Edgar Filing: AMEREN CORP

Form 10-K

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.

CO₂ – 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.

SO₂ – 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, SO₂, 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.

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. 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 SO₂, 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 CO₂, 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 CO₂ 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 CO₂ 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 CO₂ 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 CO₂ 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 CO₂ 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 SO₂ 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.

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. 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 SO₂, 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 CO₂ 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 SO₂ 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: