per credit.

Existing supply contracts from the September 2006 auction remain in place. Through the Illinois procurement auction held in September 2006, CIPS, CILCO and IP contracted for their anticipated fixed-price loads for residential and small commercial customers (less than one megawatt of demand) as follows:


	Term Ending
Term	May 31, 2009 29 Months		May 31, 2010 41 Months
CIPS’ load in megawatts ^(a)		639		639
CILCO’s load in megawatts ^(a)		328		328
IP’s load in megawatts ^(a)		928		928
Total load in megawatts ^(a)		1,895		1,895
Cost per megawatthour	$	64.75	$	66.05

(a)	Represents peak forecast load for CIPS, CILCO and IP. Actual load could be different if customers elect not to purchase power pursuant to the power procurement auction but instead to receive power from a different supplier. Load could also be affected by weather, among other things.

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Illinois Electric Settlement Agreement

The Illinois electric settlement agreement provides $1 billion of funding over a four-year period beginning in 2007 for rate relief for certain electric customers in Illinois. Funding for the settlement will come from electric generators in Illinois and certain Illinois electric utilities. The Ameren Illinois Utilities, Genco, and AERG agreed to fund an aggregate of $150 million, of which the following contributions remain to be made at December 31, 2008:


	Ameren		CIPS		CILCO (Illinois Regulated)		IP		Genco		CILCO (AERG)
2009 ^(a)	$	26.6	$	3.9	$	1.9	$	5.1	$	10.8	$	4.9
2010 ^(a)		1.9		0.3		0.1		0.4		0.8		0.3
Total	$	28.5	$	4.2	$	2.0	$	5.5	$	11.6	$	5.2

(a)	Estimated.

Also as part of the Illinois electric settlement agreement, the Ameren Illinois Utilities entered into financial contracts with Marketing Company to lock in energy prices for 400 to 1,000 megawatts annually of their round-the-clock power requirements from 2008 to 2012. See Note 14 – Related Party Transactions for additional information.

Environmental Matters

We are subject to various environmental laws and regulations enforced 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, natural gas storage plants, and natural gas transmission and distribution facilities, our activities involve compliance with diverse laws and regulations. These laws and regulations address noise, emissions, 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 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. The more significant matters are discussed below.

Clean Air Act

Both federal and state laws require significant reductions in SO ₂ and NO _x emissions that result from burning fossil fuels. In May 2005, the EPA issued regulations with respect to SO ₂ and NO _x emissions (the Clean Air Interstate Rule) and mercury emissions (the Clean Air Mercury Rule). The federal Clean Air Interstate Rule requires generating facilities in 28 eastern states, including Missouri and Illinois where our generating facilities are

located, and the District of Columbia to participate in cap-and-trade programs to reduce annual SO ₂ emissions, annual NO _x emissions, and ozone season NO _x emissions. The cap-and-trade program for both annual and ozone season NO _x emissions went into effect on January 1, 2009. The SO ₂ emissions cap-and-trade program is scheduled to take effect in 2010.

In February 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Mercury Rule. The court ruled that the EPA erred in the method it used to remove electric generating units from the list of sources subject to the maximum available control technology requirements under the Clean Air Act. The EPA and a group representing the electric utility industry filed petitions for rehearing; however, the court denied those petitions in May 2008. A group representing the electric utility industry and the EPA both filed petitions for review of the U.S. Court of Appeals decision with the U.S. Supreme Court in September 2008 and October 2008, respectively. In February 2009, the EPA withdrew its petition to the U.S. Supreme Court. In February 2009, the U.S. Supreme Court denied the petition for review filed by a group representing the electric utility industry. The impact of this decision is that the EPA will move forward with a MACT standard for mercury emissions. The standard is expected to be available in draft form by mid to late 2009, and compliance is expected to be required in the 2013 to 2015 timeframe.

We are currently evaluating the impact that the court decision will have on our environmental compliance strategy. We are unable to predict the outcome of this legal proceeding, the actions the EPA or U.S. Congress may take in response to the court decision, or the timing of such actions. We also cannot predict at this time the ultimate impact the court decision and resulting regulatory actions will have on our estimated capital costs for compliance with environmental rules.

In July 2008, the U.S. Court of Appeals for the District of Columbia issued a decision that vacated the federal Clean Air Interstate Rule. The court ruled that the regulation contained several fatal flaws, including a regional cap-and-trade program that cannot be used to facilitate the attainment of ambient air quality standards for ozone and fine particulate matter. In September 2008, the EPA, as well as several environmental groups, a group representing the electric utility industry, and the National Mining Association, all filed petitions for rehearing with the U.S. Court of Appeals. In December 2008, the U.S. Court of Appeals essentially reversed its July 2008 decision to vacate the federal Clean Air Interstate Rule. The U.S. Court of Appeals granted the EPA petition for reconsideration and remanded the rule to the EPA for further action to remedy the rule’s flaws in accordance with the U.S. Court of Appeals’ July 2008 opinion in the case. The impact of the decision is that the existing Illinois and Missouri rules to implement the federal Clean Air Interstate Rule will remain in effect until the federal Clean Air Interstate Rule is revised by the EPA at which point the Illinois and Missouri rules may be subject to change.

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The state of Missouri has adopted state rules to implement the federal Clean Air Interstate Rule for regulating SO ₂ and NO _x emissions from electric generating units. The rules are a significant part of Missouri’s plan to attain existing ambient standards for ozone and fine particulates, as well as meeting the federal Clean Air Visibility Rule. The rules are expected to reduce NO _x emissions 30% and SO ₂ emissions 75% by 2015. As a result of the Missouri rules, UE will manage allowances and install pollution control equipment. Missouri also adopted state rules to implement the federal Clean Air Mercury Rule. However, those state rules are not enforceable as a result of the U.S. Court of Appeals decision to vacate the federal Clean Air Mercury Rule.

We do not believe that the court decision that vacated the federal Clean Air Mercury Rule will significantly affect pollution control obligations in Illinois. Under the MPS, Illinois generators may defer until 2015 the requirement to reduce mercury emissions by 90%, in exchange for accelerated installation of NO _x and SO ₂ controls. To comply with the rule, Genco, CILCO (AERG) and EEI have begun putting into service equipment designed to reduce mercury emissions. This rule, when fully implemented, is expected to reduce mercury emissions 90%, NO _x emissions 50%, and SO ₂ emissions 70% by 2015 in Illinois. As a result of the Illinois rules, Genco, AERG and EEI will need to procure allowances and install pollution control equipment. Current plans include installing scrubbers for SO ₂ reduction as well as optimizing operations of selective catalytic reduction (SCR) systems for NO _x reduction at certain coal-fired plants in Illinois.

In October 2008, Genco, CILCO (AERG) and EEI submitted a request for a variance from the MPS to the Illinois Pollution Control Board. In preparing this request, Genco, CILCO (AERG) and EEI worked with the Illinois EPA and agreed to the installation of more stringent SO ₂ and NO _x controls at various stages between 2010 and 2020 in order to make the variance proposal “environmentally neutral.” In January 2009, the Illinois Pollution Control Board denied the variance request on procedural grounds. Genco, CILCO (AERG) and EEI filed a motion for reconsideration in February 2009. With the Illinois EPA’s concurrence, they now seek to amend the MPS within a pending rulemaking pertaining to technical amendments of the underlying mercury regulations. Revisions to the MPS within that rulemaking will require Illinois Pollution Control Board approval. If approved, this variance or rule amendment would allow Genco to defer approximately $375 million of environmental capital expenditures from the 2009-2012 timeframe to the 2013-2015 timeframe. This amount is reduced from the $500 million disclosed in Genco’s Quarterly Report on Form 10-Q for the period ended September 30, 2008, because of revisions to the size and timing of projected environmental capital expenditures if no variance is granted. A decision is expected in 2009.

In March 2008, the EPA finalized regulations that will lower the ambient standard for ozone. States must submit their nonattainment plans in March 2009. A final action by

the EPA to designate areas as nonattainment is expected in March 2010. State implementation plans will need to be submitted in 2013 unless Illinois and Missouri seek extensions for various requirement dates. Additional emission reductions may be required as a result of the future state implementation plans. At this time, we are unable to determine the impact such state actions would have on our results of operations, financial position, or liquidity.

The table below presents estimated capital costs that are based on current technology, to comply with the federal Clean Air Interstate Rule and related state implementation plans through 2018, as well as federal ambient air quality standards including ozone and fine particulates, and the federal Clean Air Visibility rule. The estimates described below could change depending upon additional federal or state requirements, the requirements under a mercury MACT standard, whether the variance or rule amendment request with respect to the Illinois MPS discussed above is granted, new technology, variations in costs of material or labor, or alternative compliance strategies, among other reasons. The timing of estimated capital costs may also be influenced by whether emission allowances are used to comply with any future rules, thereby deferring capital investment.


	2009		2010 - 2013				2014 - 2018				Total
UE ^(a)	$	100	$	525-	$	655	$	1,530-	$	1,885	$	2,155-	$	2,640
Genco		230		875-		1,085		95-		125		1,200-		1,440
CILCO		55		365-		455		60-		80		480-		590
EEI		15		120-		155		530-		660		665-		830
Ameren	$	400	$	1,885-	$	2,350	$	2,215-	$	2,750	$	4,500-	$	5,500

(a)	UE’s expenditures are expected to be recoverable in rates over time.

Emission Allowances

Both federal and state laws require significant reductions in SO ₂ and NO _x emissions that result from burning fossil fuels. The Clean Air Act created marketable commodities called allowances under the Acid Rain Program, the NO _x Budget Trading Program, and the federal Clean Air Interstate Rule. All existing generating facilities have been allocated allowances based on past production and the statutory emission reduction goals. NO _x allowances allocated under the NO _x Budget Trading Program can be used for the seasonal NO _x program under the federal Clean Air Interstate Rule. If additional allowances are needed for new generating facilities, they can be purchased from facilities that have excess allowances or from allowance banks. In addition, the Illinois rules to implement the federal Clean Air Interstate Rule include an allowance set aside for new generating facilities. Our generating facilities comply with the SO ₂ limits through the use and purchase of allowances, through the use of low-sulfur fuels, and through the application of pollution control technology. 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.

See Note 1 – Summary of Significant Accounting Policies for the SO ₂ and NO _x emission allowances held and the related SO ₂ and NO _x emission allowance book values that were carried as intangible assets as of December 31, 2008.

UE, Genco, CILCO and EEI expect to use a substantial portion of the SO ₂ and NO _x allowances for ongoing operations. 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 number of allowances actually required for ongoing operations. The Clean Air Interstate Rule requires a reduction in SO ₂ emissions by increasing the ratio of Acid Rain Program allowances surrendered. The current Acid Rain Program requires the surrender of one SO ₂ allowance for every ton of SO ₂ that is emitted. Unless revised by the EPA as a result of the U.S. Court of Appeals remand, the Clean Air Interstate Rule program will require that SO ₂ allowances of vintages 2010 through 2014 be surrendered at a ratio of two allowances for every ton of emission. SO ₂ allowances with vintages of 2015 and beyond will be required to be surrendered at a ratio of 2.86 allowances for every ton of emission. In order to accommodate this change in surrender ratio and to comply with the federal and state regulations, UE, Genco, AERG, and EEI expect to install control technology designed to further reduce SO ₂ emissions, as discussed above.

The Clean Air Interstate Rule has both an ozone season program and an annual program for regulating NO _x emissions, with separate allowances issued for each program. The Clean Air Interstate Rule ozone season program replaced the NO _x Budget Trading Program beginning in 2009. Both sets of allowances for the years 2009 through 2014 were issued by the Missouri Department of Natural Resources in December 2007. Allocations for UE’s Missouri generating facilities were 11,665 tons per ozone season and 26,842 tons annually. Allocations for Genco’s generating facility in Missouri were one ton for the ozone season and three tons annually. Both sets of allowances for the years 2009 through 2011 were issued by the Illinois EPA in April 2008. Allocations for UE’s, Genco’s, AERG’s, and EEI’s Illinois generating facilities were 90, 3,442, 1,368, and 1,758 tons per ozone season, respectively, and 93, 8,300, 3,418, and 4,564 tons annually.

Global Climate

establishing an economy-wide cap-and-trade program. The overarching goal of such legislation is to reduce greenhouse gas emissions to a level that is 6% below 2005 levels by 2020 and 80% below 2005 levels by the year 2050. In addition, new leadership in the Energy and Commerce Committee is considering aggressive climate legislation.

President Obama supports an economy-wide cap-and- trade greenhouse gas reduction program that would reduce emissions to 1990 levels by 2020 and to 80% below 1990 levels by 2050. President Obama has also indicated support for auctioning 100% of the emission allowances to be distributed under the legislation. Although we cannot predict the date of enactment or the requirements of any global warming legislation, it is likely that some form of federal greenhouse gas legislation will become law during President Obama’s administration.

Potential impacts from proposed legislation could vary, depending upon proposed CO ₂ emission limits, the timing of implementation of those limits, the method of allocating allowances, and provisions for cost containment measures, such as a “safety valve” that provides a ceiling price for emission allowance purchases. As a result of our diverse fuel portfolio, our contribution to greenhouse gases varies among our generating facilities, but coal-fired power plants are significant sources of CO ₂ , a principal greenhouse gas. Ameren’s current analysis shows that under some policy scenarios being considered in the U.S. Congress, household costs and rates for electricity could rise significantly. The burden could fall particularly hard on electricity consumers and the Midwest economy because of the region’s reliance on electricity generated by coal-fired power plants. Natural gas emits about half the amount of CO ₂ that coal emits when burned to produce electricity. As a result, economy-wide shifts favoring natural gas as a fuel source for electric generation also could affect the cost of heating for our utility customers and many industrial processes. Under some policy scenarios being considered by Congress, Ameren believes that wholesale natural gas costs could rise significantly as well. Higher costs for energy could contribute to reduced demand for electricity and natural gas.

Future initiatives regarding greenhouse gas emissions and global warming may also be subject to the activities pursuant to the Midwest Greenhouse Gas Reduction Accord an agreement signed by the governors of Illinois, Iowa, Kansas, Michigan, Wisconsin and Minnesota to develop a strategy to achieve energy security and to reduce greenhouse gas emissions through a cap-and-trade mechanism. It is expected that the advisory group to the Midwest governors will provide recommendations on the design of a greenhouse gas reduction program by the third quarter of 2009. However, it is uncertain whether legislation to implement the recommendations will be implemented or passed by any of the states, including Illinois.

With regard to greenhouse gas regulation under existing law, in April 2007, the U.S. Supreme Court issued a decision that the EPA has the authority to regulate CO ₂ and

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other greenhouse gases from automobiles as “air pollutants” under the Clean Air Act. This decision was a result of a Bush Administration ruling denying a waiver request by the state of California to implement such regulations. The Supreme Court sent the case back to the EPA, which must conduct a rulemaking process to determine whether greenhouse gas emissions contribute to climate change “which may reasonably be anticipated to endanger public health or welfare.” In July 2008, the EPA issued an advance notice of public rulemaking (ANPR) in response to the U.S. Supreme Court’s directive. The ANPR solicited public comments on the benefits and ramifications of regulating greenhouse gases under the Clean Air Act, and that rulemaking has not been completed. On February 12, 2009, the EPA announced its intent to reconsider the decision under the Bush Administration denying the waiver to the state of California for regulating CO ₂ emissions from automobiles. On February 17, 2009, the EPA also granted a petition for reconsideration filed by the Sierra Club to reexamine a December 2008 Bush Administration ruling that CO ₂ should not be regulated under the Clean Air Act when issuing construction permits for power plants. These EPA actions will factor into the rulemaking process on the ANPR and could ultimately lead to regulation of CO ₂ from power plants.

Future federal and state legislation or regulations that mandate limits on the emission of greenhouse gases would result in significant increases in capital expenditures and operating costs, which in turn could lead to increased liquidity needs and higher financing costs. Excessive costs to comply with future legislation or regulations might force UE, Genco, CILCO (through AERG) and EEI as well as other similarly situated electric power generators to close some coal-fired facilities. As a result, mandatory limits could have a material adverse impact on Ameren’s, UE’s, Genco’s, AERG’s and EEI’s results of operations, financial position, or liquidity.

Ameren has taken actions to address the global climate issue. These include:

seeking partners to develop wind energy for our generation portfolio;

participating in DOE-sponsored research into the feasibility of sequestering CO ₂ underground in the Illinois basin, the Plains sequestration partnership, and a Missouri sequestration project to be conducted in Southwest Missouri;

increasing the operating efficiency and capacity of our nuclear and hydroelectric plants to provide more energy to offset fossil generation;

participating in the PowerTree Carbon Company, LLC, whose purpose is to reforest acreage in the lower Mississippi valley to sequester carbon;

using coal combustion byproducts as a direct replacement for cement, thereby reducing carbon emissions at cement kilns;

participating in a DOE and state of Missouri Department of Natural Resources project evaluating Missouri wind resources for the next generation of wind turbines;

funding a project investigating opportunities to reduce nitrous oxide (N ₂ O), a potent greenhouse gas from agricultural usage, and tracking those reductions;

participating in the Illinois Clean Energy Community Foundation, a program that supports energy efficiency, promotes renewable energy, and provides educational opportunities;

establishing Pure Power, UE’s voluntary renewable energy program that allows UE’s electric customers to support development of wind farms and other renewable energy facilities in the Midwest;

purchasing Renewable Energy Credits, as when the Ameren Illinois Utilities purchased 415,000 renewable energy credits in April 2008; and

participating in funding the new Consortium for Clean Coal Utilization research center at Washington University, which will investigate clean coal technologies, such as oxy-fuel combustion and CO ₂ capture and storage.

The impact on us of future initiatives related to greenhouse gas emissions and global warming is unknown. Although compliance costs are unlikely in the near future, our costs of complying with any mandated federal or state 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 on aquatic species. These rules pertain to all 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. In January 2007, the U.S. Court of Appeals for the Second Circuit remanded many provisions of these rules to the EPA for revision. In April 2008, the U.S. Supreme Court agreed to hear an appeal of the lower court ruling. The U.S. Supreme Court heard the case in December 2008. The EPA is expected to reissue the rules early in 2009. Until a decision is issued by the Supreme Court and the new rules are adopted, and the studies on the power plants are completed, we are unable to estimate the costs of complying with these rules. Such costs are not expected to be incurred prior to 2012.

New Source Review

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 (NSR) 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 performed.

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In April 2005, Genco received a request from the EPA for information pursuant to Section 114(a) of the Clean Air Act. It sought detailed operating and maintenance history data with respect to Genco’s Coffeen, Hutsonville, Meredosia and Newton facilities, EEI’s Joppa facility, and AERG’s E.D. Edwards and Duck Creek facilities. In December 2006, the EPA issued a second Section 114(a) request to Genco regarding projects at the Newton facility. All of these facilities are coal-fired power plants. In September 2008, the EPA issued a third Section 114(a) request regarding projects at all of Ameren’s Illinois coal-fired power plants. We are in the process of responding to this request. We are also currently in discussions with the EPA and the state of Illinois regarding resolution of these matters, but we are unable to predict the outcome of these discussions.

In March 2008, Ameren 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 UE’s Labadie, Meramec, Rush Island, and Sioux facilities. All of these facilities are coal-fired power plants. The information request required UE to provide responses to specific EPA questions regarding certain projects and maintenance activities in order to determine UE’s compliance with state and federal regulatory requirements. UE is complying with this information request, but we are unable to predict the outcome of this matter.

Resolution of these matters could have a material adverse impact on the future results of operations, financial position, or liquidity of Ameren, UE, Genco, AERG and EEI. A resolution could result in increased capital expenditures for the installation of control technology, increased operations and maintenance expenses, and fines or penalties.

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 their degree of fault, the legality of original disposal, or the 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 (PRP) at several contaminated sites. Several of these sites involve facilities that were transferred by CIPS to Genco in May 2000 and facilities transferred by CILCO to AERG in October 2003. As part of each transfer, CIPS and CILCO have contractually agreed to indemnify Genco and AERG for remediation costs associated with preexisting environmental contamination at the transferred sites.

As of December 31, 2008, CIPS, CILCO and IP owned or were otherwise responsible for several former MGP sites in Illinois. CIPS has 14, CILCO 4, and IP 25. All of these sites are in various stages of investigation, evaluation and remediation. Under its current schedule, Ameren anticipates that remediation at these sites should be completed by 2015. The ICC permits each company to recover remediation and litigation costs associated with its former

MGP sites from its 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, 2008, estimated obligations were: CIPS – $17 million to $29 million, CILCO – $8 million to $13 million, IP –$74 million to $143 million. CIPS, CILCO and IP recorded liabilities of $17 million, $8 million, and $74 million, respectively, to represent estimated minimum obligations, as no other amount within the range was a better estimate.

CIPS is also responsible for the cleanup of a former landfill in Coffeen, Illinois. As of December 31, 2008, CIPS estimated its obligation at $0.5 million to $6 million. CIPS recorded a liability of $0.5 million to represent its estimated minimum obligation for this site, as no other amount within the range was a better estimate. IP is also responsible for the cleanup of a landfill, underground storage tanks, and a water treatment plant in Illinois. As of December 31, 2008, IP recorded a liability of $1 million to represent its best estimate of the obligation for these sites.

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 2 – Rate and Regulatory Matters for information on a Missouri law enabling the MoPSC to put in place environmental cost recovery mechanisms for Missouri utilities. UE does not have any retail utility operations in Iowa that would provide a source of recovery of these remediation costs. As of December 31, 2008, UE estimated its obligation at $3 million to $4 million. UE recorded a liability of $3 million to represent its estimated minimum obligation for its MGP sites, as no other amount within the range was a better estimate. UE also is responsible for four electric sites in Missouri that have corporate cleanup liability, most as a result of federal agency mandates.

In June 2000, the EPA notified UE and numerous other companies, including Solutia, that former landfills and lagoons in Sauget, Illinois, may contain soil and groundwater contamination. These sites are known as Sauget Area 2. From about 1926 until 1976, UE operated a power generating facility adjacent to Sauget Area 2. UE currently owns a parcel of property that was once used as a landfill. Under the terms of an Administrative Order and Consent, UE has joined with other PRPs to evaluate the extent of potential contamination with respect to Sauget Area 2.

Sauget Area 2 investigations overseen by the EPA are largely completed, and the results will be submitted to the EPA in June 2009. Following this submission, the EPA will ultimately select a remedy alternative and begin negotiations with various PRPs to implement it. Over the last several years, numerous other parties have joined the PRP group and presumably will participate in the funding of any required remediation. In addition, Pharmacia Corporation and Monsanto Company have agreed to assume the liabilities related to Solutia’s former chemical

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waste landfill in the Sauget Area 2, notwithstanding Solutia’s filing for bankruptcy protection. As of December 31, 2008, UE estimated its obligation at $1 million to $10 million. UE recorded a liability of $1 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

In March 2008, the EPA issued an administrative order requesting that CIPS participate in a portion of an environmental cleanup of a site within Sauget Area 2 previously occupied by Clayton Chemical Company. CIPS was formerly a customer of Clayton Chemical Company, which before its dissolution was a recycler of waste solvents and oil. Other former customers of Clayton Chemical Company were issued similar orders by the EPA. Pursuant to that order, CIPS and three other PRPs agreed to install an engineered barrier on portions of the Clayton Chemical Company site. This work is expected to be concluded in the first quarter of 2009. As of December 31, 2008, CIPS recorded a liability of $0.25 million to represent its best estimate of its obligation for this site.

In July 2008, the EPA issued an administrative order to UE pertaining to a former coal tar distillery operated by Koppers Company or its predecessor and successor companies. UE is the current owner of the site but did not conduct any of the manufacturing operations involving coal tar or its byproducts. UE is currently in negotiations with other PRPs concerning the scope of future site investigations. As of December 31, 2008, UE estimated its obligation at $2 million to $5 million. UE recorded a liability of $2 million to represent its estimated minimum obligation, as no other amount within the range was a better estimate.

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 $1.9 million at December 31, 2008, 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 of, 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.

Ash Ponds

In December 2008, an ash pond dike failed at a non-Ameren owned utility company releasing approximately one billion gallons of coal ash slurry. The ash was deposited primarily over 300 acres, destroying three homes. As a result of this incident, there has been increased activity at both the state and federal level to examine the need for

additional regulation of utility ash pond facilities and coal-combustion wastes. It is anticipated that some form of additional regulation concerning the integrity of ash ponds and the handling and disposal of coal combustion waste may be forthcoming within the next two years. At this time, we are unable to predict the outcome any such regulations might have on our results of operations, financial position, or liquidity.

Polychlorinated Biphenyls Information Request

Polychlorinated biphenyls (PCBs) are a blend of chemical compounds that were historically used in a variety of industrial products because of their chemical and thermal stability. In natural gas systems, PCBs were used as a compressor lubricant and a valve sealant before their sale for these applications was banned by the EPA in 1979. During the third quarter of 2007, the Ameren Illinois Utilities received requests from the Illinois attorney general and from the EPA for information regarding their experiences with PCBs in their gas distribution systems. The Ameren Illinois Utilities responded to these information requests.

The Ameren Illinois Utilities have evaluated their gas distribution systems for the presence of PCBs. They believe that the presence of PCBs is limited to discrete areas and is not widespread throughout their service territories. We cannot predict whether any further actions will be required on the part of the Ameren Illinois Utilities regarding this matter or what the ultimate outcome will be.

Pumped-storage Hydroelectric Facility Breach

UE has settled with FERC and the state of Missouri all issues associated with the December 2005 Taum Sauk incident. In addition, UE received approval from FERC to rebuild the upper reservoir at its Taum Sauk plant and has begun rebuilding the facility. The estimated cost to rebuild the upper reservoir is in the range of $480 million. UE expects the Taum Sauk plant to be out of service through early 2010.

In December 2006, 11 business owners filed a lawsuit regarding the Taum Sauk breach. The suit, which was filed in the Missouri Circuit Court of Reynolds County and remains pending, contains allegations of negligence, violations of the Missouri Clean Water Act, and various other statutory and common law claims. It seeks damages relating to business losses, lost profit, and unspecified punitive damages. UE has filed a motion to dismiss the lawsuit, arguing that Missouri law does not permit the plaintiffs to recover purely economic

losses under theories of negligence and strict liability. This motion is currently pending.

In December 2008, the Department of the Army, Corps of Engineers filed a lawsuit regarding the Taum Sauk breach. The suit, which was filed in the U.S. District Court in Cape Girardeau, Missouri, and remains pending, claims that Clearwater Lake in southeast Missouri was damaged by

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sediment from the Taum Sauk breach. This litigation is in its early stages, and we are evaluating the merits of the allegations. We are unable to predict the timing or outcome of this litigation, or its possible effect on UE’s results of operations, financial position, or liquidity.

At this time, UE believes that substantially all damages and liabilities caused by the breach, including costs related to the settlement agreement with the state of Missouri, the cost of rebuilding the plant, and the cost of replacement power, up to $8 million annually, will be covered by insurance. Insurance will not cover lost electric margins and penalties paid to FERC. UE expects that the total cost for cleanup, damage and liabilities, excluding costs to rebuild the reservoir, will range from $200 million to $220 million. As of December 31, 2008, UE had paid $181 million, including costs resulting from the FERC-approved stipulation and consent agreement. UE accrued a $18 million liability while expensing $33 million and recording a $166 million receivable due from insurance companies. As of December 31, 2008, UE had received $85 million from insurance companies, which reduced the insurance receivable balance to $81 million.

As of December 31, 2008, UE had recorded a $332 million receivable due from insurance companies related to the rebuilding of the facility and the reimbursement of replacement power costs. As of December 31, 2008, UE had received $158 million from insurance companies, which reduced the insurance receivable balance as of December 31, 2008, to $174 million.

Under UE’s insurance policies, all claims by or against UE are subject to review by its insurance carriers.

Until litigation has been resolved and the insurance review is completed, among other things, we are unable to determine the total impact the breach may have on Ameren’s and UE’s results of operations, financial position, or liquidity beyond those amounts already recognized.

Mechanics’ Liens

In November 2007, the primary subcontractor on a 2007 maintenance outage at AERG’s Duck Creek facility filed a complaint for foreclosure of its mechanic’s lien of $19 million plus interest against AERG. That action was filed in the Circuit Court of Fulton County, Illinois. Subsequently, various second-tier subcontractors of the primary subcontractor also filed for foreclosure of their mechanics’ lien claims against AERG in the Circuit Court of Fulton County, Illinois, in addition to filing their claims against the primary subcontractor. Approximately 13 mechanics’ liens claiming $23 million plus interest in the aggregate were filed as of December 31, 2008, against AERG for labor or material for the 2007 maintenance outage. These claims were primarily based on additional work outside of the original contract scope. Effective as of December 17, 2008, AERG entered into a Settlement and Release Agreement with the primary contractor. It provides that in exchange for AERG’s payment of $19 million to the

primary contractor, the primary contractor will, among other things, release Ameren from any existing or future claims they may have, pay off and obtain full releases of all mechanics’ liens filed against AERG and dismiss all mechanics’ lien claims against AERG in the Fulton County litigation made by the primary subcontractor and all second-tier subcontractors’, and indemnify, defend and hold AERG harmless from all such claims by these parties. The resolution of these liens and lawsuits did not have a material impact on CILCO’s results of operations, financial position, or liquidity.

Asbestos-related Litigation

Ameren, UE, CIPS, Genco, CILCO and IP have been named, along with numerous other parties, in a number of lawsuits filed by plaintiffs claiming varying degrees of injury from asbestos exposure. Most have been filed in the Circuit Court of Madison County, Illinois. The total number of defendants named in each case is significant; as many as 161 parties are named in some pending cases and as few as six in others. However, in the cases pending as of December 31, 2008, the average number of parties was 68.

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 former CILCO plants are now owned by AERG. Most of IP’s plants were transferred to a former parent subsidiary prior to Ameren’s acquisition of IP. As a part of the transfer of ownership of the CIPS and CILCO generating plants, CIPS and CILCO have contractually agreed to indemnify Genco and AERG, respectively, for liabilities associated with asbestos-related claims arising from activities prior to the transfer. Each lawsuit seeks unspecified damages that, if awarded at trial, typically would be shared among the various defendants.

The following table presents the pending asbestos-related lawsuits filed against the Ameren Companies as of December 31, 2008:


Specifically Named as Defendant
Ameren	UE	CIPS	Genco	CILCO	IP	Total ^(a)
3	25	31	-	10	36	67

(a)	Total does not equal the sum of the subsidiary unit lawsuits because some of the lawsuits name multiple Ameren entities as defendants.

As of December 31, 2008, six 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.

IP has 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 are recoverable by IP from a trust fund established by IP. At December 31, 2008, the trust fund balance was $23 million, including accumulated interest.

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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.

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 before 2020. 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. UE intends to submit a license extension application with the NRC to extend its Callaway nuclear plant’s operating license to 2044. It is assumed that the Callaway nuclear plant site will be decommissioned based on the 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 Note 1 – Summary of Significant Accounting Policies for additional information on asset retirement obligations. 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 2008, 2007 and 2006. 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. The latest study was filed in September 2008. The 2008 study included the minor tritium contamination discovered on the Callaway nuclear plant site, which did not result in a significant increase in the decommissioning cost estimate. 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 as 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 a regulatory asset or regulatory liability, as appropriate.

See Note 2 – Rate and Regulatory Matters for information on the COLA filed by UE with the NRC for a potential new nuclear unit and Note 9 – Nuclear Decommissioning Trust Fund Investments.

NOTE 17 – SEGMENT INFORMATION

Ameren has three reportable segments: Missouri Regulated, Illinois Regulated, and Non-rate-regulated Generation. The Missouri Regulated segment for Ameren includes all the operations of UE’s business as described in Note 1 – Summary of Significant Accounting Policies, except for UE’s 40% interest in EEI (which in February 2008 was transferred to Resources Company through an internal reorganization) and other non-rate-regulated activities, which are in Other. The Illinois Regulated segment for Ameren consists of the regulated electric and gas transmission and distribution businesses of CIPS, CILCO, and IP, as described in Note 1 – Summary of Significant Accounting Policies. The Non-rate-regulated Generation segment for Ameren consists primarily of the operations or activities of Genco, the CILCORP parent company, AERG, EEI, and Marketing Company. The category called Other primarily includes Ameren parent company activities and the leasing activities of CILCORP, AERG, Resources Company, and CIPSCO Investment Company. CIPSCO Investment Company was eliminated on March 31, 2008, through an internal reorganization.

UE has one reportable segment: Missouri Regulated. The Missouri Regulated segment for UE includes all the operations of UE’s business as described in Note 1 – Summary of Significant Accounting Policies, except for UE’s former 40% interest in EEI and other non-rate-regulated activities, which are included in Other.

CILCORP and CILCO have two reportable segments: Illinois Regulated and Non-rate-regulated Generation. The Illinois Regulated segment for CILCORP and CILCO consists of the regulated electric and gas transmission and distribution businesses of CILCO. The Non-rate-regulated Generation segment for CILCORP and CILCO consists of the generation business of AERG. For CILCORP and CILCO, Other comprises leveraged lease investments, parent company activity, and minor activities not reported in the Illinois Regulated or Non-rate-regulated Generation segments for CILCORP.

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The following tables present information about the reported revenues and specified items included in net income of Ameren, UE, CILCORP, and CILCO for the years ended December 31, 2008, 2007 and 2006, and total assets as of December 31, 2008, 2007 and 2006.

Ameren


	Missouri Regulated		Illinois Regulated		Non-rate- regulated Generation		Other			Intersegment Eliminations			Consolidated
2008
External revenues	$	2,922	$	3,433	$	1,482	$	2		$	-		$	7,839
Intersegment revenues		38		45		455		18			(556	)		-
Depreciation and amortization		329		219		109		28			-			685
Interest and dividend income		33		15		3		30			(38	)		43
Interest expense		193		144		99		44			(40	)		440
Income taxes (benefit)		134		16		217		(40	)		-			327
Net income (loss) ^(a)		234		32		352		(13	)		-			605
Capital expenditures		874		359		611		52			-			1,896
Total assets ^(b)		11,524		7,079		4,622		1,227			(1,795	)		22,657
2007
External revenues	$	2,915	$	3,318	$	1,315	$	14		$	-		$	7,562
Intersegment revenues		46		62		497		40			(645	)		-
Depreciation and amortization		333		217		105		26			-			681
Interest and dividend income		34		26		2		52			(59	)		55
Interest expense		194		132		107		29			(39	)		423
Income taxes (benefit)		143		25		182		(20	)		-			330
Net income ^(a)		281		47		281		9			-			618
Capital expenditures		625		321		395		40			-			1,381
Total assets ^(b)		10,852		6,385		4,027		965			(1,501	)		20,728
2006
External revenues	$	2,584	$	3,338	$	926	$	47		$	-		$	6,895
Intersegment revenues		227		15		788		27			(1,057	)		-
Depreciation and amortization		335		192		106		28			-			661
Interest and dividend income		33		20		1		34			(50	)		38
Interest expense		171		95		103		29			(48	)		350
Income taxes (benefit)		184		65		78		(43	)		-			284
Net income ^(a)		267		115		138		27			-			547
Capital expenditures		782		314		160		28			-			1,284
Total assets ^(b)		10,254		6,280		3,612		1,161			(1,672	)		19,635

(a)	Represents net income available to common stockholders; 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.

(b)	Total assets for Illinois Regulated included an allocation of goodwill and other purchase accounting amounts related to CILCO that are recorded at CILCORP (parent company).


	Missouri Regulated		Other ^(a)			Consolidated UE
2008
Revenues	$	2,960	$	-		$	2,960
Depreciation and amortization		329		-			329
Interest expense		193		-			193
Income taxes		134		-			134
Net income ^(b)		234		11			245
Capital expenditures		874		-			874
Total assets		11,524		-			11,524
2007
Revenues	$	2,961	$	-		$	2,961
Depreciation and amortization		333		-			333
Interest expense		194		-			194
Income taxes (benefit)		143		(3	)		140
Net income ^(b)		281		55			336
Capital expenditures		625		-			625
Total assets		10,852		51			10,903

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	Missouri Regulated		Other ^(a)		Consolidated UE
2006
Revenues	$	2,811	$	12	$	2,823
Depreciation and amortization		335		-		335
Interest expense		171		-		171
Income taxes		184		-		184
Net income ^(b)		267		76		343
Capital expenditures		782		-		782
Total assets		10,254		36		10,290

(a)	Included 40% interest in EEI through February 29, 2008.

(b)	Represents net income available to the common stockholder (Ameren).

CILCORP


	Illinois Regulated		Non-rate- regulated Generation			Other			Intersegment Eliminations			Consolidated CILCORP
2008
External revenues	$	805	$	342		$	-		$	-		$	1,147
Intersegment revenues		3		-			-			(3	)		-
Depreciation and amortization		50		31			-			-			81
Interest expense		16		39			-			-			55
Income taxes		5		14			-			-			19
Net income (loss) ^(a)		16		27			(1	)		-			42
Capital expenditures		61		258			-			-			319
Total assets ^(b)		1,402		1,680			2			(219	)		2,865
2007
External revenues	$	732	$	279		$	-		$	-		$	1,011
Intersegment revenues		-		4			-			(4	)		-
Depreciation and amortization		54		24			-			-			78
Interest expense		18		46			-			-			64
Income taxes		-		21			-			-			21
Net income ^(a)		9		38			-			-			47
Capital expenditures		64		190			-			-			254
Total assets ^(b)		1,202		1,455			1			(199	)		2,459
2006
External revenues	$	713	$	34		$	-		$	-		$	747
Intersegment revenues		-		181			-			(181	)		-
Depreciation and amortization		53		22			-			-			75
Interest expense		15		37			-			-			52
Income taxes (benefit)		12		(19	)		(4	)		-			(11	)
Net income (loss) ^(a)		25		(3	)		(3	)		-			19
Capital expenditures		53		66			-			-			119
Total assets ^(b)		1,217		1,246			4			(217	)		2,250

(a)	Represents net income available to the common stockholders (Ameren); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.

(b)	Total assets for Illinois Regulated and Non-rate-regulated Generation include an allocation of goodwill and other purchase accounting amounts related to CILCO that are recorded at CILCORP (parent company).

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CILCO


	Illinois Regulated		Non-rate- regulated Generation		Other			Intersegment Eliminations			Consolidated CILCO
2008
External revenues	$	805	$	342	$	-		$	-		$	1,147
Intersegment revenues		3		-		-			(3	)		-
Depreciation and amortization		50		27		-			-			77
Interest expense		16		5		-			-			21
Income taxes		5		34		-			-			39
Net income ^(a)		16		52		-			-			68
Capital expenditures		61		258		-			-			319
Total assets		1,212		1,081		-			1			2,294
2007
External revenues	$	732	$	279	$	-		$	-		$	1,011
Intersegment revenues		-		4		-			(4	)		-
Depreciation and amortization		54		19		-			-			73
Interest expense		18		8		1			-			27
Income taxes		-		39		-			-			39
Net income ^(a)		9		65		-			-			74
Capital expenditures		64		190		-			-			254
Total assets		1,012		859		-			(9	)		1,862
2006
External revenues	$	713	$	34	$	-		$	-		$	747
Intersegment revenues		-		181		-			(181	)		-
Depreciation and amortization		53		17		-			-			70
Interest expense		15		3		-			-			18
Income taxes (benefit)		12		2		(4	)		-			10
Net income (loss) ^(a)		25		23		(3	)		-			45
Capital expenditures		53		66		-			-			119
Total assets		1,029		642		1			(22	)		1,650

(a)	Represents net income available to the common stockholders (Ameren); 100% of CILCO’s preferred stock dividends are included in the Illinois Regulated segment.

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


Quarter Ended	Operating Revenues		Operating Income			Net Income			Earnings per Common Share - Basic and Diluted
Ameren
March 31, 2008	$	2,081	$	321		$	138		$ 0.66
March 31, 2007		2,025		294			123		0.59
June 30, 2008		1,790		444			206		0.98
June 30, 2007		1,728		326			143		0.69
September 30, 2008		2,060		428			204		0.97
September 30, 2007		1,997		481			244		1.18
December 31, 2008		1,908		169			57		0.27
December 31, 2007		1,812		258			108		0.52

Quarter Ended	Operating Revenues		Operating Income (Loss)			Net Income (Loss)			Net Income (Loss) Available to Common Stockholder
UE
March 31, 2008	$	724	$	111		$	64		$ 63
March 31, 2007		650		68			33		32
June 30, 2008		771		232			124		122
June 30, 2007		697		144			81		79
September 30, 2008		875		195			99		98
September 30, 2007		945		317			193		192
December 31, 2008		590		(24	)		(36	)	(38	)
December 31, 2007		669		61			35		33
CIPS
March 31, 2008	$	290	$	8		$	3		$ 2
March 31, 2007		314		23			12		11
June 30, 2008		207		3			(3	)	(3	)
June 30, 2007		229		15			5		5
September 30, 2008		217		14			7		6
September 30, 2007		224		8			1		-
December 31, 2008		268		17			8		7
December 31, 2007		238		3			(1	)	(2	)
Genco ^(a)
March 31, 2008	$	233	$	83		$	46		$ 46
March 31, 2007		244		83			43		43
June 30, 2008		196		133			74		74
June 30, 2007		186		41			17		17
September 30, 2008		238		46			20		20
September 30, 2007		221		55			25		25
December 31, 2008		241		68			35		35
December 31, 2007		225		79			40		40
CILCORP ^(a)
March 31, 2008	$	345	$	47		$	20		$ 20
March 31, 2007		315		44			21		21
June 30, 2008		232		19			4		4
June 30, 2007		226		36			12		12
September 30, 2008		264		40			18		18
September 30, 2007		211		17			1		1
December 31, 2008		306		14			-		-
December 31, 2007		259		37			13		13

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Quarter Ended	Operating Revenues		Operating Income (Loss)		Net Income (Loss)			Net Income (Loss) Available to Common Stockholder
CILCO
March 31, 2008	$	345	$	48	$	26		$ 26
March 31, 2007		315		47		27		27
June 30, 2008		232		22		12		11
June 30, 2007		226		39		21		20
September 30, 2008		264		43		24		24
September 30, 2007		211		23		10		10
December 31, 2008		306		19		7		7
December 31, 2007		259		34		18		17
IP
March 31, 2008	$	503	$	27	$	3		$ 2
March 31, 2007		515		40		15		14
June 30, 2008		360		8		(10	)	(10	)
June 30, 2007		365		29		7		7
September 30, 2008		353		29		5		4
September 30, 2007		356		8		(4	)	(5	)
December 31, 2008		480		39		7		7
December 31, 2007		410		32		8		8

(a)	Genco and CILCORP had no preferred stock outstanding.

ITEM 9.

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

None.

ITEM 9A and ITEM 9A(T). CONTROLS AND PROCEDURES.

Each of the Ameren Companies 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 2008 fiscal year.

(a)

Evaluation of Disclosure Controls and Procedures

As of December 31, 2008, evaluations were performed under the supervision and with the participation of management, including the principal executive officer and principal financial officer of each of the Ameren Companies, of 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). Based upon those evaluations, the principal executive officer and principal financial officer of each of the Ameren Companies concluded that such disclosure controls and procedures are effective to provide assurance that information required to be disclosed in such registrant’s reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and such information is accumulated and communicated to its management, including its principal executive and principal financial officers, to allow timely decisions regarding required disclosure.

(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 each of the Ameren Companies’ internal control over financial reporting based on the framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). After making that evaluation under the framework in Internal Control - Integrated Framework issued by the COSO , management concluded that each of the Ameren Companies’ internal control over financial reporting was effective as of December 31, 2008. The effectiveness of Ameren’s internal control over financial reporting as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report herein under Part II, Item 8. This annual report does not include an attestation report of UE’s, Genco’s, CIPS’, CILCO’s, CILCORP’s or IP’s (the Subsidiary Registrants) independent registered public accounting firm regarding internal control over financial reporting. Management’s report for the Subsidiary Registrants was not subject to attestation by the independent registered public accounting firm because temporary rules of the SEC permit the company to provide only management’s report in this annual report.

177

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into 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 Control

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.

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 2008 that has not previously been reported on an SEC Form 8-K.

PART III

ITEM 10.

DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE.

Information required by Items 401, 405, 406 and 407(c)(3),(d)(4) and (d)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2009 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 2009 annual meetings of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Information required by these SEC Regulation S-K items for IP is identical to the information that will be contained in CIPS’ definitive information statement for CIPS’ 2009 annual meeting of shareholders filed pursuant to SEC 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 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 and risk committee to perform such committee functions for their boards of directors. These companies 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 and risk committee, and Stephen F. Brauer and Susan S. Elliott 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 of directors 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, the principal financial officer, the principal accounting officer, the controllers, 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. It is 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.

ITEM 11.

EXECUTIVE COMPENSATION.

Information required by Items 402 and 407(e)(4) and (e)(5) of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14A and 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 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14C and is incorporated herein by reference. Information required by these SEC Regulation S-K items for IP is identical to the information that will be included in CIPS’ definitive information statement for CIPS’ 2009 annual meeting of shareholders filed pursuant to SEC 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.

178

ITEM 12.

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

Equity Compensation Plan Information

The following table presents information as of December 31, 2008, with respect to the shares of Ameren’s common stock that may be issued under its existing equity compensation plans.


Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights (a)	Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights (b)		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders ^(a)	1,122,955	$ 32.80	^(b)	3,046,330
Equity compensation plans not approved by security holders	-	-		-
Total	1,122,955	$ 32.80	^(b)	3,046,330

(a)

Consists of the Ameren Corporation Long-term Incentive Plan of 1998, which was approved by shareholders in April 1998 and expired on April 1, 2008, and the Ameren Corporation 2006 Omnibus Incentive Compensation Plan, which was approved by shareholders in May 2006 and expires on May 2, 2016. Pursuant to grants of performance share units (PSUs) under the Long-term Incentive Plan of 1998 and the 2006 Omnibus Incentive Compensation Plan, 116,877 of the securities represent PSUs that vested at December 31, 2008, (including accrued and reinvested dividends) and 920,278 of the securities represent PSUs granted but not vested (including accrued and reinvested dividends). The actual number of shares issued in respect of the PSUs will vary from 0% to 200% of the target level based on the achievement of total shareholder return objectives established for such awards.

(b)	PSUs are awarded when earned in shares of Ameren common stock on a one-for-one basis. Accordingly, the PSUs have been excluded for purposes of calculating the weighted-average exercise price.

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 2009 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 2009 annual meeting of shareholders filed pursuant to SEC 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 about 73%, of IP’s preferred stock are owned by 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, 2009. 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, 2009, 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.

ITEM 13.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE.

Information required by Item 404 of SEC Regulation S-K for Ameren will be included in its definitive proxy statement for its 2009 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 2009 annual meeting of shareholders filed pursuant to SEC Regulation 14C; it is incorporated herein by reference. Information required by this SEC Regulation S-K item for IP is identical to the information that will be contained in CIPS’ definitive information statement for CIPS’ 2009 annual meeting of shareholders filed pursuant to SEC 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.

ITEM 14.

PRINCIPAL ACCOUNTANT FEES AND SERVICES.

Information required by Item 9(e) of SEC Schedule 14A for the Ameren Companies will be included in the definitive proxy statement of Ameren and the definitive information statements of UE, CIPS and CILCO for their 2009 annual meetings of shareholders filed pursuant to SEC Regulations 14A and 14C, respectively; it is incorporated herein by reference.

179

PART IV

ITEM 15.

EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.


(a)(1) Financial Statements		Page No.
Ameren
Report of Independent Registered Public Accounting Firm		80
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006		84
Consolidated Balance Sheet - December 31, 2008 and 2007		85
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006		86
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2008, 2007 and 2006		87
UE
Report of Independent Registered Public Accounting Firm		81
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006		88
Consolidated Balance Sheet - December 31, 2008 and 2007		89
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006		90
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2008, 2007 and 2006		91
CIPS
Report of Independent Registered Public Accounting Firm		81
Statement of Income - Years Ended December 31, 2008, 2007 and 2006		92
Balance Sheet - December 31, 2008 and 2007		93
Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006		94
Statement of Common Stockholders’ Equity - Years Ended December 31, 2008, 2007 and 2006		95
Genco
Report of Independent Registered Public Accounting Firm		82
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006		96
Consolidated Balance Sheet - December 31, 2008 and 2007		97
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006		98
Consolidated Statement of Common Stockholder’s Equity - Years Ended December 31, 2008, 2007 and 2006		99
CILCORP
Report of Independent Registered Public Accounting Firm		82
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006		100
Consolidated Balance Sheet - December 31, 2008 and 2007		101
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006		102
Consolidated Statement of Common Stockholder’s Equity - Years Ended December 31, 2008, 2007 and 2006		103
CILCO
Report of Independent Registered Public Accounting Firm		83
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006		104
Consolidated Balance Sheet - December 31, 2008 and 2007		105
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006		106
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2008, 2007 and 2006		107
IP
Report of Independent Registered Public Accounting Firm		83
Consolidated Statement of Income - Years Ended December 31, 2008, 2007 and 2006		108
Consolidated Balance Sheet - December 31, 2008 and 2007		109
Consolidated Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006		110
Consolidated Statement of Common Stockholders’ Equity - Years Ended December 31, 2008, 2007 and 2006		111

(a)(2) Financial Statement Schedules
Schedule I - Condensed Financial Information of Parent - CILCORP:
Condensed Statement of Income - Years Ended December 31, 2008, 2007 and 2006		181
Condensed Balance Sheet - December 31, 2008 and 2007		181
Condensed Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006		181
Schedule I - Condensed Financial Information of Parent - CILCO:
Condensed Statement of Income - Years Ended December 31, 2008, 2007 and 2006		182
Condensed Balance Sheet - December 31, 2008 and 2007		182
Condensed Statement of Cash Flows - Years Ended December 31, 2008, 2007 and 2006		182
Schedule II - Valuation and Qualifying Accounts for the years ended December 31, 2008, 2007 and 2006		183

Schedule I and 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 191.

(b)		Exhibits are listed in the Exhibit Index commencing on page 191.

180

SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT

CILCORP INC.

CONDENSED STATEMENT OF INCOME

For the Years Ended December 31, 2008, 2007 and 2006


(In millions)	2008			2007			2006
Operating revenue	$	-		$	-		$	-
Operating expenses		12			8			14
Operating loss		(12	)		(8	)		(14	)
Equity in earnings of subsidiaries		68			74			45
Interest and other charges		34			37			33
Income tax benefit		(20	)		(18	)		(21	)
Net income	$	42		$	47		$	19


SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT CILCORP INC. CONDENSED BALANCE SHEET
(In millions)	December 31, 2008		December 31, 2007
Assets:
Cash and equivalents	$	-	$	-
Other current assets		21		16
Total current assets		21		16
Investments in subsidiaries		674		606
Property and plant, net		123		130
Goodwill		542		542
Other		35		40
Total assets	$	1,395	$	1,334
Liabilities and Stockholder’s Equity:
Accounts payable	$	1	$	1
Other current liabilities		342		190
Total current liabilities		343		191
Long-term debt		257		389
Other deferred credits and other noncurrent liabilities		40		42
Stockholder’s equity		755		712
Total liabilities and stockholder’s equity	$	1,395	$	1,334


SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT CILCORP INC. CONDENSED STATEMENT OF CASH FLOWS For the Years Ended December 31, 2008, 2007 and 2006
(In millions)	2008			2007			2006
Cash flows from operating activities	$	(25	)	$	(39	)	$	(11	)
Cash flows from investing activities		-			-			136
Cash flows from financing activities		25			39			(125	)
Net change in cash and equivalents		-			-			-
Cash and equivalents at beginning of year		-			-			-
Cash and equivalents at the end of year		-			-			-
Cash dividends received from consolidated subsidiaries		-			-			65

CILCORP (parent company only)

NOTES TO CONDENSED FINANCIAL STATEMENTS

December 31, 2008

NOTE 1 – BASIS OF PRESENTATION

CILCORP (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included under the combined notes to our financial statements under Part II, Item 8, of this report.

NOTE 2 – LONG-TERM OBLIGATIONS

See Note 5 – Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for a description and details of long-term obligations of CILCORP (parent company only).

NOTE 3 – COMMITMENTS AND CONTINGENCIES

See Note 15 – Commitments and Contingencies to our financial statements under Part II, Item 8, of this report for a description of all material contingencies and guarantees outstanding of CILCORP (parent company only).

181


SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT CENTRAL ILLINOIS LIGHT COMPANY CONDENSED STATEMENT OF INCOME For the Years Ended December 31, 2008, 2007 and 2006
(In millions)	2008			2007		2006
Operating revenue	$	793		$	732	$	713
Operating expenses		751			704		653
Operating income		42			28		60
Equity in earnings of subsidiaries		53			65		20
Miscellaneous income (expense)		(4	)		1		1
Interest and other charges		18			20		24
Income tax expense		5			-		12
Net income	$	68		$	74	$	45


SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT CENTRAL ILLINOIS LIGHT COMPANY CONDENSED BALANCE SHEET
(In millions)	December 31, 2008		December 31, 2007
Assets:
Cash and equivalents	$	-	$	4
Other current assets		248		190
Total current assets		248		194
Investments in subsidiaries		438		385
Property and plant, net		754		737
Other		209		72
Total assets	$	1,649	$	1,388
Liabilities and Stockholders’ Equity:
Accounts payable	$	86	$	52
Other current liabilities		95		158
Total current liabilities		181		210
Long-term debt		279		148
Other deferred credits and other noncurrent liabilities		501		409
Stockholders’ equity		688		621
Total liabilities and stockholders’ equity	$	1,649	$	1,388


SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF PARENT CENTRAL ILLINOIS LIGHT COMPANY CONDENSED STATEMENT OF CASH FLOWS For the Years Ended December 31, 2008, 2007 and 2006
(In millions)	2008			2007			2006
Cash flows from operating activities	$	42		$	28		$	84
Cash flows from investing activities		(61	)		(54	)		(36	)
Cash flows from financing activities		15			30			(49	)
Net change in cash and equivalents		(4	)		4			(1	)
Cash and equivalents at beginning of year		4			-			1
Cash and equivalents at the end of year		-			4			-
Cash dividends received from consolidated subsidiaries		-			10			19

CENTRAL ILLINOIS LIGHT COMPANY (parent company only)

NOTES TO CONDENSED FINANCIAL STATEMENTS

December 31, 2008

NOTE 1 – BASIS OF PRESENTATION

Central Illinois Light Company (parent company only) has accounted for wholly owned subsidiaries using the equity method. These financial statements are presented on a condensed basis. Additional disclosures relating to the parent company financial statements are included under the combined notes to our financial statements under Part II, Item 8, of this report.

NOTE 2 – LONG-TERM OBLIGATIONS

See Note 5 – Long-term Debt and Equity Financings to our financial statements under Part II, Item 8, of this report for a description and details of long-term obligations of Central Illinois Light Company (parent company only).

NOTE 3 – COMMITMENTS AND CONTINGENCIES

182


SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006
(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:
Deducted from assets - allowance for doubtful accounts:
2008	$	22	$	63	$	-	$	57	$	28
2007		11		53		-		42		22
2006		22		28		-		39		11
UE:
Deducted from assets - allowance for doubtful accounts:
2008	$	6	$	14	$	-	$	12	$	8
2007		6		14		-		14		6
2006		6		13		-		13		6
CIPS:
Deducted from assets - allowance for doubtful accounts:
2008	$	5	$	13	$	-	$	12	$	6
2007		2		10		-		7		5
2006		4		3		-		5		2
CILCORP:
Deducted from assets - allowance for doubtful accounts:
2008	$	2	$	9	$	-	$	8	$	3
2007		1		7		-		6		2
2006		5		2		-		6		1
CILCO:
Deducted from assets - allowance for doubtful accounts:
2008	$	2	$	9	$	-	$	8	$	3
2007		1		7		-		6		2
2006		5		2		-		6		1
IP:
Deducted from assets - allowance for doubtful accounts:
2008	$	9	$	27	$	-	$	24	$	12
2007		3		21		-		15		9
2006		8		9		-		14		3

(a)	Uncollectible accounts charged off, less recoveries.

183

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 2, 2009	By	/s/ Gary L. Rainwater
		Gary L. Rainwater Chairman, President 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, President, Chief Executive Officer, and Director (Principal Executive Officer)	March 2, 2009

/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	March 2, 2009

/s/ Martin J. Lyons Martin J. Lyons	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 2, 2009

* Stephen F. Brauer	Director	March 2, 2009

* Susan S. Elliott	Director	March 2, 2009

* Walter J. Galvin	Director	March 2, 2009

* Gayle P.W. Jackson	Director	March 2, 2009

* James C. Johnson	Director	March 2, 2009

* Charles W. Mueller	Director	March 2, 2009

* Douglas R. Oberhelman	Director	March 2, 2009

* Harvey Saligman	Director	March 2, 2009


* Patrick T. Stokes	Director	March 2, 2009

* Jack D. Woodard	Director	March 2, 2009

*By /s/ Warner L. Baxter Warner L. Baxter Attorney-in-Fact		March 2, 2009

184


	UNION ELECTRIC COMPANY (registrant)

Date: March 2, 2009	By	/s/ Thomas R. Voss
		Thomas R. Voss Chairman, President and Chief Executive Officer


/s/ Thomas R. Voss Thomas R. Voss	Chairman, President, Chief Executive Officer and Director (Principal Executive Officer)	March 2, 2009

/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer)	March 2, 2009

/s/ Martin J. Lyons Martin J. Lyons	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 2, 2009

* Daniel F. Cole	Director	March 2, 2009

* Adam C. Heflin	Director	March 2, 2009

* Richard J. Mark	Director	March 2, 2009

* Steven R. Sullivan	Director	March 2, 2009

*By /s/ Warner L. Baxter Warner L. Baxter Attorney-in-Fact		March 2, 2009

185


	CENTRAL ILLINOIS PUBLIC SERVICE COMPANY (registrant)

Date: March 2, 2009	By	/s/ Scott A. Cisel
		Scott A. Cisel Chairman, President and Chief Executive Officer


/s/ Scott A. Cisel Scott A. Cisel	Chairman, President, Chief Executive Officer and Director (Principal Executive Officer)	March 2, 2009

/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer)	March 2, 2009

/s/ Martin J. Lyons Martin J. Lyons	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 2, 2009

* Daniel F. Cole	Director	March 2, 2009

* Steven R. Sullivan	Director	March 2, 2009

*By /s/ Warner L. Baxter Warner L. Baxter Attorney-in-Fact		March 2, 2009

186


	AMEREN ENERGY GENERATING COMPANY (registrant)

Date: March 2, 2009	By	/s/ Charles D. Naslund
		Charles D. Naslund Chairman and President


/s/ Charles D. Naslund Charles D. Naslund	Chairman, President and Director (Principal Executive Officer)	March 2, 2009

/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer)	March 2, 2009

/s/ Martin J. Lyons Martin J. Lyons	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 2, 2009

* Daniel F. Cole	Director	March 2, 2009

* Steven R. Sullivan	Director	March 2, 2009

*By /s/ Warner L. Baxter Warner L. Baxter Attorney-in-Fact		March 2, 2009

187


	CILCORP INC. (registrant)

Date: March 2, 2009	By	/s/ Gary L. Rainwater
		Gary L. Rainwater Chairman, President and Chief Executive Officer


/s/ Gary L. Rainwater Gary L. Rainwater	Chairman, President, Chief Executive Officer and Director (Principal Executive Officer)	March 2, 2009

/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer)	March 2, 2009

/s/ Martin J. Lyons Martin J. Lyons	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 2, 2009

* Daniel F. Cole	Director	March 2, 2009

* Patrick T. Stokes	Director	March 2, 2009

* Steven R. Sullivan	Director	March 2, 2009

* Thomas R. Voss	Director	March 2, 2009

*By /s/ Warner L. Baxter Warner L. Baxter Attorney-in-Fact		March 2, 2009

188


	CENTRAL ILLINOIS LIGHT COMPANY (registrant)

Date: March 2, 2009	By	/s/ Scott A. Cisel
		Scott A. Cisel Chairman, President and Chief Executive Officer


/s/ Scott A. Cisel Scott A. Cisel	Chairman, President, Chief Executive Officer and Director (Principal Executive Officer)	March 2, 2009

/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer)	March 2, 2009

/s/ Martin J. Lyons Martin J. Lyons	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 2, 2009

* Daniel F. Cole	Director	March 2, 2009

* Steven R. Sullivan	Director	March 2, 2009

*By /s/ Warner L. Baxter Warner L. Baxter Attorney-in-Fact		March 2, 2009

189


	ILLINOIS POWER COMPANY (registrant)

Date: March 2, 2009	By	/s/ Scott A. Cisel
		Scott A. Cisel Chairman, President and Chief Executive Officer


/s/ Scott A. Cisel Scott A. Cisel	Chairman, President, Chief Executive Officer and Director (Principal Executive Officer)	March 2, 2009

/s/ Warner L. Baxter Warner L. Baxter	Executive Vice President, Chief Financial Officer and Director (Principal Financial Officer)	March 2, 2009

/s/ Martin J. Lyons Martin J. Lyons	Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)	March 2, 2009

* Daniel F. Cole	Director	March 2, 2009

* Steven R. Sullivan	Director	March 2, 2009

*By /s/ Warner L. Baxter Warner L. Baxter Attorney-in-Fact		March 2, 2009

190

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:
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
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. 1-2732
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(i)	IP	Articles of Amendment to IP’s Amended and Restated Articles of Incorporation filed March 28, 2002	Exhibit 4.1(ii), File No. 333-84008
3.12(ii)	Ameren	By-Laws of Ameren as amended effective October 10, 2008	October 14, 2008 Form 8-K, Exhibit 3.1(ii), File No. 1-14756
3.13(ii)	UE	By-Laws of UE as amended July 28, 2008	July 29, 2008 Form 8-K, Exhibit 3.1(ii), File No. 1-2967
3.14(ii)	CIPS	By-Laws of CIPS as amended July 28, 2008	July 29, 2008 Form 8-K, Exhibit 3.2(ii), File No. 1-3672
3.15(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
3.16(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
3.17(ii)	CILCO	By-Laws of CILCO as amended effective July 28, 2008	July 29, 2008 Form 8-K, Exhibit 3.3(ii), File No. 1-2732
3.18(ii)	IP	By-Laws of IP as amended July 28, 2008	July 29, 2008 Form 8-K, Exhibit 3.4(ii), File No. 1-3004

191


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
Instruments Defining Rights of Security Holders, Including Indentures
4.1	Ameren	Indenture of Ameren with The Bank of New York Mellon Trust Company, N.A., as successor trustee, relating to senior debt securities dated as of December 1, 2001 (Ameren’s Senior Indenture)	Exhibit 4.5, File No. 333-81774
4.2	Ameren	First Supplemental Indenture to Ameren’s Senior Indenture dated as of May 19, 2008	June 30, 2008 Form 10-Q, Exhibit 4.1, File No. 1-14756
4.3	Ameren UE	Indenture of Mortgage and Deed of Trust dated June 15, 1937 (UE Mortgage), from UE to The Bank of New York Mellon, as successor trustee, as amended May 1, 1941, and Second Supplemental Indenture dated May 1, 1941	Exhibit B-1, File No. 2-4940
4.4	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
4.5	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
4.6	Ameren UE	Supplemental Indenture to the UE Mortgage dated as of July 7, 1980	Exhibit 4.6, File No. 2-69821
4.7	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
4.8	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
4.9	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
4.10	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
4.11	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
4.12	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
4.13	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
4.14	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
4.15	Ameren UE	Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004A (1998A) Bonds	March 31, 2004 Form 10-Q, Exhibit 4.1, File No. 1-2967
4.16	Ameren UE	Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004B (1998B) Bonds	March 31, 2004 Form 10-Q, Exhibit 4.2, File No. 1-2967

192


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
4.17	Ameren UE	Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004C (1998C) Bonds	March 31, 2004 Form 10-Q, Exhibit 4.3, File No. 1-2967
4.18	Ameren UE	Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004D (2000B) Bonds	March 31, 2004 Form 10-Q, Exhibit 4.4, File No. 1-2967
4.19	Ameren UE	Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004E (2000A) Bonds	March 31, 2004 Form 10-Q, Exhibit 4.5, File No. 1-2967
4.20	Ameren UE	Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004F (2000C) Bonds	March 31, 2004 Form 10-Q, Exhibit 4.6, File No. 1-2967
4.21	Ameren UE	Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004G (1991) Bonds	March 31, 2004 Form 10-Q, Exhibit 4.7, File No. 1-2967
4.22	Ameren UE	Supplemental Indenture to the UE Mortgage dated February 1, 2004, relative to Series 2004H (1992) Bonds	March 31, 2004 Form 10-Q, Exhibit 4.8, File No. 1-2967
4.23	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
4.24	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
4.25	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
4.26	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
4.27	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
4.28	Ameren UE	Supplemental Indenture to the UE Mortgage dated June 1, 2007	June 15, 2007 Form 8-K, Exhibit 4.5, File No. 1-2967
4.29	Ameren UE	Supplemental Indenture to the UE Mortgage dated April 11, 2008	April 18, 2008 Form 8-K, Exhibit 4.7, File No. 1-2967
4.30	Ameren UE	Supplemental Indenture to the UE Mortgage dated June 1, 2008	June 19, 2008 Form 8-K, Exhibit 4.5, File No. 1-2967
4.31	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

193


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
4.32	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
4.33	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
4.34	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
4.35	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
4.36	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
4.37	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
4.38	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
4.39	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
4.40	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
4.41	Ameren UE	Indenture dated as of August 15, 2002, from UE to The Bank of New York Mellon Trust Company, N.A., as successor trustee (relating to senior secured debt securities)	August 23, 2002 Form 8-K, Exhibit 4.1, File No. 1-2967

194


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
4.42	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
4.43	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
4.44	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
4.45	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
4.46	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
4.47	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
4.48	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
4.49	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
4.50	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
4.51	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
4.52	Ameren UE	UE Company Order dated June 15, 2007, establishing the 6.40% Senior Secured Notes due 2017 (including the global note)	June 15, 2007 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967
4.53	Ameren UE	UE Company Order dated April 8, 2008, establishing the 6.00% Senior Secured Notes due 2018 (including the global note)	April 18, 2008 Form 8-K, Exhibits 4.3 and 4.5, File No. 1-2967
4.54	Ameren UE	UE Company Order dated June 19, 2008, establishing the 6.70% Senior Secured Notes due 2019 (including the global note)	June 19, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2967

195


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
4.55	Ameren CIPS	Indenture of Mortgage and Deed of Trust dated October 1, 1941, from CIPS to U.S. Bank National Association and Richard Prokosch, as successor trustees (CIPS Mortgage)	Exhibit 2.01, File No. 2-60232
4.56	Ameren CIPS	Supplemental Indenture to the CIPS Mortgage, dated September 1, 1947	Amended Exhibit 7(b), File No. 2-7341
4.57	Ameren CIPS	Supplemental Indenture to the CIPS Mortgage, dated January 1, 1949	Second Amended Exhibit 7.03, File No. 2-7795
4.58	Ameren CIPS	Supplemental Indenture to the CIPS Mortgage, dated June 1, 1965	Amended Exhibit 2.02, File No. 2-23569
4.59	Ameren CIPS	Supplemental Indenture to the CIPS Mortgage, dated April 1, 1971	Amended Exhibit 2.02, File No. 2-39587
4.60	Ameren CIPS	Supplemental Indenture to the CIPS Mortgage, dated December 1, 1973	Exhibit 2.03, File No. 2-60232
4.61	Ameren CIPS	Supplemental Indenture to the CIPS Mortgage, dated February 1, 1980	Exhibit 2.02(a), File No. 2-66380
4.62	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
4.63	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
4.64	Ameren CIPS	Supplemental Indenture to the CIPS Mortgage, dated December 1, 1998	Exhibit 4.2, File No. 333-59438
4.65	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
4.66	Ameren CIPS	Supplemental Indenture to the CIPS Mortgage, dated October 1, 2004	2004 Form 10-K, Exhibit 4.91, File No. 1-3672
4.67	Ameren CIPS	Supplemental Indenture to the CIPS Mortgage, dated June 1, 2006	June 19, 2006 Form 8-K, Exhibit 4.9, File No. 1-3672
4.68	Ameren CIPS	Supplemental Indenture to the CIPS Mortgage, dated August 1, 2006	September 8, 2006 Form 8-K, Exhibit 4.4, File No. 1-3672
4.69	Ameren CIPS	Supplemental Indenture to the CIPS Mortgage, dated March 1, 2007	March 14, 2007 Form 8-K, Exhibit 4.2, File No. 1-3672
4.70	Ameren CIPS	Indenture dated as of December 1, 1998, from CIPS to The Bank of New York Mellon Trust Company, N.A., as successor trustee (CIPS Indenture)	Exhibit 4.4, File No. 333-59438

196


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
4.71	Ameren CIPS	CIPS Global Note, dated December 22, 1998, representing Senior Secured Notes, 5.375% due 2008	Exhibit 4.5, File No. 333-59438
4.72	Ameren CIPS	CIPS Global Note, dated December 22, 1998, representing Senior Secured Notes, 6.125% due 2028	Exhibit 4.6, File No. 333-59438
4.73	Ameren CIPS	First Supplemental Indenture to the CIPS Indenture, dated as of June 14, 2006	June 19, 2006 Form 8-K, Exhibit 4.2, File No. 1-3672
4.74	Ameren CIPS	CIPS Company Order, dated June 14, 2006, establishing 6.70% Series Secured Notes due 2036	June 19, 2006 Form 8-K, Exhibit 4.5, File No. 1-3672
4.75	Ameren Genco	Indenture dated as of November 1, 2000, from Genco to The Bank of New York Mellon Trust Company, N.A., as successor trustee (Genco Indenture)	Exhibit 4.1, File No. 333-56594
4.76	Ameren Genco	First Supplemental Indenture dated as of November 1, 2000, to Genco Indenture, relating to Genco’s 8.35% Senior Notes, Series B due 2010	Exhibit 4.2, File No. 333-56594
4.77	Ameren Genco	Second Supplemental Indenture dated as of June 12, 2001, to Genco Indenture, relating to Genco’s 8.35% Senior Note, Series D due 2010	Exhibit 4.3, File No. 333-56594
4.78	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
4.79	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
4.80	Ameren Genco	Fifth Supplemental Indenture dated as of April 1, 2008, to Genco Indenture, relating to Genco 7.00% Senior Notes, Series G due 2018	April 9, 2008 Form 8-K, Exhibit 4.2, File No. 333-56594
4.81	Ameren Genco	Sixth Supplemental Indenture, dated as of July 7, 2008, to Genco Indenture, relating to Genco 7.00% Senior Notes, Series H due 2018	Exhibit No. 4.55, File No. 333-155416

197


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
4.82	Ameren CILCORP	Indenture, dated as of October 18, 1999, between Midwest Energy, Inc., and The Bank of New York Mellon Trust Company, N.A., as successor trustee, and First Supplemental Indenture, dated as of October 18, 1999, between CILCORP and The Bank of New York Mellon Trust Company, N.A., as successor trustee	Exhibits 4.1 and 4.2, File No. 333-90373
4.83	Ameren CILCO	Indenture of Mortgage and Deed of Trust between Illinois Power Company (predecessor in interest to CILCO) 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, Supplemental Indenture between the same parties dated as of January 1, 1935, and Supplemental Indenture between the same parties dated as of April 1, 1940	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
4.84	Ameren CILCO	Supplemental Indenture to the CILCO Mortgage, dated December 1, 1949	December 1949 Form 8-K, Exhibit A, File No. 1-2732
4.85	Ameren CILCO	Supplemental Indenture to the CILCO Mortgage, dated July 1, 1957	July 1957 Form 8-K, Exhibit A, File No. 1-2732
4.86	Ameren CILCO	Supplemental Indenture to the CILCO Mortgage, dated February 1, 1966	February 1966 Form 8-K, Exhibit A, File No. 1-2732
4.87	Ameren CILCO	Supplemental Indenture to the CILCO Mortgage, dated January 15, 1992	January 30, 1992 Form 8-K, Exhibit 4(b), File No. 1-2732
4.88	Ameren CILCO	Supplemental Indenture to the CILCO Mortgage, dated October 1, 2004	2004 Form 10-K, Exhibit 4.121, File No. 1-2732
4.89	Ameren CILCO	Supplemental Indenture to the CILCO Mortgage, dated June 1, 2006	June 19, 2006 Form 8-K, Exhibit 4.11, File No. 1-2732
4.90	Ameren CILCO	Supplemental Indenture to the CILCO Mortgage, dated August 1, 2006	September 8, 2006 Form 8-K, Exhibit 4.2, File No. 1-2732
4.91	Ameren CILCO	Supplemental Indenture to the CILCO Mortgage, dated March 1, 2007	March 14, 2007 Form 8-K, Exhibit 4.4, File No. 1-2732

198


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
4.92	Ameren CILCO	Supplemental Indenture to the CILCO Mortgage, dated December 1, 2008	December 9, 2008 Form 8-K, Exhibit 4.5, File No. 1-2732
4.93	Ameren CILCO	Indenture dated as of June 1, 2006, from CILCO to The Bank of New York Mellon Trust Company, N.A., as successor trustee	June 19, 2006 Form 8-K, Exhibit 4.3, File No. 1-2732
4.94	Ameren CILCO	CILCO Company Order, dated June 14, 2006, establishing the 6.20% Senior Secured Notes due 2016 (including the global note) and the 6.70% Senior Secured Notes due 2036 (including the global note)	June 19, 2006 Form 8-K, Exhibit 4.6, File No. 1-2732
4.95	Ameren CILCO	CILCO Company Order, dated December 9, 2008, establishing the 8.875% Senior Secured Notes due 2013 (including the global note)	December 9, 2008 Form 8-K, Exhibits 4.2 and 4.3, File No. 1-2732
4.96	Ameren IP	General Mortgage Indenture and Deed of Trust dated as of November 1, 1992 between IP and The Bank of New York Mellon Trust Company, N.A., as successor trustee (IP Mortgage)	1992 Form 10-K, Exhibit 4(cc), File No. 1-3004
4.97	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
4.98	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
4.99	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
4.100	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
4.101	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
4.102	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
4.103	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
4.104	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
4.105	Ameren IP	Supplemental Indenture dated as of June 1, 2006, to IP Mortgage for the series AA bonds	June 19, 2006 Form 8-K, Exhibit 4.13, File No. 1-3004

199


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
4.106	Ameren IP	Supplemental Indenture dated as of August 1, 2006, to IP Mortgage for the 2006 credit agreement series bonds	September 8, 2006 Form 8-K, Exhibit 4.6, File No. 1-3004
4.107	Ameren IP	Supplemental Indenture dated as of March 1, 2007, to IP Mortgage for the 2007 credit agreement series bonds	March 14, 2007 Form 8-K, Exhibit 4.6, File No. 1-3004
4.108	Ameren IP	Supplemental Indenture dated as of November 15, 2007, to IP Mortgage for the series BB bonds	November 20, 2007 Form 8-K, Exhibit 4.4, File No. 1-3004
4.109	Ameren IP	Supplemental Indenture dated as of April 1, 2008, to IP Mortgage for the series CC bonds	April 8, 2008 Form 8-K, Exhibit 4.9, File No. 1-3004
4.110	Ameren IP	Supplemental Indenture dated as of October 1, 2008, to IP Mortgage for the series DD bonds	October 23, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004
4.111	Ameren IP	Indenture, dated as of June 1, 2006 from IP to The Bank of New York Mellon Trust Company, N.A., as successor trustee	June 19, 2006 Form 8-K, Exhibit 4.4, File No. 1-3004
4.112	Ameren IP	IP Company Order, dated June 14, 2006, establishing the 6.25% Senior Secured Notes due 2016 (including the global note)	June 19, 2006 Form 8-K, Exhibit 4.7, File No. 1-3004
4.113	Ameren IP	IP Company Order, dated November 15, 2007, establishing the 6.125% Senior Secured Notes due 2017 (including the global note)	November 20, 2007 Form 8-K, Exhibit 4.2, File No. 1-3004
4.114	Ameren IP	IP Company Order, dated April 8, 2008, establishing the 6.25% Senior Secured Notes due 2018 (including the global note)	April 8, 2008 Form 8-K, Exhibit 4.4, File No. 1-3004
4.115	Ameren IP	IP Company Order dated October 23, 2008, establishing the 9.75% Senior Secured Notes due 2018 (including the global note)	October 23, 2008 Form 8-K, Exhibit 4.2, File No. 1-3004
4.116	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
Material Contracts
10.1	Ameren Genco	Amended and Restated Power Supply Agreement, dated March 28, 2008, between Marketing Company and Genco	March 28, 2008 Form 8-K, Exhibit 10.3, File No. 1-14756
10.2	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. 1-3004

200


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
10.3	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
10.4	Ameren Genco CILCORP	Ameren Corporation System Amended and Restated Non- Regulated Subsidiary Money Pool Agreement, dated March 1, 2008	March 31, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.5	Ameren UE Genco	Amended and Restated Five-Year Revolving Credit Agreement, dated as of July 14, 2006, currently among Ameren, UE, Genco and JPMorgan Chase Bank, N.A., as administrative agent	July 18, 2006 Form 8-K, Exhibit 10.1, File No. 1-14756
10.6	Ameren CILCORP CILCO	Collateral Agency Agreement, dated as of July 14, 2006, between AERG and The Bank of New York Mellon Trust Company, N.A., as collateral agent	July 18, 2006 Form 8-K, Exhibit 10.6, File No. 2-95569
10.7	Ameren CILCORP CILCO	Collateral Agency Agreement Supplement, dated as of February 9, 2007, between AERG and The Bank of New York Mellon Trust Company, N.A., as collateral agent	February 13, 2007 Form 8-K, Exhibit 10.3, File No. 1-14756
10.8	Ameren CIPS CILCORP CILCO IP	Credit Agreement - Illinois Facility, dated as of July 14, 2006, among CIPS, CILCO, IP, AERG, CILCORP and JPMorgan Chase Bank, N.A., as administrative agent (2006 Illinois Credit Agreement)	July 18, 2006 Form 8-K, Exhibit 10.2, File No. 1-14756
10.9	Ameren CIPS CILCORP CILCO IP	Amendment dated as of March 26, 2008 to 2006 Illinois Credit Agreement	March 28, 2008 Form 8-K, Exhibit 10.1, File No. 1-14756
10.10	Ameren CIPS CILCORP CILCO IP	Credit Agreement - Illinois Facility, dated as of February 9, 2007, among CIPS, CILCO, IP, AERG, CILCORP and JPMorgan Chase Bank, N.A., as administrative agent (2007 Illinois Credit Agreement)	February 13, 2007 Form 8-K, Exhibit 10.1, File No. 1-14756
10.11	Ameren CIPS CILCORP CILCO IP	Amendment dated as of March 26, 2008 to 2007 Illinois Credit Agreement	March 28, 2008 Form 8-K, Exhibit 10.2, File No. 1-14756
10.12	Ameren	Credit Agreement dated as of June 25, 2008, between Ameren and JPMorgan Chase Bank, N.A., as agent	June 27, 2008 Form 8-K, Exhibit 10.1, File No. 1-14756
10.13	Ameren CILCORP CILCO	Pledge Agreement dated as of October 18, 1999, between CILCORP and The Bank of New York Mellon, as collateral agent	October 29, 1999 Form 8-K, Exhibit 10.1, File No. 2-95569

201


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
10.14	Ameren CILCORP CILCO	Pledge Agreement Supplement, dated as of July 14, 2006, between CILCORP and The Bank of New York Mellon, as Collateral Agent	July 18, 2006 Form 8-K, Exhibit 10.3, File No. 2-95569
10.15	Ameren CILCORP CILCO	Pledge Agreement Supplement, dated as of February 9, 2007, between CILCORP and The Bank of New York Mellon, as Collateral Agent	February 13, 2007 Form 8-K, Exhibit 10.2, File No. 1-14756
10.16	Ameren CILCORP CILCO	Open-Ended Mortgage, Security Agreement, Assignment of Rents and Leases and Fixtures Filing (Illinois) - E.D. Edwards plant, dated as of July 14, 2006, by and from AERG to The Bank of New York Mellon Trust Company, N.A., as agent	July 18, 2006 Form 8-K, Exhibit 10.4, File No. 2-95569
10.17	Ameren CILCORP CILCO	Open-Ended Mortgage, Security Agreement, Assignment of Rents and Leases and Fixtures Filing (Illinois) - Duck Creek plant, dated as of July 14, 2006, by and from AERG to The Bank of New York Mellon Trust Company, N.A., as agent	July 18, 2006 Form 8-K, Exhibit 10.5, File No. 2-95569
10.18	Ameren	*Summary Sheet of Ameren Corporation Non-Management Director Compensation revised on August 8, 2008	September 30, 2008 Form 10-Q, Form 8-K, Exhibit 10.1, File No. 1-14756
10.19	Ameren Companies	*Ameren’s Long-Term Incentive Plan of 1998	1998 Form 10-K, Exhibit 10.1, File No. 1-14756
10.20	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
10.21	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
10.22	Ameren	*Ameren’s Deferred Compensation Plan for Members of the Board of Directors amended and restated effective January 1, 2009, dated June 13, 2008	June 30, 2008 Form 10-Q, Exhibit 10.3, File No. 1-14756
10.23	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
10.24	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

202


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
10.25	Ameren Companies	*Ameren 2007 Deferred Compensation Plan	December 5, 2006 Form 8-K, Exhibit 10.1, File No. 1-14756
10.26	Ameren Companies	*Ameren 2008 Deferred Compensation Plan	June 30, 2008 Form 10-Q, Exhibit 10.2, File No. 1-14756
10.27	Ameren Companies	*2004 Ameren Executive Incentive Plan	2003 Form 10-K, Exhibit 10.7, File No. 1-14756
10.28	Ameren Companies	*2005 Ameren Executive Incentive Plan	February 14, 2005 Form 8-K, Exhibit 10.2, File No. 1-14756
10.29	Ameren Companies	*2006 Ameren Executive Incentive Plan	February 16, 2006 Form 8-K, Exhibit 10.2, File No. 1-14756
10.30	Ameren Companies	*2007 Executive Incentive Compensation Plan	February 15, 2007 Form 8-K, Exhibit 99.3, File No. 1-14756
10.31	Ameren Companies	*2008 Executive Incentive Compensation Plan	December 18, 2007 Form 8-K, Exhibit 99.1, File No. 1-14756
10.32	Ameren Companies	*2009 Executive Incentive Compensation Plan	February 19, 2009 Form 8-K, Exhibit 10.1, File No. 1-14756
10.33	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
10.34	Ameren Companies	*2007 Base Salary Table for Named Executive Officers	March 31, 2007 Form 10-Q, Exhibit 10.2, File No. 1-14756
10.35	Ameren Companies	*2008 Base Salary Table for Named Executive Officers	2008 Form 10-K, Exhibit 10.31, File No. 1-14756
10.36	Ameren Companies	*2009 Base Salary Table for Named Executive Officers
10.37	Ameren Companies	*Second Amended and Restated Ameren Corporation Change of Control Severance Plan
10.38	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
10.39	Ameren Companies	*Table of Target 2007 Performance Share Unit Awards Issued to Named Executive Officers	February 15, 2007 Form 8-K, Exhibit 99.4, File No. 1-14756
10.40	Ameren Companies	*Table of Target 2008 Performance Share Unit Awards Issued to Named Executive Officers	February 14, 2008 Form 8-K, Exhibit 99.1, File No. 1-14756
10.41	Ameren Companies	*Ameren Corporation 2006 Omnibus Incentive Compensation Plan	February 16, 2006 Form 8-K, Exhibit 10.3, File No. 1-14756
10.42	Ameren Companies	*Form of Performance Share Unit Award Issued in 2006-2008 Pursuant to 2006 Omnibus Incentive Compensation Plan	February 16, 2006 Form 8-K, Exhibit 10.4, File No. 1-14756

203


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
10.43	Ameren Companies	*Ameren Supplemental Retirement Plan amended and restated effective January 1, 2008, dated June 13, 2008	June 30, 2008 Form 10-Q, Exhibit 10.1, File No. 1-14756
10.44	Ameren Companies	*First Amendment to amended and restated Ameren Supplemental Retirement Plan dated October 24, 2008
10.45	Ameren CILCORP CILCO	*CILCO Executive Deferral Plan as amended effective August 15, 1999	1999 Form 10-K, Exhibit 10, File No. 1-2732
10.46	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
10.47	Ameren CILCORP CILCO	*CILCO Restructured Executive Deferral Plan (approved August 15, 1999)	1999 Form 10-K, Exhibit 10(e), File No. 1-2732
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
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, File No. 1-14756

204


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
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
23.4	Genco	Consent of Independent Registered Public Accounting Firm with respect to Genco
23.5	CILCO	Consent of Independent Registered Public Accounting Firm with respect to CILCO
23.6	IP	Consent of Independent Registered Public Accounting Firm with respect to IP
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	Rule 13a-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	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of UE
31.4	UE	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of UE

205


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
31.5	CIPS	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CIPS
31.6	CIPS	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CIPS
31.7	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of Genco
31.8	Genco	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of Genco
31.9	CILCORP	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCORP
31.10	CILCORP	Rule13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCORP
31.11	CILCO	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of CILCO
31.12	CILCO	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of CILCO
31.13	IP	Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer of IP
31.14	IP	Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer of IP
Section 1350 Certifications
32.1	Ameren	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Ameren
32.2	UE	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of UE
32.3	CIPS	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CIPS
32.4	Genco	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of Genco
32.5	CILCORP	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCORP

206


Exhibit Designation	Registrant(s)	Nature of Exhibit	Previously Filed as Exhibit to:
32.6	CILCO	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of CILCO
32.7	IP	Section 1350 Certification of Principal Executive Officer and Principal Financial Officer of IP
Additional Exhibits
99.1	Ameren CILCORP CILCO	Amended and Restated Power Supply Agreement, dated March 28, 2008, between Marketing Company and AERG	March 28, 2008 Form 8-K, Exhibit 99.1, 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.

207

EXHIBIT 10.36

2009 BASE SALARY TABLE FOR NAMED EXECUTIVE OFFICERS

On December 12, 2008, the Human Resources Committee of the Board of Directors of Ameren Corporation (Committee) approved the 2009 annual base salaries of the following Named Executive Officers of Ameren Corporation (Ameren), Union Electric Company (UE), Central Illinois Public Service Company (CIPS), Ameren Energy Generating Company (Genco), CILCORP Inc. (CILCORP), Central Illinois Light Company (CILCO) and Illinois Power Company (IP) (which officers were determined to the extent applicable by reference to the Ameren Proxy Statement and the UE, CIPS and CILCO Information Statements, each dated March 6, 2008, for the 2008 annual meetings of shareholders and by reference to the definition of “Named Executive Officer” in Item 402(a)(3) of SEC Regulation S-K).


Name and Position	2009 Base Salary
Gary L. Rainwater Chairman, President and Chief Executive Officer - Ameren and CILCORP	$	940,000	*

Warner L. Baxter Executive Vice President and Chief Financial Officer – Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP	$	552,933	*

Thomas R. Voss Executive Vice President and Chief Operating Officer – Ameren; Chairman, President and Chief Executive Officer of UE	$	477,400	*

Steven R. Sullivan Senior Vice President, General Counsel and Secretary – Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP	$	417,133	*

Charles D. Naslund President (principal executive officer) – Genco; and until 07/01/08, Senior Vice President and Chief Nuclear Officer – UE	$	427,267	*

Daniel F. Cole Senior Vice President – UE, CIPS, Genco, CILCORP, CILCO and IP	$	350,800

Scott A. Cisel Chairman, President and Chief Executive Officer – CIPS, CILCO and IP	$	387,000

Jerre E. Birdsong Vice President and Treasurer – Ameren, UE, CIPS, Genco, CILCORP, CILCO and IP	$	297,200

* On February 12, 2009, the Committee, due to the current business environment, revised downward the annual base salary payable to such Named Executive Officer, effective March 1, 2009, to the base salary level payable to such named Named Executive Officer at the end of the 2008 fiscal year (2008 base salary). Consequently, the 2009 base salary payable to such named Executive Officer is the same as such Named Executive Officer’s 2008 base salary, except that for the first two months of fiscal 2009 such Named Executive Officer’s base salary was higher as approved by the Committee on December 12, 2008. The 2009 base salaries for certain of the Ameren Named Executive Officers may be subject to adjustment as may be disclosed by Ameren in its Current Report on Form 8-K dated March 2, 2009.

Exhibit 10.37

SECOND AMENDED AND RESTATED AMEREN CORPORATION

CHANGE OF CONTROL SEVERANCE PLAN

Introduction

The Board of Directors of Ameren Corporation recognizes that, as is the case with many publicly held corporations, there exists the possibility of a Change of Control of the Company. This possibility and the uncertainty it creates may result in the loss or distraction of senior executives of the Company, to the detriment of the Company and its shareholders.

The Board considers the avoidance of such loss and distraction to be essential to protecting and enhancing the best interests of the Company and its shareholders. The Board also believes that when a Change of Control is perceived as imminent, or is occurring, the Board should be able to receive and rely on impartial service from senior executives regarding the best interests of the Company and its shareholders, without concern that senior executives might be distracted or concerned by the personal uncertainties and risks created by the perception of an imminent or occurring Change of Control.

In addition, the Board believes that it is consistent with the Company’s employment practices and policies and in the best interests of the Company and its shareholders to treat fairly its employees whose employment terminates in connection with or following a Change of Control.

Accordingly, the Board has determined that appropriate steps should be taken to assure the Company of the continued employment and attention and dedication to duty of its senior executives and to seek to ensure the availability of their continued service, notwithstanding the possibility, threat or occurrence of a Change of Control.

Therefore, in order to fulfill the above purposes, the following plan has been developed and is hereby adopted.

ARTICLE I

ESTABLISHMENT OF PLAN

As of the Effective Date, the Company hereby amends and restates the Ameren Corporation Change of Control Severance Plan, as set forth in this document.

ARTICLE II

DEFINITIONS

As used herein, the following words and phrases shall have the following respective meanings unless the context clearly indicates otherwise.

(a) Annual Bonus Award . The target annual cash bonus that a Participant is eligible to earn for the year in which a Change in Control occurs pursuant to the Company’s Executive Incentive Plan, the Ameren Corporation 2006 Omnibus Incentive Compensation Plan, or any successor to either such plan.

(b) Annual Salary . The Participant’s regular annual base salary immediately prior to his or her termination of employment, including compensation converted to other benefits under a flexible pay arrangement maintained by any Employer or deferred pursuant to a written plan or agreement with any Employer.

(d) Cause . The occurrence of any one or more of the following:

(i) The Participant’s willful failure to substantially perform his duties with the Company (other than any such failure resulting from the Participant’s Disability), after a written demand for substantial performance is delivered to the Participant that specifically identifies the manner in which the Committee believes that the Participant has not substantially performed his duties, and the Participant has failed to remedy the situation within fifteen (15) business days of such written notice from the Company;

(ii) Gross negligence in the performance of the Participant’s duties which results in material financial harm to the Company;

(iii) The Participant’s conviction of, or plea of guilty or nolo contendere , to any felony or any other crime involving the personal enrichment of the Participant at the expense of the Company or shareholders of the Company; or

(iv) The Participant’s willful engagement in conduct that is demonstrably and materially injurious to the Company, monetarily or otherwise.

(e) Change of Control . The occurrence of any of the following events after the Effective Date of this Plan:

(i) The acquisition by any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 20% or more of either (x) the then outstanding shares of common stock of the Company (the “Outstanding Company Common Stock”) or (y) the combined voting power of the then outstanding voting securities of the Company entitled to vote generally in the election of directors (the “Outstanding Company Voting Securities”); provided, however, that for purposes of this subsection (i), the following acquisitions shall not constitute a Change of Control: (A) any acquisition directly from the Company, (B) any acquisition by the Company, (C) any acquisition by any employee benefit plan (or related trust) sponsored or maintained by the Company or any corporation controlled by the Company or (D) any acquisition by any corporation pursuant to a transaction which complies with clauses (A), (B) and (C) of paragraph (iii) below; or

(ii) Individuals who, as of the Effective Date of this Plan, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the Effective Date whose election, or nomination for election by the Company’s shareholders, was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of (A) an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board or (B) any agreement intended to avoid or settle any election contest; or

(iii) Consummation of a reorganization, merger or consolidation or sale or other disposition of all or substantially all of the assets of the Company or the acquisition of assets of another corporation (a “Business Combination”), in each case, unless, following such Business Combination, (A) all or substantially all of the individuals and entities who were the beneficial owners, respectively, of the Outstanding Company Common Stock and Outstanding Company Voting Securities immediately prior to such Business Combination beneficially own, directly or indirectly, more than 60% of, respectively, the then outstanding shares of common stock and the combined voting power of the then outstanding voting securities entitled to vote generally in the election of directors, as the case may be, of the corporation resulting from such Business Combination (including, without limitation, a corporation which as a result of such transaction owns the Company or all or substantially all of the Company’s assets either directly or through one or more subsidiaries) in substantially the same proportions as their ownership, immediately prior to such Business Combination of the Outstanding Company Common Stock and Outstanding Company Voting Securities, as the case may be, (B) no Person (excluding any corporation resulting from such Business Combination or any employee benefit plan (or related trust) of the Company or such corporation resulting from such Business Combination) beneficially owns, directly or indirectly, 20% or more of, respectively, the then outstanding shares of common stock of the corporation resulting from such Business Combination or the combined voting power of the then outstanding voting securities of such corporation except to the extent that such ownership existed prior to the Business Combination and (C) at least a majority of the members of the board of directors of the corporation resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

(iv) Approval by the shareholders of the Company of a complete liquidation or dissolution of the Company.

Notwithstanding the foregoing, a Change of Control shall not be deemed to occur solely because any Person (the “Subject Person”) acquired beneficial ownership of more than the permitted amount of the then Outstanding Company Common Stock or the Outstanding Company Voting Securities as a result of the acquisition of shares of common stock or voting securities by the Company which, by reducing the number of shares of Outstanding Company Common Stock or the Outstanding Company Voting Securities, increases the proportional number of shares beneficially owned by the Subject Persons, provided that if a Change of Control would occur (but for the operation of this sentence) as a result of the acquisition of shares of Outstanding Company Common Stock or the Outstanding Company Voting Securities by the Company, and after such share acquisition by the Company, the Subject Person becomes the beneficial owner of any additional shares of Outstanding Company Common Stock or the Outstanding Company Voting Securities which increases the percentage of the then Outstanding Company Common Stock or the Outstanding Company Voting Securities beneficially owned by the Subject Person, then a Change of Control shall occur.

(f) Code . The Internal Revenue Code of 1986, as amended from time to time.

(g) Committee . The Human Resources Committee of the Board.

(h) Company . Ameren Corporation and any successors thereto.

(i) Date of the Change of Control . The date on which a Change of Control occurs.

(j) Date of Termination . The date on which a Participant ceases to be an Employee.

(k) Disability . A termination of a Participant’s Employment for Disability shall have occurred if the Termination occurs because of a disability which qualifies the Participant for benefits under the Company’s long-term disability plan.

(l) Effective Date . October 1, 2008.

(m) Employee . Any full-time, regular-benefit, non-bargaining employee of the Company or any other Employer.

(n) Employer . The Company or any subsidiary of the Company.

(o) Employment . The state of being an Employee.

(p) ERISA . The Employee Retirement Income Security Act of 1974, as amended, and the regulations thereunder.

(q) Good Reason . The occurrence after a Change in Control of the Company of any one or more of the following without the Participant’s express written consent:

(i) A net reduction of the Participant’s authorities, duties, or responsibilities as an executive and/or officer of the Company from those in effect prior to the Change in Control, other than an insubstantial and inadvertent reduction that is remedied by the Company promptly after receipt of notice thereof given by the Participant;

(ii) The Company’s requiring the Participant to be based at a location in excess of fifty (50) miles from the location of the Participant’s principal job location or office immediately prior to the Change of Control; except for required travel on the Company’s business to an extent substantially consistent with the Participant’s then present business travel obligations;

(iii) Any material reduction by the Company of the Participant’s Base Salary or targeted Annual Bonus Awards, in effect on the Date of the Change of Control, or as the same shall be increased from time to time;

(iv) The failure to provide the Participant with an annualized long-term incentive opportunity which is either essentially equivalent in value to or greater in value than the Participant’s regular annualized long-term incentive opportunity in effect on

the Date of the Change of Control (for this purpose, the permissible floor value is intended to reference normal long-term incentive awards made as a part of the regular annual pay package, and not special awards that are not made on a regular basis) when calculated on a grant date basis using widely recognized valuation methodologies (e.g., Black-Scholes for options);

(v) The failure of the Company to continue in effect the aggregate value in any of the employee benefit or retirement plans in which the Participant participates prior to the Change in Control of the Company;

(vi) The failure of the Company to obtain a satisfactory agreement from any successor to the Company to assume and agree to perform the Company’s obligations under this Plan, as contemplated in Article V herein; and

(vii) A material breach of this Plan by the Company which is not remedied by the Company within ten (10) business days of receipt of written notice of such breach delivered by the Participant to the Company.

In the event it is necessary to determine the value of a long-term incentive opportunity under Section q(iv) above or the aggregate value of employee benefit or retirement plans under Section q(v) above, an outside independent benefit consulting firm shall be engaged by the Company to make such determination.

(r) Multiple . With respect to any Participant, the number set forth opposite the Participant’s name under the heading “Benefit Level” on Schedule I hereto.

(s) Participant . An individual who is designated as such pursuant to Section 3.1.

(t) Plan . The Ameren Corporation Change of Control Severance Plan.

(u) Retirement . A termination by Retirement shall have occurred where a Participant’s termination is due to his or her late, normal or early retirement under a pension plan sponsored by the Company or any of its affiliates, as defined in such plan.

(v) Separation Benefits . The benefits described in Section 4.2 that are provided to qualifying Participants under the Plan.

(w) Separation Period . With respect to any Participant, the period beginning on a Participant’s Date of Termination and ending after the expiration of a number of years equal to the Multiple for such Participant.

ARTICLE III

ELIGIBILITY

3.1 Participants . Each of the individuals named on Schedule I hereto shall be a Participant in the Plan.

3.2 Duration of Participation . A Participant shall only cease to be a Participant in the Plan as a result of an amendment or termination of the Plan complying with Article VI of the Plan, or when he ceases to be an Employee, unless, at the time he ceases to

be an Employee, such Participant is entitled to payment of a Separation Benefit as provided in the Plan or there has been an event or occurrence that constitutes Good Reason which would enable the Participant to terminate his employment and receive a Separation Benefit. A Participant entitled to payment of a Separation Benefit or any other amounts under the Plan shall remain a Participant in the Plan until the full amount of the Separation Benefit and any other amounts payable under the Plan have been paid to the Participant.

ARTICLE IV

SEPARATION BENEFITS

4.1 Terminations of Employment Which Give Rise to Separation Benefits Under Plan . A Participant shall be entitled to Separation Benefits as set forth in Section 4.2 below if, at any time before the second anniversary of the Date of the Change of Control, the Participant’s Employment is terminated (i) by the Employer for any reason other than Cause or (ii) by the Participant within 90 days after the occurrence of Good Reason. A Participant shall not be entitled to Separation Benefits if the Participant’s Employment is terminated (i) voluntarily by the Participant without Good Reason (or more than 90 days after any event which constitutes the occurrence of Good Reason) or (ii) by reason of death or Disability or (iii) by the Employer for Cause. In addition, if a Participant’s employment is terminated by the Company without Cause prior to the date of a Change of Control, either (i) at the request of a third party who has indicated an intention or taken steps reasonably calculated to effect such Change of Control, or (ii) otherwise in connection with, or in anticipation of, such a Change of Control which has been threatened or proposed, such termination shall be deemed to have occurred after a Change of Control for purposes of this Plan provided a Change of Control shall actually occur.

4.2 Separation Benefits .

(a) If a Participant’s employment is terminated under circumstances entitling him to Separation Benefits as provided in Section 4.1, the Company shall pay such Participant, within 30 days of the Date of Termination, a cash lump sum as set forth in subsection (b) below and the continued benefits set forth in subsection (c) below. For purposes of determining the benefits set forth in subsections (b) and (c), if the termination of the Participant’s employment is for Good Reason after there has been a reduction of the Participant’s Annual Salary, opportunity to earn Annual Bonuses, or other compensation or employee benefits, such reduction shall be ignored.

(b) The cash lump sum referred to in Section 4.2(a) is the aggregate of the following amounts:

(i) the sum of (1) the Participant’s Annual Salary through the Date of Termination to the extent not theretofore paid, (2) the product of (x) the Annual Bonus Award and (y) a fraction, the numerator of which is the number of days in such year through the Date of Termination, and the denominator of which is 365, and (3) any accrued vacation pay, to the extent not theretofore paid and in full satisfaction of the rights of the Participant thereto;

(ii) an amount equal to the product of (1) the Participant’s Multiple times (2) the sum of (x) the Participant’s Annual Salary plus (y) the Participant’s Annual Bonus Award; and

(iii) an amount equal to the difference between (a) the actuarial equivalent of the benefit under the qualified defined benefit retirement plans of the Employer in which the Participant participates (collectively, the “Retirement Plan”) and any excess or supplemental retirement plans in which the Participant participates (collectively, the “SERP”) which the Participant would receive if his or her employment continued during the Separation Period, assuming that the Participant’s compensation during the Separation Period would have been equal to his or her compensation as in effect immediately before the termination or, if higher, on the Effective Date, and (b) the actuarial equivalent of the Participant’s actual benefit (paid or payable), if any, under the Retirement Plan and the SERP as of the Date of Termination. The actuarial assumptions used for purposes of determining actuarial equivalence shall be no less favorable to the Participant than the more favorable of those in effect under the Retirement Plan and the SERP on the Date of Termination or the Date of the Change of Control.

(i) during the Separation Period, the Participant and his or her family shall be provided with medical, dental and life insurance benefits as if the Participant’s employment had not been terminated; provided, however, that if the Participant becomes reemployed with another employer and is eligible to receive medical or other welfare benefits under another employer-provided plan, the medical and other welfare benefits described herein shall be secondary to those provided under such other plan during such applicable period of eligibility. For purposes of determining eligibility (but not the time of commencement of benefits) of the Participant for retiree medical, dental and life insurance benefits under the Employer’s plans, practices, programs and policies, the Participant shall be considered to have remained employed during the Separation Period and to have retired on the last day of such period; and

(ii) if the Participant’s employment is terminated by the Company other than for Cause, the Company shall, at its sole expense as incurred, provide the Participant with outplacement services the scope and provider of which shall be selected by the Participant in his or her sole discretion (but at a cost to the Company of not more than $30,000), provided that no such outplacement services shall be provided beyond the end of the second calendar year following the calendar year in which the Date of Termination occurs;

To the extent any benefits described in this Section 4.2(c) cannot be provided pursuant to the appropriate plan or program maintained for Employees, the Company shall provide such benefits outside such plan or program at no additional cost (including without limitation tax cost) to the Participant.

4.3 Other Benefits Payable . The cash lump sum and continuing benefits described in Section 4.2 above shall be payable in addition to, and not in lieu of, all other accrued or vested or earned but deferred compensation, rights, options or other benefits which may be owed to a Participant upon or following termination, including but not limited to accrued vacation or sick pay, amounts

or benefits payable under any bonus or other compensation plans, stock option plan, stock ownership plan, stock purchase plan, life insurance plan, health plan, disability plan or similar or successor plan, but excluding any severance pay or pay in lieu of notice required to be paid to such Participant under applicable law.

4.4 Certain Additional Payments by the Company .

(a) Anything in this Plan to the contrary notwithstanding and except as set forth below, in the event it shall be determined that any payment or distribution by the Company to or for the benefit of any Participant (whether paid or payable or distributed or distributable pursuant to the terms of this Plan or otherwise, but determined without regard to any additional payments required under this Section 4.4) (a “Payment”) would be subject to the excise tax imposed by Section 4999 of the Code or any interest or penalties are incurred by the Participant with respect to such excise tax (such excise tax, together with any such interest and penalties, are hereinafter collectively referred to as the “Excise Tax”), then the Participant shall be entitled to receive an additional payment (a “Gross-Up Payment”) in an amount such that after payment by the Participant of all taxes (including any interest or penalties imposed with respect to such taxes), including, without limitation, any income taxes (and any interest and penalties imposed with respect thereto) and Excise Tax imposed upon the Gross-Up Payment, the Participant retains an amount of the Gross-Up Payment equal to the Excise Tax imposed upon the Payments. Notwithstanding the foregoing provisions of this Section 4, if it shall be determined that the Participant is entitled to a Gross-Up Payment, but that the Payments do not exceed 110% of the greatest amount (the “Reduced Amount”) that could be paid to the Participant such that the receipt of Payments will not give rise to any Excise Tax, then no Gross-Up Payment shall be made to the Participant and the Payments, in the aggregate, shall be reduced to the Reduced Amount. In the event that the preceding sentence applies, the Payments shall be reduced first out of Payments which are not subject to Code Section 409A and, if necessary, then Payments which are subject to Code Section 409A shall be reduced, starting with the Payments which are to be paid on the latest future date, until the Payments have been reduced to the Reduced Amount.

(b) Subject to the provisions of Section 4.4(c), all determinations required to be made under this Section 4.4, including whether and when a Gross-Up Payment is required and the amount of such Gross-Up Payment and the assumptions to be utilized in arriving at such determination, shall be made by such certified public accounting firm, human resources consulting firm, or other consulting firm in the business of performing such calculations as may be designated by the Company (the “Consulting Firm”), which shall provide detailed supporting calculations both to the Company and the Participant. All fees and expenses of the Consulting Firm shall be borne solely by the Company. Any Gross-Up Payment, as determined pursuant to this Section 4.4, due upon a Change of Control or due upon the Participant’s termination of employment shall be paid by the Company to the Participant no later than the last day of the calendar year following the calendar year in which the related taxes are remitted to the taxing authorities. Any determination by the Consulting Firm shall be binding upon the Company and the Participant. As a result of the uncertainty in the application of Section 4999 of the Code at the time of the initial determination by the Consulting Firm hereunder, it is possible that Gross-Up Payments which will not have been made by the Company should have been made (“Underpayment”), consistent with the calculations required to be made hereunder. In the event that the Company exhausts its remedies pursuant to Section 4.4(c) and the Participant thereafter is required to make a payment of any Excise Tax, the Consulting Firm shall determine the amount of the Underpayment that has occurred and any such Underpayment shall be paid by the Company to or for the benefit of the Participant by the last day of the calendar year following the calendar year in which the taxes that are the subject of audit, litigation, or any claim by the Internal Revenue Service are remitted to the taxing authorities.

(c) The Participant shall notify the Company in writing of any claim by the Internal Revenue Service that, if successful, would require the payment by the Company of the Gross-Up Payment. Such notification shall be given as soon as practicable but no later than ten business days after the Participant is informed in writing of such claim and shall apprise the Company of the nature of such claim and the date on which such claim is requested to be paid. The Participant shall not pay such claim prior to the expiration of the 30-day period following the date on which it gives such notice to the Company (or such shorter period ending on the date that any payment of taxes with respect to such claim is due). If the Company notifies the Participant in writing prior to the expiration of such period that it desires to contest such claim, the Participant shall:

(i) give the Company any information reasonably requested by the Company relating to such claim,

(ii) take such action in connection with contesting such claim as the Company shall reasonably request in writing from time to time, including, without limitation, accepting legal representation with respect to such claim by an attorney reasonably selected by the Company,

(iii) cooperate with the Company in good faith in order effectively to contest such claim, and

(iv) permit the Company to participate in any proceedings relating to such claim;

provided, however, that the Company shall bear and pay directly all costs and expenses (including additional interest and penalties) incurred in connection with such contest and shall indemnify and hold the Participant harmless, on an after-tax basis, for any Excise Tax or income tax (including interest and penalties with respect thereto) imposed as a result of such representation and payment of costs and expenses. Without limitation on the foregoing provisions of this Section 4.4(c), the Company shall control all proceedings taken in connection with such contest and, at its sole option, may pursue or forgo any and all administrative appeals, proceedings, hearings and conferences with the taxing authority in respect of such claim and may, at its sole option, either direct the Participant to pay the tax claimed and sue for a refund or contest the claim in any permissible manner, and the Participant agrees to prosecute such contest to a determination before any administrative tribunal, in a court of initial jurisdiction and in one or more appellate courts, as the Company shall determine; provided, however, that if the Company directs the Participant to pay such claim and sue for a refund, to the extent permitted by law the Company shall advance the amount of such payment to the Participant, on an interest-free basis and shall indemnify and hold the Participant harmless, on an after-tax basis, from any Excise Tax or income tax (including interest or penalties with respect thereto) imposed with respect to such advance or with respect to any imputed income with respect to such advance; and further provided that any extension of the statute of limitations relating to payment of taxes for the taxable year of

the Participant with respect to which such contested amount is claimed to be due is limited solely to such contested amount. Furthermore, the Company’s control of the contest shall be limited to issues with respect to which a Gross-Up Payment would be payable hereunder and the Participant shall be entitled to settle or contest, as the case may be, any other issue raised by the Internal Revenue Service or any other taxing authority.

(d) If, after the receipt by the Participant of an amount advanced by the Company pursuant to Section 4.4(c), the Participant becomes entitled to receive any refund with respect to such claim, the Participant shall (subject to the Company’s complying with the requirements of Section 4.4(c)) promptly pay to the Company the amount of such refund (together with any interest paid or credited thereon after taxes applicable thereto). If, after the receipt by the Participant of an amount advanced by the Company pursuant to Section 4.4(c), a determination is made that the Participant shall not be entitled to any refund with respect to such claim and the Company does not notify the Participant in writing of its intent to contest such denial of refund prior to the expiration of 30 days after such determination, then such advance shall be forgiven and shall not be required to be repaid and the amount of such advance shall offset, to the extent thereof, the amount of Gross-Up Payment required to be paid.

4.5 Payment Obligations Absolute . The obligations of the Company and the other Employers to pay the separation benefits described in Section 4.2 and any additional payments described in Section 4.4 shall be absolute and unconditional and shall not be affected by any circumstances, including, without limitation, any set-off, counterclaim, recoupment, defense or other right which the Company or any of the other Employers may have against any Participant. In no event shall a Participant be obligated to seek other employment or take any other action by way of mitigation of the amounts payable to a Participant under any of the provisions of this Plan, nor shall the amount of any payment hereunder be reduced by any compensation earned by a Participant as a result of employment by another employer, except as specifically provided in Section 4.2(c)(i).

ARTICLE V

SUCCESSOR TO COMPANY

This Plan shall bind any successor of the Company, its assets or its businesses (whether direct or indirect, by purchase, merger, consolidation or otherwise), in the same manner and to the same extent that the Company would be obligated under this Plan if no succession had taken place.

In the case of any transaction in which a successor would not by the foregoing provision or by operation of law be bound by this Plan, the Company shall require such successor expressly and unconditionally to assume and agree to perform the Company’s obligations under this Plan, in the same manner and to the same extent that the Company would be required to perform if no such succession had taken place. The term “Company,” as used in this Plan, shall mean the Company as hereinbefore defined and any successor or assignee to the business or assets which by reason hereof becomes bound by this Plan.

ARTICLE VI

DURATION, AMENDMENT AND TERMINATION

6.1 Amendment or Termination . The Board may amend or terminate this Plan (including Schedule I) at any time; provided , that this Plan (including Schedule I) may not be terminated or amended (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 Participant. If a Change of Control occurs while this Plan is in effect, this Plan shall continue in full force and effect and shall not terminate or expire until after all Participants who become entitled to any payments hereunder shall have received such payments in full and all adjustments required to be made pursuant to Section 4.4 have been made.

6.2 Procedure for Amendment or Termination . Any Amendment or termination of this Plan by the Board in accordance with the foregoing shall be made by action of the Board in accordance with the Company’s charter and by-laws and applicable law, and shall be evidenced by a written instrument signed by a duly authorized officer of the Company, certifying that the Board has taken such action.

ARTICLE VII

MISCELLANEOUS

7.1 Legal Fees and Expenses . The Company shall pay as incurred all legal fees, costs of litigation, costs of arbitration, prejudgment interest, and other expenses which are incurred in good faith by the Participant as a result of the Company’s refusal to provide the benefits to which the Participant becomes entitled under this Agreement, or as a result of the Company’s (or any third party’s) contesting the validity, enforceability, or interpretation of the Agreement, or as a result of any conflict between the parties pertaining to this Agreement; provided, however, that if the court (or arbitration panel, as applicable) determines that the Participant’s claims were arbitrary and capricious, the Company shall have no obligation hereunder. This reimbursement provision shall apply for the lifetime of the Participant. Any reimbursement under this section must be made on or before the last day of the calendar year following the calendar year in which the expense was incurred, and the right to reimbursement shall not be subject to liquidation or exchange for another benefit; provided, however, that if the court (or arbitration panel, as applicable) determines that the Participant’s claims were arbitrary and capricious, the Participant shall be obligated to repay to the Company all expenses previously reimbursed under this Section 7.1 immediately at the time such determination has been made final and unappealable.

7.2 Employment Status . This Plan does not constitute a contract of employment, nor does it impose on the Participant or the Employers any obligation for the Participant to remain an Employee or change the status of the Participant’s employment or the Employers’ policies regarding termination of employment.

7.3 Named Fiduciary; Administration . The Company is the named fiduciary of the Plan, with full authority to control and manage the operation and administration of the Plan, acting through the Benefits Administration Committee.

7.4 Claim Procedure . If an Employee, former Employee or other person who believes that he or she is being denied a benefit to which he or she is entitled (“claimant”), or his or her duly authorized representative, makes a written request alleging a right to receive benefits under this Plan or alleging a right to receive an adjustment in benefits being paid under the Plan, the Company shall treat it as a claim for benefit. All claims for benefit under the Plan shall be sent to the Chief Executive Officer of the Company at Ameren Corporation, 1901 Chouteau Avenue, P.O. Box 66149, St. Louis, MO 63166, and must be received within 30 days after termination of employment.

(a) Claim Decision . Upon receipt of a claim, the Chief Executive Officer shall advise the claimant that a reply will be forthcoming within a reasonable period of time, but ordinarily not later than 90 days, and shall, in fact, deliver such reply within such period. However, the Chief Executive Officer may extend the reply period for an additional ninety days for reasonable cause. If the reply period will be extended, the Chief Executive Officer shall advise the claimant in writing during the initial 90-day period indicating the special circumstances requiring an extension and the date by which the Chief Executive Officer expects to render the benefit determination. If the Chief Executive Officer denies the claim, in whole or in part, the Chief Executive Officer will inform the claimant in writing of his or her determination and the reasons therefor in terms calculated to be understood by the claimant. The notice shall set forth the specific reasons for the denial, make specific reference to the pertinent Plan provisions on which the denial is based, and describe any additional material or information necessary for the claimant to perfect the claim and explain why such material or such information is necessary. Such notice shall, in addition, inform the claimant what procedure the claimant should follow to take advantage of the review procedures set forth below in the event the claimant desires to contest the denial of the claim, including a statement of the claimant’s right to bring a civil action under Section 502(a) of ERISA following an adverse benefit determination on review and the time limits for requesting a review and for the actual review.

(b) Request for Review . The claimant may within 60 days thereafter request in writing that the Committee of the Board review the Chief Executive Officer’s prior determination. Such request must be addressed to the Committee of the Board at Ameren Corporation, 1901 Chouteau Avenue, P.O. Box 66149, St. Louis, MO 63166. The claimant or his or her authorized representative may submit written comments, documents, records or other information relating to the denied claim, which shall be considered in the review without regard to whether such information was submitted or considered in the initial benefit determination. The claimant or his or her authorized representative shall be provided, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information which (i) was relied upon by the Chief Executive Officer in making his or her initial claims decision, (ii) was submitted, considered or generated in the course of the Chief Executive Officer making his or her initial claims decision, without regard to whether such instrument was actually relied upon by the Chief Executive Officer in making his or her decision or (iii) demonstrates compliance by the Chief Executive Officer with the administrative processes and safeguards designed to ensure and to verify that benefit claims determinations are made in accordance with governing Plan documents and that, where appropriate, the Plan provisions have been applied consistently with respect to similarly situated claimants. If the claimant does not request a review of the Chief Executive Officer’s determination within such 60-day period, he or she shall be barred and estopped from challenging such determination.

(c) Review of Decision . The Committee shall, within a reasonable period of time, ordinarily not later than 60 days, after the Committee’s receipt of a request for review, review the Chief Executive Officer’s prior determination. If special circumstances require that the 60-day time period be extended, the Committee will so notify the claimant within the initial 60-day period indicating the special circumstances requiring an extension and the date by which the Committee expects to render its decision on review, which shall be as soon as possible but not later than 120 days after receipt of the request for review. In the event that the Committee extends

the determination period on review due to a claimant’s failure to submit information necessary to decide a claim, the period for making the benefit determination on review shall not take into account the period beginning on the date on which notification of extension is sent to the claimant and ending on the date on which the claimant responds to the request for additional information. The Committee has discretionary authority to determine a claimant’s eligibility for benefits and to interpret the terms of the Plan. Benefits under the Plan will be paid only if the Committee decides in its discretion that the claimant is entitled to such benefits. The decision of the Committee shall be final and non-reviewable, unless found to be arbitrary and capricious by a court of competent review. Such decision will be binding upon the Company and the claimant. If the Committee makes an adverse benefit determination on review, the Committee will render a written opinion, using language calculated to be understood by the claimant, that sets forth the specific reasons for the denial, makes specific references to pertinent Plan provisions on which the denial is based and includes a statement of the claimant’s right to bring a civil action under Section 502(a) of ERISA following the adverse benefit determination on such review. The opinion shall also include a statement that the claimant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records and other information which (i) was relied upon by the Committee in making its decision, (ii) was submitted, considered or generated in the course of the Committee making its decision, without regard to whether such instrument was actually relied upon by the Committee in making its decision, or (iii) demonstrates compliance by the Committee with its administrative processes and safeguards designed to ensure and to verify that benefit claims determinations are made in accordance with governing Plan documents, and that, where appropriate, the Plan provisions have been applied consistently with respect to similarly situated claimants.

7.5 Unfunded Plan Status . This Plan is intended to be an unfunded plan maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees, within the meaning of Section 401 of ERISA. All payments pursuant to the Plan shall be made from the general funds of the Company and no special or separate fund shall be established or other segregation of assets made to assure payment. No Participant or other person shall have under any circumstances any interest in any particular property or assets of the Company as a result of participating in the Plan. Notwithstanding the foregoing, one or more of the Employers may (but shall not be obligated to) create one or more grantor trusts, the assets of which are subject to the claims of the Employers’ creditors, to assist them in accumulating funds to pay their obligations under the Plan.

7.6 Validity and Severability . The invalidity or unenforceability of any provision of the Plan shall not affect the validity or enforceability of any other provision of the Plan, which shall remain in full force and effect, and any prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

7.7 Governing Law . The validity, interpretation, construction and performance of the Plan shall in all respects be governed by the laws of Missouri, without reference to principles of conflict of law, except to the extent pre-empted by ERISA.

7.8 Specified Employees; Section 409A Compliance . To the extent necessary to comply with Code Section 409A, any payments due to a “specified employee” hereunder as a result of a separation from service will, to the extent required by Code Section 409A,

be payable no earlier than six months following such specified employee’s separation from service. The terms “specified employee” and “separation from service” shall be interpreted in accordance with the resolution of the Board defining such terms. This Plan shall be interpreted in a manner so as to be consistent with Code Section 409A and the regulations thereunder to the extent applicable to payments and benefits provided hereunder.

SCHEDULE I

CHANGE OF CONTROL

SEVERANCE PLAN PARTICIPANTS


Benefit Level - 3

Baxter, Warner L.		Moehn, Michael
Cisel, Scott A.		Naslund, Charles D.
Cole, Daniel F.		Nelson, Gregory L.
Heflin, Adam C.		Rainwater, Gary L
Lyons, Martin J.		Sullivan, Steven R.
Mark, Richard J.		Voss, Thomas R.
Martin, Donna K.


Benefit Level - 2

Barnes, Lynn M.		Mosier, Don M.
Birdsong, Jerre E.		Mueller, Michael G.
Birk, Mark C.		Neff, Robert K.
Borkowski, Maureen A.		Nelson, Craig D.
Brawley, Mark		Ogden, Stan E.
Bremer, Charles A.		Pate, Ron D.
Cissell, Richard C.		Power, Joseph M.
Diya, Fadi M.		Prebil, William J.
Evans, Ronald K.		Schepers, David J.
Fey, John R.		Schukar, Shawn E.
Foss, Karen C.		Serri, Andrew M.
Glaeser, Scott A.		Simpson, Jerry L.
Herrmann, Timothy E.		Sobule, James A.
Iselin, Christopher A.		Steinke, Bruce A.
Kidwell, Stephen M.		Weisenborn, Dennis W.
Lindgren, Mark C.		Zdellar, Ronald C.
Menne, Michael L.

Exhibit 10.44

FIRST AMENDMENT TO THE

AMEREN SUPPLEMENTAL RETIREMENT PLAN

WHEREAS, Ameren Corporation (“Ameren”) previously adopted the Ameren Supplemental Retirement Plan (“Plan”); and

WHEREAS, Ameren previously acquired Central Illinois Light Company (“CILCO”) and became the sponsor of the CILCO Benefit Replacement Plan (“BRP”); and

WHEREAS, Ameren reserved the right to amend the Plan and the BRP; and

WHEREAS, Ameren desires to merge the BRP into the Plan effective November 1, 2008;

NOW THEREFORE, effective November 1, 2008, the BRP is merged into the Plan, and the Plan is amended by adding a new Schedule B as attached hereto; and

RESOLVED FURTHER, the terms of the BRP in effect prior to the merger shall continue to apply with respect to a participant who terminated employment prior to January 1, 2005, and the benefits of such participants shall be “grandfathered” for purposes of Section 409A of the Internal Revenue Code of 1986, as amended.

IN WITNESS WHEREOF, this Amendment is executed as of the date below.


AMEREN CORPORATION

By:		/s/ Donna K. Martin

Title:		SVP & CHRO

Date:		10-24-08

SCHEDULE B

CILCO BENEFIT REPLACEMENT PLAN BENEFITS

Effective November 1, 2008, the CILCO BRP is merged into the Plan. An individual who is a Participant under the CILCO BRP on such date (“CILCO Participant”) shall become a Participant in the Plan on such date, and his or her benefits under the Plan shall be determined in accordance with the terms of the Plan, subject to the following provisions:

•

In lieu of the death benefits described in Section 3.3, upon the death of a CILCO Participant before termination of employment, if he or she leaves a surviving spouse to whom he or she had been continuously married for the one-year period ending on the date of his or her death, his or her spouse shall be entitled to a death benefit equal to (a) the monthly benefit which would have been payable to the surviving spouse as a pre-retirement death benefit under the CILCO Salaried Supplement without regard to any limitations described in Section 2.1(a) of the Plan, minus (b) the monthly pre-retirement death benefit actually payable to the surviving spouse under the CILCO Salaried Supplement. Such benefit shall be paid at the time and in the form described in Section 3.3 of the Plan.

•

In addition to the forms of payment described in Section 3.4B, a CILCO Participant may elect, in accordance with the terms of Section 3.4, to receive his or her benefit upon termination of employment in the form of an annuity option available under the CILCO Salaried Supplement (or its successor document) under the Retirement Plan.

Exhibit 12.1

Ameren Corporation

Computation of Ratio of Earnings to Fixed Charges

(Thousands of Dollars, Except Ratios)


	Year Ended December 31,
	2004			2005			2006			2007			2008
Net income from continuing operations	$	529,884		$	605,725		$	546,738		$	617,804		$	605,189
Less- Change in accounting principle		—			(22,135	)		—			—			—
Less- Minority interest		(4,201	)		(3,231	)		(27,135	)		(27,266	)		(28,422	)
Add- Taxes based on income		282,558			356,016			283,825			330,141			326,736

Net income before income taxes, change in accounting principle and minority interest		816,643			987,107			857,698			975,211			960,347
Add- fixed charges:
Interest on long term debt		269,868			297,822			345,410			421,406	⁽¹⁾		440,507	⁽¹⁾
Estimated interest cost within rental expense		3,185			4,208			4,081			5,020			6,510
Amortization of net debt premium, discount, and expenses		12,983			14,687			15,341			18,638			19,716
Subsidiary preferred stock dividends		11,089			12,745			10,936			10,871			10,357
Adjust preferred stock dividends to pre-tax basis		5,913			7,227			5,565			5,709			5,497

Total fixed charges		303,038			336,689			381,333			461,644			482,587

Less: Adjustment of preferred stock dividends to pre-tax basis		5,913			7,227			5,565			5,709			5,497

Earnings available for fixed charges	$	1,113,768		$	1,316,569		$	1,233,466		$	1,431,146		$	1,437,437

Ratio of earnings to fixed charges		3.67			3.91			3.23			3.10			2.97

⁽¹⁾ Includes FIN 48 interest expense

Exhibit 12.2

Union Electric Company

Computation of Ratios of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)


	Year Ended December 31,
	2004		2005		2006		2007			2008
Net income from continuing operations	$	378,670	$	351,770	$	348,806	$	341,966		$	250,998
Less- Income from equity investee		5,098		6,463		54,285		54,545			10,948
Add- Taxes based on income		207,641		193,156		183,867		139,782			133,514

Net income before income taxes, change in Accounting principle and income from equity investee		581,213		538,463		478,388		427,203			373,564
Add- fixed charges:
Interest on long term debt		103,338		120,899		176,088		203,456	⁽¹⁾		205,314	⁽¹⁾
Estimated interest cost within rental expense		2,790		2,528		2,754		2,540			3,533
Amortization of net debt premium, discount, and expenses		5,168		5,278		5,468		5,634			6,226

Total fixed charges		111,296		128,705		184,310		211,630			215,073

Earnings available for fixed charges		692,509		667,168		662,698		638,833			588,637

Ratio of earnings to fixed charges		6.22		5.18		3.59		3.01			2.73

Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends		5,941		5,941		5,941		5,941			5,941
Adjustment to pre-tax basis		2,891		2,896		3,244		2,429			3,160

		8,832		8,837		9,185		8,370			9,101

Combined fixed charges and preferred stock dividend requirements	$	120,128	$	137,542	$	193,495	$	220,000		$	224,174

Ratio of earnings to combined fixed charges and preferred stock dividend requirements		5.76		4.85		3.42		2.90			2.62

⁽¹⁾ Includes FIN 48 interest expense

Exhibit 12.3

Central Illinois Public Service Company

Computation of Ratios of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)


	Year Ended December 31,
	2004		2005		2006		2007			2008
Net income from continuing operations	$	32,463	$	42,998	$	37,372	$	16,535		$	14,739
Add- Taxes based on income		16,135		24,596		15,539		9,322			5,199

Net income before income taxes		48,598		67,594		52,911		25,857			19,938
Add- fixed charges:
Interest on long term debt		31,372		28,969		29,932		36,670	⁽¹⁾		29,422	⁽¹⁾
Estimated interest cost within rental expense		—		—		726		899			760
Amortization of net debt premium, discount, and expenses		903		953		1,025		1,105			1,024

Total fixed charges		32,275		29,922		31,683		38,674			31,206

Earnings available for fixed charges		80,873		97,516		84,594		64,531			51,144

Ratio of earnings to fixed charges		2.50		3.25		2.67		1.66			1.63

Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends		2,512		2,512		2,512		2,512			2,512
Adjustment to pre-tax basis		1,248		1,437		1,045		1,416			886

		3,760		3,949		3,557		3,928			3,398

Combined fixed charges and preferred stock dividend requirements	$	36,035	$	33,871	$	35,240	$	42,602		$	34,604

Ratio of earnings to combined fixed charges and preferred stock dividend requirements		2.24		2.87		2.40		1.51			1.47

⁽¹⁾ Includes FIN 48 interest expense

Exhibit 12.4

Ameren Energy Generating Company

Computation of Ratio of Earnings to Fixed Charges

(Thousands of Dollars, Except Ratios)


	Year Ended December 31,
	2004		2005			2006		2007			2008
Net income from continuing operations	$	107,292	$	96,732		$	48,929	$	124,894		$	175,450
Less- Change in accounting principle		—		(15,600	)		—		—			—
Add- Taxes based on income		64,245		72,433			21,955		77,799			100,005

Net income before income taxes and change in accounting principle		171,537		184,765			70,884		202,693			275,455
Add- fixed charges:
Interest on long term debt		93,118		71,720			59,070		54,783	⁽¹⁾		54,153	⁽¹⁾
Estimated interest cost within rental expense		—		—			107		164			228
Amortization of net debt premium, discount, and expenses		1,497		1,345			586		586			760

Total fixed charges		94,615		73,065			59,763		55,533			55,141

Earnings available for fixed charges	$	266,152	$	257,830		$	130,647	$	258,226		$	330,596

Ratio of earnings to fixed charges		2.81		3.52			2.18		4.64			5.99

⁽¹⁾ Includes FIN 48 interest expense

Exhibit 12.5

CILCORP INC.

Computation of Ratio of Earnings to Fixed Charges

(Thousands of Dollars, Except Ratios)


	Year Ended December 31,
	2004			2005			2006			2007			2008
Net income from continuing operations	$	10,367		$	3,222		$	21,004		$	49,402		$	43,542
Less- Change in accounting principle		—			(2,497	)		—			—			—
Add- Taxes based on income (benefit)		(8,526	)		(3,164	)		(10,944	)		21,018			19,411

Net income before income taxes and change in accounting principle		1,841			2,555			10,060			70,420			62,953
Add- fixed charges:
Interest on long term debt		51,992			50,562			51,574			62,824	⁽¹⁾		53,592	⁽¹⁾
Estimated interest cost within rental expense		395			390			289			343			430
Amortization of net debt premium, discount, and expenses		767			693			801			1,322			1,428
Subsidiary preferred stock dividends		2,062			1,988			1,933			1,869			1,354
Adjust preferred stock dividends to pre-tax basis		346			1,293			(1,007	)		812			604

Total fixed charges		55,562			54,926			53,590			67,170			57,408

Less: Adjustment of preferred stock dividends to pre-tax basis		346			1,293			(1,007	)		812			604
Earnings available for fixed charges	$	57,057		$	56,188		$	64,657		$	136,778		$	119,757

Ratio of earnings to fixed charges		1.02			1.02			1.20			2.03			2.08

⁽¹⁾ Includes FIN 48 interest expense

Exhibit 12.6

Central Illinois Light Company

Computation of Ratios of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)


	Year Ended December 31,
	2004		2005			2006		2007			2008
Net income from continuing operations	$	32,384	$	25,296		$	47,012	$	75,984		$	69,638
Less- Change in accounting principle		—		(2,497	)		—		—			—
Add- Taxes based on income		5,450		16,357			9,966		39,195			38,673

Net income before income taxes and change in accounting principle		37,834		44,150			56,978		115,179			108,311
Add- fixed charges:
Interest on long term debt		15,179		13,918			18,044		26,071	⁽¹⁾		19,724	⁽¹⁾
Estimated interest cost within rental expense		395		390			289		343			429
Amortization of net debt premium, discount, and expenses		611		473			705		1,065			1,112

Total fixed charges		16,185		14,781			19,038		27,479			21,265

Earnings available for fixed charges		54,019		58,931			76,016		142,658			129,576

Ratio of earnings to fixed charges		3.33		3.98			3.99		5.19			6.09

Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends		2,062		1,998			1,933		1,869			1,354
Adjustment to pre-tax basis		346		1,293			410		977			752

		2,408		3,291			2,343		2,846			2,106

Combined fixed charges and preferred stock dividend requirements	$	18,593	$	18,072		$	21,381	$	30,325		$	23,371

Ratio of earnings to combined fixed charges and preferred stock dividend requirements		2.90		3.26			3.55		4.70			5.54

⁽¹⁾ Includes FIN 48 interest expense

Exhibit 12.7

Illinois Power Company

Computation of Ratios of Earnings to Fixed Charges and Combined

Fixed Charges and Preferred Stock Dividend Requirements

(Thousands of Dollars, Except Ratios)


	Year Ended December 31,
	2004 ⁽¹⁾		2005		2006		2007			2008
Net income from continuing operations	$	137,538	$	97,039	$	56,659	$	25,780		$	4,970
Add- Taxes based on income		87,591		65,171		37,246		15,341			4,746

Net income before income taxes		225,129		162,210		93,905		41,121			9,716
Add- fixed charges:
Interest on long term debt		112,616		41,028		46,167		69,085	⁽²⁾		91,143	⁽²⁾
Estimated interest cost within rental expense		1,696		1,290		205		234			701
Amortization of net debt premium, discount, expenses and losses		18,772		2,315		3,537		8,454			8,922

Total fixed charges		133,084		44,633		49,909		77,773			100,766

Earnings available for fixed charges		358,213		206,843		143,814		118,894			110,482

Ratio of earnings to fixed charges		2.69		4.63		2.88		1.52			1.09

Earnings required for combined fixed charges and preferred stock dividends:
Preferred stock dividends		2,294		2,294		2,294		2,294			2,294
Adjustment to pre-tax basis		1,461		1,542		1,508		1,365			2,191

		3,755		3,836		3,802		3,659			4,485

Combined fixed charges and preferred stock dividend requirements	$	136,839	$	48,469	$	53,711	$	81,432		$	105,251

Ratio of earnings to combined fixed charges and preferred stock dividend requirements		2.61		4.26		2.67		1.46			1.04

⁽¹⁾ Ameren Corporation purchased Illinois Power Company on September 30, 2004, amounts include combined predecessor and successor financial information.

⁽²⁾ Includes FIN 48 interest expense

Exhibit 21.1

SUBSIDIARIES OF AMEREN CORPORATION

AT DECEMBER 31, 2008


Name		State or Jurisdiction of Organization
Ameren Corporation		Missouri
Ameren Development Company		Missouri
Enporion, Inc. (21% interest)		Delaware
Missouri Central Railroad Company		Delaware
CIPSCO Leasing Company		Illinois
Gateway Energy Systems, L.C. (89.1% interest)		Missouri
Gateway Energy WGK Project, L.L.C.		Illinois
Ameren Energy Resources Company, LLC		Delaware
Ameren Energy Generating Company		Illinois
Coffeen and Western Railroad Company		Illinois
Ameren Energy Marketing Company		Illinois
Illinois Materials Supply Co.		Illinois
Electric Energy, Inc. (80% interest)		Illinois
Midwest Electric Power Inc.		Illinois
Joppa and Eastern Railroad Company		Illinois
Met South, Inc.		Illinois
Massac Enterprises LLC		Illinois
AmerenEnergy Medina Valley Cogen, L.L.C.		Illinois
Ameren Energy Fuels and Services Company		Illinois
Ameren Illinois Transmission Company		Illinois
Ameren Services Company		Missouri
Central Illinois Public Service Company, d/b/a AmerenCIPS		Illinois
CILCORP Inc.		Illinois
Central Illinois Light Company, d/b/a AmerenCILCO		Illinois
AmerenEnergy Resources Generating Company		Illinois
CLC Aircraft Leasing LLC		Delaware
QST Enterprises Inc.		Illinois
ESE Land Corporation		Illinois
California/Nevada Development L.L.C. (15% interest)		Delaware
Energy Risk Assurance Company		Vermont
Missouri Energy Risk Assurance Company LLC		Missouri
Illinois Power Company, d/b/a AmerenIP		Illinois
Illinois Power Securitization Limited Liability Company*		Delaware
Illinois Power Special Purpose Trust*		Delaware
Union Electric Company, d/b/a AmerenUE		Missouri
Fuelco LLC (33.33% interest)		Delaware

Subsidiaries not included on this list, considered in the aggregate as a single subsidiary, would not constitute a significant subsidiary as of December 31, 2008.

Dissolved February 2009

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-152046, 333-155416, 333-155416-04 and 333-155416-05) and the Registration Statements on Form S-8 (Nos. 333-50793, 333-133998 and 333-136971) of Ameren Corporation of our report dated March 2, 2009 relating to the financial statements, financial statement schedule and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

Exhibit 23.2

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (Nos. 333-151432 and 333-151432-01) of Union Electric Company of our report dated March 2, 2009 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

Exhibit 23.3

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-155416-03) of Central Illinois Public Service Company of our report dated March 2, 2009 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

Exhibit 23.4

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-155416-02) and the Registration Statement on Form S-4 (No. 333-151014) of Ameren Energy Generating Company of our report dated March 2, 2009 relating to the financial statements, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

Exhibit 23.5

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-155416-01) of Central Illinois Light Company of our report dated March 2, 2009 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

Exhibit 23.6

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-155416-06) and the Registration Statements on Form S-4 (Nos. 333-149502, 333-150973 and 333-156606) of Illinois Power Company of our report dated March 2, 2009 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.

PricewaterhouseCoopers LLP

St. Louis, Missouri

March 2, 2009

Exhibit 24.1

POWER OF ATTORNEY

WHEREAS, AMEREN CORPORATION, a Missouri corporation (herein referred to as the “Company”), is required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2008; and

WHEREAS, each of the below undersigned is a director of the Company.

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Gary L. Rainwater and/or Warner L. Baxter and/or Thomas R. Voss and/or Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-fact of the undersigned, for and in the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments thereto, and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or more attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-fact may do by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:


Stephen F. Brauer, Director		/s/ Stephen F. Brauer


Susan S. Elliott, Director		/s/ Susan S. Elliott


Walter J. Galvin, Director		/s/ Walter J. Galvin


Gayle P. W. Jackson, Director		/s/ Gayle P. W. Jackson


James C. Johnson, Director		/s/ James C. Johnson


Charles W. Mueller, Director		/s/ C. W. Mueller


Douglas R. Oberhelman, Director		/s/ Douglas R. Oberhelman


Harvey Saligman, Director		/s/ Harvey Saligman


Patrick T. Stokes, Director		/s/ Patrick T. Stokes


Jack D. Woodard, Director		/s/ Jack D. Woodard

On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the above-named directors of Ameren Corporation, known to me to be the persons described in and who executed the foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.

IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.

/s/ Carolyn J. Shannon

CAROLYN J. SHANNON

Notary Public- Notary Seal

STATE OF MISSOURI- ST. LOUIS COUNTY

Commission #08383284

My Commission Expires 03/02/2012

Exhibit 24.2

POWER OF ATTORNEY

WHEREAS, UNION ELECTRIC COMPANY, a Missouri corporation (herein referred to as the “Company”), is required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2008; and

WHEREAS, each of the below undersigned is a director of the Company.

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Thomas R. Voss and/or Warner L. Baxter and/or Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-fact of the undersigned, for and in the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments thereto, and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or more attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-fact may do by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:




Daniel F. Cole, Director				/s/ Daniel F. Cole

Adam C. Heflin				/s/ Adam C. Heflin

Richard J. Mark, Director				/s/ Richard J. Mark

Steven R. Sullivan, Director				/s/ Steven R. Sullivan

On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the above-named directors of Union Electric Company, known to me to be the persons described in and who executed the foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.

IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.

/s/ Carolyn J. Shannon

CAROLYN J. SHANNON

Notary Public – Notary Seal

STATE OF MISSOURI – ST. LOUIS COUNTY

Commission #08383284

My Commission Expires 03/02/2012

Exhibit 24.3

POWER OF ATTORNEY

WHEREAS, CENTRAL ILLINOIS PUBLIC SERVICE COMPANY, an Illinois corporation (herein referred to as the “Company”), is required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2008; and

WHEREAS, each of the below undersigned is a director of the Company.

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Scott A. Cisel and/or Warner L. Baxter and/or Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-fact of the undersigned, for and in the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments thereto, and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or more attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-fact may do by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:




Daniel F. Cole, Director				/s/ Daniel F. Cole

Steven R. Sullivan, Director				/s/ Steven R. Sullivan

On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the above-named directors of Central Illinois Public Service Company, known to me to be the persons described in and who executed the foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.

IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.

/s/ Carolyn J. Shannon

CAROLYN J. SHANNON

Notary Public – Notary Seal

STATE OF MISSOURI – ST. LOUIS COUNTY

Commission #08383284

My Commission Expires 03/02/2012

Exhibit 24.4

POWER OF ATTORNEY

WHEREAS, AMEREN ENERGY GENERATING COMPANY, an Illinois corporation (herein referred to as the “Company”), is required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2008; and

WHEREAS, each of the below undersigned is a director of the Company.

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Charles D. Naslund and/or Warner L. Baxter and/or Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-fact of the undersigned, for and in the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments thereto, and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or more attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-fact may do by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:




Daniel F. Cole, Director				/s/ Daniel F. Cole

Steven R. Sullivan, Director				/s/ Steven R. Sullivan

On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the above-named directors of Ameren Energy Generating Company, known to me to be the persons described in and who executed the foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.

IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.

/s/ Carolyn J. Shannon

CAROLYN J. SHANNON

Notary Public – Notary Seal

STATE OF MISSOURI – ST. LOUIS COUNTY

Commission #08383284

My Commission Expires 03/02/2012

Exhibit 24.5

POWER OF ATTORNEY

WHEREAS, CILCORP Inc., an Illinois corporation (herein referred to as the “Company”), is required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2008; and

WHEREAS, each of the below undersigned is a director of the Company.

NOW, THEREFORE, each of the undersigned hereby constitutes and appoints Gary L. Rainwater and/or Warner L. Baxter and/or Steven R. Sullivan and/or Martin J. Lyons and/or Jerre E. Birdsong the true and lawful attorneys-in-fact of the undersigned, for and in the name, place and stead of the undersigned, to affix the name of the undersigned to said Form 10-K and any amendments thereto, and, for the performance of the same acts, each with power to appoint in their place and stead and as their substitute, one or more attorneys-in-fact for the undersigned, with full power of revocation; hereby ratifying and confirming all that said attorneys-in-fact may do by virtue hereof.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:




Daniel F. Cole, Director				/s/ Daniel F. Cole

Patrick T. Stokes, Director				/s/ Patrick T. Stokes

Steven R. Sullivan, Director				/s/ Steven R. Sullivan

On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the above-named directors of CILCORP Inc., known to me to be the persons described in and who executed the foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.

IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.

/s/ Carolyn J. Shannon

CAROLYN J. SHANNON

Notary Public – Notary Seal

STATE OF MISSOURI – ST. LOUIS COUNTY

Commission #08383284

My Commission Expires 03/02/2012

Exhibit 24.6

POWER OF ATTORNEY

WHEREAS, CENTRAL ILLINOIS LIGHT COMPANY, an Illinois corporation (herein referred to as the “Company”), is required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2008; and

WHEREAS, each of the below undersigned is a director of the Company.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:




Daniel F. Cole, Director				/s/ Daniel F. Cole

Steven R. Sullivan, Director				/s/ Steven R. Sullivan

On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the above-named directors of Central Illinois Light Company, known to me to be the persons described in and who executed the foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.

IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.

/s/ Carolyn J. Shannon

CAROLYN J. SHANNON

Notary Public – Notary Seal

STATE OF MISSOURI – ST. LOUIS COUNTY

Commission #08383284

My Commission Expires 03/02/2012

Exhibit 24.7

POWER OF ATTORNEY

WHEREAS, ILLINOIS POWER COMPANY, an Illinois corporation (herein referred to as the “Company”), is required to file with the Securities and Exchange Commission, under the provisions of the Securities Exchange Act of 1934, as amended, its annual report on Form 10-K for the year ended December 31, 2008; and

WHEREAS, each of the below undersigned is a director of the Company.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands this 13th day of February 2009:

On this 13th day of February, 2009, before me, the undersigned Notary Public in and for said State, personally appeared the above-named directors of Illinois Power Company, known to me to be the persons described in and who executed the foregoing power of attorney and acknowledged to me that they executed the same as their free act and deed for the purposes therein stated.

IN TESTIMONY WHEREOF, I have hereunto set my hand and affixed my official seal.

/s/ Carolyn J. Shannon

CAROLYN J. SHANNON

Notary Public – Notary Seal

STATE OF MISSOURI – ST. LOUIS COUNTY

Commission #08383284

My Commission Expires 03/02/2012

Exhibit 31.1

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN CORPORATION

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Gary L. Rainwater, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Ameren Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Gary L. Rainwater

Gary L. Rainwater

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

Exhibit 31.2

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN CORPORATION

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Warner L. Baxter, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Ameren Corporation;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/ S / W ARNER L. B AXTER

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 31.3

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL EXECUTIVE OFFICER OF UNION ELECTRIC COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Thomas R. Voss, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Union Electric Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/ S / T HOMAS R. V OSS

Thomas R. Voss

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

Exhibit 31.4

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL FINANCIAL OFFICER OF UNION ELECTRIC COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Warner L. Baxter, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Union Electric Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 31.5

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL EXECUTIVE OFFICER OF CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Scott A. Cisel, certify that:

1. I have reviewed this report Form 10-K for the fiscal year ended December 31, 2008 of Central Illinois Public Service Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Scott A. Cisel

Scott A. Cisel

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

Exhibit 31.6

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL FINANCIAL OFFICER OF CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Warner L. Baxter, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Central Illinois Public Service Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 31.7

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL EXECUTIVE OFFICER OF AMEREN ENERGY GENERATING COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Charles D. Naslund, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Ameren Energy Generating Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Charles D. Naslund

Charles D. Naslund

Chairman and President

(Principal Executive Officer)

Exhibit 31.8

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL FINANCIAL OFFICER OF AMEREN ENERGY GENERATING COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Warner L. Baxter, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Ameren Energy Generating Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 31.9

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL EXECUTIVE OFFICER OF CILCORP INC.

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Gary L. Rainwater, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of CILCORP Inc.;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Gary L. Rainwater

Gary L. Rainwater

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

Exhibit 31.10

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL FINANCIAL OFFICER OF CILCORP INC.

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Warner L. Baxter, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of CILCORP Inc.;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 31.11

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL EXECUTIVE OFFICER OF CENTRAL ILLINOIS LIGHT COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Scott A. Cisel, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Central Illinois Light Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Scott A. Cisel

Scott A. Cisel

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

Exhibit 31.12

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL FINANCIAL OFFICER OF CENTRAL ILLINOIS LIGHT COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Warner L. Baxter, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Central Illinois Light Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 31.13

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL EXECUTIVE OFFICER OF ILLINOIS POWER COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Scott A. Cisel, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Illinois Power Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Scott A. Cisel

Scott A. Cisel

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

Exhibit 31.14

RULE 13a-14(a)/15d-14(a) CERTIFICATION

OF PRINCIPAL FINANCIAL OFFICER OF ILLINOIS POWER COMPANY

(required by Section 302 of the Sarbanes-Oxley Act of 2002)

I, Warner L. Baxter, certify that:

1. I have reviewed this report on Form 10-K for the fiscal year ended December 31, 2008 of Illinois Power Company;

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 2, 2009

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.1

SECTION 1350 CERTIFICATION OF

AMEREN CORPORATION

(required by Section 906 of the

Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-K for the fiscal year ended December 31, 2008 of Ameren Corporation (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: March 2, 2009

/s/ Gary L. Rainwater

Gary L. Rainwater

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.2

SECTION 1350 CERTIFICATION OF

UNION ELECTRIC COMPANY

(required by Section 906 of the

Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-K for the fiscal year ended December 31, 2008 of Union Electric Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: March 2, 2009

/s/ Thomas R. Voss

Thomas R. Voss

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.3

SECTION 1350 CERTIFICATION OF

CENTRAL ILLINOIS PUBLIC SERVICE COMPANY

(required by Section 906 of the

Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-K for the fiscal year ended December 31, 2008 of Central Illinois Public Service Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: March 2, 2009

/s/ Scott A. Cisel

Scott A. Cisel

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.4

SECTION 1350 CERTIFICATION OF

AMEREN ENERGY GENERATING COMPANY

(required by Section 906 of the

Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-K for the fiscal year ended December 31, 2008 of Ameren Energy Generating Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: March 2, 2009

/s/ Charles D. Naslund

Charles D. Naslund

Chairman and President

(Principal Executive Officer)

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.5

SECTION 1350 CERTIFICATION OF

CILCORP INC.

(required by Section 906 of the

Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-K for the fiscal year ended December 31, 2008 of CILCORP Inc. (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: March 2, 2009

/s/ Gary L. Rainwater

Gary L. Rainwater

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.6

SECTION 1350 CERTIFICATION OF

CENTRAL ILLINOIS LIGHT COMPANY

(required by Section 906 of the

Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-K for the fiscal year ended December 31, 2008 of Central Illinois Light Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: March 2, 2009

/s/ Scott A. Cisel

Scott A. Cisel

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)

Exhibit 32.7

SECTION 1350 CERTIFICATION OF

ILLINOIS POWER COMPANY

(required by Section 906 of the

Sarbanes-Oxley Act of 2002)

In connection with the report on Form 10-K for the fiscal year ended December 31, 2008 of Illinois Power Company (the “Registrant”) as filed by the Registrant with the Securities and Exchange Commission on the date hereof (the “Form 10-K”), each undersigned officer of the Registrant does hereby certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)); and

(2)	The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: March 2, 2009

/s/ Scott A. Cisel

Scott A. Cisel

Chairman, President and

Chief Executive Officer

(Principal Executive Officer)

/s/ Warner L. Baxter

Warner L. Baxter

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)